WTI (Feb) $73.41 -67c, Brent (Mar) $78.56 -54c, Diff -$5.15 +13c
USNG (Feb) $2.52 -18c, UKNG (Feb) 68.5p -2.5p, TTF (Feb) €27.35 -€0.955

Oil price

I can’t add much any more to the existing furore, today oil is up well over a dollar as experts are reading more into the agitation in the Middle East, I can’t add anything to what I have already said but the key variable is Iran, if they are upping the stakes, and I think that they are then things will get worse. 

PetroTal Corp

PetroTal has announced its fully funded 2024 budget.  All amounts are in US dollars unless otherwise stated.

Key 2024 Budget and drilling highlights

• Average 2024 production and sales target of 17,000 barrels of oil per day, expected to grow 20% year on year.  The production forecast assumes a dry season as severe as in 2023 with a quarterly profile of (Q1 18,500 bopd, Q2 19,000 bopd, Q3 13,000 bopd, Q4 17,500 bopd);
• Investing $107 million at the Bretana oilfield, including three new oil wells, alongside infrastructure growth in line with the field’s development plan with flexibility for reduction at lower Brent levels;
• 2024 funds flow forecast to reach $160 million and free funds flow (after capex but prior to net working capital cash adjustments) of $25 million using the December 14, 2023 Brent oil strip ($77/bbl flat in 2024) with an estimated incremental $10 million of free funds flow for every $3/bbl change in Brent oil price;
• Initiating a two year seismic program south of our producing Bretana oilfield in Block 95, aiming to validate our technical interpretation of oil migration towards the southern structural leads;
• Maintaining a return of capital program consisting of quarterly dividends at US$0.015/share and share buybacks of approximately $1.0 million/month in accordance with the Company’s return of capital policy;
• Commercializing two new Bretana oil sales routes, via Yurimaguas to the port of Bayovar and also through the OCP in Ecuador; each expected to deliver 2,000 bopd commencing around July and October 2024, respectively; and,
• Well 16H is on stream and has averaged around 7,500 bopd in the first week, estimated to payback by the end of Q1 2024.  Well 17H commenced drilling on January 12, 2024 and is expected to be completed by the end of March 2024. 

Notes:

1. Production guidance range is 16,500 to 17,500 bopd and assumes matching production and sales profiles.
2. Royalties include the 2.5% social trust allocations.
3. Erosion control expense refers to erosion amounts expensed related to community support totaling $23 million.  The other $7 million pertains to ongoing community support opex projects.
4. 2024 G&A includes community spending and non-cash equity compensation amounts totaling $8.4 million of the $30 million.
5. Adjusted EBITDA – see disclaimers and non Gaap financial metrics.
6. Finance expense includes factoring and other finance related items.
7. Taxes per table above indicate 2024 accrued taxes.  Taxes accrued in 2024 that will be cash paid in 2025 are approximately $25 million.
8. Capex includes approximately $14 million of capitalized erosion control costs.
9. Estimated net working capital movements are approximately $30 million in cash savings from the payment of tax in 2025 offset by prepaid erosion costs of approximately $15 million and other smaller payable items.
10. Dividends are assumed at the base dividend level of US$0.015/share and buybacks are assumed at $1.0 million per month.
11. Derivative true up payments refer to expected payments from Petroperu that reflect the difference in value from when the Company’s oil entered the ONP to when it is exported at Bayovar.  The assumed export at Bayovar represents approximately 500,000 barrels already in the ONP, is targeted for Q1 2024, and the expected true up payment is based on using December 14, 2023 Brent oil strip pricing.
12. “Adjusted EBITDA”, “Free Funds Flow” and “Net Operating Income” do not have standardized meanings under IFRS, See “Reader Advisories – Specified Financial Measures”.

Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented:
“PetroTal’s fully funded 2024 budget has many exciting components.  Last year we were focused on repaying debt and starting to return capital, with both items being successfully achieved in early 2023.  In 2024, the Company will continue to develop Bretana, aiming to deliver 20% average daily production growth, while maintaining our base return of capital program to offer around 12% in total yield at current prices.  We will also continue to invest in critical safety infrastructure to protect the river banks near our asset from future erosion threats. 

Our exploration program will further advance our Block 95 and 107 expansion areas with the kickoff of a seismic program in Block 95 aimed at proving up the technical assumption of oil migration to prospective leads on trend to the south of the Bretana Field.

