EnergyNow July 2015 by Kerry Peters

Opinion | Page 12

More contracts required for deepwater resources bordering Venezuela

Opinion | Page 16

Being responsible is the heart of CSR, not doing “responsible acts”

Issue 03 July 2015 Free Copy

energy.tt

A publication of the Energy Chamber of Trinidad and Tobago

TOFCO forced to use Texas fabricator Lessons for energy services firms from Juniper jacket relocation Kerry Peters | @kerrypetersceo

peculation about the future of the local fabrication industry rose this week on news that TOFCO, the major supplier of offshore fabrication services in the country, had farmed out to a U.S. company some of the construction work it had been hired to do for bpTT’s $2.1 billion Juniper project.

On July 16, both TOFCO and bpTT issued press releases announcing that construction of the jacket and piles for the Juniper platform had been relocated to the Gulf Coast. Neither bpTT nor TOFCO would confirm the identity of their new supplier, but there have been several press reports that Gulf Island Fabrication, a Houston-based specialist in floating production platforms, has recently won offshore construction work for Trinidad. It is unclear if this is for Juniper or another upcoming Trinidad-based project. A source close to the story said TOFCO had been forced to make the decision after it lost 97 days through

Twitter: @ttenergychamber

07 A data centre to rule them all 21 Venezuela's gas deposits to replace diesel, save billions

a combination of industrial unrest and an incident last March in which Colombian authorities impounded a Chinese vessel transporting steel and other materials to its Labidco facility in La Brea. The vessel had been leased by TOFCO’s German supplier and remained docked in Colombian waters for 45 days after authorities found arms and ammunition bound for Cuba. Moreover, contractual obligations require bpTT to produce first gas from Juniper in 2017 or face penalties, so there was no chance that delivery of the topside, jacket and piles could be pushed back. k Continued on page 03

Drill floor of the Ocean Victory rig which is currently drilling off Trinidad's southeast coast

Photo by Mark Gellineau

Opinion

Tough calls must be made on unsustainable fuel subsidies Dax Driver | Energy Chamber CEO In Trinidad and Tobago, whoever takes over the reins of government in September 2015 will also have some tough decisions to make, one of which pertains to our subsidies … k Story on page 11

Regional

Exploration activity picks up in Suriname Staff Writer Photo by Marc Morrison

k Story on page 19

energy.tt |

@ttenergychamber | July 2015

energy.tt/news @ttenergychamber

Lack of double taxation agreement with Suriname hurting business Staff Writer The lack of a double taxation agreement with Suriname is hampering the growth of Trinidad and Tobago business with that country, a view shared by several energy services companies which must pay taxes to both the Surinamese government and to the government of Trinidad and Tobago. The double taxation agreement says that profits resulting from business activities are only taxable by the member state where those activities are carried out. The agreement has been signed by Trinidad and Tobago, Antigua and Barbuda, Grenada, Jamaica, St. Kitts and Nevis, St. Lucia, and St. Vincent and the Grenadines. For energy operators, business activities include construction in progress at any place or facility where natural resources are extracted or exploited. Suriname became a member of CARICOM in 1995 and is not a signatory to the double taxation agreement of 1994. For Trinidad and Tobago firms operating in Suriname, double taxation is a financial burden that undermines their competitiveness. Moreover, it is a trade barrier for smaller energy services companies trying to penetrate the Surinamese market. Double taxation treaties are not abnormal and are allowed within World Trade Organization (WTO) rules. But the Energy Chamber has been lobbying to replace double taxation agreements altogether with a bilateral treaty between Suriname and Trinidad and Tobago. Failing that, the next best option — and the one that might provide the quickest relief — is an amendment to the double taxation order to include Suriname. Either option would require CARICOM’s approval. Energy Chamber CEO Dax Driver said after a trade mission to Suriname in June that the Surinamese were open to a double taxation agreement since there was limited risk to them. “The important thing here is to bring relief to local firms now,” Driver said. “There is an elephant in the room and we have to act quickly.” Below: A worker at the Uitkijk onshore block in Suriname. Learn more and have your say online: fb.com/ttenergychamber · #energynow

Photo courtesy Staatsolie

Photo by Mark Gellineau

TOFCO forced to use Texas fabricator Lessons for energy services firms from Juniper jacket relocation Continued from page 01 It was the dire shortage of natural gas facing the country, the potential loss of government revenue, the spectre of penalties and the multiplier effect of each of these factors which led bpTT to accept TOFCO’s recommendation to use an alternate supplier “to preserve the project schedule.” On a project the size and scope of Juniper, there was simply no wiggle room, sources said. In these circumstances, TOFCO’s decision to outsource appears to make business sense. Yet it is emblematic of broader challenges facing local energy services providers in a low-price environment in which capital projects in all major markets have either been postponed or shelved. In the case of major offshore fabrication, Korean firms still dominated most topside work up to the middle of 2015. Superior capacity, including in-house engineering and subsidies from the Korean government, have boosted their financial strength and made yards such as Daewoo and Samsung hard to compete with. In Houston, companies like Seadrill and McDermott International Inc, put out by sustained low oil and gas prices, have reported significant job cuts. The San Antonio Business Journal reported last month that Gulf Marine Fabricators, which was acquired by Gulf Island Fabrication in 2006, was gearing up to lay off more than 500 energy workers by the end of July.

Facing decreased workloads brought about by low oil prices and stiff competition, these fabrication yards in the U.S., where, incidentally, there are no local content requirements, have been scrambling to fill order books. What they currently lack in number of orders, they make up for in their capacity to handle whatever is thrown at them. Fabricators on the US Gulf Coast are able to build significantly larger platforms than small yards in locations like Trinidad. These yards boast superior engineering technology, more acreage and skilled labour. Local fabrication, for example, has been hit with a shortage of welders with 6GR certification, according to a source familiar with the Juniper project. Considering their strategic location relatively close to Trinidad, fabrication yards such as Gulf Island could easily compete for more local projects, especially those with challenges beyond the control of the project owners, as TOFCO’s case proved. By one gauge of competitiveness, TOFCO has much to be proud of: It has an impressive track record. In the past few years, it has built a total of eight platforms on schedule and within budget at its La Brea yard, five for bpTT alone, all to world-class standards. A joint venture between Weldfab of Trinidad and Chet Morrison of the U.S., TOFCO won the Juniper contract from

among a tough field. Pound-for-pound, the company can compete. But with the loss of vital project days, it simply lacked the bespoke facilities to deliver all three components for Juniper on time. Another source who requested anonymity provided further insight into why Juniper’s jacket construction had to be moved to Texas. “The variables between the U.S. and any other country is that the number of men [working on fabrication projects] and the number of days will be lower. But the cost per man-hour will be higher. Strictly speaking, the U.S. yards can do it quicker because of their facilities.” Sources say fabrication yards are designed for the markets they serve, so it would be interesting to see what adjustments TOFCO makes to existing facilities to be more competitive with deepwater exploration on the horizon. No doubt, Juniper has been a learning opportunity for the company. TOFCO’s past projects simply do not compare with Juniper. Its largest topside before Juniper was Poinsettia, a major installation for BG T&T in 2009 weighing 3,600 tonnes in 530 feet of water. By comparison, Juniper’s jacket alone is 5,775 tonnes with the deck coming in at 4,500 tonnes and 3,400 tonnes for the piles, all bound for installation in 360 feet of water, 50 miles off Trinidad’s southeast coast. A bpTT spokesperson confirmed to EnergyNow that construction of the jacket and piles by the Texas fabricator — the work that TOFCO lost — accounts for 2 percent of Juniper’s overall project

costs. This includes both electrical and steel work. Even as TOFCO proceeds with construction of the Juniper topside at its La Brea plant for delivery in the last quarter of 2016, the message that it’s not business as usual for local energy services companies was echoed by bpTT itself in response to questions from EnergyNow: “Given the current price environment and the increased focus by operators on capital discipline, there is a global decline in major capital projects and increased pressure on service providers to be more efficient and to deliver services at better costs. This naturally creates a lot more competition in the services sector across all markets. Trinidad and Tobago therefore needs to be very mindful of this and may need to make adjustments to ensure that its energy services can continue to compete with those of other markets.” “Whoever is appointed Minister of Energy and Energy Affairs after the September 7 general election,” said Chamber CEO Dax Driver, “will do well to consider TOFCO’s experience before and after Juniper in any policies around local content.” Above: The waterfront facility of Trinidad Offshore Fabricators (TOFCO) where a total of eight platforms have been completed. TOFCO is currently building the topside for bpTT's Juniper platform, its largest project to date. Learn more and have your say online: fb.com/ttenergychamber · #energynow

| energy.tt

@ttenergychamber | July 2015

News Ammonia prices down but De La Bastide optimistic Link to natural gas supply, prices confirmed Andrew Hosein | @andrewhosein

lobal ammonia prices are down 13 percent at the end of the first half of 2015, and while they have not fallen as dramatically as oil and gas prices, the Trinidad and Tobago ammonia industry is faced with threats from several fronts. Richard De La Bastide, president of Yara Trinidad, said the decline confirms that the price of ammonia is linked to the supply and pricing of natural gas, since gas is a major input into the production process. He noted that most of the global ammonia production is geared toward conversion to downstream products (fertilisers such as urea, ammonium nitrate and ammonium phosphate), while only 10 percent is exported for international trade, and it is this 10 percent that determines the global price. One of the major drivers of falling ammonia prices has been the lower price of natural gas — largely due to increased gas production through U.S. shale gas. The impact on the ammonia industry has resulted in higher-capacity utilisation rates of marginal commodity producers. According to De La Bastide, these global dynamics in the ammonia market are also motivating producers to build chemical plants in the U.S., thereby increasing supply. There are several projects at various stages of development in the midwest and southern states such as Louisiana and Texas aimed at boosting ammonia, urea and UAN production. Most of the new production of ammonia is geared toward onsite production of downstream products such as urea; however, there are a few standalone projects which will reduce demand for imported ammonia, and the U.S. has traditionally been one of Trinidad and Tobago’s major export markets for ammonia. “Trinidad will follow a pattern similar to that of LNG,” De la Bastide said, “by moving to access alternative markets in Latin America, including Brazil and Mexico, as well as Europe.” While ammonia supply is expected to increase in the U.S., demand is still

