bp Annual report 2025
Strong performance – building for the future (Link)
“With your support we can and will become a stronger bp. One that is more sustainable in every way, especially in the creation of value for shareholders.” Albert Manifold, Chair
“We’re focused, we’re in action, we’re determined to make bp the strongest it can be, and we look forward to welcoming Meg O’Neill as CEO in April 2026.” Carol Howle, interim CEO
bp operations in Trinidad and Tobago focus on natural gas production. With 12 offshore platforms and three subsea installations, we are the country’s largest hydrocarbon producer, accounting for about 50 per cent of gas production. We’re also partnering on T&T’s first large scale solar development.
Cypre is bpTT’s third subsea development. It includes 7 wells and subsea trees tied back into bpTT’s existing Juniper platform via flexible flowlines. The Cypre gas field is located 78 kilometres off the southeast coast of Trinidad within the East Mayaro Block, in water depth of approximately 80 metres. The Cypre project announced the successful completion of its Phase 1 startup in the first quarter of 2025, marking a significant step forward in the development of this world-class energy asset.
Building on this achievement, the project completed the drilling and completions program for three Phase 2 subsea wells utilizing the Joe Douglas jack-up rig during the third quarter. These milestones reinforce the project’s commitment to safety, operational excellence and timely delivery as it continues to advance offshore developments.
In addition, the manufacturing and rigorous testing of the Phase 2 subsea production and controls equipment has been successfully finalized. The project is now entering its next phase with the readiness and mobilization of the subsea construction vessel, Seven Arctic, from Norway which commenced offshore construction and commissioning operations in fourth quarter 2025.
These collective efforts underscore Cypre’s dedication to innovation and reliability, positioning the project for continued success. The first set of subsea trees for Cypre have arrived in T&T. Subsea trees manage the flow of gas on the sea floor.
Ginger will become bpTT’s fourth subsea development and will include four subsea wells and subsea trees tied back to bpTT’s existing Mahogany B platform. First gas from the project is expected in 2027 and will make up one of bp’s ten major projects expected to start up between 2025 and 2027.
At peak, the development is expected to have the capacity to produce average gas production of 62 thousand barrels of oil equivalent per day. Ginger is well underway with the first well completed!
Ocelot Project consists of a new 7” onshore liquid pipeline that connects bpTT`s Beachfield facility to the Galeota Terminal Facility. The pipeline is approximately 13 km long and is routed along an existing pipeline corridor that is currently in use by bpTT`s 06BECH pipeline. This route traverses the forested area in Guayaguayare , through the La-Savanne community and parallel to the Isthmus Court road into the Galeota facility.
The new pipeline is made of steel and will be buried approximately 4 ft deep on average but goes deeper at road and river crossings. Typical onshore practices will be utilized , which involves welding of 12m lengths of pipe together to create the 13km string, inspection and coating of the welded joints, digging a trench and lowering the welded pipe string into the trench and finally reinstatement of the ground and Right of Way corridor.
Construction will be in manageable segments to mitigate construction risks and minimize exposure to the community and environment. Additionally, once the new pipeline is completed, the project will flush and clean the old 06BECH pipeline of hydrocarbons , disconnect from the facility connections and plug the ends of the old pipeline. The Project is being executed by Stork Technical Services Limited as the main contractor.
Drilling will continue through 2026. We’re also progressing with the fabrication of kit required for 2026 offshore topsides and subsea construction. Tubing hangers delivered to Trinidad & Tobago. These are critical to the production process. Preparation works have commenced on the Juniper platform for 2026 construction.
Ginger flexibles will tie back to the Mahogany B platform and umbilicals to Juniper. The Ginger project is progressing well. Since project sanction earlier this year, work has focused on fabricating flexibles and umbilicals which will connect the wells to the Mahogany B and Juniper platforms, respectively. Work is also progressing on the subsea trees as well as the manifold. Drilling is due to start soon and will continue into 2026.
Noble wins US$375,000 day-rate deal to drill 3 bp wells
13 March
Energy major bp awarded Noble Corporation a contract for its semi-submersible rig Noble Developer to drill three wells offshore, expected to begin in the first quarter of 2027. In its full year results for 2025, Noble confirmed the drilling programme is expected to last 240 days at a day rate of US$375,000, with options for up to three additional wells. The Noble Developer was built in 2009. With 12 offshore platforms and two subsea installations, bp is Trinidad and Tobago’s largest hydrocarbon producer.
Westwood Global Energy Group yesterday stated that offshore rig market activity remained steady at the start of the year, with utilisation levels holding firm across the global fleet.
“The global committed jackup fleet decreased by four units to 384, with marketed committed utilisation at 88% and total utilisation at 79%.
During the month, nine new contracts were awarded, adding approximately 2,193 days (six rig years) of backlog. Notably, Borr Drilling’sOdin secured a 120-day contract with ExxonMobil to drill two wells offshore the US starting in July 2026.
In the semisubmersible segment, the committed fleet increased to 59 units, while marketed committed utilisation remained stable at 79%. Among seven new contracts recorded, Noble Corporation’sNoble Developer was awarded a 240-day contract with bp to drill three wells offshore Trinidad and Tobago at a $375,000 dayrate.”
Westwood Global said in the drillship segment, the committed fleet increased to 82 units and marketed committed utilisation rose to 93%. Ten new fixtures were recorded, including a 440-day contract awarded to Seadrill’s drillship West Capella by PTT Exploration and Production to drill nine wells offshore Malaysia.
Noble Developer
Shell, BP prepare for 2027 production surge
March 18, 2026
Harbinger of strong growth, bright stars in the western firmament, global energy giants bp and Shell are proceeding to bring a new wave of upstream gas projects onstream in 2027, a welcome production rebound, after years of gas curtailment.
bp’s Ginger and Mento projects and Shell’s Manatee and Aphrodite fields, are expected to deliver first gas within that window, according to their latest annual reports this month.
Two bpTT projects, the Ginger gas development and the Juniper Wells infill programme, were among eight major capital expenditure decisions assessed for Paris Agreement consistency in 2025. Both projects are expected to deliver first gas next year.
“We sanctioned the Ginger gas development in Trinidad and Tobago. Ginger will be our fourth subsea project in the country and will be tied back to our existing Mahogany B platform. First gas from the project is expected in 2027, making Ginger one of bp’s ten major projects expected to start up between 2025 and 2027.
At peak, the development is expected to have the capacity to produce average gas production of 62,000 barrels of oil equivalent per day.
We approved investment in decompletion of three existing wells, along with drilling and completion of three single zone sidetracks . The infill programme is expected to deliver around 19mmboe, with the first gas expected in 2027.”
For the period from 2026 to 2028 worldwide, BP is contractually committed to deliver approximately 288 million barrels of oil, 6,288 billion cubic feet of natural gas and 70Mt of liquefied natural gas.
“The commitments principally relate to group subsidiaries based in Azerbaijan, Oman, Trinidad and Tobago, the UK and the US. We expect to fulfil these delivery commitments with production from our proved developed reserves and supplies from existing contracts, supplemented by market purchases as necessary.”
In T&T BP holds interests in exploration and production licences and production-sharing contracts (PSCs) covering 2.1 million acres offshore the east and north-east coast. These facilities include 12 offshore platforms, 3 subsea tiebacks and 2 onshore processing facilities. Production comprises gas and associated liquids. Another development bp is anticipating in 2027 is restructuring of its shareholding in Atlantic LNG.
BP also holds interests in the Atlantic LNG facility. The total gross capacity of the LNG facility is approximately 12Mtpa, with three trains in operation. Its shareholding averages 43% across the companies which own the LNG trains comprising the LNG facility.
Upon expiration of the Train 4 contract on 1 May 2027, and completion of full restructuring, its shareholding will increase to 45%.
Bp outlined the advances it made last year. In May it announced first gas from the Mento project.
Mento is a 50:50 joint venture between EOG Resources Trinidad Ltd (EOG) and bpTT, with EOG as the operator. The development features a 12-slot attended facility that is located in acreage jointly licensed by bpTT and EOG off Trinidad’s south-east coast.
