With respect to oil where most of the incentives are focused, these have not resulted in any substantial or sustained increase in production.

Helena INNISS Executive director and energy consultant KRONUS GEOLOGICAL SERVICES

Creative solutions required

March 29, 2017

TOGY talks to Helena Inniss, executive director of Kronus Geological Services and former director of resource management for the Ministry of Energy and Energy Industries, about the variables associated with continuing gas shortages in Trinidad and Tobago. Kronus operates as a provider of geological consultancy services throughout the region.

The company has been present in Trinidad and Tobago since 2007. While its initial focus was geology services, Kronus has since expanded to provide new services like energy sector governance, acreage management, hydrogeology, groundwater management and natural resource management to name a few.

• On impediments to deepwater gas production: “In the absence of data I really don’t know whether or not gas found in deepwater can work. That was the issue for many of the companies which did not bid in the deepwater bid rounds. They thought that there was mainly gas to be found and that it wouldn’t work commercially in a deepwater environment far from established infrastructure.”

• Future potential versus immediate concerns: “Deepwater is part of the future of oil for us in the long term. We had hopes for a big discovery in the early wells, but there were no oil discoveries in the first drilling campaign. There are also prospects for oil discoveries in the deep shelfal area, held mainly by BPTT [BP Trinidad and Tobago], and possibly onshore Trinidad if we can persuade companies to drill pass the current economic basement. These solutions are however medium to long term and we have the immediate issues of declining oil production that needs to be addressed.”

Besides touching on these topics, TOGY spoke at length to Helena Inniss about the advantages of allowing smaller companies to develop smaller accumulations of hydrocarbons and meeting the domestic market obligations of the production-sharing contracts [PSCs] in the country. Most TOGY interviews are published exclusively on our business intelligence platform TOGYiN, but you can find the full interview with Helena Inniss below.

How would you characterise the current state of Trinidad and Tobago’s hydrocarbons industry?
I would characterise it as ailing. It needs a shot in the arm to restart it. We have incentivised over the years and while it seems to have worked with respect to attracting companies to explore the deep water areas, it has not had the hoped for effects in the rest of the industry. With respect to oil where most of the incentives are focused, these have not resulted in any substantial or sustained increase in production. Fiscal incentives are viewed as the panacea for all that ails us but we have to develop or utilise creative solutions for increasing oil and gas production in the short, medium and long term.

How will the domestic hydrocarbons industry evolve in the future?
Deepwater is part of the future of oil for us in the long term. We had hopes for a big discovery in the early wells, but there were no oil discoveries in the first drilling campaign. There are also prospects for oil discoveries in the deep shelfal area, held mainly by BPTT, and possibly onshore Trinidad if we can persuade companies to drill pass the current economic basement. These solutions are however medium to long term and we have the immediate issues of declining oil production that needs to be addressed.
We do have oil producing acreage held by Petrotrin on the west coast, Trinmar. This area is both underexplored and underexploited. There are two issues here. The facilities are old and crumbling and there is no cash available to undertake exploration, exploitation and a complete revamp of facilities. Therefore, while there could be positive results in the short term in Trinmar if the required work is executed, we are not seeing signs of it. In the short term, EOR should be able to provide an increase in production if projects are initiated soon.

What plans are Trinidad and Tobago entertaining with regards to its natural gas resources?
With respect to gas, there are deposits in the shallow waters off the east coast, south coast and north coast that could be developed sooner, rather than later but the discussion has [to focus on] how to commercialise. Some of these deposits are in acreage held by operating companies and others are in open acreage. How do we provide quick access to these deposits to ensure that the gas shortage is addressed is the burning question? Incentives are again touted as curing all ills, but how do you fashion incentives such that the country is not left holding an empty bag?
There was a gas discovery in the deep water but the discussion will focus on the commercialisation of deep water gas deposits. I am assuming, however, that the company which won the deepwater bid catered for all price environments in their bid submission. In the absence of data I really don’t know whether or not gas found in deepwater can work. That was the issue for many of the companies which did not bid in the deepwater bid rounds. They thought that there was mainly gas to be found and that it wouldn’t work commercially in a deepwater environment far from established infrastructure.

How does Trinidad and Tobago issue oil and gas acreage and what are the advantages and disadvantages of the current and alternative forms?
There are two ways by which the Government of the Republic may award acreage for exploration in Trinidad and Tobago. First, the law allows one-on-one negotiation with companies. This removes the element of competition and it can be a bit opaque because the transparency of the competitive bidding process is lost. However, if you need award acreage quickly, then one-on-one negotiation is faster; which gives it an advantage over the competitive bidding process.
Trinidad and Tobago’s competitive bidding process has a set schedule, you must prepare and publish a competitive bidding order, a legal notice which takes time to prepare. Once that is done, companies are then licensed a data package associated with the areas in which they have interest. [Operators] are allowed at least three months to do that work and to evaluate the commercial strength of the venture and its value to their company. On this basis companies will then decide whether or not to submit a bid. After bid submission there is an evaluation process, the results of the first evaluation are then evaluated by another committee where the results may or may not be ratified. Afterwards, recommendations are made to the Cabinet which may seek the advice of yet another committee. While transparent, this process takes a long time – at least a year from start to finish.

