Any gas after Dragon? What's on the blocks for Trinidad and Tobago's energy economy

JAVED RAZACK

Why should we care if there is any gas after Dragon? Petroleum, particularly gas, is the backbone of our economy. The US-dollar limit on your credit card is tied intrinsically to gas production.

Finding oil or gas fields and getting them online is a lengthy process. Generally, the government has a bid round, putting out blocks for auction.

These rounds may take two years from opening to signing a block to an operator (like a bp or Shell).

Then exploration occurs which means acquiring seismic data followed by drilling wells. This is usually about six years.

A chance of exploration success of 25 per cent is considered very good and in deepwater it may be as low as ten per cent.

Any discoveries may be appraised by further drilling and then commercial evaluation takes place. This will be another few years.

If all goes well, the project reaches FID (final investment decision) and then the engineering to bring that field to life begins. A couple more years goes by.

It may be anything from ten-20 years from a bid round to first gas or oil. For example, the blocks for Woodside’s Calypso project were signed in 2012 and in 2025, FID has not been reached yet.

Many more aspects than we can list here will factor in and can change those timeframes.

Trinidad and Tobago’s gas decline

TT’s gas production averaged 2.5 bcf/day in 2024. This is 42 per cent less than the country’s peak gas production of 4.3 bcf/day, last seen in 2010.

The huge drop is due to a mixture of:

1. Natural decline of fields.

2. Not enough new gas fields were brought online due to:

• Exploration slowed because of a seven-year gap in blocks being awarded (2010 to 2015: 21 blocks, 2015 to 2022: 0 and 2023 to present: 13 blocks).

• Exploration also slowed due to a lack of fiscal incentives.

For example, from 2014 to 2017 there was a capital allowance for 100 per cent of exploration costs to be written off in that year vs over five years.

After 2017, this was not continued nor was any new incentive given to encourage exploration.

• Exploration failures such as Shell’s Aphrodite and Ice wells in 2022 which would have hoped to find new gas fields that could be brought online quickly.

3. Underperforming fields. For example, Shell’s Starfish and Dolphin fields as well as Woodside’s Ruby did not produce gas at the rates expected or for the durations expected.

4. The fact that most of the large gas fields in our shallow water have already been found. While there is certainly exploration potential, we are a pretty mature gas province. Most of the big easy gas has simply been exploited.

There are, however, a few cross-border and near-border Venezuelan gas fields that could greatly alleviate our gas pains, without any major technical challenges – namely, Dragon, Manakin-Cocuina and Loran.

There are also a host of domestic gas projects in the pipeline, but these will generally make up for the natural decline of current fields, keeping the daily average around 2.5 bcf/day, or raising it a bit when Manatee comes online.

Therefore, the gas industry, petrochemical and LNG production, and by extension, the US-dollar inflows to the country, has two main challenges:

• Balancing natural field decline by having a stream of new projects coming online in a timely manner. We are not doing so bad in this area but there is room for improvement.

• Increasing overall gas production. This requires fields that can produce large amounts but also for long periods. We are not doing very well here. This is what the Venezuelan gas projects were trying to address.

Is Venezuelan gas truly dead?

Now that the OFAC licences have been revoked, Dragon has gone back to slumber. Can it be revived again? Time will tell.

As geopolitical winds continue to evolve anything is possible. A new US administration in four years may present another chance if no progress is made under the Trump government.

It is indeed unfortunate as the 3.5 tcf Dragon gas field sits less than 20 km from Shell’s Hibiscus platform. Survey work began in October 2024 and continues as of April 2025 but will end soon as the licence winds down. Manakin-Cocuina, bp’s cross border one tcf field is also now dormant. Both these fields were planned for first gas between 2027 and 2029.

The big prize was really that Dragon would have led to unlocking the massive Loran field (73 per cent of almost 10 tcf), the Venezuelan portion of Manatee. The fields themselves are not going anywhere and will likely continue to make economic and technical sense, should politics shift in our favour.