In November bp announced that it had safely completed the Cypre seven-well drilling programme in Trinidad, the second phase of the Cypre project, following delivery of first gas in April 2025. Cypre is bpTT’s third subsea development with seven wells tied back into bpTT’s existing Juniper platform.
Under a similar joint venture, BpTT and operator EOG are developing the Coconut natural gas field in the Columbus Basin of Trinidad, with first gas expected in 2027. Construction is in progress with start-up expected in 2027.
Seismic processing activity over the joint Manakin-Cocuina field was successfully completed in September 2024. Bp is operator of the Manakin block which was discovered in 2000. Bp and NGC also hold an exploration and production licence for the development of the Cocuina gas discovery, which is the Venezuelan portion of the cross-border Manakin-Cocuina gas field.
Activity ceased in April 2025 with the revocation of its specific OFAC licence. In February 2026 General Licences 48, 49 and 50 were issued by OFAC which authorised contractors and certain companies including bp plc and its subsidiaries to progress with oil and gas projects in Venezuela. Bp is therefore authorised to progress with the development of the Manakin-Cocuina project subject to the conditions contained in the General Licences.
Seismic processing activity was completed and interpretation of results under way on deepwater blocks Blocks 25a, 25b and 27 in Trinidad and Tobago. These blocks are a 50:50 joint venture between bp and Shell, with bp operating Blocks 25a and 25b, and Shell operating Block 27.
BP reported net natural gas production in Trinidad and Tobago of 1,045 in 2025, compared with 1,145 in 2024 and 1,191 in 2023.
Aphrodite and Manatee will sustain T&T into 2030
Shell reported that its global LNG liquefaction volumes fell by 2% compared with the previous year which it attributed primarily to ownership restructuring in Trinidad and Tobago and higher maintenance across its portfolio, which was partly offset by the ramp-up at LNG Canada. In Trinidad and Tobago, Atlantic LNG is a significant supplier of LNG for the export market.
“Shell’s interests in the production trains range from 47.15% to 51.1%. We also have interests in two concessions with producing fields: North Coast Marine Area (Shell interest 80.5%) and East Coast Marine Area (Shell interest 100%)—both are already home to some of Shell’s largest gas-producing fields.”
Shell took a final investment decision (FID) in July 2024 to develop the Manatee gas field, followed by an FID in 2025 for the Aphrodite backfill project.
“Aphrodite, together with Manatee, will help sustain Trinidad and Tobago’s gas industry into 2030. Aphrodite will connect to existing subsea infrastructure in the Shell Operated East Coast Marine Area, sending gas to the Dolphin A platform. Production is expected to start in 2027 and reach a peak production capacity of about 18,400 boe/d. Manatee is also expected to deliver first gas in 2027 and reach a peak production capacity of 104,000 boe/d,” Shell stated.
Shell holds interests in two producing-field concessions in Trinidad and Tobago: the North Coast Marine Area (80.5% interest) and the East Coast Marine Area (100% interest), where it took a final investment decision (FID) in June 2025 to develop the Aphrodite project.
“In May 2025, we completed the sale of our 65% interest in the Central Block facility to Touchstone Exploration Trinidad Limited. We have a 100% interest in exploration blocks 5(c)REA, 6d and modified block U(c). We also have a 50% interest in exploration blocks 25a, 25b and 27 in the Columbus Basin.
We operate Block 27 and bp is the operator of the remaining two. In 2025, we submitted notification of our relinquishment of all portions of the Block 5d contract area.”
Shell attributed the 1,664 million standard cubic feet increase in proved reserves from 2023 to 2024 primarily to the final investment decision on the Manatee project in Trinidad and Tobago. CEO Wael Sawan stated,
“We are in a world defined by more uncertainty—from increasingly fragmented geopolitics, to the rapid rise of artificial intelligence and the pressures of climate change. Energy sits at the heart of this changing world, highlighting the critical role of our sector. As I write this message, amid the turmoil of the conflict in the Middle East, we feel that critical role more than ever.
We are focusing first and foremost on the safety and wellbeing of our colleagues. I would like to thank all our staff for their professionalism, commitment and the care they continue to show for each other. Shell has an important role to play in the evolving energy system. We provide the oil and gas people need today, including liquefied natural gas (LNG).
We are also helping to build the energy system of the future, with low-carbon energy products and solutions. We are transforming into a more competitive and resilient business so that we are in the best possible position to support the around a billion people we serve, directly or indirectly, every year.
We are building trust in Shell as the investment case and partner of choice in a complex and changing world. At the heart of Shell’s transformation is its focus on performance, discipline and simplification. We are embedding this focus across our organisation, from the way we make investment decisions to how we reshape our retail network and maintain our oil and gas platforms, improving reliability and production.”
Shell’s 2025 LNG Outlook forecasts global demand for LNG to rise by around 60% by 2040, largely driven by economic growth in Asia.
“Gas, including LNG, is a stabilising force in energy systems because it is versatile, flexible and reliable. Gas is versatile because it can be used in power generation, industry, heating and transport. It is also flexible and reliable because it is simple to deploy and can be shipped, as LNG, to where it is needed to meet changing demand. Gas is a lower-carbon alternative to coal in power generation and industry, and to oil in transport. Gas can balance renewable energy to provide stability for national grids.”
SHELL plc ANNUAL REPORT
AND ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 2025 (Link)
Strengthening Trinidad and Tobago’s gas future In Trinidad and Tobago, the Atlantic LNG facility is a significant supplier of LNG for the export market. Shell’s interests in the production trains range from 47.15% to 51.1%. We also have interests in two concessions with producing fields: North Coast Marine Area (Shell interest 80.5%) and East Coast Marine Area (Shell interest 100%) – both are already home to some of Shell’s largest gas producing fields. We took a final investment decision (FID) in July 2024 to develop the Manatee gas field and in 2025 we took an FID on the Aphrodite backfill project development [A]. Aphrodite, together with Manatee, will help sustain Trinidad and Tobago’s gas industry into the 2030s. Aphrodite will connect to existing subsea infrastructure in the Shell Operated East Coast Marine Area, sending gas to the Dolphin A platform. Production is expected to start in 2027 and reach a peak production capacity of about 18,400 boe/d. Manatee is also expected to deliver first gas in 2027 and reach a peak production capacity of 104,000 boe/d.
. Trinidad and Tobago.
We have interests in two concessions with producing fields: North Coast Marine Area (Shell interest 80.5%) and East Coast Marine Area (Shell interest 100%), where in June 2025 we took a final investment decision on the Aphrodite development project. In May 2025, we completed the sale of our 65% interest in the Central Block facility to Touchstone Exploration Trinidad Limited. We have a 100% interest in exploration blocks 5(c)REA, 6d and modified block U(c). We also have a 50% interest in exploration blocks 25a, 25b and 27 in the Columbus Basin. We operate Block 27 and bp is the operator of the remaining two. In 2025, we submitted notification of our relinquishment of all portions of the Block 5d contract area.
Other
We have interests in Barbados, Colombia (withdrawal is in progress), Cyprus, Tanzania and Venezuela [A]. [A] Our previous Office of Foreign Assets Control (OFAC) licence was withdrawn in 2025 in line with US policy at the time, meaning that we have been unable to undertake any activities related to our Venezuela interest since then. In mid-February 2026, the USA issued several general licences that authorise various activities in Venezuela, including one that allows certain companies to engage in oil and gas operations in Venezuela and produce from its reserves. We are currently reviewing these general licences to understand how they impact our activities.
NGC signs gas sales contract with PLNL
to secure ammonia production
3 March
Chairman of the National Gas Company, Gerald Ramdeen witnessed Point Lisas Nitrogen Ltd president Fitzroy Harewood and acting NGC president Edmund Subryan signing a new gas supply contract.
The National Gas Company of Trinidad and Tobago signed a new gas sales contract with Point Lisas Nitrogen Ltd to continue supply of natural gas to the PLNL ammonia plant.