I would like to wish everyone a productive 2024, and thank all our shareholders, employees and wider stakeholders for their continued support in 2023.  As we look forward to 2024, we are confident that the Company is well positioned to meet the opportunities and challenges head on, with well 16H setting the stage for a great year.”

PetroTal are in a very strong position as it delivers guidance for this year to the market. Most importantly production is guided towards 17/- b/d over the whole year, and taking into account the dry season, which would be a 20% rise y/y.  

Key is obviously the Bretana oilfield where PTAL are investing $107m which includes three new oil wells which makes for the infrastructure planned at varying Brent levels possibly below today’s, this includes $7m carried forward from last year.

Also Bretana is moving south towards Block 95 where a two year seismic programme is getting under way to follow up ‘southern structural leads’. Indeed the company estimates that there could be ‘several commercial fields in the block some potentially as large as Bretana’. 

The capital programme totals $135m, itself a 13% increase which also incudes permitting as the company advances partnership discussions on the block. Finally the company need to spend $14m on its erosion mitigation control programme. 

The final piece of good news in a busy document, is with regard to shareholder return which is what they started last year after paying down the company’s debt. Base dividends of $0.015 per share are expected with top-ups along the way, in line with policy as well as a buyback programme worth some $1m per month. The company suggest ‘total estimated returns from the Company’s 2024 dividend and buyback plan represent 12%, prior to any additional liquidity sweep enhancements, based on a market capitalization of approximately $550 million’.

My Target Price for PetroTal remains at 150p, with best in sector managements, excellent and growing production with scope for massive increases the company gives growth at income and capital levels and should be a core holding in any energy portfolio.

Drilling and Facilities Program at Bretana

In 2024, having recently completed the 16H oil well, the Company will drill and complete three other oil wells (17H, 18H, and 19H) for an approximate cost of $50 million.  These new wells will be drilled in Q1, Q2, and Q3 2024 respectively, after which the Company will assess its options based on oil price and performance, and may continue drilling.

PetroTal’s 2024 facilities program will be approximately $57 million and deployed with a focus on current and future fluid handling and water handling infrastructure with many upgrades to accommodate field sustainability over the long term.  A summary of these key projects is provided below:

• Facility upgrades and reliability improvements – $27 million
• Water injection facilities and flowlines – $14 million
• Logistics & dock upgrades, carbon footprint reduction and studies – $12 million
• IT, digital and other

Production and Sales Guidance

• The Company is guiding 2024 average production and oil sales to 17,000 bopd, with a range of 16,500 to 17,500 bopd, representing an increase of approximately 20% over 2023 average production.  The forecast assumes a dry season as impactful as in 2023, which is expected to be partially mitigated by dedicated barge unloading at Manaus, and an upsized fleet capacity to 1.6 million barrels from late 2023.
• The Company will conduct pilot sales shipments to the OCP in Ecuador of 200,000 barrels of oil with permanent recurring sales of 2,000 bopd assumed to start in Q4 2024.
• A new sales route will commence through Yurimaguas to Bayovar starting in July 2024, assuming permanent and recurring sales of 2,000 bopd at that time.  This route will involve barging oil to Yurimaguas and trucking to the Bayovar port for export.
• No oil volumes are expected to be delivered through the Northern Peruvian Pipeline (“ONP”) in 2024 and the Company’s budget was contemplated using route to markets that are currently commercial and or in development/pilot phase.  Should the ONP become a viable option in 2024, PetroTal will consider the financial and technical risks of using the ONP as an additional dry season coverage option. 

Opex

Operating costs will consist of four parts:  lifting, transportation, erosion control, and community support totaling $93 million. 

• Lifting costs will be approximately $37 million, an increase of $8 million from 2023 due to inflation adjusted fixed contract services, increased chemical use and additional technical allocations from G&A;
• Transportation costs will be around $26 million in 2024 to include barging, trucking, and terminal transfer costs for both the Ecuadorian and Yurimaguas routes.
• Erosion control in opex is estimated to be $23 million ($3.70/bbl) and represents erosion control mitigation that benefits the nearby Bretana community.
• Excluding erosion and community support, total lifting and transportation costs are approximately $10.13/bbl, just slightly above the 2023 amount.

G&A

• G&A in 2024 will be approximately $30 million, roughly flat from 2023. This equates to $4.82/bbl using the 2024 budget midpoint production level. PetroTal’s G&A includes approximately $4.2 million in community support programs and $4.2 million in non-cash equity compensation for 2024.  The operating and G&A portion of community support will be reduced in future years as social trust funds are invested in community projects. Normalising these items out of the G&A results in a run rate of $3.47/bbl. 