expected to outstrip supply in regional markets in Latin America, Europe, North Africa and Asia. Exporting to diversified markets, however, comes with new challenges, and De La Bastide says that distance to these markets will result in higher freight costs and lower netback prices. “Trinidad and Tobago still has a competitive advantage in the ammonia market, since most plants in Trinidad are well-established and were built at a time when construction costs were less than the price of building a new plant in the U.S. today,” said De La Bastide. Even the older plants on the Point Lisas Estate are being upgraded. Two of the major producers of ammonia in Trinidad, Yara and PCS Nitrogen, have executed efficiency upgrades in older plants in recent years to ensure that they get the most out of their feedstock. An efficiency upgrade to an existing brownfield plant, he says, can often provide an attractive return on investment for the company as well as the country. But the Yara Trinidad president lamented that natural gas curtailments have been hurting the local industry. The inconsistency of supply means that the plants cannot operate at maximum efficiency despite upgrade investments. He indicated that inconsistent production has led to increased maintenance, costs since more wear and tear is experienced when production levels vary. De la Bastide recalled that the industry had been competitive in the past mainly because of access to markets and relatively competitive natural gas prices. The local price of natural gas and regular supply is a major factor for overall competitiveness, as are geographic concentration and the sheer economy of scale at the Point Lisas estate. As he acknowledges the challenges facing his company, De la Bastide said he is encouraged by the development of the Juniper project and recent cross-border talks with Venezuela regarding the Loran-Manatee field. Learn more and have your say online: fb.com/ttenergychamber · #energynow

Below: President of Yara Trinidad Limited Richard De La Bastide.

Photo by Mark Gellineau

Above: A aerial shot of Petrotrin's refinery in Pt. Lisas. Petrotrin's supply could be improved through enhanced oil recovery techniques for which the MEEA recently funded two R&D initiatives.

Research projects could revive Trinidad’s stagnant oil production Energy Minister throws support behind R&D David Renwick Energy Journalist Research into aspects of Trinidad and Tobago’s TT$67 billion (2012 prices) petroleum sector has suddenly been pushed to the front burner as both the Ministry of Energy and Energy Affairs (MEEA) and the Petroleum Studies Unit (PSU) of the University of the West Indies (UWI), St. Augustine, embark on such projects. For years, research and development (R&D) contributions made by energy companies signing on to production sharing contracts (PSCs) have been largely lying idle and have not been utilised for their intended purposes. Minister of Energy and Energy Affairs Kevin Christian Ramnarine has been keen for some time to rectify that situation, and he has chosen two components of what he calls “Trinidad and Tobago’s new energy economy” as the first subjects of assessment — heavy oil, and carbon dioxide recovery and its use in retrieving “left-behind” crude oil in reservoirs scattered around south Trinidad. The formal names for the projects are: “A techno-economic analysis of heavy oil in Trinidad and Tobago” and “A techno-economic analysis of carbon management in Trinidad and Tobago through enhanced oil recovery (EOR) and geological storage.” “R&D money has seldom been used for its intended purpose,” Minister Ramnarine has often complained, so he has thrown those two projects into the lap of the University of Trinidad and Tobago (UTT), with a government grant of TT$4.5 million to fund them. Heavy oil is defined by the MEEA as that with an API gravity rating of 18 degrees or less, and only a small portion of the billions of barrels that are

believed to exist on land and offshore in the Gulf of Paria has so far been recovered, primarily because of the expense involved and the difficulties Petrotrin’s refinery may face in processing it. CO2 injection, for its part, is seen as the favoured method of EOR in relation to left-behind oil, of which there is also estimated to be billions of barrels, but it requires being captured (principally from the Point Lisas petrochemical plants) and transported to the locations where it is needed. The findings of these two research projects could eventually lead to a significant turnaround of the country’s stagnant crude oil production. At the Petroleum Studies Unit at UWI, meanwhile, newly-installed Professor Andrew Jupiter, who has taken over administration of the unit from Professor Richard Dawe, is throwing himself with gusto into his own energy industry-related research. He has also been tapping into R&D research funds and has persuaded the MEEA to support two projects in the first instance, the titles of which are: 1. “Heavy oil recovery from Trinidad tar sands by radio frequency heating”; and 2. “A new technique in sequence stratigraphy for deep-water successions in non-glacial times.” The MEEA has agreed to allocate TT$543,000 for the first project and TT$463,000 for the second. Assistance is also being provided by the Harris Corporation of Orlando, Florida, for the first project and by the prestigious Smithsonian Institution in Washington for the second project. Professor Jupiter points out to EnergyNow that “the Harris Corporation is a top-class organisation that has done work for the United States government.” The Smithsonian Insti-

tution, of course, is the world’s largest museum and research complex. While UTT is looking into heavy-oil resources, the Petroleum Studies Unit is going one step further by focussing on tar sands which are at the very heavy end of heavy oil and have to be extracted through quarrying, rather than through drilling. The research initiative will, no doubt, show how radio frequency heating can be employed in this effort. Tar sands advocates insist that as much as 50,000 b/d of crude could be added to the country’s output if a determined effort were made to access some of the 300 million tonnes of the stuff even the MEEA believes to exist in south Trinidad. But even under the present minister, tar sands activity has been virtually ignored, so UWI has decided to take up the cudgels in this regard. With deepwater activity in nine blocks as the most important exploration programme in Trinidad and Tobago at the moment, Jupiter insists his second project will produce results that can materially assist in this effort. “We should get a much better understanding of deep water, so we will know how to proceed in terms of exploiting deepwater resources — how we can optimise exploration in deep water, that’s the important thing.” BHP Billiton, the operator of all the deepwater blocks that have been allocated so far by the MEEA, “is funding a full scholarship for a student to study reservoir characterisation in Trinidad and its extension into deep water.” Jupiter confidently expects the findings of the student “to be helpful to the company as they unfold.” Learn more and have your say online: fb.com/ttenergychamber · #energynow

energy.tt |

@ttenergychamber | July 2015

News Tax incentives may be key to development of smaller gas fields Ramnarine: A separate fiscal regime will be required David Renwick | Energy Journalist

Photo by Marc Morrison Above: bpTT's Cassia B offshore platforms is responsible for two-thirds of the company’s daily production but between one and two trillion cubic feet of stranded gas in smaller or mature pools could boost supply.

Smaller gas pools, remnants of older wells could help boost supply David Renwick | Energy Journalist

t a time when gas demand seems to be outstripping supply, small gas pools need to be developed (see other story in this issue) and “left-behind” gas in mature pools must be accessed as well, contend energy analysts. They point out that an unbelievable 50 percent of gas in a productive reservoir can fail to make it to the surface when the pressure in the reservoir drops below that at the wellhead. In the case of the country’s biggest gas producer, bpTT, the amount of that “stranded gas” has been estimated at 25 to 40 percent. The gas in the scores of accumulations mapped by the bpTT comes up to about “1 to 2 trillion cubic feet (tcf ),” declares Yatindranath Keith Bally, the company’s vice president for reservoir development. For a company that adheres to a “no molecule left behind” policy, this situation is clearly unsatisfactory, no matter how many new gas fields are discovered in the meantime. As long ago as 2008, bpTT began investigating the financial and technological feasibility of a low-pressure reserves

access (LPRA) project, designed to recover as much stranded gas as possible, which was due to be given the green light by late 2009. Somehow, the programme fell off the front burner and other projects took precedence, but Bally insists that “LPRA has not been abandoned and we still have it in our development plan. We are still looking at various ways of how best to do it.” The concept behind LPRA is fairly simple. As Bally explains: “If you reduce the pressure at the Cassia hub, for example, all the fields that come into the hub will see a lower pressure back on their systems, which translates to a lower pressure at the sand face and allows you to produce more gas. But you have to work it out — if you reduce the pressure, how much are you going to get?” That’s the key, because the whole idea is to retrieve as much of the stranded gas as possible. But it’s a matter of timing, Bally insists, which probably explains why LPRA has not yet been put into effect. “You don’t want to pull the pressure down on these facilities if you believe there is new stuff that is going to come

through, because the new stuff will overwhelm that. So you want to make sure you do it properly.” bpTT undoubtedly also wants to make sure it can keep costs down. A price tag of US$1 billion was originally put on LPRA in 2008. The final cost will be influenced by the development concept chosen. LPRA will entail modifications to existing infrastructure offshore, including pipelines and platforms and, of course, the addition of compressors. Fluid-handling systems and control system modifications are also almost always part of a compression project. Onshore infrastructure improvements are also likely. “We are looking at various options on how we do the compression,” Bally points out. “Will it be strictly all offshore? What type of compression will we need? This is where technology plays a role and we are looking at the most cost-effective approach.” While Bally stresses that LPRA is still on the cards, he also says the country should not expect that stranded gas to make it to the market soon. Right now, bpTT is busy with reservoirs that can produce under existing primary pressure, such as the Juniper field development, which will have an output of around 590 million cubic feet per day (mmcfd) from the Coralita and Lantana gas discoveries made many years ago. Water depth in the area is about 360 feet and the reserves are being tapped through subsea wells, a first for bpTT in this country. Learn more and have your say online: fb.com/ttenergychamber · #energynow