The contract is a “significant milestone” for both organisations, which acting NGC President Edmund Subryan called an “economically suitable outcome” for both sides, “Balancing the needs of various stakeholders requires meaningful dialogue, cooperation, and a shared focus on long-term national interests.”
NGC aims to strengthen its partnership with PLNL as part of efforts to maintain a resilient and sustainable domestic downstream energy sector. PLNL is a 50/50 joint venture owned by Koch Fertilizer LLC (a subsidiary of Koch Industries, Inc.) and CF Industries Holdings, Inc.
“The execution of this contract reaffirms the commitment to continue to provide a reliable and economic supply of gas to its downstream petrochemical customers. PLNL owns and operates a globally competitive plant that produces anhydrous ammonia for international markets.
This arrangement will continue to support the operations of PLNL’s ammonia production facility allowing it to satisfy its contractual obligations with its customers while at the same time, adding to the revenue generation of this country.”
NGC chairman Gerald Ramdeen said the contract highlights the stability and long-term strength of the local petrochemical industry.
“NGC remains conscious of its role within the energy sector, particularly as this country’s aggregator and supplier of natural gas to downstream industries and as the State entity responsible for maximising value from the natural gas resources. The execution of the GSC is a solid indicator of the resilience and permanency of the local petrochemical sector.”
NGL confirms resumption of dividends
5 March
The board of Trinidad and Tobago NGL (TTNGL) confirmed that the special resolution passed by shareholders of the company “facilitates the declaration and payment of dividends pursuant to Section 55 of the Companies Act.”
The special resolution authorised the company to reduce TTNGL’s stated capital by $2.2 billion, which effectively eliminated the $1.8 billion deficit it accumulated as a result of having to impair the value of its underlying asset, its investment in 39 per cent of Phoenix Park Gas Processors Ltd (PPGPL).
The decision was taken at the company’s annual meeting on March 5, 2026, according to a notice signed by its corporate secretary, Aegis Business Solutions Limited.
The resolution authorised a proportional reduction in the stated capital account across all classes of shares.
TTNGL indicated that the move does not change the number of issued shares, but reduces the amount recorded in the company’s stated capital account. According to the company, the restructuring allows TTNGL to satisfy requirements under Sections 54 and 55 of the Companies Act, which govern capital reductions and the ability of companies to declare and distribute dividends.
TTNGL did not pay dividends in the years 2022, 2023 and 2024 because of the impairment issue.
PPGPL operates the natural gas liquids processing plant at Point Lisas, which extracts propane, butane and natural gasoline from natural gas supplied by upstream producers.
TTNGL is an investment holding company whose primary source of income is its 39 per cent shareholding in PPGPL, one of the largest natural gas liquids processing facilities in the region.
The company’s performance is closely linked to the profitability of PPGPL and the broader natural gas sector in T&T.
PPGPL processes gas supplied by upstream producers, including bpTT and Shell, before the liquids are exported mostly to international markets. The plant also supplies feedstock to several downstream petrochemical producers operating on the Point Lisas Industrial Estate.
For the nine-month period ended September 30, 2025, TTNGL reported profit after tax of $63.75 million, a decrease of 23 per cent, compared with the $82.77 million the company earned for the same period in 2024.
The reduced earnings for the nine-month period pushed TTNGL’s earnings per share down to $0.41, from $0.53 in the corresponding period a year earlier. For the quarter ended September 30, 2025, TTNGL recorded profit after tax of $99.59 million, 175 per cent more than the $26.10 million recorded for the same quarter in 2024.
TTNGL chairman, Gerald Ramdeen, in the nine-month report, stated, “Profit from TTNGL’s investment in PPGPL for the quarter was positively impacted by the reversal of recognised impairment charges of $85.3 million. This treatment is supported by the reinstatement of the licence issued by the US Department of Treasury’s Office of Foreign Assets Control for natural gas collaboration regionally.”
TTNGL dividends payable in USD
March 5, 2026
Chairman of NGC and Trinidad and Tobago NGL, Gerald Ramdeen has said shareholders of TTNGL Ltd will not only receive dividends again after three years, but may be able to request payments in US dollars.
Energy Minister Roodal Moonilal told a post-Cabinet news conference the TTNGL board would consider paying about $308 million in dividends to approximately 11,000 shareholders. Payment followed a resolution passed at the tenth annual shareholders meeting of TTNGL, a publicly listed company created by the Government to hold a minority shareholding in Phoenix Park Gas Processors Ltd, the gas processing subsidiary of NGC.
Ramdeen said, “The board will be meeting before the end of the month to determine a dividend payment. The board will be considering payments by TTNGL to shareholders in USD.”
This decision followed the shareholders’ agreement for the company to reduce its stated capital account by $2.2 billion.
“Included on the agenda for 2025 under special business is a special resolution for the reduction of the company’s stated capital. Over the past three years, TTNGL has been unable to pay dividends to its shareholders, due to the Company’s inability to satisfy the solvency test prescribed under Section 54 of the Companies Act Chapter 81:01 of the laws of Trinidad and Tobago (the Companies Act).
In particular, the net realised value of TTNGL’s assets has been less than the aggregate of its liabilities and stated capital of all classes of shares,” TTNGL stated in a letter to shareholders on January 12.
“This position was brought about by the impact of impairment charges recorded in the company’s financial statements which have eroded/reduced the retained earnings, resulting in an estimated accumulated deficit of $1.8 billion as at December 31, 2025.
These impairments reflect lower calculated valuations of TTNGL’s investment in its underlying asset, Phoenix Park Gas Processors Ltd (PPGPL), that were driven by materially lower long-term cash flows at PPGPL. The lower valuation was primarily a result of reduced forecast gas supply volumes to PPGPL for processing, the inclusion of a finite useful life for Trinidad operations to 2042 (due to decommissioning provisions), and lower forecast cash flows from PPGPL’s operations in North America.”
The board explained to the shareholders yesterday that the reason they reduced the stated capital account was to be able to pay dividends.
Shareholders are happy, Moonilal said.
“This of course we believe is the reward to shareholders for placing a good government in place so that the shareholders themselves have received today relief and their share value has been impacted upon positively. We believe that the shareholders now of TTNGL will be extremely happy as they were today to hear that they will receive dividends for the first time in three years,”
TTNGL’s closing price on the T&T Stock Exchange yesterday was $5.45 compared to $20.75 for the comparative period in 2022.
TTNGL board comprises Judy Kalloo, Ashmeer Mohamed and Dr Rampersad Motilal. Ramdeen said the board will remain for a term not expiring later than the close of the next AGM.
Shareholder Peter Permell, said the resumption of dividend payments could be seen as “TTNGL is back in business. The payment in US dollars is welcomed. “
He noticed Ramdeen’s concern about the management of TTNGL prior to his takeover last year. He described Ramdeen as “candid” in the way he addressed shortfalls in the company and what he was greeted with when he was appointed chairman which was well-received. Previous boards never paid in US currency.
“He expressed his disappointment by what happened in TTNGL—the fall in share price, the halt of dividend payment. They are going to fix this. They sought advice from their attorneys on how to fix this,” said Permell.
In 2024, despite earning an after-tax profit of $82.8 million for the nine-month period ended September 30, 2024, shareholders were still without their dividends. Former chairman of TTNGL, Dr Joseph Khan, at the time, said,
“The board and management remain deeply committed to addressing this issue as a priority, knowing the impact it has had on shareholder value. We are actively exploring pathways that, while complex, we believe will ultimately strengthen TTNGL’s ability to resume dividends and improve shareholder returns.
We appreciate our shareholders’ patience as we work diligently to position TTNGL for sustainable growth and value creation.”
At TTNGL’s 2016 annual meeting, shareholders voted in favour of receiving their dividends either in local currency or US dollars.
Atlantic LNG appoints Motilal chairman
10 March
Dr Rampersad Motilal
Dr Rampersad Motilal has been appointed chairman of Point Fortin-based LNG producer Atlantic, replacing Vincent Pereira who was chairman of the Point Fortin-based LNG producer since October 1, 2024.