Dividends and Share Buybacks

• The Company expects to continue its monthly share buyback program at approximately $1.0 million per month.  
• PetroTal plans to maintain its base quarterly dividend of US$0.015/share, along with dividend top up payments to be determined at the declaration dates, pursuant to the Company’s dividend policy.
• Total estimated returns from the Company’s 2024 dividend and buyback plan represent 12%, prior to any additional liquidity sweep enhancements, based on a market capitalization of approximately $550 million. 

Other Items

• 2024 taxes are expected to be $40 million on an accrued basis. The cash tax impact in 2024 is approximately $15 million, with the remainder of 2024’s accrued tax being paid in early 2025. 
• True up revenue of $5 million is estimated in 2024 using the December 14, 2023 Brent strip price for oil already in the ONP, but which hasn’t yet reached the Bayovar port for export.  Please refer to the Company’s financial statements for a detailed explanation on the mechanics of this arrangement.

Government and Community Amounts

• PetroTal estimates its royalties to the government will be approximately $28 million in 2024, an increase of almost $7 million over 2023 based on higher production volumes in 2024.
• In addition, approximately $9 million will be allocated to the Company’s 2.5% social fund for 2024 in addition to the $4.2 million of amounts estimated in G&A and approximately $7 million in opex.  This totals approximately $20 million for social funding in 2024.

Well 16H update

The Company is pleased to announce the first 7-day oil rate for well 16H of 7,500 bopd.  The well should be in line with or slightly above the Company‘s performance expectations.  Using a $42/bbl netback assumption, the well should payout after producing approximately 360,000 barrels of oil, estimated by the end of Q1 2024. 

Drilling Commencement of Well 17H

PetroTal also announces the drilling commencement of well 17H, the Company‘s 18th producing well, budgeted at $15.2 million with production expected by the end of Q1 2024.   

Rockhopper Exploration

Rockhopper notes the recent update published by Navitas Petroleum LP on Sea Lion development progress, which included an updated development plan to align with their static and dynamic reservoir models, resulting in the increase in certified resources in an updated NFB independent resource report conducted by Netherland Sewell & Associates on behalf of Navitas.

According to the 2024 NSAI Independent Report, the certified gross 2C resources in the overall NFB have increased from 712 MMbbls to 791 MMbbls. This represents an increase in resources of 11% in the overall NFB portfolio compared to the previous certified 2C resource, as published on 20 March 2023.

Navitas has identified suitable and available existing floating production storage and offloading vessels and is actively working with leading industry vendors to secure all long lead equipment, continuing to target Sea Lion phase 1 Final Investment Decision in 2024 and first oil at the end of 2026.

The Sea Lion Field Development Plan, which has been optimised utilising the selected FPSO specifications, still comprises 23 wells drilled in two phases with a 16% increase in gross 2C resources from 269 MMbbls to 312 MMbbls out of overall 791 MMbbls certified discovered resources in the NFB.  Against a background of continued industry cost inflation, gross capex required to first oil has been reduced from US$1.3 billion to US$1.2 billion with a capex of approximately US$8 per barrel and opex across life of field has been materially reduced to under US$17 per barrel, providing very robust economics and a lower risk project with a lower attractive break even under US$25 per barrel (compared to the US$27 previously reported).

The hydrocarbons will be produced through the redeployed FPSO, to provide an extended plateau for some eight years through a “Drill to Fill” optimization, with a peak production rate of up to 55,000 bbls/d.  The prolonged plateau increased total recovery and lowered cost per barrel means that the NPV10 remains within 5% of previously published numbers despite the initial lower plateau production rate.  Front end engineering design is ongoing evaluating potential for further accelerated production ramp up and increased capacity.

The FPSO has a disconnectable turret enabling redeployment to another NFB field and allowing a second, potentially larger vessel to replace it on Sea Lion with increased production capacity above 80,000 bbls/d.  The long term potential for the Basin could utilise up to 3 FPSOs with a total production of approximately 200,000 bbls/d.  This phased plan minimises CAPEX to first oil while providing flexibility for basin expansion and acceleration of production from fields beyond Sea Lion.

An updated FDP has been submitted to the Falkland Islands Government and it is anticipated that an updated Environmental Impact Assessment (“EIA”) will be submitted during Q1 2024.