About 6.2 trillion cubic feet (tcf ) of natural gas resources on a risked basis are locked up in small gas pools, mainly in Trinidad and Tobago’s East Coast Marine Area (ECMA), with little or no effort being made to retrieve them. This is more than twice the amount of gas in the Manatee field in block 6d (2.7 tcf ) in the unitised, cross-border arrangement with Venezuela’s Loran discovery in its Plataforma Deltana block 2. Eventual extraction of Manatee and Loran reserves (7.3 tcf ) is being pursued, but significant accumulations elsewhere on the Trinidad and Tobago side of the border have been almost completely neglected so far. That 6.2 tcf on a risked basis (39.9 tcf unrisked) is sitting in about 151 scattered prospects, mainly in bpTT’s acreage. The size is about 200 billion cubic feet or less. Like all other gas producers, the company has, up to now, preferred to spend money developing much larger discoveries (usually in the 1 tcf range) simply because it is more economical to do so. Small gas discoveries do not pass the commercialisation hurdle because “developing them is very costly,” as bpTT’s president, Norman Christie, has often pointed out. Energy and Energy Affairs Minister Kevin Christian Ramnarine seems sympathetic to this view. As he told an Energy Chamber luncheon in mid-May, “These small gas deposits, depending on their liquid content and distance from infrastructure, may not justify exploration expenditure.” But he also accepts that “we cannot ignore those stranded reserves. Poten and Partners has identified this as a key finding of the Natural Gas Master Plan.” The Minister conceded in that same address to the Energy Chamber that “a separate fiscal regime will be required for the development of these small prospects.” In other words, only tax incentives will bestir upstream companies to take small pool exploitation seriously. The government realised earlier that incentives would be useful in encouraging the development of small oil pools and offered a special supple-

Photo by Mark Gellineau

mental petroleum tax (SPT) rate of 25 percent in 2012 for companies to do so. How successful this has been is not known precisely, as Minister Ramnarine has not reported back on the matter. But it must have been reasonably successful for him to consider offering a similar fiscal lure for small gas pool development. The Minister’s position is backed up by that of Gregory Hannays, industry leader, energy, for Ernst and Young Services, who has noted in the past that “incentives for small gas pool development are absolutely needed.” With Parliament dissolved, it is impossible for Ramnarine to put his small gas pool fiscal incentive into effect, so that inducement will have to wait for the next government, be it the People’s Partnership (PP) or otherwise. But the very possibility of such relief has caused bpTT, which already produces an average of about 2 billion cubic feet a day (bcfd) from existing larger gas fields, to take another look at the potential for small gas pool development. bpTT’s vice president for reservoir development, Yatindranath Keith Bally, told EnergyNow that “if you operate under the mantra of leaving no molecule behind, as bpTT does, then you’ve got to figure out a way of going after small gas pools, because when you add all these fields together, the reserves are bound to be big.” He concedes that “it may require fiscal incentives,” but it also needs the requisite “technology and operating in an innovative manner.” bpTT, like all other gas producers, also has “left-behind gas” in its larger fields, the recovery of which could also be part of any incentives considered. Below: Energy Minister Kevin Ramnarine addresses stakeholders at an event hosted by the Energy Chamber in May. Minister Ramnarine indicated then that tax incentives may be the best way to develop T&T's stranded reserves. Learn more and have your say online: fb.com/ttenergychamber · #energynow

energy.tt |

@ttenergychamber | July 2015

News

A data centre to rule them all LandOcean makes case for centralised data management Kerry Peters | @kerrypetersceo Chinese company LandOcean is set to expand its interests in the sector should the government join forces to build a best-in-class data centre. The facility will be designed to store and optimise years of geological research and, more broadly, make T&T the energy technology hub for the region. It’s the latest plug for growing the T&T economy by exploiting Big Data. Gwengwen Sun, LandOcean’s chairman, estimates that the National Energy Data Centre, a Tier III facility, will cost approximately US$100 million and measure 200,000 square feet when completed. The facility will likely offer tiered services including cloud access to highquality geospatial data. LandOcean says it wants to enable T&T to provide powerful exascale computing specifically for multinationals operating in Latin America and the Caribbean. Potentially, the data centre could sell secure storage and processing services to countries such as Peru, Ecuador, Colombia, Venezuela, Jamaica, Barbados and Guyana, where supermajor ExxonMobil has just announced a significant hydrocarbon find. Over time, it could offer competitively-priced data services to countries as far away as North Africa. But there’s a catch. To bring the idea to fruition, Sun is proposing a concessional loan deal between Trinidad and Tobago and the Chinese government. His team has already submitted a proposal to local investment promotion agency InvesTT and had preliminary talks with InvesTT president Racquel Moses as well as T&T’s ambassador in Beijing, Chandradath Singh.

“I am aware that there is an election going on,” Sun said through David Chen, his business partner in the role of interpreter, “But we need to actively consider this type of infrastructure investment [and get] the Chinese government to help.” Under the project, LandOcean will build the facility and provide technical services. These include petroleum geological data processing, reservoir simulation, digital oilfield technology and seismic data processing. There’s a plan to clean up a rash of datasets that either exist in silos or, worse, are unusable. The company said it will also deploy its own E&P software, which it claims is every bit as powerful as Schlumberger’s GeoQuest but competitively priced. Several factors suggest that any proposal for a central data repository for the energy sector merits consideration. First, the industry has been clamouring for this for years. Second, LandOcean is not the first company to float the idea. David Borde of PetroCom Technologies has been making the case to successive Ministers of Energy for the past eight years. “We are calling it the Petroleum Intelligence Centre that would drive the knowledge economy,” Borde said. “We are talking about adding 10 percent to GDP based on better data.” Michelle Allum, PetroCom’s technical team lead and a petroleum geoscientist, has overseen her company’s assessment of the way data is handled across the industry. “The ministry’s practices have to move from storage to data optimisation, Allum said. “It is huge and complex and

Photo by Mark Gellineau Above: LandOcean Chairman Gwengwen Sun (left) and business partner David Chen, who is the Chairman of Range Resources, discuss a proposal for a super data centre to host T&T's geological data. it is going to require significant stakeholder consultation.” In the past 10 years, policies on data management across successive administrations have become stale. There has been nothing further from the ministry about the draft energy policy which fol-

lowed consultations in 2011, when issues about data management were raised. Executives interviewed for this story, speaking on condition of anonymity, said data security remains a primary concern, mostly because data provides a competitive advantage. But if companies such as PetroCom and LandOcean have anything going for them, it could be timing. In a lowprice environment, with companies still spending significant cash on data services, neither Ramnarine, if he is returned to office after the election, nor his successor will want to discount the growing body of evidence showing that expert data management is a potential boon to the economy. Gwengwen Sun, who is based in Beijing, remains optimistic — as well he should, given that the government’s diversification strategy identifies ICT as one of the sectors for development. And LandOcean will be encouraged by early signs that investors are getting the message about T&T’s suitability for ICT projects. In February, Caribbean IXP (Trinidad) Limited, backed by a U.S. investor, announced construction of a US$40 million Tier III carrier-neutral data centre at Tamana InTech Park in East Trinidad, the first of its kind in the country. That decision, according to InvesTT’s manager of investor sourcing, Sekou Alleyne, “reinforced key advantages this country has over other sites, including low energy costs, a stable political environment, quality telecommunications infrastructure which includes

at least five Miami-linked fibre optic cables and, importantly, T&T’s geographic location outside the hurricane belt.” While Caribbean IXP’s facility will operate as a kind of data centre hotel serving clients in various industries, Sun said LandOcean’s data centre will be purpose-built to meet the unique needs of oil and gas companies. If the project gels, he says, T&T could beef up exports of energy services to the region and attract higher levels of foreign investment. On the face of it, this is a compelling value proposition. Still, the most important plus for LandOcean’s proposal is that it comes on the heels of renewed economic cooperation between China and T&T following the historic visit of President Xi Jinping in 2013. That visit culminated with the opening of the Trinidad and Tobago embassy in Beijing and suggests that financing for the data centre is well within reach even if — and Sun is adamant about this — the initiative has to come from the T&T government. China’s handshake with CARICOM leaders in 2013 was a US$3 billion handshake. Last month, the Wall Street Journal reported that Chinese loans to Venezuela alone have amounted to nearly US$37 billion since 2008, so nobody should doubt China’s willingness to put its money where its own energy needs can be met. A Tier III data centre of this kind could align with China’s strategic interests in the region.. Learn more and have your say online: fb.com/ttenergychamber · #energynow

| energy.tt

@ttenergychamber | July 2015

News

Renewable energy plans ready, but little progress so far T&T will manage modest contribution to regional targets David Renwick | Energy Journalist

espite its commitment under the Caribbean Energy Policy (CEP) to generate 20 percent of electricity from renewable energy sources (RE) by 2017, a goal agreed to by CARICOM ministers of energy in March 2013, Trinidad and Tobago itself has a much more modest goal of only 5 percent by 2020. This would amount to only 60 megawatts of electricity, according to government insiders. This suggests Trinidad and Tobago will play an extremely modest role in the CARICOM targets of 28 percent by 2022 and 47 percent by 2027, as envisaged by CARICOM’s Energy Programme Unit at its headquarters in Georgetown, Guyana. Why such modest goals for a country ranked second in the world in carbon dioxide (CO2) emissions per capita? It seems that the authorities in Trinidad and Tobago should be doing their utmost to help stem global warming, which is predicted to have destructive consequences for island nations like those in the Caribbean. It was noticed that in his compre-