Atlantic said that with over four decades of leadership in Trinidad and Tobago’s energy sector, Motilal brings deep industry expertise and strategic insight.
“Dr Motilal previously served as Chief Executive Officer and Managing Director of Methanol Holdings (Trinidad) Ltd (MHTL) and its predecessor companies for sixteen years. Over the course of his career, he has gained extensive experience in petrochemicals, large scale project development, production and engineering management and financial strategy.”
Motilal holds a Doctorate in Business Administration from the International School of Management (ISM) in Paris, an Executive MBA with distinction from The University of the West Indies and an honorary doctorate in Engineering and Entrepreneurship from the University of Trinidad and Tobago. He served on numerous local and international boards across the energy, business and education sectors.
“As Dr Motilal joins the Atlantic Board, Mr Vincent Pereira concludes his tenure as Chairman. During his term, Atlantic commenced operationalisation of the first phase of its restructuring, positioning the company for continued excellence in safety, reliability and sustainability.
Atlantic extends its sincere appreciation to Mr Pereira for his dedicated Atlantic service.”
LNG Prime Staff March 11, 2026
Atlantic LNG
Predator publishes Independent Technical Report for Cory Moruga onshore
5 March 2026
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- 2P resources of 8.73 MM bls
- Project economics based on US$60/bo
- SC-3 drilling plans proceeding as planned
- BON-20 well programme, objectives and progress as planned
- Programme to increase production coinciding with oil price spike
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Predator Oil & Gas Holdings, the Jersey- based Oil and Gas Company with hydrocarbon operations focussed on production in Trinidad and appraisal and near-term development in Morocco, announced that further to the release of 25 February 2026 in respect of an operations update for Trinidad, the Company is publishing the Independent Technical Report (‘ITR’) by Scorpion Geoscience Ltd. for the proposed Snowcap-3 (‘SC-3’) appraisal well in the Cory Moruga Exploration and Production Licence.
Following the management team’s site visit to Trinidad last week, initial site and land registry investigations for two locations for an SC-3 and a potential follow-up SC-4 well commenced.
Star Valley Rig 205 was viewed and assessed at its current site by the Company’s corporate operations manager. The BON-20 drilling programme, objectives and current progress were reviewed. A further update will be issued after the completion and anticipated testing of BON-20.
Paul Griffiths, Chief Executive Officer of Predator Oil & Gas Holdings Plc commented:
‘We are making good progress on preparations to drill an SC-3 appraisal well, that in a success case and subject to regulatory approval can be put on production within a relatively short time framework.
The publication of the ITR, which is based on US$60/bo, is timely given the current spike in oil prices and the prospect of continuing conflict within a key area contributing to global hydrocarbon production.’
Source: Predator Oil & Gas
New EMA Board Grants CEC to Touchstone
for Gas Production At Carapal Ridge
March 5, 2026
The Environmental Management Authority (EMA) granted a Certificate of Environmental Clearance (CEC) No. CEC7201/2026 to Primera Oil and Gas Limited , a subsidiary of Touchstone Exploration (Trinidad) Limited, for the drilling and production of natural gas and condensate at the existing Carapal Ridge-3 well site within the Central Block, Moruga.
This approval follows the successful performance of the Carapal-3 well and enables the development of two wells designed to increase national gas output from a newly identified gas-charged reservoir.
The project will utilise an already developed surface well location, significantly reducing potential environmental risks, minimising additional land disturbance, and optimising existing infrastructure. Early engagement between Primera and the EMA facilitated the submission of the CEC application and approval granted well within the statutory timeline.
The issuance of CEC7201/2026 marks the eighth major CEC granted under the new Board of Directors for priority projects. Of these, seven approvals were within the oil and gas sector, with one for tourism development, demonstrating a balanced regulatory approach across key economic sectors.
EMA Chairman Doolar Ramlal said, “By processing priority projects efficiently, without ever compromising environmental integrity, the EMA is actively enabling responsible investment, strengthening job creation and advancing long-term national resilience. Effective regulation is not a barrier to growth; it is the foundation of sustainable development.”
The EMA remains committed to upholding its mandate under the Environmental Management Act Chap. 35:05 to manage the environment while facilitating sustainable development that benefits present and future generations.
Front left to right: Ms. Nova Johnson, Director – EMA, Ms. Rhea de Gourville, HSE Manager – Touchstone Exploration Ltd., Mr. Doolar Ramlal, Chairman – EMA, Mr. Xavier Moonan, Exploration Manager – Touchstone Exploration Ltd., Ms. Neeala Mongroo – Deputy Chairman and Dr. Rebecca Gookool-Bosland, Director, of the EMA. Back left to right: EMA Directors Dr. Steve Rajpatty, Mr. Kadeem Williams, Mr. Naresh Ragoonanan and Mr. Avinash Phagoo.
Central Block boosts Touchstone LNG growth outlook
2 March 2026
Chief executive officer and president Paul Baay said Touchstone Exploration established a “new pillar” of LNG-linked growth after integrating its Central Block into its producing reserves base .
Touchstone released its 2025 year-end reserves, based on an independent evaluation prepared by GLJ Ltd effective December 31, 2025, detailing its total proved developed producing (PDP), total proved (1P), and total proved plus probable (2P) reserves. Baay said,
“Our year-end reserves report highlights the strategic integration of the Central block into our producing reserve base, establishing a new pillar for LNG-linked growth alongside our stable oil production and Ortoire natural gas assets.”
The report reflected growth in its gas marketing portfolio, supported by fixed-price sales from Ortoire and LNG contracts tied to Central block production.
“While data from the Cascadura-5 well necessitated a downward revision to our Block B reserves, Block A remains on forecast and continues to represent a significant opportunity for production growth, particularly as natural gas pricing is subject to redetermined in October 2027.”
“This independent evaluation underscores the substantial value of our Trinidadian portfolio. The NPV10 of future net revenues for our 2P reserves was estimated at approximately US$653 million before tax and approximately US$315 million after tax, which represented a 2% increase over 2024 despite our 2025 production.”
Addition of medium-gravity oil reserves from Cascadura-5 also points to further potential within the emerging Herrera play. The company said low-cost recompletion opportunities could allow it to tap deeper oil zones in Block B, adding incremental output without significant new drilling.
“Looking ahead, we remain focused on execution. We look forward to tying in Carapal Ridge-3 for production in late March 2026, commencing our legacy oil block drilling programme in March, and commissioning the Cascadura compressor in the second quarter of 2026.”
Year-end 2025 reserves overview
- • Reserves performance: Compared with the end of 2024, and after accounting for production during 2025, the company increased the amount of oil and gas currently in active production by 45%. However, total proven reserves dipped slightly, while overall proven and probable reserves were largely stable.
- • Portfolio changes: The growth in producing reserves was driven mainly by the acquisition of the Central block and the addition of the Cascadura-5 well. This was partly offset by the sale of the Fyzabad block.
- • Revisions to estimates: Adjustments were made to natural gas and liquids estimates at Cascadura, along with the impact of the Fyzabad sale. These were partly balanced by the Central block acquisition and stronger crude oil estimates at several producing wells.
- • Value of reserves (before tax): The estimated future value of reserves currently in production rose 35% year-on-year to US$107 million. The value of total proven reserves declined slightly, while proven and probable reserves also saw a modest dip.
- • Value of reserves (after tax): After-tax estimates showed solid gains for producing reserves, up 34% from 2024, while overall proven and proven-plus-probable reserves recorded modest improvements.
- • Long-term outlook: The company’s reserves are expected to last more than 13 years based on proven reserves alone, and more than 23 years when probable reserves are included, underscoring the longevity of its asset base.
Woodside appoints Liz Westcott as CEO, Managing Director
March 19, 2026 (WO) –
Woodside Energy has appointed Liz Westcott as Chief Executive Officer and Managing Director, following her tenure as acting CEO since December 2025.
