Woodside Energy CEO and Managing Director Meg O’Neill has great expectations for the Australian company’s Gulf of Mexico (GoM) portfolio, where it is flexing its deepwater technical capabilities in three key projects.

Woodside CEO
Meg O’Neill, CEO, Woodside. (Source: Woodside)

Woodside’s involvement in the GoM is centered around Shenzi, Mad Dog and Atlantis. O’Neill classifies the three as Tier 1 assets with more than 1 Bbbl in place and that challenge operators with the technical complexity of drilling in deepwater.

O’Neill, during an exclusive interview with Oil and Gas Investor, said the difficulties in deepwater revolve around the obvious water depths, which have implications for development plans and design structures to be built. There is also a huge amount of subsurface complexity, as a number of these resources are difficult for seismic devices to build images. Additionally, there’s quite a bit of geologic faulting in the structures.

That said, the GoM wells can be extremely productive. They simply require technical sophistication.

“Between both LNG and deepwater, these are higher risk parts of the business, [and] you’ve got a strong process, safety focus. The subsurface work required is at a very high level of sophistication, again with the complex imaging,” O’Neill said. “And those are some of the capabilities that we think we bring to the table.”

The Woodside-operated Shenzi (72% interest) is a conventional field being developed through a tension leg platform (TLP). It has 16 producers flowing to the TLP and six water injection wells, plus two subsea wells tied back to the non-operated Marco Polo platform.

Shenzi North is a two-well subsea tieback to the Shenzi TLP. However, production has been below expectations due to reservoir connectivity.

“The next couple of years with Shenzi are very much going to be focused on maximizing value from the assets, updating our reservoir models, making sure we really understand what’s going on in the subsurface,” O’Neill said.

The BP-operated conventional oil and gas development Atlantis (44% interest) is one of the largest producing fields in the GoM. The development includes a semisubmersible facility with 28 active producer wells and three water injector wells. Two wells (one producer and one injector) were completed in 2023 alongside an extensive well intervention campaign.

“This is another complex field, and we continue with infill well drilling, and we’re continuing to focus on maximizing recovery from that asset,” O’Neill said.

At the BP-operated Mad Dog conventional oil and gas development (23.9% interest), Phase 1 of the project includes a spar facility (A-spar) with drilling capability and 10 active producer wells.

mad dog spar
Mad Dog spar in the GoM. (Source: Woodside)

Mad Dog Phase 2 relates to the southern flank of the field through the new Argos floating production facility. The facility achieved first oil in April 2023, and production ramped throughout the year. After a successful appraisal well was drilled to extend the field to the southwest, the co-owners subsequently sanctioned a three-well subsea tie back.

“[At Mad Dog Phase 2] there was a bit of remedial work we needed to do with some components, things called flex joints, which basically connect the riser to the floating structure. That work was completed over this past winter in December and January. At this point, [the] focus for Argos is really getting to that maximum production,” O’Neill said.

The company’s overall strategy in the GoM is to be a non-op partner. Woodside only operates the Shenzi project, which saw the start-up of Shenzi North in 2023—ahead of its 2024 target, said Omar Rio, North America research analyst at Welligence Energy Analytics.

“Atlantis and Mad Dog are both operated by BP and have significant running room remaining. With the heavy investment phase now over at Atlantis, Mad Dog and Shenzi, Woodside is able to enjoy steady cash flow to maintain dividend payments to their shareholders and fund growth projects in its global portfolio, along with exploration efforts,” Rios told OGI. “We don’t view this strategy changing, as Woodside’s GoM portfolio is poised for strong growth in the medium term, plus it is a non-op partner in multiple exploration leases.”

Rios said that on the exploration front, Welligence has a line of sight on the Chevron-operated Corvus prospect, which was spud in January. Woodside’s farm-in could pay off as the partners target the proven Miocene formation with the hopes of developing the potential resource with its own dedicated infrastructure.

Woodside boasted record production of 187.2 MMboe, or 513,000 boe/d in 2023, split between gas (69%) and liquids (31%). Woodside’s share of production in 2023 from Shenzi was 10.8 MMboe (29,600 boe/d), Atlantis’ share was 12.6 MMboe (34,500 boe/d) and Mad Dog’s share was 7.2 MMboe (19,700 boe/d).