hensive address to the Energy Chamber luncheon in mid-May, Energy and Energy Affairs Minister Kevin Ramnarine never once mentioned what progress his ministry is making toward introducing RE into the Trinidad and Tobago power mix. He did refer to CO2 tangentially, but only in relation to a research project by the University of Trinidad and Tobago (UTT) studying the capture of such emissions. It could be that the minister is leaving it up to the independent power producers (IPPs) — the Power Generation Co. of Trinidad and Tobago (Powergen), Trinidad Generation Unlimited (TGU) and Trinity Power — to make their own arrangements for adding RE to the power generation currently fueled by natural gas. If so, the betting among analysts is that it will take a very long time. This is because the IPPs seem to be waiting on the power transmitter and distributor, the Trinidad and Tobago Electricity Commission (T&TEC), to advise them whether it would like to see RE added to the generation mix, either for

current electricity supplies or for anticipated new demand for power. As it stands, the IPPs, of which Powergen is the most important, take their cue from T&TEC on how they should structure their generation capacity to meet its needs going forward. “T&TEC works out its requirements for electricity well ahead,” explains Fitzroy Harewood, Powergen’s general manager. “The IPPs then have to decide how they meet those requirements. We have to work with T&TEC, and they say when they need generation and we decide how best to meet that. We are guided by the Commission’s appetite for electricity.” Mr. Harewood does concede that “T&TEC has told us they would like to have RE in the generation mix, and we have taken that on board very seriously.” But Harewood and his fellow CEOs have to grapple with the cost factor — at the present favourable price of natural gas, any source of RE, be it wind or solar, would have a hard time competing with gas. While the cost of establishing a wind farm is coming down worldwide, the IPPs would need a respectable return on capital for any such initiative, which would then determine the price they could charge the transmitter. Despite this, Harewood is adopting an ambitious posture and says that “maybe a Powergen subsidiary company could get into this and we could set up a wind farm and consider IPP arrangements for that. We would see it as a supplement to the main gas-fired business.” To be fair, MEEA has not been entirely indolent in the matter of RE-generated power. As Randy Ramadhar Singh, RE adviser to the energy minister, has noted,

“We have been pushing off-grid projects, such as solar photovoltaic (PV) units, solar distillation systems in 50 schools around the country and 30 community centres are being equipped with PV lighting for exterior needs.” The Ministry of Public Utilities assistance programme for the installation of PV systems in low-income households without electricity is also under way, and the Housing Development Corp. (HDC) is also pushing solar street

lighting in its housing estates. Electricity from solid waste sources is also in the cards. Below: PowerGen's plant in Port-ofSpain has an installed capacity of 308 megawatts. Despite high CO2 emissions in T&T there has been little progress on renewable energy power generation. Learn more and have your say online: fb.com/ttenergychamber · #energynow

Photo by Chris Anderson

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@ttenergychamber | July 2015

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Tough calls must be made on unsustainable fuel subsidies Electricity generation from gas alone needs review Dax Driver Energy Chamber CEO | @dax_driver

New government must do all it can to stimulate flow of projects Reforms imperative to ensure sector’s sustainability

editorial Energy Chamber | @ttenergychamber Whatever the outcome of the September 7 general election, the government is going to have to make some tough decisions to ensure the sustainability of Trinidad and Tobago’s energy sector. With oil prices likely to stay low for the foreseeable future, structural changes to the energy sector are imperative. Such changes will set the stage to help us reach the capital investment levels required to maintain our existing industry. As Minister of Energy Kevin Ramnarine stated in his interview in the June 2015 edition of EnergyNow, “Very hard decisions have to be made in the next five years.” Over the past five years, a number of significant reforms have been made in the oil and gas industry, specifically with the introduction of various tax measures to incentivise exploration and production. These measures have encouraged new activity, and we have seen high levels of drilling being maintained even in amid current low oil prices. We need to be realistic, however, that much of the current drilling was planned at a time when oil and gas prices were still at historic highs prior to mid-2014. If we are to maintain momentum, we need to see new projects continue to be planned even in this low-price environment. This is going to need further reform. Changing the fiscal terms for companies operating under exploration and production licenses is not going to be enough. Decisions must also be made on how to incentivise investment into potential reserves held under production sharing

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contracts (PSCs), especially smaller, geologically complex or inaccessible gas fields. We must remember that there are gas fields discovered many years ago which nobody has found ways to economically exploit, such as the gas reservoir in block 22 off Tobago’s north coast, first drilled by Petro Canada back in 2008 with the Cassra-1 well. Incentivising development of new reserves under existing PSCs is going to require one-to-one negotiations with the companies holding the contracts. This will require significant inputs of time and expertise from the senior public servants in the Ministry of Energy, at a time when many observers believe that the ministry is understaffed and has lost some of its former technical strength. This is a challenge that any new government is going to have to address and address quickly. But it is not just the fiscal or contractual terms of the upstream operators that need to be reformed. Across the industry, there is near-consensus that the current structure of the gas value chain also needs to be reformed and that new marketing relationships are required if new gas reserves are to be developed. There is much less agreement, however, about the details of this restructured gas value chain. The new gas master plan, due to be completed by the end of July 2015, will certainly make some specific recommendations about how the gas value chain should be restructured. However, there must be significant dialogue between the government and a wide variety of stakeholders in the industry if we are to successfully move from consultants’ recommendations to an implementable energy policy. While the details of the new policy are far from certain, what is clear is that tough decisions must be made and that business as usual is not an option. Learn more and have your say online: fb.com/ttenergychamber · #energynow

ne of the more enjoyable aspects of my job is the chance to share experiences with friends and colleagues in Chambers of Commerce and trade associations in the countries we visit regularly on trade missions. Last month, I had the pleasure of spending some time with leaders of the Suriname Chamber and other business leaders in the country. I’ve been visiting Suriname regularly since the late 1990s, and the Energy Chamber has taken numerous trade missions there over the past decade, so we have some very good and longstanding relationships in the country. Suriname had a general election in May 2015, and the party of the incumbent President Dési Bouterse has been returned with an increased share of the vote that means he no longer needs to govern with the help of coalition partners. Most of the business leaders I spoke with saw this as a significant change for Suriname, where coalitions have been the norm for some time. While the Surinamese economy has performed very well in recent years, there is also a common view that some hard decisions needed to be made if this economic transformation is going to be sustained. One of the major issues at the top of people’s minds, especially for leaders in the energy sector, is electricity prices. Suriname and Trinidad and Tobago both have very low electricity prices, especially compared to the rest of the Caribbean. In the case of Trinidad and Tobago, the low electricity prices have been possible because of low-cost natural gas purchased from the upstream producers via the National Gas Company. Trinidad and Tobago is one of the few countries in the world where 100 percent of electricity generation is from natural gas. In the case of Suriname, cheap electricity has traditionally been supplied by the hydroelectric dam at Afobaka. This hydroelectric generation was originally installed primarily to supply the Suralco alumina refinery and aluminium smelter, with the excess supply coming at low costs to what was originally a small electric grid primarily in the capital city of Paramaribo. However, the growth in demand for electricity in the country, coupled with strong economic growth, means that the installation of additional generation capacity has been necessary.

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In the absence of other fuel sources, the additional capacity has come from fuel oil-fired thermal power generators, one of the more expensive ways to generate electricity. The average cost of generating electricity has therefore increased significantly, but the cost to the consumer has remained very low, with the state subsidising the difference. Much of the conversation amongst the business leaders in Suriname was that this situation is unsustainable and that the state cannot go on subsidising these costs. Prices to the consumer will therefore have to increase, one of the tough decisions that the newly installed government is going to have to consider very seriously. In Trinidad and Tobago, whoever takes over the reins of government in September 2015 will also have some tough decisions to make, one of which pertains to our subsidies, especially for transportation fuels. There is a nearconsensus amongst economists and other informed commentators that Trinidad and Tobago has to seriously begin a programme to eliminate our transport fuel subsidy, especially the subsidy on diesel. But this is a hard sell to the general public, and no political party is going to want to tackle this issue in the run-up to the general election. With a national budget due right on the heels of the election, it will be interesting to see if the government will be willing to make the necessary but unpopular decision on transport fuels. It will also be interesting to see if they begin to look at our electricity prices. With continued gas shortages hampering our LNG and petrochemical industries, there are serious questions about the current policy of allocating precious molecules of natural gas to cheap electricity generation. This issue has hardly been discussed in the country so far, but I wonder how much longer we can continue to turn a blind eye to such a major economic issue. In Trinidad and Tobago, there are serious issues regarding subsidies and cheap electricity or transport fuels that must be addressed in the immediate post-election period.

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Disclaimer: Except for the editorial on this page, all opinions are those of the authors or interviewees and do not necessarily reflect the views of the Energy Chamber.

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@ttenergychamber | July 2015

Opinion

More contracts required for deepwater resources bordering Venezuela Framework Treaty and unitisation agreement just the foundation Richard Beckles | Contributor In Trinidad and Tobago’s continued development of its oil and gas sector, it is clear that success in the deepwater acreage is of paramount importance, and we look forward to seeing the results of the exploration work being done in that area. There are, however, discovered reserves that straddle the maritime boundary between Trinidad and Tobago and Venezuela that also merit our attention, as unlocking these resources can have a great impact on our economy. Some of the work required to exploit these resources has already been done. The governments of Trinidad and Tobago and Venezuela have executed a Framework Treaty relating to the Unitisation of Hydrocarbon Reservoirs. The Framework Treaty provides that any hydrocarbon reserves that extend across the maritime boundary of the countries are to be developed as a unit and, as the title suggests, it establishes the general legal framework required to achieve this objective.