Westcott joined Woodside in 2023 and most recently served as Executive Vice President and Chief Operating Officer for Australian operations, where she led major projects including the Scarborough Energy Project and the Bass Strait operator transition.
She brings more than 30 years of experience in the global energy sector, including prior roles as Chief Operating Officer at EnergyAustralia and a 25-year career with ExxonMobil across Australia, the UK and Italy.
Woodside Chair Richard Goyder said the appointment followed a comprehensive selection process and reflected the company’s internal leadership depth.“I am delighted with the appointment of Liz as Woodside’s next CEO and Managing Director. Liz’s proven track record of outstanding strategic leadership and disciplined delivery distinguished her as the Board’s top candidate for this role.”
Westcott said her focus will be on operational performance and delivering long-term value as the company advances its global portfolio.“My focus as CEO is on sustainable value creation for Woodside shareholders, operational excellence and disciplined execution of our growth projects,” she said.
“I look forward to working closely with the Board and Woodside’s leadership team to continue building a leading global energy company.”
The leadership transition comes as Woodside continues to progress key upstream and LNG developments, positioning the company to meet growing global energy demand.
Woodside names permanent CEO after O’Neill’s departure for BP
Australian energy major had been hoping to find new leader by end of first quarter
Robert Stewart North America Energy Correspondent Baton Rouge, 17 March 2026
Woodside Energy named Liz Westcott as its permanent chief executive and managing director, three months after receiving the interim title following Meg O’Neill’s departure for BP.
Energy services report decline in business in Q1 2026
Energy Chamber of Trinidad and Tobago
2026, 03/19
The latest Energy Services Sector Survey (ESSS), conducted by the Energy Chamber, reveals a decline in both the volume and value of business during the first quarter of 2026.
60 per cent of respondents reported the value of their business was lower than normal. 56 per cent indicated that their volume of business fell below typical levels. Data suggests the energy services and contracting community executed fewer projects, with many firms earning less for services provided.
Among companies reporting lower-than-normal activity, 72 per cent identified decreased demand for their services, 66 per cent reported fewer business opportunities, 38 per cent reported a loss of contracts and 11 per cent were forced to provide fewer services.
Conversely, the small segment of companies that experienced an uptick in activity attributed their growth to increased demand, introduction of new services and the acquisition of additional contracts.
Outlook for the second quarter remains cautious. 50 per cent of respondents anticipate a lower volume of business in Q2 2026, and 54 per cent expect the value of their business to continue to decline. The current experience of these companies highlights a critical need for further upstream investment.
Typically, a downturn in upstream activity directly constricts opportunities for the energy services sector.
Lower investment levels result in fewer greenfield projects, which are generally higher in value. At present, the industry notes a shift toward brownfield projects, primarily maintenance-based work, which tends to carry a lower financial value.
While several national projects currently in the pipeline will provide some relief, strengthening this project queue is essential for the long-term health of the services sector and the broader supply chain.
Shell’s Manatee and Aphrodite are already being developed, along with the EOG/bpTT Coconut project, which is in execution with the platform being constructed in the TOFCO yard.
bpTT’s fourth subsea project, Ginger, remains on schedule to deliver first gas in 2027.
The largest project in execution at the moment is Shell Manatee, set to come onstream at the end of 2027. By all reports, the execution of these major projects is proceeding as planned.
Projects further down the pipeline seeking a final investment decision (FID), such as the Woodside/bp Calypso deepwater gas project, bpTT’s Frangipani and Kanikonna projects, Perenco’s Onyx field, and another EOG/bp joint venture, Beryl, will likely improve the service sector’s perception when they enter execution phase.
Exxon’s development of the new block UD1 and indications that CNOOC will sign two new PSCs will certainly add excitement as these projects develop.
The Minister of Energy Dr. Roodal Moonilal initiated the creation of an Energy Accelerator Hub, which aims to bring together key decision-makers and regulators involved in the approval process.
This will essentially shorten the delivery time for projects, bringing them onstream faster, while ensuring work becomes available to contractors during the construction phase, thus increasing local content contribution. This should also bring relief to the contractor community as more projects become viable. The Energy Chamber fully supports this initiative.
The ESSS is a quarterly assessment tool mapping the performance and optimism of energy service contractors. By providing data on business confidence and the operational phenomena impacting the industry, the survey offers a clear picture of the sector’s current health and future prospects.
Marajh appointed interim CEO of Energy Chamber
2026, 03/21
Dr Priya Marajh has been selected as the interim chief executive officer of the Energy Chamber of T&T, stepping into the role as the organisation begins a leadership transition following the departure of long-serving president and CEO Dr Thackwray Driver.
Marajh confirmed her appointment yesterday, indicating she will support the board during the transition period while a permanent CEO is recruited.
“I’m happy to step into that role to assist the board in the transition,” she said, adding that she would also welcome the opportunity to take on the position on a permanent basis if selected.
“I am really happy for that vote of confidence, and I would welcome that opportunity as well if it should present itself.”
The recruitment process for a substantive CEO is expected to take approximately three months, though Marajh noted the timeline is tied to the completion of that process rather than a fixed interim term. Her appointment comes as Dr Driver prepares to demit office on March 31, bringing to a close more than two decades at the helm of the Chamber.
In a statement, the board expressed appreciation for his tenure, noting his contribution to both the organisation and the wider energy sector.
It “extends its sincere thanks to Dr Driver for his 24 years of service to the organisation and the wider energy sector” and confirmed that a formal transition plan is underway.
Driver has led the Chamber since 2002, a period marked by significant shifts in T&T’s energy landscape, including fluctuations in global energy markets and evolving domestic production challenges.
Marajh brings extensive industry experience to the interim role. She currently serves as a board director at Touchstone Exploration Inc and TOSL Engineering Ltd.
She also previously held the position of vice president of advocacy and member engagement at the Energy Chamber, where she was responsible for stakeholder relations and policy engagement. Her familiarity with the organisation and its membership base is expected to support continuity during the transition.
“I’ve been here for a really long time,” she noted, signalling her longstanding involvement with the Chamber’s work.
The Energy Chamber represents companies operating across the oil, gas, and energy services sectors, and plays a key role in policy advocacy, industry coordination, and engagement with the Government. Marajh indicated that maintaining value for members will remain a priority during the transition, as the organisation navigates leadership change and ongoing industry challenges.
Energy ministers meet Halliburton and Noble
2026, 03/11
Executives from the Ministry of Energy, Ayasha Nickie, Director, Downstream Petroleum Management Division; Marc Rudder, Chief Technical Officer; Ava Mahabir-Dass, Permanent Secretary (Ag.); Minister Ernesto Kesar, Dr. Roodal Moonilal, Minister of Energy and Karinsa Tulsie, Permanent Secretary (Ag.); met industry staff from Halliburton Trinidad Ltd. and Nobel Corporation at the Ministry.
Representing Halliburton were President and Chief Executive Officer Jeff Miller, Senior Vice President Latin America Francisco Tarazona, Vice President Caribbean Franco Delano, Operations Manager Halliburton Trinidad and Suriname Santiago Zambrano and Business Development Manager Halliburton Caribbean Shivanand Pancham.
Chief Executive Officer Robert Eifler represented Noble Corporation.
Both companies provided updates on activities across Latin America and the Region and Trinidad and Tobago where Halliburton worked for over seventy years.
Discussions addressed collaboration between the Government and energy service companies operating in the country, including opportunities for further engagement focused on the upstream sector and on the role of service companies in the energy industry.
Minister Moonilal and Minister Kesar stated that the Government will maintain an investment environment for companies operating in the sector and continue. engagement with industry stakeholders .
EOG Resources, Inc. Presents at 47th Annual Raymond James Institutional Investor Conference
Transcript
March 3, 2026
Well, thank you. I appreciate the introduction there. And as you said, my name is Jeff Leitzell. I’m the Executive Vice President and Chief Operating Officer of EOG. And we’re going to run you through a little bit about the company here.
