A more attractive oil and gas market

What changes were made to the Supplemental Petroleum Tax (SPT) in recent years to improve the business environment for oil and gas companies in Trinidad and Tobago?
There were two SPT rates for offshore: 42% and 33%. During my tenure, that was simplified to one rate for offshore, 33%, and we also gave a special SPT rate of 25% for new field development. We also gave a number of tax credits that could be used to discount the SPT. These included incentives for mature offshore fields because there are a lot of mature marine oilfields, such as the Trinmar fields and TSP [Teak, Samaan and Poui].
In 2014, we introduced accelerated capital allowance for exploration and developmental drilling. When companies invest in either exploration or developmental drilling, they get to claim their capital against their taxable income against whatever revenue, so they pay less taxes. This incentive has been massively misunderstood by the present government.
Capital allowances have always been part of the oil and gas landscape. They didn’t suddenly drop from the sky in 2014. The capital allowance structure in Trinidad used to be spread out over many years. We allowed for the capital allowance for exploration to be accelerated. This incentive for exploration expired on December 31, 2017. It’s what led to BP drilling two exploration wells in 2017.
The accelerated allowances simply allowed the companies to claim their capital expenditure faster, and because of the time-value of money, they had better economic returns. That improved the net present value of the investment and it made the economics more attractive. We had a problem and doing nothing wasn’t an option.

How did IOCs respond to these changes?
This got the largest gas producer, BP to start investing heavily. One of the things that really got BP excited about Trinidad again was the OBC [ocean bottom cable] seismic survey done between 2011 and 2013. It was the first time that BP was doing an OBC seismic survey anywhere in the world. BP’s view of the subsurface was greatly enhanced through this type of seismic, allowing it to see Savannah, Macadamia and Angelin a lot more clearly. There would no Angelin production in 2019 had it not been for that OBC seismic in 2011-2013. The OBC seismic allowed BP to see below shallow gas deposits and better image the subsurface. That changed BP’s perception of Trinidad’s Columbus Basin.
The accelerated capital allowance allowed BP to recover its capital investment faster – it gave the company a better net present value for its investments and a better economic story to tell its board in London. Because of that, we got Juniper, approved by BP in August 2014. Construction of the platform started in November 2014. We had some industrial relations issues that cost us to lose half of the Juniper platform to the US, but we had to do that to keep the project on schedule. By January 2017, the platform topside was completed and by August 2017, Juniper started to produce.
The actions taken in 2013 and 2014 must be credited for saving the Trinidad and Tobago economy in 2018.

How has Trinidad and Tobago’s gas production been evolving and what is the outlook?
Gas production is going back up. We’ve had some smaller gas projects, such as TROC [Trinidad Regional Onshore Compression] and Sercan, but those two just keep us flat because the country has a constant decline taking place. They provide stability, but Juniper is a big volume of gas, 590 mcf [16.7 mcm]. That gave the country a large positive increment, and hence, growth in net gas volumes.
In 2015, gas production averaged 3.8 bcf [108 mcm] per day. By 2016 and 2017, that had fallen to 3.3 bcf [93.5 mcm] per day. In 2018, we expect it to be 3.7 bcf [105 mcm] per day. That’s the Juniper effect. That would not have happened had it not been for the OBC seismic and the accelerated capital allowances.
We’ve had gas shortages now for almost the past eight years. The improvement of the gas supply in 2018 and 2019 is going to help, but it’s not going to eliminate the gas shortage. There will still be some element of a gas shortage, but it’s not going to be as painful as it was during the past two years. We are not out of the woods.

How do you expect Shell’s gas projects to develop?
In 2017, Shell, which took over BG, averaged about 500 mcf [14.2 mcm] of gas per day. There has been a significant decline, from about 1 bcf [28.2 mcm] to 500 mcf [14.2 mcm]. That’s a big drop, and part of that story has to do with the Starfish project failing in 2015. BG just wasn’t successful; there were problems with the drilling programme on Starfish and with well completions.
Shell has been carving out a very significant upstream and midstream portfolio in Trinidad since it entered the market in 2013, but to feed that midstream portfolio, it has to have gas, and 500 mcf [14.2 mcm] of gas per day doesn’t cut it. The company has been investing heavily in Dolphin infill drilling, which is happening now, and it has gone back into Starfish. We should therefore see Shell’s production begin to inch back up to about 750 mcf [21.2 mcm] of gas per day.

How have oil and gas authorities in Trinidad and Tobago adjusted regulations to make deepwater areas more attractive?
Before BHP’s big splash in deepwater, it was very difficult. We had failed bid rounds. We found it difficult to get companies into deepwater, so we completed a reassessment as to why we were unattractive, and we changed a lot of things.
One of the key things we did was get rid of the taxable PSC and go back to the old PSC, where the minister pays the taxes of the operator out of his share of profit petroleum, which is how it looks in most countries in the world, including Guyana. That taxable PSC was a disaster.
We also got rid of the requirement that companies had to carry Petrotrin up to 20%, and we increased the cost recovery rate from 60% to 80%, which was consistent with a lot of jurisdictions in the world.
We also simplified the bidding process, so we only had two biddable items: government take, or how much you’re prepared to give the government; and a work programme, under which the more wells you drill and the more seismic you do, the more points you get. The result of that, coupled with the work of a great team at the Ministry of Energy, was success in attracting investment and signing nine deepwater production-sharing contracts.