The Framework Treaty requires the governments to enter into a unitisation agreement for each cross-border discovery which will set out the volume of hydrocarbons in the discovery and allocate those volumes between the two countries. Of the known cross-border discoveries between the countries — Kapok-Dorado, Manakin-Coquina and Loran-Manatee — the governments have only executed a unitisation agreement for the Loran-Manatee Field. Approximately 27 percent of the estimated 7.5 trillion cubic feet of the reserves in the Loran-Manatee Field have been allocated to Trinidad and Tobago, with the remaining 73 percent being allocated to Venezuela. From a legal perspective, the following items are a few of the issues to consider as we seek to develop these resources. The Framework Treaty and the unitisation agreement are important, but they are only the first of many contracts required to develop the field. These

agreements are only between the governments; thus, from a Trinidad legal perspective, their effect is to unitise the interests of the respective governments regarding the hydrocarbons in the ground. Both agreements recognise the need for a unit operating agreement between Trinidad-based contractors that have an interest in the productionsharing contract and the licensees on the Venezuelan side. In fact, those companies have to enter into a unitisation and unit operating agreement, as the rights of the companies to the hydrocarbons that will be produced have not been unitised by either the Framework Treaty or the unitisation agreement. The negotiation of a unitisation and unit operating agreement should therefore be a primary focus of all parties that have an interest in the field. The Framework Treaty only establishes a framework for the development, as it sets out a number of areas in which more detailed agreement is still required. These include applicable health, safety and environmental regulations; the payment of taxes and royalties; security; cross-border pipelines; and decommissioning. One area of concern is that the Framework Treaty provides that any dispute between the par-

ties is to be ultimately resolved by direct negotiation between the governments. Given the significant areas which still require agreement, including the fact that each government has the right to seek a redetermination of the allocation of volumes, it is not sufficient to rely on negotiation between two sovereign nations, and provision should be made for international arbitration to settle any unresolved disputes. Two final points to consider: The development of these cross-border resources slips in and out of public attention. The Framework Treaty establishes a Ministerial Commission which is to meet at least twice per year and a Steering Committee which is to meet at least every two months. It would be useful for those involved in the industry to receive information as to whether these bodies are in fact meeting and, to the extent that it is not confidential, the progress that is being made or the lack thereof. The service companies in the industry should also be interested in the provisions of the Framework Treaty that require compliance with the local content policies of both governments. Again, this is another area which will require further detailed agreement between the governments but where, in a

development of this size, operators are required to maximise the use of local goods and services. We need to pay particular attention and contribute to the development of this area. I trust that we are all sharpening our Spanish-speaking skills, and I hope that we get to put them to good use. Learn more and have your say online: fb.com/ttenergychamber · #energynow

The Framework Treaty and the unitisation agreement are important, but they are only the first of many contracts required to develop the field.

| energy.tt

@ttenergychamber | July 2015

Opinion Market recalibrations painful but necessary to stem spending There is little fiscal wiggle room left Dr. Roger Hosein Contributor It is possible that the rapid economic growth in the Trinidad and Tobago economy from 1994 to 2008 may have perpetuated a type of irrational exuberance in the dormant economic period that followed. “Irrational exuberance” was a phrase first used by Alan Greenspan but made popular by Robert Shiller, one of the winners of the 2013 Nobel Memorial Prize in Economic Sciences. In a now-famous speech in 1996, Greenspan said, “But how do we know when irrational exuberance has unduly escalated asset values, which then be-

come subject to unexpected and prolonged contractions…?” Shiller famously utilised the concept of irrational exuberance later on to explain that housing prices in the U.S. were growing at a pace that would eventually trigger a precipitous crash. Shiller’s forecast was correct, and housing prices in the U.S. eventually came down. In T&T, what has happened is that the rapid buildup of economic rents associated with the expansion in gasbased output prompted a very sharp rise in economic activity. In this regard, one is tempted to ask whether T&T also experienced some form of irrational exuberance regarding its economy. As a starting point, let us consider the economic rents earned from the petroleum sector. These rents increased partly because of rapid growth in the petroleum sector, mainly from natural gas, in the past two decades.

Real & nominal GDP indices for TT (1991 = 100), 1991–2014

The rapid increase in natural gas output and the increase in the price of crude oil and natural gas for a large part of the data period helped usher in a golden period of economic growth, from 1994 to 2008. The growth has since sputtered, however, and since 2008 has averaged -0.196 percent per annum (2009 to 2014), compared to an average of 7.6 percent during the golden era of growth (1994 to 2008). But also during this period, there was an even sharper increase in the size of the services sector spurred by spending associated with energy rents. Indeed as the economy began to overheat wage demands outstripped productivity and asset prices soared. An impression of the economic bubble and its associated size may be obtained from the difference between nominal and real GDP. The economic bubble precipitated Real GDP (1991 = 100)

790 590 490 390 290 190

04 20 05 20 06 20 07 20 08 20 09 20 10 20 11 20 12 20 13 20 14 p

93 19

1991 = 100

690

by the rapid inflow of rents contributed in part to an irrational allocation of scarce resources. This irrational allocation is reflected in the relative size of the economy’s transfer and subsidy programmes, in addition to the overall increase in employment in community, social and personal (CSP) services at the expense of manufacturing and agriculture. Even more, a careful look at the data would indicate that in some sectors of the economy, particularly in the services sector, there has been a decline in output per worker. The continued buoyancy of real estate prices in T&T, even though some of the core fundamentals of the economy may have necessitated a greater degree of downward motion, may be suggesting some degree of irrational exuberance therein. Indeed, the economy has been experiencing clear-cut overall stagnation, the prices of the main export goods have softened and their associated output lev-

els in the past few years have declined. Even so, from 1994 to 2008 the construction sector prospered, but thereafter it showed a sharp level of deterioration between 2008 and 2012. Since that time, however, there has been some element of a recovery. Relatively low mortgage rates since 2008 have helped keep the demand for mortgages high, and this in turn has helped keep the median prices of real estate assets high. The economy will have to recalibrate during the next five years, as there is little fiscal wiggle room left. The public has to compel politicians to rein in their impulsive spending and irrational exuberance if fiscal sanity is to return to the private sector. Let’s not just sit back and watch these events unfold, but rather let’s lobby and help shape the events as they happen. Learn more and have your say online: fb.com/ttenergychamber · #energynow

energy.tt |

@ttenergychamber | July 2015

Opinion

Photo courtesy DPI Photography

Post-crisis communication key in business planning Why local firms must act well before a crisis arises Sheldon Daniel Contributor It is difficult to evaluate the state of readiness for a crisis among our local businesses and organisations. It is known that the multinationals operating in our local energy sector, spurred on by parent-company experiences and resources, tend to give this issue substantial attention. Amongst local energy companies, the big state-owned players are probably most advanced in their understanding and planning for crises. Petrotrin, for instance, may have started a bit slow in their handling of the oil spill at the beginning of 2014, but quickly learned the main elements of good crisis management as events unfortunately reappeared over the course of several months. However, for other local entities, there is very little hard data about their readiness for handling a crisis. Casual observation suggests that their readiness level might not be too high, even amongst organisations that you would expect to

be better-prepared. An example involving the University of the West Indies can be used to illustrate the point. UWI’s handling of issues around the death of a baby boy at the Mount Hope Maternity Hospital (MHMH) on Carnival Saturday in 2014 can at best be described as saying the “right thing” (i.e., factually accurate) by addressing the facts surrounding the incident, but the “wrong thing” in light of media coverage and public perception over the general level of competence at the specific hospital and the emotional content of the story. As a three-time graduate of the UWI, I am a huge supporter of the institution, but I believe the institution’s handling of that matter was not one of its finest moments. So how does an organisation say the “right thing” in a time of crisis? As with all good crisis management practices, it requires work done well ahead of any crisis. In this case, the work to be done is specific to understanding the “context for action” that will shape the public “representation” of any incident. That is to say, all organisations should

always have a current understanding of the key public issues pertaining to their products and services generally and their company specifically. In the case of UWI above, the media’s use of such sensitive and emotion-filled events to support a wider narrative of incompetence and poor service at public health institutions might have resulted in a slightly different first response from UWI (which, incidentally, was to affirm the competence of the health professional involved). In basic marketing terms, an organisation needs to “know their audience.” Contextual awareness needs to extend not only to the media, but to all key stakeholders who will be impacted in a time of crisis: employees, fence line communities, customers, competitors and regulators. Having a good grasp of the issues that each of these critical stakeholders thinks are important in relation to your organisation is imperative if you are the say “the right thing” (i.e., a response aligned to the concerns of the stakeholders) in the time of crisis. This “issue management” process should be a key risk management activity of any firm as part of its reputation manage-

ment — and should serve as a key foundational activity of a business’s crisis management preparation. There is another contextual frame that shapes the “how” of crisis management: the role of social media. Social media impacts the speed at which a crisis spreads in modern business. Twitter allows for user-generated perspectives to quickly frame the way an issue is understood. It can also amplify the scale of the “crisis,” since pictures and video about any incident can reach an unlimited audience. The reach of these social media platforms into the local population should not be underestimated. I have seen some private studies in which around 20 to 25 percent of local respondents state that they get their news mainly from social media sources. Such a level of penetration is only going to increase. So while social media will shape the impact of your next business crisis, the extent to which local businesses are ready and able to integrate these technologies in their crisis response process is less clear. Many businesses have a limited Internet presence, and what online presence they do have tends to be a static website with very little interactive functionality. Business accounts on Twitter and Instagram are very rare beyond those businesses in the entertainment sphere in which a youthful consumer base makes such platforms imperative. Local firms need to quickly improve their performance in this area — since these are no longer merely “nice to have” but “business

essential.” An established Web-based presence allows for a rapid deployment of the company’s perspective, undiluted by the media voices — you have a greater chance of “managing the message” and getting the company’s voice heard. Maybe these sound foreign to your business, but in most instances, a quick-and-dirty role-playing exercise of “if this happened, how would we respond?” will help sharpen crisis-time thinking and will help get consistent messages out quickly when a crisis does occur. Having an up-to-date social media presence can be a great first step in establishing a crisis communications framework for your business. Of course, the issues addressed here comprise only one aspect of an effective crisis communications capability. The need for proper crisis procedures, tabletop exercises and media and crisis training for senior staff are other key components. Crisis management should have a more prominent place on the agenda of our local firms, especially those that are directly involved in the energy sector, where high-risk activities occur as a matter of course. Being well-prepared enables a firm to respond humanely in times of crisis while at the same time minimising losses to the firm’s business value and reputation. Above: Flashback: Clean-up operations during the 2014 Petrotrin oil spill Learn more and have your say online: fb.com/ttenergychamber · #energynow