We’ve got our earnings presentation. Obviously, we just had earnings here recently. A lot of great information on the company, talk a little bit about our plan and talk about our portfolio and some of the information associated with it.
So this first slide here really, this is our value proposition as a company. I mean our main focus is obviously sustainable value creation through the cycles.
We don’t chase commodity price. We want to make sure that we’ve got investments that have great returns through the cycle through multiple commodity prices. So it really has kind of these 4 pillars, I would say, our main focuses.
The first one is capital discipline. We want to make sure that we’re investing in the right project at the right time, and we’re maximizing returns. We want to make sure that we maintain our pristine balance sheet, that we keep that healthy and that we’re generating plenty of additional cash flow to where we can return that to shareholders.
And you can see up there, we actually have a marker right now that’s a minimum return to shareholders of 70% of our free cash flow. But you’ll see throughout the presentation for the last 2 years, we’ve been right around 100%. And in this current environment, we plan on probably being pretty close to that 100% moving forward.
Second is operational excellence. It’s basically doing what we say, making sure that we’re executing, that we’re improving the portfolio in each one of our assets day in and day out, that we have operational excellence. We continue to innovate. And then on top of that, what makes EOG unique is to make sure that we’re exploring, looking for the next organic opportunity for the company to continue to improve the overall portfolio.
Next, you can see sustainability. Obviously, we want to practice extremely safe operations. We want to be good stewards to the environment and obviously, great partners with our community.
And then last but not least is culture. You’ll hear culture a lot throughout this talk just because it’s really what makes the company special. It’s more decentralized culture. We’re very non-bureaucratic. There’s not a whole lot of red tape in it. People can get things done very, very quickly.
All of our people are business people first. What’s very amazing about EOG is they’re interdisciplinary. You might talk to a geologist and you might think they’re an engineer or vice versa. And each one of them on their projects, they understand the decisions they make, not only how it affects just their personal asset, they understand how it flows through to the income statement, really affects the business because each one of them are business people first.
And you’ll see a lot of that throughout the slides. This is why we think EOG is an extremely compelling investment. It’s like a tear sheet that we put in there to really kind of talk through EOG as a whole. So you can see up in the top left, the first one, we obviously have an extremely high-return inventory, both domestic and international, and it’s got extreme long duration.
So the way we look at inventories, we’ve got about 12 billion barrels of total resource plus. And if you take that and you look at the economics of it at $55 oil, it’s all greater than 100% direct after-tax rate of return. So extremely strong, strong portfolio. We obviously have a ton of experience in this.
We’ve been operating unconventional for over 25 years, and we can really leverage that experience, both domestically in our operations and exploration and the same thing with international. We’ll talk a little bit about international as we move, but we see a lot of opportunity on conventional because there really hasn’t been a whole lot of exploitation of unconventional on the international front.
And then obviously, from an operations standpoint, we’re a low-cost efficient operator. We really focus on improving operationally every single year and primarily through what I would say is sustainable efficiency gains, efficiency gains that can basically stand the test of time with the asset and be there for improvement the whole time.
We also look for places that we can take control of the supply chain. So whether it’s sand supply, whether it’s water logistics, it could be cement services. We actually have EOG cement services. We have EOG motor programs, EOG Mud, anywhere that we can take control of the supply chain side of it, we feel like there’s added efficiency and quite a bit of cost reduction. And you can see the performance we had in ’25.
Now moving down to the bottom. Obviously, we want to make sure we’ve got durable cash flow. And you can see over the last 3 years, we’ve generated $15 billion in free cash flow. And you can see how that affects, obviously, the return on capital employed of the company, averaging 24% over the last 3 years.
We’re very, very focused on a sustainable regular dividend. We’ll talk about it a little bit more in depth on another slide, but current dividend right now is $2.2 billion. That’s $4.08 a share on an annual basis. And as I talked about before there, returning 100% of free cash flow back to shareholders.
And then last but not least, just make sure that we’re maintaining an industry-leading pristine balance sheet. And you can see currently right now, we’re at 0.4x net debt to EBITDA. So extremely strong balance sheet, and we’ll kind of walk through what we’re focused on with the balance sheet here in a little bit.
For 2025, I mean, really, the summary of this slide is in 2025, we basically met or exceeded all of our operational or financial goals. You can see impressive financial results on the left-hand side, $5.5 billion of adjusted income, outstanding return on capital employed there, and then it flows over, obviously, to the free cash flow with $4.7 billion of free cash flow and 100% of that return to shareholders. And really, what I’d point you to is down on the bottom right, strengthening the portfolio.
2025, I would say, was truly a transformational year for EOG. We really had 3 things take place. We had the acquisition of Encino, as you guys know, for $5.6 billion that expanded our Utica footprint by 1.1 million acres, and it immediately moved that play to a foundational play where it’s free cash flow positive. So we’re going to have quite a bit of additional activity there.
We were awarded the first ever onshore concession in the UAE for unconventional oil. This is an area that has penetration points and a lot of data. So really, we just got to get in and operationally execute. And then we also executed on a JV partnership with BAPCO in Bahrain on an onshore unconventional gas play that’s very similar, plenty of penetration points and data, a very exciting opportunity that we think we can bring our technology and knowledge to and really extract a lot of value out of.
Taking a look quickly at our plan. So how we look at plans is, as I talked about in the first slide, we really start with capital discipline. We want to look and see where every one of our assets is in the portfolio in the life cycle and make sure they’re improving and they’re generating the target returns that we’re looking for.
Then after that, we’ll take the macro environment and considerations and make sure that the market needs the commodity based off where we’re at in the cycle. And what we ended up doing with this plan is based off current environment right now, we’re actually holding volumes flat to Q4 of 2025. And what that rolls up to is, as you can see here, $6.5 billion capital budget. It’s 5% increase year-over-year in oil. And what that takes into account is obviously Encino acquisition, which closed in August of last year. So we have 5 months in last year of Encino and then a full year this year.
And total volume-wise, that’s 13% year-over-year on a BOE basis. There’s substantial free cash flow generation, as you can see with that. And some of the plan highlights, I’d say, is extremely capital-efficient plan. Our breakevens on it, if you look for the CapEx is about $40 WTI. If you take the CapEx and regular dividend into consideration, it’s $50. And really, what we’re doing with this year’s program is the first thing is we’re balancing the activity between our 3 foundational oil assets, which is the Delaware Basin, Eagle Ford and the Utica now, our new foundational asset.
And then we have some additional investment to continue to grow our very prolific Dorado gas play down in South Texas. And then we have additional investment, obviously, in our international assets, which would be Trinidad and our new entries into the GCC.
We did update our 3-year scenario. So we came out with this 3 years ago. And obviously, it’s been 3 years. And then also with the Encino acquisition, we wanted to kind of dust this off for you. This is not guidance by any means. This is not our plan. This just kind of gives you an idea of the resiliency of the cash flow of the company moving forward. You can see over on the left-hand side, outstanding ROCE and free cash flow, cash flow growth and cash — free cash flow growth at varying commodity prices there.
And when you look at it, basically, this is going to be kind of a low single-digit oil growth, mid-single-digit BOE growth. It’s got a reinvestment rate of less than 60%, and we have no improvement in the company here.
There’s no improvement in overall cost, efficiency, production whatsoever. It’s basically maintaining the status quo. And you can see we’ve got a couple of different scenarios there at $55 and $70, but I really want to turn your attention to the right-hand side where you see the last 3 years at the actual price was about $15 billion.
Well, with this scenario, if you move forward that exact same price for the next 3 years, we have about a 20% increase in free cash flow to $18 million. So very substantial and continued growth of free cash flow for the company. All right. This is a quick look at our multi-basin portfolio, which we think is a huge benefit. You’ll hear me say this multiple times, but we have 7 different divisions domestically, multiple divisions internationally.
And really, what each one is, is they’re a separate business unit. So each one is focused on their operations of their assets, continuing to improve that. They’re focused. Each one has an exploration team within their division. So they are strategically exploring for a next organic opportunity within their asset there.