Approved gas projects

Manatee – Shell’s Manatee is the biggest gas project currently being developed – as mentioned above, this is the Trinidad side of Loran-Manatee and holds about 2.7 tcf. First gas is expected late in 2027, attaining a peak of 600 mmscf/day (0.6 bcf/day).

Cypre – Pronounced "sip", bp’s latest project achieved first gas a few months early in March 2025, and will peak at 250 mmscf/day.

Ginger – bp also announced in March 2025 that its Ginger project is a go, and will have first gas in 2027, with peak production of 350 mmscf/day.

Coconut is be a 50/50 joint venture between bp and EOG, with EOG as operator. First gas is expected in 2027. The field size is approximately 1 tcf. Production rates have not been disclosed publicly.

Mento – Another 50/50 partnership between EOG and bp, Mento is expected to produce first gas later in 2025 from another 1 tcf gas field. Production rates have not been disclosed publicly.

Shallow water projects – in exploration or awaiting FID

Frangipani: In March 2025, bp said its 2024 Frangipani exploration well was successful and they will proceed to get this discovery on production. The timeline and gas production for Frangipani is yet to be announced.

Onyx is a gas field located between Poui and Teak that Perenco is currently assessing the commercial viability of. No further details are public. Hopefully this field does make it to FID.

Beryl – EOG and bp partnered on the Beryl exploration well in 2024. It is expected that this field will also be developed, but so far, nothing has been announced.

Blackjack is a planned gas exploration well from Shell for later in 2025.

Deepwater projects – awaiting FID

There is only one deepwater gas project awaiting a FID– Calypso. It is projected to produce up to 700 mmscf/d (0.7 bcf/day).

BHP signed nine deepwater blocks between 2012 and 2014 and exploration wells from 2016 to 2019 found several gas discoveries in blocks 23(a) and 14 (north east of Tobago) that have been collectively called the Calypso field. The gas in place is approximately 3.2 tcf (about the same size as Dragon). Woodside took over these assets when they bought BHP Petroleum.

Now the challenge here is both technical and economic. Deepwater gas developments are not common, and the plan would likely be to build a pipeline that goes to shore or to an existing platform in the shallow water. This is a multi-billion US-dollar investment. Even if technically feasible, the sticking point is around commercial terms (basically taxes). Earlier in 2025, Reuters reported that favourable tax terms had been met between Woodside and the Ministry of Energy and Energy Industries (MEEI), but rumours have been circulating that things are not looking so great for a Woodside FID.

To make things more challenging, Woodside just announced they are selling all their TT producing assets to Perenco. These produce both gas and oil from the Ruby and Angostura fields off Trinidad’s east coast. This makes a complete Woodside pullout seem imminent. The potential good news is that bp is a 30 per cent partner on Calypso and may consider taking over the project.

After FID, it is likely that it would take anywhere from five to10 years to achieve first gas, given it will be our first deepwater development and is far trickier than what we are accustomed to. A likely timeframe if all goes well would be seven years after FID, meaning a first gas best case scenario of 2032. Delays due to the blocks being relinquished or changing operatorship would delay this at least a year or two – time we really cannot afford to waste.

It is not at all acceptable that over six years after the discoveries were made, that we still do not know whether this project will materialise. The last appraisal drilling occurred in 2021.

If it isn’t yet, then this should be the focus of the MEEI and government at this time – finding a way to get this project approved in 2025.

Newly signed blocks with gas potential

The following blocks (see map above for locations) were all operated by other companies in the past with no commercial success. Clearly, the companies, namely bp, Shell and EOG have reason to believe they are worth exploring again. Perhaps new data, new technology, new information and new commercial reasoning are all parts of the logic here.

NCMA 2 was signed to bp at the end of 2024. Gas prospects for drilling were identified in this block several years ago. Seismic acquisition or reprocessing and drilling are hopefully on the fast track.

NCMA 4(a) – In January 2025, EOG signed this block, which was their first PSC signed in 20 years. Like NCMA 2, seismic reprocessing and drilling are likely being advanced.