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@ttenergychamber | July 2015

Opinion

Being responsible is the heart of CSR It’s not about doing “responsible acts” Melanie Richards | Contributor In 2007, the Energy Chamber (then the South Trinidad Chamber of Industry and Commerce) published its seminal study Mapping Corporate Social Responsibility in Trinidad and Tobago: Private Sector and Sustainable Development. Almost a decade on, most companies still seem to be getting it wrong. From where I sit, it appears that the discourse on CSR in Trinidad and Tobago has developed quite askew, and, as organisations continue to grapple with what it is, and what it is not, the underlying intent seems to be lost somewhere between the marketing department and the communications department, never quite making it to the CEO’s office. Add to this the rapid expansion of literature and terminology evolving from and related to the field, from “corporate citizenship” to “conscious capitalism” to “sustainable development,” and we seem to have lost our way. My take on it is simple: Call it what you want, the intent must focus on being a “responsible organisation,” not merely doing a “responsible act,” and this is

where I think we started to go wrong. Step back for a moment and think of your organisation, its purpose, vision and mission: How can your organisation fulfil this purpose in a responsible way? The definition of “responsibility” varies from individual to individual and from organisation to organisation, but very broadly speaking, it’s about being accountable. So again, very broadly speaking, the focus needs to be on accountability to society for all the actions of the business in fulfilling its purpose. Now, contrast this with merely doing a “responsible act.” Any organisation, even an “irresponsible organisation,” can do a “responsible act,” and these acts are then highlighted and marketed as CSR without the organisation really being accountable to society for all of its actions. The focus of CSR in Trinidad and Tobago still appears to be on doing ad hoc “responsible acts” (CSR projects) while the rest of the organisation operates completely oblivious to the necessary social accountability for all the actions of the business.

It follows, therefore, that if we want to be responsible organisations that are accountable to society for all of our actions, then we need to look at responsibility in all areas of the business, including procurement practices, the meeting of statutory obligations, labour practices, supply chains, and the list goes on. We need to focus locally not just on the community and the environment, but also on

the workplace and the marketplace. We cannot, therefore, have organisations that continue to do “responsible acts” (CSR Projects) while simultaneously evading taxes, bribing customs officials, taking kickbacks, circumventing procurement practices, discharging effluent into waterways, infringing on human rights or not properly utilising and managing resources. Such things

just do not add up and are about as far as you can get from being sustainable. I think it’s time we start to look again at the CSR agenda and start to change the discourse, transforming ourselves from organisations that merely do “responsible acts” to organisations that are responsible. Learn more and have your say online: fb.com/ttenergychamber · #energynow

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@ttenergychamber | July 2015

Opinion

No real boost for T&T economy from Shell/BG merger unless … Success depends on one important factor Terry Follen | Contributor If all goes well with Shell’s takeover of BG, then in early 2016, BG’s flagship offices just off the Savannah on St. Clair Avenue will be flying Shell’s colours. But unless the deepwater exploration takes off, I don’t believe Shell’s acquisition will bring about any noticeable change to the economy or the lives of most people in Trinidad and Tobago — a situation not dissimilar to when BP acquired Amoco. BG’s offshore supply base in Chaguaramas could prove beneficial to any activity Shell may be considering in the Caribbean and in the deepwater resources off the northern coasts of South America. If Shell takes advantage of this infrastructure, it could mean more work for local service providers — as was the case recently when Shell ran its French Guiana drilling operations from Trinidad. Shell has a presence in French Guiana, Guyana, Colombia and Venezuela — although for the moment, we can forget Venezuela until it is able to extract itself from economic self-destruction and welcome back international investors other than the Chinese. Up to 2013, using Trinidad as its base, Shell drilled four wells in the deep waters offshore French Guiana in its Guyane Maritime Permit. Unfortunately, it seems, all the wells were dry. Nonetheless, with Shell having a permanent base in Chaguaramas, it will increase Trinidad and Tobago’s potential to become the operational hub of oil and gas deepwater services in the region and an opportunity for local businesses to expand Trinidad and Tobago’s oil and gas capabilities.

of capital and investment hurdle rates. The T&T government will still apply the same taxes and, apart from naming Shell as the new “contractor,” BG’s current PSCs are cast in stone. If the merger goes through, Shell would become the largest shareholder of Atlantic LNG, but this will not change Atlantic’s operational activities and business drivers one bit. Why? Because the governance of Atlantic’s four processing trains is conducted through shareholder agreements, which are not changing, nor will the ability of one party to influence decisions over another.

Investment decision-drivers are not different

Going forward a few years, Shell’s influence will be significant if the BHP-led deepwater exploration efforts prove fruitful. The main reason is that Shell has a corporate strategy which is not hamstrung like BG Group’s strategic focus on just “Exploration and LNG.” Shell’s strategic goals are broader, more holistic and have no real financial constraints, with the likely out-

Like the majority of large IOCs, BG and Shell make upstream investment decisions using very much the same criteria of proven and probable (1P and 2P) oil and gas reserve profiles while using similar commodity pricing assumptions, cost

Photo by Mark Gellineau

Ranking among other IOCs Shell is a mammoth company, and the acquisition of BG Group will add 0.7 million barrels per day (mbbl/d) to its current production of 3.7 mbbl/d, giving it a daily production total of 4.4 mbbl/d. This would leapfrog Shell from third place (tied with BP) over PetroChina into second place worldwide for IOCs, and close on the heels of ExxonMobil’s total of 4.7 mbbl/d. In terms of worldwide industry rankings, this would make Shell a more financially important and capable company than BP, but I don’t think there will be an immediate Shell-versus-BP battle for “top dog,” as BP is too well-established and entrenched in Trinidad and Tobago, and Shell is unlikely to want to draw swords. It will be interesting, however, to see how Shell handles Chevron, BG’s partner in ECMA, as they have had their differences in the past. Shell has more muscle and experience in deepwater

come that Shell will increase its participation in the development phases of a deepwater project costing billions of dollars. Many observers believe Trinidad and Tobago’s deepwater resources are just sitting there waiting to be found — and what a huge game-changer this would be for Trinidad. If Exxon’s recent significant oil discovery 200 kilometres offshore Guyana in 1,700 metres of water is anything to go by, then future deepwater potential has just became more probable and exciting. Shell is a world leader in deepwater drilling, and its experience in deepwater developments is equally impressive: Malaysia, Gumusut-Kakap floating platform; U.S. Gulf of Mexico, the Cardamom and Mars B developments; and Nigeria, the Bonga North West project. Shell’s strategy for innovation is refreshing Over the past 20 years or so, the IOCs, in their quest to hit declared performance targets and keep Wall Street and City of London analysts happy, have lost ground to the large service companies such as Schlumberger and Halliburton in terms of R&D and innovation. This is a shortsighted, flawed and dangerous business strategy. It is refreshing that, unlike BG Group, Shell is one of the largest investors in R&D spending — $1.2 billion in 2014. (BG Group boasts an R&D commitment of just $66 million.) For example, if it is gas rather than oil which may be discovered in the deepwater tracts, then Shell’s proprietary Floating LNG (FLNG) technology could mean Trinidad and Tobago may well see one of these monster processing plants positioned in the deep water 200 kilometres east of Galeota. What it all means Will Shell make a difference? Maybe, but not immediately. Operationally, though, Shell will bring its own management philosophy and style; this will likely make for some reasonably significant changes within the old BG offices and operations. In the short term, Shell will consolidate its position, enjoy the cash flows from an established and solid business footing and then, if the deepwater plays are successful, both Shell and Trinidad and Tobago should reap economic benefits from BG Group’s demise. Below: BG T&T corporate headquarters in Port-of-Spain. Learn more and have your say online: fb.com/ttenergychamber · #energynow

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@ttenergychamber | July 2015