And what that really does is they’re almost like separate laboratories. So as one of them learn something new, they don’t just keep it in-house. They go ahead and share it with each one of the other divisions. So really, you have 7 different learning areas here domestically that really accelerates our knowledge, and we’re able to share that and move along each asset that much quicker.
So especially when we find a new asset or an emerging division or an exploration play, we’re able to take all of our best practices from all of these divisions across and apply it directly there. So looking at the portfolio, we really started as an unconventional operator in the Barnett in the gas play. From there, we kind of moved up to the Williston Basin and the Bakken and had a large position there and have been active there ever since. Next, we discovered the Eagle Ford down in South Texas. We were able to and very lucky to acquire the majority of the acreage to the core in the Eagle Ford, which has been a very prolific asset for us. And then moving to the Delaware and the Powder River Basin, we had nice acreage holds there. But in 2016, we went ahead and we acquired Yates and greatly increased our overall footprint in both of those basins and really pushed them forward.
And then the last 2 domestic that I’ll touch on here is obviously our Utica play, which I’ve talked about with the Encino acquisition. We are the largest producer of oil and have the largest footprint up in Ohio, and we are focused on the volatile oil window up there. And then we have our South Texas Dorado gas play, 21 Tcf down there, very close to the market center. We feel like it’s going to be a huge value to the company as we move forward from a gas aspect.
And then over on the right-hand side, we have our international assets, Trinidad Tobago, shallow offshore gas play. We’ve been there for over 30 years, great returns. We’re able to sell to premium markets there in Trinidad, Tobago. And then our 2 new entries, we’ve got Bahrain, which — that’s the onshore gas unconventional asset and the UAE, which that’s the onshore oil unconventional asset, 900,000 acres.
And obviously, these 2 are very topical at this point. We started exploration in the fourth quarter of last year, planning on results, Q2. Obviously, with everything happening in the events over there, I’m happy to say we had procedures and plans in place. Activity and everything is secure, all of our people are safe, and we’re just monitoring the situation at this point.
But excited about these assets once, obviously, things calm down over there in the Middle East. Moving on. Really on this slide, I just want to hit. We’ve talked about the multi-basin portfolio of long-duration, high-return inventory. Really, what I want to hit on here is just how good the returns on that inventory is. So on the chart on the right there, you can see bottom cycle, what we call bottom cycle pricing, $45 oil and $2.50 gas.
Our full portfolio averages around 55% or greater direct after-tax rate of return. And you can see what happens with that with commodity prices, just continues to improve exponentially as you improve the commodity price. And that’s what we like to do with our portfolios. We like to pressure test it against very severe environments just because we know it’s a very cyclic environment. We want something that’s able to, like we said, generate solid returns through those cycles.
When you take that and you roll that up from a returns aspect from a company standpoint, return on capital employed, outstanding over the last 5 years. You can see EOG here in the dark blue versus our peer average, averaging close to 20%, if not higher for EOG and outpacing the overall peer average. So great results from an ROCE basis from a company. And then you look at that and you roll it forward into our cash flow priorities as a company. So first and foremost, our #1 cash flow priority is our regular dividend, as I talked about, $2.2 billion or $4.08 a share. We really think that a sustainable growing dividend is truly the hallmark and foundation of a really great company.
Obviously, maintaining the pristine balance sheet, as we talked about. Balance sheet is in great shape right now, but we do have a marker out there, and we have that at bottom cycle pricing that we want to maintain less than 1x total debt to EBITDA, which is obviously an extremely healthy balance sheet. We obviously have the capital investment in the company, both through our activity and opportunistic entries and bolt-ons and other marketing opportunities that we can have for the company.
And then last but not least, we obviously have cash returns to shareholders outside of the regular dividend, which we’ll talk about a little bit here in a second. We have done special dividends in the past, but primarily here most recently in the last couple of years, we’ve really focused on buybacks. And I think you can plan on in the current environment, we’ll focus primarily on buybacks moving forward and lean in that direction.
So for the dividend, this just really shows the history of it. We’ve got 28 years of sustainable and growing dividend, where we’ve never cut or suspended it in that whole time period. So pretty impressive growth since 1999. And you can see there really a lot of growth in the last 5 years from a dividend aspect, where we jumped up quite a bit in ’22 after the pandemic and then continue to grow it up to where we’re at, at the $4.08. And I think this just shows you the confidence that we have in the portfolio and really the resiliency that we have. We take for this dividend too, every single year before we increase it, we run it through numerous different scenarios, both market scenarios and portfolio development scenarios to make sure that it is sustainable. And that even if we do go into a downturn that there’s no reason that we have to suspend or cut this dividend. So it is pressure tested, and it is very, very resilient.
And then we’ve talked about the cash flow returns to shareholders. I mean you can see what we’ve done over the last 3 years here as a company, significant returns there. You can see the regular dividend. We did do some special dividends back in 2023. But like I said, we’ve been focused more on the share repurchases, $6.7 billion in the last 3 years, and that’s reducing our outstanding share count by about 10%. So substantial move there as far as buying back shares. And then you can see the breakdown down in the bottom, as I talked about, year-over-year, how that’s been distributed between regular dividend, special dividend and share buyback. And then on the right-hand side, you can just see from an actual cash returns as a percentage of market cap, how we rank against the peers, obviously, being a peer leader there in cash returns.
Our pristine balance sheet. I’m proud to say we think we have one of the industry’s best balance sheets right now. Like I said, it’s 0.4x net debt to EBITDA. You can see peer-leading from that aspect. And I think really the point that I’d like to get across on this slide is the balance sheet is in great shape.
We really don’t need to put a lot of cash in this current environment on the balance sheet. We’ve got very robust cash flows. And I think our primary focus moving forward is to be opportunistic for the company wherever we may, whether that’s opportunistic bolt-ons, marketing agreements, other opportunities for the company and then obviously, additional cash returns to shareholders to really balance out and be able to support that 100% return of cash to shareholders as we’ve talked about. And you can see the last couple of years, we’ve been right around that marker.
Okay. So I’ll get into the assets here for a second. I mean this is really where the rubber meets the road, and this is really where our culture comes into play. As I said, that decentralized culture, the sharing, the innovative qualities being business people first. As I said, each one of these divisions is focused on their own asset.
They’ve got boots on the ground. They can get to the asset every single day. So you really help — that helps out see the improvement in the asset just from an efficiency standpoint and pushing forward innovation and then also from an overall exploration aspect. Instead of just having one exploration team and headquarters, each one of our divisions has an exploration team that is focused on organically growing.
So here, first, starting in the Delaware, we’ve made outstanding progress in the Delaware. And I know the Delaware has been very, very topical for us. It’s been in the news for productivity reduction year-over-year. And what I’d say is that was completely strategic, and it was by plan and by design. So what we’ve done is, you can see here, we’ve increased our lateral lengths like much of industry a lot over the last 3 years, 30%.
Well, what that equates to is we’ve really lowered the overall cost basis there in the Delaware. The well costs are down 20%, reducing cash costs. And what that does is it’s given us the opportunity to where there were certain targets that didn’t meet our very stringent bottom cycle hurdle rate, but now it does. And it goes up above that, and it’s very additive to it. Not only that, what it does is it balances out our actual payout and improves the payout of it. It’s improving the overall margins of it. And really, we’re starting to look at the value and an NPV per acre out there and make sure we’re extracting the maximum amount of value and improving our recovery per acre.
And where that puts us now is we’re well over 20 unique targets across all of our Delaware acreage with just outstanding improvement there. And as far as the improvement, you can see here 4% improvement year-over-year in capital efficiency on that. And we feel very, very confident that now that we’ve set in this new actual development program, well productivity in the Permian will be consistent moving forward with this development program unless we have to have another step change where we’re able to add more value because of cost reduction, which we will keep you guys apprised and abreast of that. But as far as our inventory, we did come out and we talked about it on the call that we can go at our current pace right now in the Delaware of over 300 wells, maintain the same economics, the same free cash flow and success for 10 years plus with the inventory we have out there. So very, very robust. And obviously, with adding in these additional targets, that just helps the inventory there in the Delaware.