“We see quite a bit of running room in the Mad Dog area, particularly with Argos just starting up. We had some appraisal success last year at Mad Dog Southwest and really pleased that the joint venture has already agreed to sanction that further development. I think that is really reinforcing the value of that Gulf of Mexico portfolio—that there’s opportunities to continue to add value in that business,” said O’Neill, who holds a Master of Science degree in ocean engineering from the Massachusetts Institute of Technology.

Three projects
(Source: Woodside)

Woodside after BHP and Santos

Perth-based Woodside, which completed a transformational merger with Melbourne-based miner BHP in 2022, isn’t necessarily on the prowl for another acquisition. The company walked away from a plan to acquire Adelaide, Australia-based Santos Ltd. in a deal that would have created a near-$60 billion Aussie powerhouse.

Woodside’s early February decision to forgo the Santos deal was simple: it wasn’t accretive, O’Neill told OGI. This is true despite the upside it would have given Woodside through three LNG projects—Papua New Guinea LNG, Gladstone LNG in Australia and Bayu-Undan and Barossa to Darwin LNG—as well as two Australian domestic gas businesses.

Completion of the BHP deal allowed Woodside to merge complementary long-life, high-margin assets with strong growth profiles and a wide range of growth options. The deal boosted Woodside´s production by 105% and also doubled its interest in the North West Shelf (NWS) project in the northwest of Western Australia and acquired interest in Bass Strait in Victoria (southeast Australia), and Pyrenees (northwest Australia) and Macedon (located near Onslow), also in the northwest of Western Australia. 

The BHP deal lifted Woodside into a top 10 global independent energy company based on hydrocarbon production and created the largest energy company listed on the Australian Securities Exchange.

Today, Woodside is a true international company with a diversified, large-scale, low-risk portfolio. The company has operations in Australia, the GoM, the Caribbean, Senegal, Timor-Leste and Canada. However, the bulk of its production comes from Western Australia. In terms of product mix in 2023, LNG dominates by a large margin, followed by crude oil and condensate, piped gas and NGLs.

As of December, Woodside’s remaining proved reserves were 2,450.1 MMboe, proved plus probable reserves remaining were 3,757 MMboe, while the best estimate contingent resources remaining were 5,902 MMboe, according to details in its annual report.

Woodside’s change of heart on the Santos buy is testament to the company’s capital discipline, O’Neill said. Across Woodside’s three main pillars, its capital allocation plan is quite clear.

In the oil space, especially offshore, the company seeks to generate high returns to fund diversified growth amid a focus on high quality resources. The opportunity target is for an IRR that exceeds 15% while the preferred payback period is within five years.

In the piped gas and LNG spaces, the focus is on leveraging infrastructure to monetize undeveloped gas, including optionality for hydrogen. The opportunity target is for an IRR that exceeds 12% while the preferred payback is within seven years.

In the new energy diversified space, the focus is on new products and lower carbon services to reduce customers’ emissions; hydrogen, ammonia and carbon capture utilization and storage (CCS). The opportunity target is for an IRR that exceeds 10% while the preferred payback is within 10 years.

In the aftermath of BHP and Santos, O’Neill said the near-term focus revolves around three growth opportunities: a massive liquefaction project at Pluto Train 2 in Australia, a deepwater project in Mexico at Trion and another deepwater project in Senegal at Sangomar. All three will come online within the next five years.

“Our goal is to thrive through the energy transition, and that means being a resilient, low-cost, lower-carbon profitable company. We have a number of top tier high quality assets both in Australia, Gulf of Mexico, and then we’ve got growth opportunities and projects that are underway,” said O’Neill.

“Sangomar, Scarborough and Trion will come online in a series of reasonably quick successions. Beyond that, we have optionality, that includes options like Calypso in Trinidad and Tobago, Sunrise and Browse here in Australia, as well as a number of new energy opportunities both in hydrogen and CCS. We’ve got good organic growth options beyond the projects we’re executing today.”

With M&A frenzy in the U.S. featuring mega-deals like Exxon Mobil’s $60 billion all-stock purchase of Pioneer Natural Resources and Chevron’s $53 billion all-stock deal for Hess Corp. fresh on investor’s minds, Woodside at most could divest some assets.

“We do have a process underway for Pyrenees and Macedon. And we had some inbound interest, a couple of potential players saying they would be interested in those fields and if they are willing to offer something that’s compelling for our shareholders, we’d be willing to part with those assets,” O’Neill said.