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Exploration activity picks up in Guyana/Suriname basin Chamber impressed with slate of projects Staff Writer It appears that exploration activity is picking up in the Guyana/Suriname basin with major works being driven by state-owned oil company Staatsolie and Inpex (Teikoku). Suriname is relatively new to hydrocarbons and first struck oil in 1980s. Since then, the country has steadily been growing their reserves and attracting new project activity, mainly in the

upstream. The Suriname playing field is both onshore and offshore. Staatsolie is the sole onshore operator and owner of the national refinery, while companies active in the Suriname offshore are mainly international and include Apache, Tullow, Inpex (Teikoku), Murphy Oil, Kosmos and Petronas. These companies are engaged in the exploration phase at the moment, rather than

production and operation. Staatsolie has a number of projects set to be completed by 2030. While onshore, nearshore and deepwater projects are developing, Staatsolie continues to focus on the onshore and nearshore blocks as a strategy to maintain its reserves through 2020. In 2014, it Staatsolie announced plans to resume nearshore exploration

activity in Block 4 and indicated that nine exploratory wells would make up their drilling programme in this block. Well Services Petroleum of Trinidad and Tobago received a three-year contract to execute the work programme and will be managed by a Staatsolie subsidiary, Paradise Oil Company. Staatsolie has been conducting seismic surveys on land as well as in rivers

in its wetland areas. They are trying to attract experienced international oil companies (IOCs) to operate in these onshore blocks. Staatsolie also recently completed an international bid round for Blocks 58, 59 and 60 and signed a 30-year production sharing contract for the deepwater Block 58 with Apache, a Houston, Texas-based company through its Suriname subsidiary. Earlier in 2015, Apache also began drilling in Block 53, another deepwater well, in collaboration with CEPSA, which has a 25 percent stake in the block. CEPSA, a Spanish company, is working with Apache to carry out the exploration phase. Geological surveys and the drilling of two wells are slated for completion before April 2016. Canadian firm CGX signed an agreement with Inpex and Petronas to share exploration costs in Suriname, including the cost of rigs. This threeway arrangement will be the first drilling contract for the new Hakuryu rig, which was built in January by the Japan Drilling Company. Among other companies, Tullow Oil already holds three licenses in Suriname, with an acreage of more than 16,400 sq/km. Tullow plans to drill one exploratory well in Q2/Q3 2015 in Block 31, of which Inpex transferred 30 percent participating interest in the block to Tullow in 2013. Tullow has also submitted an environmental impact assessment to conduct a 3-D seismic survey in Block 54. With exploration picking up in Suriname, new discoveries will add to the country’s proven and probable reserves. And deepwater exploration in the basin is an exciting development for the Caribbean region triggering hopes of a large find. Left: Increased activity at Suriname's national oil company Staatsolie is driving E&P projects in the Guyana/ Suriname basin. Learn more and have your say online: fb.com/ttenergychamber · #energynow

Photo courtesy Staatsolie

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Regional

Caribbean LNG increasing dominance in regional energy markets Lower gas prices disrupt liquefaction projects David Renwick | Energy Journalist

he news could not have come at a better time for Caribbean LNG, the midscale plant to liquefy more of Trinidad and Tobago’s gas that will be sited at the Labidco industrial estate in La Brea, southwest Trinidad, which is that the abandonment of potentially competitive LNG plants will leave it in a dominant position in its chosen marketplace in the region. Lower gas prices, around US$2.72 per million British thermal units (mmbtu) in the United States in mid-July, have forced the cancellation of “the vast majority of the nearly 30 liquefaction projects currently proposed for the United States, the 18 in western Canada and the four in eastern Canada,” according to a new report by Moody’s Investors Service, the U.S. rating agency. Tumbling oil prices, which have also pulled down gas prices, make gas-related investments such as LNG less attractive. As Moody’s points out, “While some companies like ExxonMobil can afford to be patient and wait several years until markets are more favourable, most LNG sponsors have far less wherewithal.” It stresses, however, that “projects already under construction will continue” which only adds to the dilemma

of those companies that had planned to enter the LNG industry, since this is expected to lead to “excess liquefaction capacity over the rest of this decade,” which itself only puts further downward pressure on prices. Australia alone will be adding 25 percent more capacity to the world LNG industry by 2017, and Cheniere Energy’s LNG project in Sabine Pass, Louisiana, one of the few to survive the gas price plunge, will start exporting by the end of this year. Cheniere will also likely continue with its Corpus Christi, Texas, LNG investment. The latter is noteworthy, since it is the vehicle through which Cheniere may attempt to access the Caribbean market, primarily the northwestern Caribbean (Dominican Republic, Puerto Rico, Jamaica, Haiti), rather than the southeastern Caribbean, where Caribbean LNG will be seeking its customers. Caribbean LNG has virtually sewn up the French departments of Martinique and Guadeloupe as its first customers (see related story on our website) and will be actively seeking others. Energy and Energy Affairs Minister Kevin Ramnarine has said that Guyana is a potential market for Caribbean LNG.

“We have had a lot of requests coming out of Guyana for LNG,” he told EnergyNow. “This is because the gold price has fallen and the gold mining industry there has become very marginal. The profit margins have shrunk. The companies are looking for ways of reducing costs, of which one-third is energy. They can do this by converting to gas.” He said Guyana, where CARICOM’s Secretariat is located, “could be a market for small packages of LNG,” which is exactly what Caribbean LNG will be in a position to supply. Caribbean LNG, which is sponsored by Roland Fisher’s Gasfin Development SA, registered in Luxembourg and Martin Houston’s Parallax, is now in the “project development agreement” (PDA) stage and should be ready to proceed with a firm “project agreement” by year’s end. Mr. Fisher has long advocated the sale of more of Trinidad and Tobago’s LNG within its own neighbourhood, where larger-scale LNG producer Atlantic has been active down at Point Fortin, rather than relying almost exclusively on exports to other parts of the world. It is somewhat interesting that Fisher’s first customers are the two Frenchspeaking territories rather than any English-speaking CARICOM state, but the territories were first off the block to make the switch from oil to gas. Some facts about Caribbean LNG: • Initial capacity: 500,000 tonnes a year, from one train

Above: Roland Fisher of Gasfin Development SA which is registered in Luxembourg speaks at the 2014 Energy Conference. • Plans to add one or two additional trains as business expands • Cost (in 2012 dollars): US$400 million. • Gas supply is to come from a 5km spur off the cross island pipeline (CIP) between Galeota and Point Fortin.

• Two state companies, NGC and National Energy, are closely involved in the project and one may become a shareholder. Learn more and have your say online: fb.com/ttenergychamber · #energynow

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@ttenergychamber | July 2015

Regional

Venezuela’s massive gas deposits to replace diesel, save billions New projects to also cover domestic deficit in two years Piero Stewart | Energy Journalist

etróleo de Venezuela SA’s natural gas-for-diesel fuel shift could net the state oil company an estimated savings of $4.4 billion over the next five years. That’s how much the company expects to save during 2015-2019 by substituting natural gas to be sourced from Venezuelan projects offshore to generate electricity instead of using diesel, much of which is imported, PDVSA Gas President Anton Castillo revealed on June 19 during a hydrocarbon congress in Maracaibo, Venezuela. “We’re expecting initial Cardon IV block gas production of 150 million cubic feet per day on July 15,” said Castillo. Future use of natural gas sourced from gas projects offshore Venezuela will allow PDVSA, as the state oil company is known, to reduce its diesel consumption by NEARLY 187,000 barrels per day, Castillo said. “The problem is that any of these kinds of solutions in the oil sector are more medium-term solutions. When you have cash flow constraints it's hard to think about a five-year horizon,” said Jefferies' Head of Latin American Fixed Income Siobhan Morden in a phone call from New York City. Initial gas production in Venezuela from the country’s massive non-associated natural gas deposits offshore in the Rafael Urdaneta, Mariscal Sucre and Deltana Platform projects will be destined to cover demand in the country’s highly subsidised domestic market, while excess volumes could be destined for export and could help augment Venezuela’s supply of U.S. dollars. “Under the plans we are promoting, onshore and offshore in two years we could easily cover the national gas deficit and then convert Venezuela into a potential exporter,” said PDVSA official Douglas Sosa on June 21 during the hydrocar-

bon congress in Maracaibo. “This is our vision, but before we can export gas, we need to fulfill the national deficit.” Venezuela, with proven natural gas resources of 196.8 trillion cubic feet as of year end 2014, is home to the world’s eighth-largest gas reserves and world’s largest oil reserves, according to BP’s Statistical Review of Energy. About 90 percent of Venezuela’s gas reserves are associated with crude oil. Of this, the bulk is contained in gas caps above the country’s major oil fields. About 70 percent of the associated natural gas that is produced is used to maximise oil production through re-injections, gas lift, in-field power generation and crude upgrades. Offshore Venezuela, PDVSA estimates there are another 147 trillion cubic feet of natural gas that could be proved up. “In three Venezuelan regions — east, central and west — we have potential to add 147 Tcf of gas,” said the PDVSA’s Sosa during the hydrocarbon congress. “Summing this with the 197 Tcf of proved reserves, we’ll have more reserves than the United States if we can prove up or convert these prospective reserves offshore into proved reserves.” Initial Gas Production Spain’s Repsol SA and Italy’s Eni S.p.A. discovered the Cardon IV block on the western side of Venezuela in 2009. The Perla field is located offshore in the Cardon IV block, in shallow waters in the Gulf of Venezuela, 50 kilometres offshore, and will feed four producing platforms that use underwater connections to transport the gas onshore for processing. Repsol holds a 50 percent interest in Cardon IV S.A. joint venture. Eni holds the remaining