Key Information

2C Contingent Resources (Development Pending) phase 1 and 2 development concept for the Sea Lion field:

• 23 wells
• Phased drilling
• 11 wells in phase 1, with 5 of them pre first oil
• 12 additional wells in phase 2 approximately 4 years post first oil
• Total barrels developed 312 MMbbls
• Peak production rate up to 55,000 barrels per day
• Total capex US$2.5bn
• Pre first oil capex US$1.2bn

Per barrel cost life of field (rounded):

Navitas published the 2024 NSAI Independent Report which is available on Navitas’ website, and contains the following resource estimates:

The Development Pending category of 2C 312 MMbbls is the phase 1 and 2 development outlined above. The Development Unclarified category of 479 MMbbls 2C are the additional gross resources contained on the NFB held by Navitas and Rockhopper, including Sea Lion and Isobel/Elaine, that could be developed under future phases but for which there is currently no published development plan.

Rockhopper holds a 35% working interest in Sea Lion and associated NFB licences and benefits from various loans from Navitas in relation to the development, which are detailed in previous announcements.

Corporate Update

The Company’s cash position as at 31 December 2023 was approximately $8 million which does not include a further $2.2 million receivable by the Company in January pursuant to the exercise of warrants.

Further to the announcement on 20 December 2023 regarding the monetisation of Ombrina Mare Arbitration Award, the Company continues to work through the requisite approvals and still expects completion by no later than 30 June 2024.

There is no comment here from RKH but it must be delighted the way that Navitas are progressing at Sea Lion. With use of an FPSO they are expecting Phase 1 FID in 2024 and first oil in 2026 which has a real ring about it given those of us who have followed it for so long. 

Costs are the really big plus in this announcement, gross capex expectations of $1.2bn are down as is the $8 pb number, on Opex which is under $17 pb and the figures are indeed ‘robust’ with break-even of under $25 at a rate of 55/- b/d going to 80/- b/d. 

All RKH have to do now is to sort out the Ombrina Mare case…

Eco (Atlantic) Oil & Gas

Eco has announced that its wholly owned subsidiary, Azinam Limited, has received final government approval for the farm out of its 6.25% Participating Interest in Block 3B/4B to Africa Oil Corp announced on 11 July 2023. The Company also provides an operational update on entering next license phase for Orinduik block and confirms, further to its announcement of 2 January 2024, that Dr Oliver Quinn has been appointed as a Non-Executive Director with immediate effect. 

Final Transaction Approval

The South Africa Department of Mineral Resources and Energy (“DMRE”) and the Petroleum Agency South Africa (“PASA”) have now provided Section 11 approval to assign and transfer a 6.25% Participating Interest in Block 3B/4B, offshore South Africa to Africa Oil SA Corp, a wholly owned subsidiary of Africa Oil. The Section 11 approval was the final consent required in order to complete the Transaction, and accordingly all requisite regulatory approvals and deeds in respect of the Transaction have now been signed and completed.

As per the terms of the Assignment and Transfer Agreement with Africa Oil, Eco has received further payment of US$2.5m from Africa Oil. Under the terms of the Agreement, upon a further farm out to a third party into Block 3B/4B Eco will receive a further payment of US$4m from Africa Oil and when the first well is spud an additional US$1.5m, will be due to the Company from Africa Oil.

Orinduik License Operational Update

As Operator, Eco Orinduik BV, gave notice to the Minister of Natural Resources of the Cooperative Republic of Guyana (“MNR”) to enter the Second Phase of the Second Renewal Period of the Orinduik License effective as of 14 January 2024. This Second Phase has a commitment to drill one exploration well to the Cretaceous formation during the remainder of the license period which ends on 13 January 2026. Further, Eco advised MNR last week that TOQAP Guyana B.V (the SPV joint entity held by TotalEnergies and QatarEnergy 60:40) has relinquished their 25% WI for strategic reasons and will not participate in the next phase, the former TOQAP Guyana B.V 25% WI will be assigned to Eco Guyana. Subject to the requisite government notifications, Eco will remain the Operator holding 40% WI in Orinduik License as Eco Guyana and 60% WI as Eco Orinduik BV.