Pyrenees is an FPSO facility off the northwest coast of Western Australia (Woodside operates with a 40% interest in WA-43-L and 71.4% in WA-42-L). Woodside also operates Macedon with a 71.4% interest. Macedon is a gas project located near Onslow, Western Australia and produces piped gas for the Western Australian domestic gas market. Woodside’s share of production from Macedon in 2023 was 8.2 MMboe.

“I’m really pleased with the portfolio that we have. From a growth perspective, there’s three big gas growth opportunities: Calypso in Trinidad and Tobago, Browse in Australia and Sunrise, which straddles the border between Australia and Timor-Leste,” O’Neill said.

Woodside ended 2023 with net debt of $4.7 billion. The company’s gearing ratio at 12.1% is at the lower end of its target range, while the company has $7.8 billion in available liquidity to support major capital investments, said Woodside CFO Graham Tiver during the company’s February year-end webcast with analysts. Woodside also has sustained credit ratings of BBB+ or equivalent.

“Looking at our sources of cash in the period 2024 to 2028, we expect a significant increase in our cash generation as each of our three major projects—Sangomar, Scarborough and Trion—come online,” Tiver said. “Assuming an oil price of $70 per barrel, we expect to generate cash flow from operations that more than covers our current budgeted capital expenditure and dividends, creating a projected surplus of cash through the period of 2024 to 2028.”

Macedon gas treatment plant
Macedon offshore gas field in Onslow, Western Australia. (Source: Woodside)

Australia, Pluto LNG and Pluto Train 2

Russia’s invasion of Ukraine in early 2022 rattled energy markets. Global gas markets started to rebalance in 2023 but remained tight, aggravated by uncertainties around Russian LNG sanctions. Wood Mackenzie’s base case scenario forecasts global LNG demand growing 53% by 2033, supported by growth in Europe (until 2029), China and emerging Asian markets, the consultancy said in October.

Woodside is well-positioned on the LNG business side to take advantage of this scenario. Its reliability of gas supply tied to LNG was reported to be 98% in 2023.

Woodside’s Pluto LNG project consists of a gas processing facility in the Pilbara region of Western Australia. Woodside operates Pluto LNG and holds a 90% interest. Kansai Electric and Tokyo Gas each hold a 5% interest.  Gas from the offshore Pluto and Xena fields is sent through a 180-km pipeline to Pluto Train 1, which has 4.9 million tonnes per annum (mtpa) of processing capacity and is located on the Burrup Peninsula, near Karratha, Western Australia. Woodside has operated the facility since start-up in 2012.

“The Pluto Train 1 actually is running flat out. When it was built, the nameplate was 4.3 mtpa. The team’s done a lot of work over the last decade to try to be able to get more gas through and just working through debottlenecking in a very structured manner. The train’s actually doing better than it was built to do,” O’Neill said.

A brownfield expansion of Pluto LNG will add a second gas processing facility, Pluto Train 2, which will have the capacity to process 5 mtpa. Gas from the offshore Scarborough field located in the Carnarvon Basin, 375 km off the Pilbara coast, will be developed through new offshore facilities connected by a 430-km pipeline to the onshore facility. The project is around 55% complete and first LNG cargoes are targeted for 2026.

The Scarborough energy project represents a gross investment of around $12 billion.

Woodside operates the Scarborough energy project in the Scarborough field. However, in August, Woodside entered into an agreement with LNG Japan for the sale of a 10% non-operating participating interest in Scarborough. Woodside has also entered into an agreement with JERA for the sale of a 15.1% non-operating participating interest in Scarborough.

Woodside holds a 100% interest in Scarborough, 51% interest in Pluto Train 2 and 90% interest in Pluto LNG. Upon completion of the transactions with LNG Japan and JERA, Woodside will hold a 74.9% interest in Scarborough and remain as operator. Woodside expects to complete the transaction with LNG Japan as well as JERA by the second half of 2024.

At Scarborough, eight wells will be drilled initially, with 13 wells drilled over the life of the field. Scarborough will produce around 8 mtpa, of which 5 mtpa of Scarborough gas will be processed through Pluto Train 2, with up to 3 mtpa processed through the existing Pluto Train 1.

“[Due to] the very lean gas that we have from Scarborough, we are making modifications at Pluto Train 1 to enable it to process a blend of Scarborough and Pluto gas. Right now, it’s full on Pluto gas, but when we bring the blend in, we’re going to curtail Pluto production to allow initially 2 mtpa of Scarborough to flow through it. And then when Pluto field life ceases, then Scarborough gas we can flow through at 3 mtpa,” O’Neill said.