Are there any other disadvantages of the competitive bidding process that you would like to mention?

Another disadvantage of the competitive bidding process is that it may result in a concentration of acreage in the hands of one operator. In the deepwater areas, for example, BHP Billiton holds all of the deepwater acreage that is currently licensed which is not an ideal position for us. There is always competition for capital within a company which can become critical because it’s one company exploring the area. In the current scenario BHPB has drilled two wells, and they have discontinued drilling to evaluate the results of the wells. Exploration drilling has ceased for a period of time. Whereas, if there were multiple companies operating in the deep water area, there would probably be drilling ongoing at this time. It is an unfortunate by product of a perfectly legal, transparent and often successful method of granting acreage.
A bidder may also submit a completely unrealistic bid in an effort to win. This normally results in non-completion of the bidded work programme or attempts at renegotiation of the licensing arrangement.

As it stands currently, what would be the ideal method of issuing acreage?

In the current environment there is a chronic gas shortage, which should be addressed quickly, if it’s not to cost us billions of dollars. I do not think the project involving the Dragon Field will materialise quickly because Venezuela has its own issues and is not known for being efficient. Petróleos de Venezuela has cash flow issues and the company is not reinvesting. Profits are being used by the state to sustain the nation’s day-to-day activities. Therefore to look to Venezuela for solution to our current difficulty may be problematic.
Given that this identified solution for addressing the gas shortage may provide no relief in the short term, I would suggest that competitive bidding is not the ideal route to take as it would result in at least a one year time delay before exploration starts and we need the gas as soon as possible. We need to identify a company or companies that we can persuade to enter into an agreement to explore for gas or to exploit identified deposits utilising one-on-one negotiations. We have to weigh the cost of proceeding quickly against the perceived transparency of the competitive bidding process in monetary terms.


What are some of the barriers to producing deepwater gas?
There are commercial barriers. This is the furthest east that T&T has had a discovery therefore there is no infrastructure in the area. A challenge would be the construction of pipelines to connect the new fields. For example, the Dolphin/Starfish and the Juniper Platform are the easternmost platforms located on the offshore east coast, and while ideally there could be possibilities for connectivity here, there may be a capacity issue. It is likely however that by the time any development in deep water comes online the capacity issues would be non-existent. I am not sure. Is Floating LNG a possibility? I will leave that to the experts.

Why is there a gas supply issue when there are identified undeveloped gas accumulations offshore Trinidad and Tobago?
There are several different issues: Companies having very high productivity wells, therefore shut down for maintenance will always create issues especially if no other producing company can take up the slack. While these can be planned to coincide with turnarounds in the downstream plants, it is not always possible as unplanned shutdowns may occur.
One company holds the majority of the licenses or acreage in the shallow water east coast where a number of the smaller currently identified accumulations exist. The same argument holds here regarding the concentration of acreage in the hands of one company. The company’s priority and the competition within the company for the use of scarce capital. This often means that the company would require some incentive to utilise its capital in Trinidad. The question we may ask ourselves is whether there are different solutions to this issue.
My view is that it also relates to the strictures placed on gas in the PSC. There is a domestic gas obligation in the contract and while the downstream industries are not strictly domestic in the true sense of the word, they rely on gas supplied locally. The issue is complex because the NGC [National Gas Company of Trinidad and Tobago] acts as the aggregator and negotiates a gas price with the downstream companies. The price given to the upstream operator is therefore an artificial construct. It has become very expensive to develop the gas as accumulations are in deeper waters, the gas is drier and the price received in the domestic market because of the price of product in the end market may not cover the suppliers’ expected return. In that scenario, companies would want to sell to the highest bidder.

What are operators’ reservations with regards to these types of policies?
Companies with PSCs are saying that the domestic market obligation is not a commitment to which they wish to be held and that they would prefer to supply gas for the export market. A case in point is that Centrica, a company which operated in the North Coast Marine Area of T&T, discovered gas in commercial quantities, but was unable to settle on a market for its gas and pointed fingers at the domestic gas obligation as an impediment. These companies prefer to earn a return on investment that satisfies the shareholders.
Centrica examined multiple options including CNG, modular LNG and supplying to the existing LNG plant, however, the company was unable to commercialise its north coast discoveries. The company highlighted the fact that the obligation to the domestic market is an impediment, but, then again, you must have a supply to the domestic market. Shell has purchased the Centrica holdings on the north coast. I don’t know how they will develop it, but they have the capacity in the pipeline coming from the Hibiscus Field which supplies directly to Atlantic LNG.