Non-Executive Director Appointment

On 2 January 2024, the Company announced that Dr Oliver Quinn had been elected as a Director of the Company subject to completion of the due diligence by Strand Hanson, the Company’s Nominated Adviser, in accordance with the AIM Rules for Companies and Nominated Advisers. The Company is pleased to confirm that the aforementioned process has now been completed and Dr Oliver Quinn has been appointed to Eco’s Board with immediate effect as the nominee Director of Africa Oil, which holds 14.84% of the Company’s issued share capital.

Dr Quinn was appointed as the Chief Commercial Officer of Africa Oil in September 2023, having previously been employed as Senior Vice President, Corporate Development at Kosmos Energy Ltd. Dr Quinn started his career at Shell and has 19 years of experience in the Oil & Gas industry. He is a graduate of the University of Manchester, where he studied for a BSc (Hons), Environmental & Resource Geology, and a graduate of the University of Edinburgh where he completed a PhD in Petroleum Science. While Dr Quinn replaces Keith Hill as Africa Oil’s board nominee, the Board is pleased to confirm that Mr Hill has agreed to remain as a Non-Executive Director of the Company.

Gil Holzman, Co-founder and Chief Executive Officer of Eco Atlantic, commented:
“I am delighted to welcome Oliver to our Board. His extensive technical and commercial experience are an excellent addition for our Company entering into 2024 which is lining up to be a transitional year for the Company.”

“With respect to Block 3B/4B, we are pleased to have received final approval from the South African Government for our transaction with Africa Oil, which now paves the way to completing a further farm out in respect of the Block and the drilling of our identified targets of up to five wells.”

Colin Kinley, Co-founder and Chief Operating Officer of Eco Atlantic, commented: 
“Knowing the material value and potential of Orinduik Block, Eco acquired Tullow’s 60% WI and has remained focused on drilling a massive, stacked pay interval in the Southeastern quadrant of the block.  Eco Atlantic now approved Operator intends to bring in new partners and to drill the significant potential of the Cretaceous interval on the Guyana oil fairway.  With this well commitment, we now move into planning and engineering preparations to drill in next 12-18 months. 

We feel extremely positive about the future of the Orinduik block, receiving significant interest from key industry partners and IOCs in our recently commenced farm out process.  We will provide further updates to shareholders on operational and farm out progress throughout the year. Eco is grateful to the Government of Guyana and specifically the MNR for their collaborative efforts and support in enabling Eco to now progress towards drilling.” 

Nothing much to add to this purely confirmatory announcement, for Eco they have completed on this deal but the management remains bursting with confidence in South Africa and I for one wouldn’t be surprised to see further activity in the post code.

Guyana is a large process now but not without its upside and Eco will be looking for partners now that the original partners have left town. 

Overall I’m confident about Eco at the moment, it is looking in as strong a position as I’ve seen for a very long time and the company has no need for fresh funds at the moment and remains a favourite with a great deal of upside. 

United Oil & Gas

United has announced that it has received a default notice from Kuwait Energy Egypt Limited for a total of USD $3,822,143 for outstanding cash calls in relation to the Abu Sennan concession. Pursuant to the joint operating agreement relating to the Abu Sennan concession, the Company has 30 days to remedy the default from the start of the default period which is 28 January 2024.  In the event that the Company does not remedy the situation during the Default Period, then each non-defaulting party to the JOA has the option to require the Company to withdraw from the Abu Sennan Concession pursuant to the terms of the JOA.

The Company had been in advanced discussions regarding the potential sale of its 22% stake in the Abu Sennan concession to United Energy Egypt Limited (“UEEL”). UEEL, a sister company of the operator Kuwait Energy; both share the same parent, United Energy Group which is listed on the Hong Kong stock exchange.  However, discussions aborted as the Company was unable to agree to execute the draft sale and purchase agreement presented to it by UEEL following legal advice notwithstanding the attempts from the Company to agree a mutually acceptable SPA.

The effective date for the SPA was 1 November 2023, when the consideration was $2.052 million which would have settled all outstanding cash calls as at that date, and the Operator would pay all future cash calls and receive all future revenues. The increased figure for the default notice is due to the cash calls received for work undertaken on the concession in the interim period.

The Company believes that its commercial position remains unchanged between a default scenario out of the Abu Sennan concession and the commercial terms of the SPA (if completed), as the proposed cash consideration from a sale would be used to settle outstanding cash calls with the Operator and either of scenarios would involve the divestment of the Abu Sennan concession.