“Pluto is more than halfway through its reserve life, so we’ve produced more than half of the gas we expect to recover from that field. We do expect to see production increase when Scarborough comes online, but there’ll be a point in time where Pluto goes offline. Again, a lot of what we’re doing is about preparing the business to be resilient in the 2030s when some of our legacy assets start to come offline,” O’Neill said.

Scarborough gas has a very low reservoir CO2 content. That, when coupled with the highly efficient design of the offshore facility and Train 2, will allow Woodside to deliver gas to Asia with a much lower carbon intensity than many competing sources of LNG, O’Neill said, adding it was “a plus for buyers.”

Pluto LNG Plant
Sangomar FPSO. (Source: Woodside)

While Pluto LNG will soon have two trains, there are no plans for a third.

“When we sort of leased the land for Pluto sites, there were a lot of questions of how big would the trains be and how many could fit? We’ve ended up building a couple of quite large trains, so the site is full, so there’s no Train 3,” O’Neill said.

In 2024, Woodside expects 26%-33% of its produced LNG to be sold at prices linked to gas hub indexes. Long-term the percentage is expected to be around 30%, so that the company can sell on the spot market and take advantage of gas price swings or volatility.

“Our LNG footprint is today largely in Australia, and so we have that proximity to the Asian markets and that’s historically been our area of focus and continues to be an area of focus. Now, that said, we [recently] started lifting LNG from Corpus Christi,” O’Neill said. “Part of why we signed up for that offtake position was because we saw an opportunity to deliver LNG to European customers and we see an opportunity through our marketing and trading team if we have a position in both the Atlantic and the Pacific to increase value even further to our shareholders. We do have a position in the Atlantic, but it’s a smaller position than our Pacific position.”

Woodside has been building up the capabilities of its trading teams over the past five years, which sees a lot of value in optimization work.

“[With] our Pacific portfolio between Northwest Shelf, Pluto and Wheatstone, we’ve got enough kinds of levers in that portfolio plus our shipping position. We’ve got a number of ships on long-term lease to be able to add value, add incremental value by optimization. Now bringing those additional LNG volumes from Mexico Pacific Limited into that Pacific portfolio just gives us another optimization lever,” O’ Neill said.

O’Neill continued: “We do see value in being able to offer that North American LNG to our Asian customers. We see additional value by our ability to optimize and to make sure that we get the right cargo to the right customer at the right time, and we think we can generate more value for our shareholders along the way.”

In December, Woodside signed a sales and purchase agreement (SPA) with Mexico Pacific to acquire 1.3 mtpa, equivalent to approximately 18 LNG cargoes each year, for 20 years. The SPA is subject to Mexico Pacific taking final investment decision (FID) on the proposed third train at the Saguaro Energía LNG Project. The FID is expected in the second half of 2024 and commercial operations are slated to start in 2029.

Woodside’s fourth GoM project: Trion

Woodside’s project offshore Mexico at the large, high-quality conventional resources Trion development continues to move forward. Trion checks key production, climate and financial boxes for both Mexico and operator Woodside (60% interest) and its partner state-owned Pemex (40% interest).

Trion’s $7.2 billion FID was announced in June. It is Woodside’s first major investment decision following its merger with BHP. Trion was an asset in BHP’s portfolio, and will be Woodside’s fourth major project in the GoM, albeit on Mexico’s side of the maritime border after Shenzi, Atlantis and Mad Dog on the U.S. side.

Woodside’s Trion deal validates growth in its Americas deepwater portfolio from a valuation perspective, Welligence’s Rios said, which also includes Trinidad and Tobago.

“The project is a priority for the current administration and will continue to be for the next. The project is still in its early stages, but Woodside seems to be making timely progress on its first oil target,” Rios said.

“[Trion is] a big deal for the post-merger Woodside because, again, it really reinforces the upside quality of the BHP portfolio. This is an asset that BHP secured when the Mexican sector opened up, I think we were quite disciplined in how we approached it,” O’Neill said.

Production from Trion will be processed through a floating production unit (FPU) with a nameplate capacity of 100,000 bbl/d. The FPU can process up to 120,000 bbl/d when Woodside is producing early in the field’s life with no water breakthrough. First oil is slated for 2028. The project continues to award contracts including for the wellheads and subsea line pipe. Procurement activities also commenced for FPU materials and subsea equipment.