50 percent interest. PDVSA has the option to back-in. Combined exploration and development investments in Cardon IV, part of the Rafael Urdaneta project, could reach $6 billion, according to Repsol. Production from the block is expected to reach 450 million cubic feet per day by year end 2015, 800 million cubic feet per day by September 2017 and 1.2 billion cubic feet per day by September 2020, according to a July 8 PDVSA statement. Additionally, PDVSA expects the offshore Mariscal Sucre project, located on the eastern side of Venezuela, to come online in late 2015. The project is composed of three gas fields, Dragon, Patao and Mejillones, and one condensate field, Rio Caribe. Production from the Dragon field — wells Dragon 5, Dragon 8, Dragon 9 and Dragon 11— could be producing 300 million cubic feet per day by year end 2015, said Sosa. Development of Venezuela’s third offshore natural gas project Deltana Platform is not expected over the shortterm one- to two-year horizon. Early indications are that Venezuela plans to send future production from the project to the Gran Mariscal de Ayacucho Industrial Complex or to the Cigma gas processing plant in Guiria, Venezuela, according to the PDVSA executive. “How will we export our gas: directly, or will WE liquefy it for export? We have to study these options,” Sosa told the audience. “We plan and are in negotiations with possible partners for the possible construction and transportation of the gas from Deltana Platform to Cigma.” With regard to Deltana, after covering Venezuela’s national gas deficit, PDVSA will ponder the development and export of this natural gas. To this end, meetings with officials from Trinidad are expected to commence soon to evaluate the options, said Sosa. Learn more and have your say online: fb.com/ttenergychamber · #energynow

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@ttenergychamber | July 2015

Regional

Venezuelan state oil company lays out plan to bolster gas production, exports Excess gas could be destined for T&T, other markets Piero Stewart | Energy Journalist

tate oil company Petróleos de Venezuela SA plans to boost investments in the country’s natural gas sector over the next five years in order to almost double natural gas production. PDVSA, as the Caracas-based company is known, plans capital investments of $38.4 billion during 2015-2019 to increase natural gas production from 8.7 billion cubic feet per day in 2015 to 10.5 billion cubic feet per day by 2019, said PDVSA Offshore Executive Director Douglas Sosa in late June during the fifth Hydrocarbon Congress in Maracaibo. Under this investment plan, PDVSA expects to increase offshore gas production to 1.6 billion cubic feet per day by 2019 from nil in 2014, according to Sosa, which would represent 16 percent of the country’s total gas production. Increased natural gas production will help PDVSA meet increasing demand in the domestic market from the industrial and petrochemical sectors and reduce its dependence on costly refined product imports to generate electricity. Excess natural gas production could be destined for various export markets. “In two years, under the plans we are promoting onshore and offshore, we could easily cover the national gas deficit and then convert Venezuela into a potential exporter,” said Sosa. “This is

in Latin America and the Caribbean, is planning to develop its massive natural gas reserves offshore as it looks to increase the participation of natural gas in its energy matrix from 26 percent currently to 51 percent by 2031, said the country’s natural gas vice minister, José Gregorio Prieto, during his participation on May 21 in the Venezuelan Gas Processor Association (AVPG) conference in Caracas. Venezuela’s natural gas ministry is looking to develop prospects offshore for the eventual exportation of gas, a move to increase the country’s dollar receipts, said Prieto. Of Venezuela’s total proved natural gas reserves: 165.93 trillion cubic feet are onshore, while 31.7 trillion cubic feet are located offshore. The country has additional probable reserves of 30.5 trillion cubic feet and possible reserves of 29.6 trillion cubic feet, according to PDVSA. Venezuela expects to prove up an additional 147 trillion cubic feet of natural gas reserves offshore and 53 trillion cubic feet onshore. About 90 percent of Venezuela’s gas reserves are associated with crude oil. Of this, the bulk is contained in gas caps above the country’s major oil fields. About 70 percent of the associated natural gas that is produced is used to maxim-

al of 150 million cubic feet per day in July from the Cardon IV block, increasing to 450 million cubic feet per day by yearend 2015, PDVSA expects it will be able to export gas to Colombia in early 2016. “PDVSA plans to initially export 40 million cubic feet per day of natural gas to Colombia in January of 2016,” said PDVSA Gas President Anton Castillo in late June during the fifth Hydrocarbon Congress in Maracaibo, Venezuela. Despite the plans, upgrades and other completion work along a key pipeline route to allow PDVSA to ship Cardon IV block natural gas to Ule and then on to Maracaibo in Zulia state are still unfinished and could delay this export target, said Gas Energy Latin America Director Antero Alvarado in an interview from Caracas. “Besides exporting gas to Colombia via natural gas pipelines, excess Venezuelan natural gas could potentially be exported in the form of compressed natural gas or CNG, or in the form of liquefied natural gas or LNG,” said Cardon IV Planning and Commercialisation Manager Jorge Estebanez Lazaro during the AVPG conference. All of these options are considered technically feasible, the executive said. “The export of Venezuelan gas will not only allow the country to gain another dollar source, but will also allow the country to optimise its consumption of natural gas,” said Lazaro. A natural gas pipeline could allow Venezuela to export gas to Aruba and Curacao, while CNG could be used to export gas to Central America and the Caribbean, including Panama, the Dominican Republic, Jamaica, Cuba and Puerto Rico, he added. Regional dynamics are shifting, and the increase in U.S. shale gas production has significantly impacted regional market dynamics. Given a Henry Hub price of around $4/MMbtu for 2014-2015, increased production in the United States and future exports in 2018 will have an impact on gas markets in Latin America, according to IPD Latin America; thus, the United States will no longer be a viable market destination for gas supply from Latin America. Left: President Nicolás Maduro at the signing of technical cooperation agreements with Trinidad and Tobago on March 3 at the Diplomatic Centre, St. Ann's. Learn more and have your say online: fb.com/ttenergychamber · #energynow

our vision, but before we can export gas, we need to fulfill the national deficit. We are talking about exports to Trinidad and Tobago, Central America, South America and, if we consider the LNG projects that we are promoting, we could export this gas to further destinations.” Caracas Capital Markets Managing Partner Russ Dallen said in a phone call from Miami, “Given the repeated failure by PDVSA to boost crude oil or natural gas production over the last decade and a half, any kind of projection that they are going to do something that hasn’t been done inHOST: 15 years is always overly optimistic on their part.” Venezuela, the South American country with 196.8 trillion cubic feet of proved natural gas reserves, the largest

Barbados’ oil company focusing on boosting crude But plan is to diversify in the long term David Renwick | Energy Journalist The state-owned Barbados National Oil Co. (BNOC) is going all-out to try to boost its current very modest crude oil production, which is around 1,000 b/d. It is moving to reactivate its Fisherpond and Scotland fields, which contain a number of wells that Winton O’D Gibbs, BNOC’s general manager, says “have not been abandoned, but over the past several years have not been on production.” A new plunger lift technique is being employed for this purpose, which Mr. Gibbs says should succeed in adding to current crude output. All of Barbados’ oil comes from the Woodbourne area, which contains five fields – West Woodbourne, Central Woodbourne, Lower Greys, Hampton and Edgecumbe. In addition to field reactivation, BNOC will soon be going after other sources of crude since, for its size, Barbados remains relatively underexplored. What’s more, the state-owned company has even bigger ambitions, which include going outside of Barbados entirely in order to find oil. As Mr. Gibbs observes, “The company recognises the importance of increasing its reserves base (which now totals a mere 3,044,083 million barrels proven) and continues to seek opportunities aimed at expanding operations overseas.” BNOC was one of the bidders for a block in Petrotrin’s last acreage auction under the incremental production services programme, but was unsuccessful in securing a block. However, if BNOC does manage to obtain an overseas foothold (presumably somewhere in the Caribbean, with Trinidad and Tobago and Suriname being the obvious possibilities), it would have done better than its counterpart in Trinidad and Tobago, which has only fitfully flirted with the idea of bidding for blocks elsewhere in the region but which has not pursued it with any great vigour. Gibbs is anxious to make the point that he envisions BNOC’s future as an “integrated” energy company, moving

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ise oil production through re-injections, gas lift, for in-field power generation and crude upgrading. Despite this abundance of resources, Venezuela continues to suffer a natural gas deficit in its industrial western region. The arrival of Venezuela’s first natural gas production this summer from the Cardon IV block offshore Falcon state will allow PDVSA to reduce consumption of costly imported diesel that’s used to generate electricity. For many years, PDVSA has relied on natural gas imports from Colombia to help it cover demand in Zulia state. How- SPONSORS: PLATINUM ever, the company announced June 11, opportunities For on sponsorship 2015, that its contract to import gas from call (868) 6-ENERGY or Colombia would not be renewed when it email michelle@energy.tt expired on June 30, 2015. With the arriv-

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THEME: ENERGY AND DEVELOPMENT

HYATT REGENCY, PORT-OF-SPAIN

away from its current role as a crude oil and associated gas producer (about 2 million cubic feet a day). BNOC has ruled out any re-entry into the refining business for Barbados. (The United States’ Mobil operated a small refinery there until 1997.) But BNOC is already very active in the fuels-importing business, bringing in gasoline, diesel and fuel oil through its Barbados National Terminal Co. Ltd (BNTCL) subsidiary, which it then passes on to the country’s several retailers, most of them well-known foreign names that have operated in the region for decades. Now BNOC wants to branch out into renewable energy (RE) because, as Gibbs says, “We are aware of the negative impact fossil fuels (particularly fuel oil, which Petrotrin refines for it in Trinidad, with crude supplied by BNOC and supplemented by Petrotrin’s own fuel oil) can have on the country from an environmental perspective, and also in terms of foreign exchange usage.” BNOC, he says, “is continuing its discussions with reputable entities aimed at the development of solar and wind energy, generating projects to facilitate the transformation of the company into a fully integrated energy corporation.” BNOC has set up a renewable energy department, with an initial focus on the design and installation of photovoltaic systems on a commercial basis, and “discussions will continue with the relevant agencies and prospective clients for the execution of these projects.” Its new corporate building is fully serviced with renewable energy. Another RE initiative involves adding ethanol and biodiesel to the gasoline mix in Barbados. Experiments with 10 percent ethanol (E10) and 20 percent biodiesel in the gasoline and diesel mix, respectively, are continuing. Learn more and have your say online: fb.com/ttenergychamber · #energynow