Lower Reverse L Block (LRL) was also signed to EOG in January.

Block U(c) – signed in September 2024 to Shell. 3D Seismic has already been conducted and drilling prospects are being identified.

Deepwater blocks 25(a), 25(b) and 27 were awarded in September 2023 to a 50/50 consortium of BP and Shell, with BP operating 25(a) and 25(b) and Shell operating 27. Seismic was acquired over these blocks in 2024. Data should be processing and prospects being identified for drilling.

New bid rounds

The latest deepwater bid round was opened in January 2025 and has 26 blocks on offer (see map below). It will close in July 2025. Successful bids are expected to be announced 3 months after this.

Tax incentives

Despite several new blocks having been signed and currently under exploration, the majority of new gas projects have actually come from existing acreage operated by bp, EOG and Shell. Perenco has now taken over some gas fields from both bp and Woodside. There are fiscal incentives that can be used to accelerate projects in these areas. The downside of such incentives is that they may forego or delay some tax revenue, but the upside can be getting a steady supply of new projects.

Currently, none of the sanctioned projects have first gas dates past 2027. This is extremely worrying.

Even with several projects in the pipeline, these will only stave off further decline for a couple years.

With Dragon and the other Venezuelan gas projects no longer on the table, we need to refocus quickly. Recommendations are:

1. Get Calypso to FID as soon as possible and fast track development in under seven years – whether with existing operator Woodside or another one like BP. The government may have to concede more tax take to make this a reality. One deepwater FID may rejuvenate interest from the majors in our ultradeep waters.

2. Fast track other developments – MEEI can hand-hold operators through all regulatory approvals, employing the minister to push through unnecessary red tape where possible. This can save years but requires real ownership.

3. Rethink bid rounds – identify the most prospective blocks and directly approach and negotiate with operators. Do not limit to the big operators currently in TT. Find the small- and medium-sized ones (many in North, Central and South America) whose profiles match the block potential and approach directly. This can reduce award time to months instead of years and ensure a better fit of operators for the potential fields. Also helps diversify the operators so we are not so reliant on just a few big ones.

4. Introduce fiscal incentives that encourage quick drilling and help make small marginal fields economic. Need to balance this so we don’t reduce revenue collection by too much or too quickly.

5. Enforce existing exploration and production (E&P) licences and PSCs strictly – if operators are not holding to their work obligations and timelines, either renegotiate new obligations and timelines as soon as possible or take back the blocks and put them back out quickly.

There are two other areas in development that can impact the gas situation, but progress on both have gone silent:

1. Renewable projects like Project Lara (the solar farm being built at Brechin Castle by bp, Shell and NGC) can reduce the amount of gas needed for electricity, rerouting that gas to petrochemicals and LNG. However, this solar farm was supposed to be online in 2025 but there is no public update. Unlike offshore E&P, a solar farm is simple engineering by comparison. Again, it is totally unacceptable that the RFP for renewable projects went out in 2017, and 8 years later there isn’t a single one active.

2. In a TT Energy Conference in 2019, hydrogen was presented as the long term solution to our gas supply woes. The part of natural gas (CH4) used for petrochemical production is hydrogen (H2) so we could theoretically replace gas with H2. The hydrogen would be produced by electrolysing water and splitting it into H2 and O2. There are reportedly several MOUs, plans and pilots in the works but we don’t know if this will be technically or commercially feasible. If it can work as promised, then this should be at the top of the list for the government and all efforts should be made here. If it is unlikely to be feasible, then that should be communicated clearly.

Notwithstanding everything said above, we should keep the dialogue open with Venezuela and the US about Dragon and the others. These projects remain economic and may yet materialise.

There is no magic bullet to solve the gas situation. Nothing can be done overnight but speed is absolutely critical. To make the best of where we are, it will require some very intense, difficult and expedient negotiations between the companies and the government (whoever they turn out to be after April 28).

The above article is courtesy the Geological Society of TT.