Woodside expects Trion will have an all-in breakeven below $50/bbl and then below $43/bbl excluding the Pemex capital carry. Trion is expected to deliver an IRR that exceeds 16% and excluding the capital carry it is greater than 19%.

Trion’s average carbon intensity is expected to come in at 11.8 kg CO2e/boe during the life of the field, which is lower than the global deepwater oil average.

“The team took a number of steps in the design phase to, we call it, ‘design out’ emissions. So, the best way to reduce emissions is to never have them in the first place. We’re really happy with the work the team did to design out and avoid those emissions,” O’Neill said.

The use of the local workforce in Mexico is a priority for Woodside.

“There certainly is plenty of talent. Now, we’ll want to, of course, make sure that we’re setting up the organization there with the right Woodside culture. We will be bringing in some of our experts from the Gulf of Mexico, potentially also from Australia. Again, just to make sure that when we’re setting up that team, that they’ve got that Woodside mindset and that we’re bringing our best technical capability,” O’Neill said. “But there will be a lot of focus on local content and doing what we can to support local businesses and local industry as well.”

On the financial side, Pemex carries a massive debt load—$106.1 billion at year-end 2023. Over the short term, Pemex has significant debt amortizations looming, Rios said.

“We feel good about the project economics as they stand, and there are mechanisms in the agreements to deal with that situation of a partner not paying their way,” O’Neill said when asked whether she had concerns regarding Pemex.

“We’ve been working very closely with Pemex and the Mexican government to make sure everybody understands the point in time where they will start to get cash calls, the budgetary obligation that is expected. Pemex has assured us, and the Mexican government also clearly understands their obligations. So, I feel good about Pemex and paying their way once we get to that point of cash-calling them here.”

Further uncertainty remains in Mexico amid presidential elections in 2024. All indications are the country will have a woman president since both of the front runners from the last two competing parties are female.

“The thing that gives us great comfort in Mexico is, you’ve got the structures and systems to be robust in terms of defending a foreign investor’s interest. Between the legislature, the executive and the court system, we’ve got a very strong three-branch system of government. So again, we did a lot of work before we took the final investment decision to make sure we’re comfortable with the legal framework in Mexico,” O’Neill said.

Senegal’s first offshore oil development: Sangomar

Woodside has been in and out of Africa over the last decade but its Sangomar field development offshore Senegal could be a more enduring footprint for the company, according to O’Neill, who said it represented a significant investment for Woodside and was likewise important for the country.

Offshore Senegal, the Sangomar field development Phase 1 will be that African country’s first offshore oil development. Work on the Sangomar field development started in early 2020. The field (formerly the SNE field), is located 100 km south of Dakar and contains both oil and gas.

Sangomar represents a gross investment of between $4.9 billion-$5.2 billion. Woodside operates Sangomar and holds an 82% interest in the Sangomar exploitation area and a 90% interest in the remaining Rufisque Offshore, Sangomar Offshore and Sangomar Deep Offshore (RSSD) evaluation area. Societé des Petroles du Sénégal (Petrosen) holds an 18% interest in Sangomar and a 10% interest in RSSD.

Sangomar field development Phase 1 includes a stand-alone floating production storage and offloading (FPSO) unit, named Léopold Sédar Senghor, with subsea infrastructure and an expected production capacity of 100,000 bbl/d.

The FPSO reached Senegal in mid-February 2024 and first oil is slated for mid-2024. The project was 94% complete at the end of 2023, with 17 of 23 wells drilled and completed.

“It’s a very complex field architecture. It’s 23 subsea wells that include producers, water injectors and gas injectors. The flow assurance is complex, so we’re going to take a measured approach to starting up to make sure that we start up smoothly and that we continue on a positive trend,” O’Neill said.

The FPSO was previously a Very Large Crude Carrier (VLCC) that was converted by MODEC into a fit-for-purpose FPSO suitable for the Sangomar field in accordance with agreed specifications under an FPSO purchase deal between MODEC and Woodside.

Woodside continues to focus on local content and has been working with Senegalese small- and medium-sized companies to help them understand what services the company needs in the country while also trying to help them build up their capabilities.