What is your opinion on the effectiveness of the domestic market obligation? What variables would make the obligation easier to meet?

The domestic market obligation is in all of the PSCs and we need to look at how we could make that work for the country. My question is why sign a contract with this obligation if you have no intention of honouring it? Participants need to find a way to work it out that would satisfy all parties.
In contrast to this, DeNovo Energy is currently developing gas accumulations on the west coast of Trinidad to supply to the domestic market. This is in shallow water where it is cheaper to drill and closer to infrastructure servicing the market, [making it] easier for them to supply the domestic market. The company is small and nimble, no large overheads and therefore can turn around approvals quickly. Their operations will therefore be less costly.
We need to examine DeNovo’s model and seek ways to upscale it. We also need to find creative ways to have companies wishing to supply the export market underwrite the effort of supplying to the domestic market from the smaller, shallow water gas accumulations.

Can the domestic market obligation be reformed to make it more attractive such that gas producers put more gas into the domestic market?
No, the domestic market for the downstream industry consists of methanol, urea and ammonia, iron and steel etc. However, the product is sold in an end market in North America or elsewhere; the product is not being sold in a controlled environment. Therefore if the feedstock is more expensive the producer could be driven out by competition in the end market. LNG attracts the highest profit margins with most companies operating with some degree of vertical integration, which is why most of them prefer to supply to LNG rather than to the domestic market.

Could you lower costs to make it cheaper to supply the domestic market?
There is a standard way to develop any accumulation. The deeper the water, the more expensive it is. Most of the larger accumulations are no longer in shallow water, which makes developing them more expensive. Drilling costs are also higher. Production platforms for example could cost USD hundreds of million, which is monumentally expensive. The cost efficiencies may be derived from the type of operating companies and the agility they bring to bear in making decisions. Moreover, you are looking for fewer overheads. If you take a company such as EOG Resources, BPTT is in a joint venture with the company to develop the Sercan Field. EOG is an efficient low cost driller and producer and they developed the accumulation because it is below BPTT’s optimum size for development. I think that is the lesson we need to take away.

What are some of the advantages to having smaller players exploit smaller accumulations?
Fiscal regime adjustments may be unnecessary. The cost of production is less because of lower overheads and other efficiencies.
The larger companies don’t consider gas deposits below 1ccm commercial, but that same amount could be commercial to another company with a more pared down structure and a culture of operating efficiency without the benefit of a fiscal regime adjustment.
Less competition for capital. Smaller companies will not have as many projects on the books therefore expectations can be better managed. The internal approval process would take less time. With operating efficiencies gas can be brought to the market quickly

What is the effect on the country of players having huge producing wells?
Some companies have huge wells. For example, one well produces 250 mcf [7.08 mcm] per day. One platform might produce 1 bcf per day [28.3 mcm], and the facilities are constructed such that, when maintenance is undertaken on a hub, multiple platforms are affected. That was the start of the gas horror which created an instant shortage. In 2010 and 2011, EOG and BG were able to take up the slack but by 2012 no company could.
As it stands now, neither of the larger supply companies are producing to their contract quantities. Industry managers did not look far enough down the road when we were setting up the industry and we should have known that, at some point in time, companies would need to undertake maintenance of their facilities.
The issue is the management of gas supplies. Scheduled maintenance and turnarounds could be managed for a short time but even then if a 1 bcf [28.3 mcm] per day platform is taken off production for maintenance, there is not one company that can take up the slack. As I mentioned previously the case for storage has not been made. So, the question remains, how do we mitigate the supply peaks and troughs? We need to have a short and long term solution for this problem.

What do you see as the solution? Is it more co-ordination or maintenance without shutting down the platform?

For gas, especially if undertaking hot work, shut down of the platform is necessary. Co-ordination of shutdowns with turnarounds has always been a part of the industry shutdowns on the platforms and the plants but, with the amount of gas, it is difficult. BPTT accounts for the majority of production such that, when they go down, nobody else can make up the capacity at this point.
BP has said that they are no longer willing to be the swing producer. It used to be the case that when production was taken off line, the company could bridge the gap. BG and EOG were also able to do so in the past, but these companies do not have the quantum of resources required to bridge the current gap. We have also not taken into account failure. It is never wise to assume that in the difficult geological environment that is Trinidad, all developments would be successful.
The questions remain: do we need to provide incentives to companies to maintain some sort of gas storage? If natural gas storage is too expensive, how do you give companies the incentive to keep gas behind-pipe for emergencies? Does NGC take the risk of contracting for more gas than they need with the implied take or pay risk? Or do the downstream companies weigh the cost of not being able to access gas freely and opt to underwrite some of this risk?
All these options need to be considered by all of the affected players in the industry with the aim to choose the best option that works for all. Are the issues being examined in a piecemeal fashion instead of looking at the entire matrix from upstream all the way to the downstream. The supply of gas is not consistent throughout the year, however, this is something that people want to achieve.

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