This is just quick. I’ll breeze over this. This is Rystad data over the last 3 years. You can see how we kind of stack up operationally and from an efficiency aspect and then how that rolls through versus the peers from a breakeven. So a leader as we’ve been there in the Permian. Moving up to our Utica asset. Obviously, this is one that’s a premier asset for us now, a new foundational one. We had the Encino acquisition last year, as we talked about. When we did announce that acquisition, we had put a target out there of about $150 million of synergies in the first year. And I’m happy to say we’ve reached that target early in about 5 or 6 months. So the majority of that, I would say, is obviously just in the well cost side and the efficiency side. You can see where Encino was at $750 a foot. EOG was at $650 or below a foot. And combined now after 6 months into the actual acquisition, we’re pro forma under $600 a foot there. So just outstanding results across the board.You see on the bottom, just some of the efficiencies from an overall operational aspect that we’ve been able to enjoy through the acquisition and improving the overall asset over the last 3 years. And this has really become one of those foundational assets for us with a lot, a lot of running room. You’re going to see we’re shifting, almost doubling the activity there. We’ll be running 3 rigs and 3 frac fleets. And this will really be one of the big growth arms for the company as we move forward. So extremely excited about the Utica, and I think we still have a lot more upside even just with the acquisition and synergies as we move forward.
Next, we’ve got our Eagle Ford play. This is just one of those amazing assets that just keeps on giving after 15-plus years of development, where we’ve moved from — the majority of our development was in the East where it’s much more prolific, I would say, rock to the west through operational advancements through technology, through longer laterals, 15-plus years later, we’re actually getting better economic results now than we did back at the beginning of the play. And you can see still improving our overall efficiencies, our capital efficiency there. We’ve got great operational performance even after the 15-plus years. So we continue to improve there. And you can see how that flows through to the breakeven price versus our peers there in the Eagle Ford being a leader and plan on continuing being a leader there.
And then moving down to South Texas to our Dorado dry gas play in Webb County. This is a 21 Tcf resource. That is 21 Tcf, so it’s massive. It’s very, very prolific wells. We keep them choke back. We bring them on over 20 million a day. We’ve just made outstanding progress down there. Like a lot of the other plays that I showed you in the portfolio, you can see we’ve rapidly dropped our costs there. We’ve optimized our operational efficiencies. And on top of that, we’ve actually just last year alone, through unique designs within our wellbore and our completions, we increased the overall productivity per foot, which is a recovery basis in this play 13%. So continuing to improve it there, and we still got a lot of upside. It’s very early in its days.
We exited last year at 750 million a day, and the plan for 2026 is to exit at 1 Bcf a day. And it is, we think, the lowest cost gas in the U.S.We’ve got it currently with a breakeven price per Mcf of $1.40. And we’re so excited in the play. We actually have installed a 100-mile 36-inch pipeline that goes from the center of the field, completely EOG-owned over to Agua Dulce. It has a capacity of 1 Bcf currently, and it’s easily expandable up to 1.5-plus Bcf just by adding on some booster compression along the line for minimum capital, and that’s completely controlled by EOG. So that allows us to get access over into the market center on the Gulf Coast and also take advantage of our LNG contracts, which we’ll be able to talk about here in a minute.
So how does that all roll up? I mean, not just even in Dorado, but from a full portfolio’s perspective, we’re looking at to make sure we’ve got an extremely diverse, flexible marketing strategy, and we’re really not worried anymore about flow assurance. It’s not about getting the molecules to market. It’s about having numerous markets to be able to select it and maximize our overall netbacks of each one of the molecules.
And you can see that on this price realization chart versus our peers. And we’ve always prided ourselves of outpacing what the average is to our peers in the market. And that is a huge priority to us to continue to make sure that we optimize our markets and that we’re maximizing our netbacks on every single molecule.The great thing about this is it really has become a big part of technology, and we have control rooms in each one of our assets to where we’re able to control where each molecule goes, move it from market to market as those markets move and make sure, like I said, we are maximizing that netback.And then quickly, these are the gas sales agreements that we have over on the coast from an LNG aspect.
What I’d say about these is they’re not tied to any specific play by any means. We can move any kind of gas to them. But you can see over on the right-hand side, we currently right now of that 420,000 MMBtu wedge, we’re producing 280,000 MMBtu, and that is linked to either JKM or Henry Hub on a monthly basis. We’re able to elect that. So you can obviously imagine in recent years, we’ve been obviously electing to JKM. So that was really a sweetheart deal. The additional 140,000 of that agreement comes on here later this year, so we’ll be at full capacity there. And then we’re also — the other stacked bar on top of that, we’re currently producing 300,000 MMBtu that’s directly linked to Henry Hub there on the offshore.And then as we move into 2027, we have a Vitol agreement that’s going to be coming online for 140,000 MMBtu, which is Brent-linked to take some of the volatility out of gas price. And then there’s additional 40,000 that’s either Brent-linked or linked to U.S. Gulf Coast.
And then moving on to the last couple of slides here. As we talked about, sustainability, it’s really core to our DNA. What I’d say about this is we’ve had a lot of success over the last handful of years. We did have targets set in 2020 with a 5-year goal. We achieved that goal 2 years early. So we did come out and set new targets. You can see on the left-hand side. Obviously, reduce GHG emission intensity, maintain near zero methane emissions there and then obviously maintain our World Bank zero routine flaring across the company to make sure we’re good stewards. And you can see our strategy on the right-hand side.
The big thing I’ll point out there and the easiest thing is reduce. Don’t flare, make sure you get engineering controls in, engineer out any kind of venting or any kind of emissions from that aspect. And how we look at this is it’s not only just being good stewards of the environment, but each one of these molecules, I mean, it’s revenue. Why would we not want to capture that and go ahead and put it downstream to markets because a lot of the projects from an engineering aspect that you’re able to apply here actually have returns to it. So this is a big piece of who we are as a company.
And then lastly, as we finish up here, this is the last slide. As I said, everything kind of really all rolls up to the culture of the company. It really has to do with, as I said, each one of our people, they’re business people first. They understand how they’re affecting the business and how each decision is affecting the business. They’re focused on the actual financials, the returns. They really utilize our decentralized culture, which is unique within the industry.
We’re one of the only companies that actually has divisions in each one of our assets. So we’re close and proximal to it, and we can be hands on. Every one of our people is multidisciplinary. We really promote them, not just focusing on their discipline, but understanding the full cycle of jobs and technology we have in our industry, making sure they continue to innovate and that they’re extremely responsible from a sustainability aspect.
So with that, go ahead and hand it back over to John to see if we have any questions.
Jeffrey Leitzell
Executive VP & COO
We prefer to invest in returns. This is — that’s what I would say. So we’re not really — we don’t lean one way or the other. That’s why we’ve got very stringent markers where at bottom cycle pricing, $45 oil, $2.50 gas, the minimum return that we look for is 30% direct after-tax rate of return at that bottom cycle pricing.
So no matter if you’re gas, no matter if you’re oil, we’re pretty agnostic to it. We’re just about returns, and that’s how we look at it. Obviously, as you look at where we stand right now with oil and gas, I mean, oil, we’re obviously getting a little bit of a bump here with the unfortunate activities over in the Middle East.
We think it’s going to be probably short-lived and really what we need to do is we need to see how spare capacity flows through OPEC+ and where that actually sits. And once that actually flows through the market at the end of the year, and our personal view is we think that demand is going to be very strong and the spare capacity is probably not quite as high as what is thought of out there.
So we think we’ll have pretty robust pricing as we move into the end of the year and into 2027.And then on natural gas, obviously, we’re pretty positive on natural gas for the foreseeable future. With all the additional demand, we see about a 3% to 5% compounded annual growth rate in demand over the next handful of years to 2030. And obviously, with all the LNG coming on, we think that there’s going to be quite a bit of a support there, both domestically and international for the molecules.