The Sangomar project will go a long way to help the Senegalese government address the west African country’s financial stresses. Like other countries in Africa, Senegal’s population is young and the government is more fixated on tackling energy poverty first but with an eye on trying to contain emissions.

“The government’s message to us is very much focused on this as an important asset for our nation. It’s important that we do what we can to build local capability,” O’Neill said. “We have conversations around energy transition, but their focus is very much around that revenue security that this investment will bring.”

BHP legacy in Trinidad, Calypso Gas

Gas producing and LNG exporting Trinidad and Tobago rounds out Woodside’s American assets. In the small twin-island country the Australian energy giant is filling a void once filled by the so-called three Bs: BPTT, which partners BP and Repsol, British Gas and BHP. These three companies were once among the top four, with Shell, over a decade or more. Shell swallowed BG and Woodside swallowed BHP.

“The thing that has impressed me from day one about Trinidad is the government’s strong support for and deep understanding of the industry,” O’Neill said.

“We’ve got a couple of assets that we operate now that I would describe as later in their life,” O’Neill said. “And the government has been incredibly supportive on working with us to figure out what are the sorts of things we can do to really extend field life to ensure that we continue to create value for all of the stakeholders: and that’s ourselves, that’s the government, that’s the downstream customers who consume our product.”

Woodside is in the Greater Angostura field, a conventional offshore oil and gas field located 38 km northeast of Trinidad that was discovered in 1999, with first oil achieved in January 2005 (Phase 1). Phase 2 started gas sales in 2011, while first gas for Angostura Phase 3 started in September 2016. Ruby is a conventional offshore oil and gas field located within the Greater Angostura Fields. First oil started flowing in May 2021.

Woodside operates Angostura with a 45% interest with partners The National Gas Company of Trinidad and Tobago Limited or NGC (30% interest) and Chaoyang (25% interest). Woodside also operates Ruby with a 68.46% interest with partner NGC (31.54% interest).

Today, Woodside is the third-largest gas producer in Trinidad, trailing only BPTT and Shell, according to recent data published by Trinidad and Tobago’s Ministry of Energy and Energy Industries (MEEI). A pending FID and production to come from Woodside’s Calypso project, coupled with production to come from Shell’s Manatee project, are expected to help Trinidad stabilize its gas production by 2026, Trinidad’s Energy Minister Stuart Young told OGI in an earlier interview.

Young told attendees at the annual Trinidad and Tobago Energy Conference in February that Calypso is planned to produce around 700 MMcf/d of gas, according to details from the event.

“The government is really phenomenal and Calypso is another opportunity to bring some new gas to market in Trinidad and Tobago. Now it’s a deepwater field from a size perspective, it’s two to three Tcfs, so not particularly big for the water depths that we’re talking about. It’s got a bit of complexity, but the government is very engaged and supportive and wants to work with us to figure out what we need to do to be able to move this opportunity forward,” O’Neill said.

Trinidad, located just off the eastern coast of Venezuela, is home to the four-train 14.8 mtpa Atlantic LNG facility, the first liquefaction plant constructed in the Latin America and Caribbean region (LAC). Trinidad is also home to ammonia and methanol plants even though the bulk of the country’s value is generated from its gas derived from the LNG business, according to recent official statements from NGC President Mark Loquan.

However, declining gas production in recent years in Trinidad, coupled with disagreements between Atlantic LNG shareholders BP, the country’s largest gas producer, and Shell, the largest shareholder, saw Train 1 initially idled in December 2020. The train is still offline. However, a recent Atlantic LNG restructuring as well as a deal to tap into gas from Venezuela’s offshore Dragon fields look to assure the Train returns to operation soon, according to Young.

“The restructuring gives us the opportunity to potentially process Calypso gas through that facility and lift LNG if we so desire. A lot of the work that we’re doing right now is understanding the possible outlets for Calypso gas. There’s also a very significant petrochemical industry in Trinidad and Tobago. There’s a number of different potential customers, and that’s a key part of our scope of work in the near term.”

Beyond oil and gas, Trinidad is really leaning on IOCs already in the country to assist with the country’s energy transition and shift to renewables.

“As we’ve been working on our strategy to thrive through the energy transition, we’ve really focused our efforts on hydrogen and integrated carbon solutions, so things like CCS and carbon offsets,” O’Neill said. “We do see some opportunities in Trinidad, but renewables isn’t a focus area for us. It’s not something that particularly matches our capabilities. So, that’s not something that we’ll be pursuing.”