The decision to divest from Abu Sennan was influenced by the challenging macro-economic conditions in Egypt and the persistent difficulty the Company faced in repatriating funds from the country, as previously reported. The Company remained committed to collaborating with local Egyptian stakeholders, EGPC, and the Operator to navigate and address these challenges but unfortunately these efforts have not been rewarded. Also, the 2024 proposed budget, indicating a net deficit of USD $3 million, reflects United’s belief that the main value has been extracted from the Abu Sennan concession, prompting a refocus by the Company on other assets to enhance shareholder value.

Before September 2023, the Company received payments from the Egyptian National Oil Company (“EGPC”) in both USD and EGP, with the latter primarily used to settle operational liabilities. Since September 2023, approximately 13% of payments have been in USD, with the rest in EGP, resulting in considerable foreign exchange losses when converting EGP to USD. The Company has a receivables balance of USD $0.80 million outstanding from EGPC and cash in the bank  of approximately USD $1.3 million.

In early November 2023, the JOA partners on the Abu Sennan concession received a request from the Operator to make a material USD payment to support the operational needs of the joint venture. Since this time, United has engaged with EGPC to seek a USD remittance against our outstanding USD receivable position to satisfy this demand from the Operator. In parallel, United has engaged with the Operator to seek alternative solutions to this USD demand, which included a continuation of the agreed position that had previously been accepted by the Operator, whereby the JOA partners settle the Operator cash calls in EGP.

United is currently reviewing the Default Notice in consultation with its legal advisers. In parallel, we will continue to engage with the Operator to seek a solution and/or explore other options. Further information will be provided in due course.     

 The Company is in discussions with its debt provider (current balance owing USD $1.089 million) and will update the market in due course.

United Chief Executive Officer, Brian Larkin commented:
“We are very disappointed that we could not reach agreement with United Energy Egypt Limited to sell the Abu Sennan concession. We had worked tirelessly from early December and over the holiday period to finalise the Sale and Purchase Agreement (“SPA”) and engaged external lawyers to assist through the whole process at a significant cost. We had agreed the commercial terms, however, based on external legal advice, we were unable to sign the SPA in the form that United Energy Egypt Limited presented to us. However, we believe the differences could have been easily resolved and this commercial issue avoided.”

Readers should decide for themselves the nature of the discussions UOG have had in Egypt but to me it looks like they were in between a rock and a hard place and having already decided to leave town they had to take the medicine. 

To be fair they had been exiting the concession and it is only through the fortunate extension in Jamaica below that today they aren’t in the situation of having nothing to report on. With a close call on farming-out before Christmas there is a good chance that Jamaica will provide excitement going forward. 

United has issued the following operations update in relation to our Jamaican asset.

Jamaica Update

United Oil and Gas Plc is pleased to announce that the terms for a two-year extension to the Initial Exploration Period of the Walton Morant Licence in Jamaica, have been agreed with the Ministry of Science, Energy, Telecommunications and Transport, pending final signature by MSETT.

Following final signature on an amendment to the Production Sharing Agreement the licence will run to 31 January 2026. United is committing to a programme of technical studies including piston core surveying and seismic reprocessing.

The Walton Morant licence is a 22,400km2 offshore exploration block situated to the south of the island of Jamaica. The licence benefits from excellent data coverage, and this has helped provide compelling evidence for a working hydrocarbon system and defined multiple plays and material prospects within the acreage. An independent evaluation of 11 high-graded leads and prospects indicated the potential for a combined estimated 2.4 billion barrels unrisked mean prospective resources. The company is seeking a strategic partner to support its planned work programme, including piston core surveying and seismic reprocessing. This is expected to further de-risk the acreage, with a view to drilling the Colibri prospect – estimated to hold unrisked mean prospective resources of 406 million barrels.

United currently holds and operates a 100% equity interest in the Walton Morant Licence, Jamaica.

United Chief Executive Officer, Brian Larkin commented:
“We are very pleased to announce the agreement of terms for a two-year license extension in Jamaica. United has dedicated significant effort to the technical aspects of this asset, which has over 2.4 billion barrels of unrisked oil potential and the promising Colibri prospect. This extension will empower us to confidently continue our farm-out campaign, seeking a strategic partner to unlock the immense potential in this region. The support from the Government of Jamaica underscores our relationship and the optimistic industry outlook in Jamaica. We will continue to focus on the recent positive interest that has been shown by a number of parties, and with the extended licence, this is a significant opportunity for the benefit of all stakeholders.” 

KeyFacts Energy Industry Directory: Malcy's Blog