How are BHP Billiton’s deepwater operations progressing?
BHP has gone very big in deepwater in Trinidad. The company has a lot of confidence in deepwater hydrocarbons potential here. BHP drilled two wells in 2017. We are told that the LeClerc well discovered 3 tcf-5 tcf [85 bcm-142 bcm] of gas. The second well, Burrokeet, which was drilled off the east coast of Tobago, was plugged and abandoned. The company has done 20,199 square kilometres of 3D seismic over its deepwater acreage.
BHP is back in 2018, using the same drillship, Transocean’s Deepwater Invictus, and it plans to drill three exploration wells this year. It’s an exciting time and I expect more discoveries beyond LeClerc.

How do you expect the deepwater sector to develop in the future?
I remain confident that there is going to be a deepwater oil or gas discovery. The problem with our geology is that we tend to have a lot of faulting in Trinidad and Tobago and, as a result of all this faulting, we have smaller compartments of oil, so that’s a challenge.
Shell is also part of deepwater because it is a minority shareholder in four blocks inherited from BG. BP is a minority shareholder in two blocks. Therefore, this is a big thing to look forward to in 2018.

Has Trinidad and Tobago’s Gas Master Plan helped bring smaller players into the market?
The Gas Master Plan was submitted to me in August 2015. It identified a significant amount of gas in small pools. There is a case for smaller companies to go after small pools of gas, and DeNovo is proving that case right now with Iguana.
However, one has to appreciate that the commercial and economic realities of small companies may require a unique approach in the fiscal system. They may need more help to make these things happen. Once again, what we have is a lot of talk from the current government and no action around the fiscal regime, which has now been totally static for the past three years.

How will these smaller players contribute to the domestic downstream and petrochemicals sectors?
Once DeNovo comes into production, which should be in August or September 2018, I expect MHTL [Methanol Holdings] will restart its M1 and M2 plants. It was unfortunate that they had to shut down in the first place; I didn’t think there was a need for that. It was avoidable.
Methanol prices are good these days. They are forecasted to be in the high USD 300s per tonne for 2018. Ammonia prices could be challenging, as there is a glut of ammonia in the United States, as a result of the shale revolution. You have mothballed ammonia plants being started in the US, so ammonia prices have been in the USD 200s per tonne for 2017. It’s a tough time for the ammonia plants in Trinidad and it’s not going to get better when contracts come up for renegotiation in 2018/2019.
It’s clear that the price of natural gas sold to Point Lisas companies in T&T is going to significantly increase. This is why politicians should stay far from natural gas price negotiations.

How can Trinidad and Tobago become more competitive?
The number one threat to the energy sector of Trinidad today is declining competitiveness. A case in point would be what happened with the Angelin platform in 2017. BP took the decision to build the Angelin platform in Altamira, Mexico because the company felt it could build it there faster and probably cheaper.
Tofco [Trinidad Offshore Fabricators] is our local fabrication company. It is a very good company and it has built nine platforms, the most recent of which was Juniper. The lack of competitiveness has nothing to do with Tofco and everything to do with the environment in La Brea, where Tofco operates. Tofco has always had industrial relations, disputes and work stoppages, and that does not help competitiveness. We have also had work stoppages on the Mitsubishi plant across the road from Tofco.
The other thing is that National Energy has to revisit the rates that it charges companies to use the port at Brighton and the La Brea Industrial Estate company, Labidco. Perhaps it should be looking at comparing the rates for using the port with renting land to what happens in Mexico and the US, because we want to be competitive with those jurisdictions, in terms of platform fabrication.
Competitiveness means we are competing with the Mexicans and with fabrication yards in Texas and Louisiana, which have massive economies of scale and infrastructural support, roads and ports. We have to look at the whole issue of competitiveness again.
Petrotrin also has to look at its competitive position. It has to reduce costs. Petrotrin’s lifting cost is USD 44 per barrel, which is among the highest in the world. That has to come down. I don’t see a plan to bring that down. What we are seeing at Petrotrin is a reverse: Costs are going up. The whole ideology and philosophy around supporting business has to change in T&T, or else we will be left behind.

What opportunities will become available to Trinidad and Tobago with the development of the oil and gas industry in nearby countries?
There will probably be a large oil industry in Suriname and Guyana for the next 30-40 years, so we would like to support that from Trinidad in terms of fabrication, services and logistics. Guyana and Suriname have deepwater oil, so they will use FPSOs to produce that oil. Those vessels are built in Singapore and South Korea, but there are other things that they might need – pipeline manifolds, for example. We can do all that from the Tofco yard.
Guyana is a huge opportunity for Trinidad. The recoverable reserves that have been discovered to date are somewhere in the region of 3 billion-4 billion barrels of oil, and we expect that figure to rise, because Exxon is still working on the reserves for the Ranger-1 well. That well discovered carbonate reservoir systems. All the other wells are discovering sandstone reservoirs. The carbonate reservoirs tend to be prolific producers. There’s more exploration set to happen for Exxon, as well as for CGX, Tullow, Anadarko, Repsol and Ratio.

How is Guyana’s nascent hydrocarbons industry likely to evolve?
The Guyanese would like to be like Norway. We have had three examples I could cite with similar starting circumstances – Nigeria, Equatorial Guinea and Angola – where there has been a lot of oil produced and you don’t see the impact of that oil on the average citizen. I think Guyana wants to avoid that. Spending money on health, education and infrastructure is one way to avoid that. I think the government knows this. They have a fantastic example of what not to do right next door in Venezuela.

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