Africa Oil Corp. - World-Class East Africa Oil Exploration

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auffallend hoher AOI Umsatz heute in Schweden

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Testergebnisse Marula 1-X

Auszug aus der Veröffentlichung:

VANCOUVER, BC, April 28, 2025 /CNW/ - (AOI–TSX, AOI–Nasdaq-Stockholm) – Africa Oil Corp.’s (“Africa Oil” or the “Company”) representatives on Impact Oil & Gas Limited’s (“Impact”) Board have received an update on the Marula-1X drilling operation on Block 2913B (PEL 56), offshore Namibia.

Highlights

Safely drilled the Marula-1X well to a total depth of 6,460m (measured depth) on block 2913B, targeting Albian aged sandstones, within the Marula fan complex, approximately 47 Km south of the Venus-1X well, using the Deepsea Mira semi-submersible drilling rig.
No hydrocarbons were encountered in the primary target in the Marula-1X well. No Drill Stem Test was performed.
A comprehensive analysis of the well results is now underway.
Impact has a 9.5% interest in Blocks 2912 and 2913B in Namibia’s Orange Basin. Africa Oil through its 39.5% interest in Impact, has an effective interest of approximately 3.8% in these blocks. Block 2913B contains the Venus light oil discovery.

Africa Oil President and CEO, Roger Tucker commented: “The farm down agreement between Impact and TotalEnergies that completed last year, provides full carry of Impact’s exploration and development costs on Blocks 2912 and 2913B through to first commercial production from these blocks. This presents us with an attractive opportunity set to test different geological plays on these blocks at no upfront cost.”

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Pouyanne meets Namibia's new president in Windhoek to discuss Venus project
French supermajor's chief executive paid courtesy visit to President Netumbo Nandi-Ndaitwah

Iain Esau
Africa CorrespondentDubai
Published 25 April 2025, 23:25

TotalEnergies chief executive Patrick Pouyanne paid a courtesy visit to Namibia's President Netumbo Nandi-Ndaitwah in Windhoek on Friday, underscoring the supermajor's plans to develop its deepwater Venus oil discovery in the Orange basin.

The French oil giant aims to bring Venus on stream in 2029 or 2030, targeting a peak production rate of about 150,000 barrels per day based on 40 subsea wells tied back to a floating production, storage and offloading vessel.

President Nandi-Ndaitwah - who took up her office last month - said in her Facebook account that "Namibians are excited about the discovery of oil in Namibia and have high expectations from the industry, which is expected to benefit and grow the Namibian economy," adding that "the meeting has come at the right time."

Pouyanne said TotalEnergies had decided to explore and potentially invest in Namibia due to the country’s investor-friendly environment.

from [sic] global energy players following several promising offshore discoveries in recent years, positioning the country as a potential key player in Africa’s oil and gas landscape.

https://www.upstreamonline.com/politics/pouyanne-meets-namib…

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Iain Esau
Africa CorrespondentMaun

Published 23 April 2025, 15:01
Namibia’s top upstream executive is “confident” that TotalEnergies will take a final investment decision on its groundbreaking Venus project in 2026, despite the discovery’s challenges.

The French supermajor is currently wrapped up in a tendering process for a major floating production, storage and offloading vessel and within months is set to light the touchpaper for two big subsea contracts covering up to 40 wells.

However, despite Venus holding billions of barrels of oil in place, how much can be actually recovered will be impacted by the reservoir’s permeability and inherent pressure drive as well as the volumes of associated gas that have to be reinjected in three kilometres of water.

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https://www.upstreamonline.com/field-development/totalenergi…

Total arbeitet Venus bereits relativ detailliert aus. So gesehen wäre es eine größere Überraschung, wenn Total die FID stoppt, als wenn Total die FID umsetzt.

"TotalEnergies has unveiled the full technical details of its challenging ultra-deep water Venus project offshore Namibia, including the design specifications of its big floating production, storage and offloading vessel and equally impressive subsea system. Located in 3000 metres of water in the Orange basin, Venus will be developed by up to 40 subsea wells tied back to an FPSO that can handle peak output of 160,000 barrels per day of oil. A final investment decision is set to be taken in 2026, targeting first oil in late 2029 or early 2030, with all but a small portion of the development’s produced gas to be reinjected in order to provide critical reservoir support.

Last month, the supermajor published environmental documentation that offered a skeletal view of the project’s big subsea system, which is expected to have a seabed footprint of 165 square kilometres. On Wednesday, in its latest filing to Namibia's government as it seeks environmental clearance for a project of national significance, TotalEnergies added flesh to this initial subsea skeleton while also providing clarity on the FPSO specifications. These technical details will be pored over by contractors' engineers and procurement specialists — and compared with what they have already been advised by the supermajor — as they gear up to take part in bid processes this year for the subsea and FPSO hardware.

One well-placed source told Upstream last week that TotalEnergies is expected to launch design competitions in the third quarter of 2025 for two packages — the subsea production system and the subsea umbilical, flowline and riser system. As for the FPSO, Upstream reported previously that Hanwha and SBM Offshore were the top contenders to supply Venus' first FPSO - there could be more than one. TotalEnergies expects that half the project's wells will be oil producers, with the remainder being gas re-injectors, according to a 379-page draft scoping report (DSR), the precursor to a full-blown environmental and social impact assessment. The wells will all be drilled to a depth of about 3000 metres below the seabed."

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https://seekingalpha.com/article/4770048-africa-oil-corp-sta…

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The Company is pleased to announce that its Board has declared the distribution of the Company’s first quarterly cash dividend of USD 25 million or approximately USD 0.0371 per common share. This dividend will be payable on April 11, 2025, to shareholders of record at the close of business on March 27, 2025.

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News - einfach mal unkommentiert:

VANCOUVER, BC, March 20, 2025 /CNW/ - (AOI–TSX, AOI–Nasdaq-Stockholm) – Africa Oil Corp. (“Africa Oil”, or the “Company”) is pleased to announce the completion of the amalgamation (the “Amalgamation”) to consolidate all of the Prime Oil & Gas Coöperatief U.A (“Prime”) shareholding in Africa Oil, and declares the first quarterly cash dividend of USD 25 million, as it implements its new enlarged base dividend policy, with a target annual distribution of at least USD 100 million. The Company also announces Board and Executive Management changes, and presents its full-year 2025 Management Guidance.

Africa Oil President and CEO, Roger Tucker commented: “This is a transformational milestone that marks the next stage of value creation and shareholder returns for Africa Oil as an enlarged company. There is compelling strategic rationale for the consolidation and we believe that the quality and materiality of the assets within our diversified portfolio, our newly combined balance sheet, the strength of the cash flow profile and an attractive double-digit dividend yield all help emphasise a superior investment proposition for investors. In that regard, I am pleased to announce that the Company’s new Board has approved the declaration of the first quarterly dividend as we seek to set a new high mark for shareholder returns.

I welcome our new Directors and thank our outgoing Directors for their support over the past year as we delivered several strategic transactions to simplify and strengthen the Company’s fundamental business proposition. I would like to thank Pascal Nicodeme, our outgoing CFO, for his steadfast service to the Company and the Board is pleased to retain his unique insights and expertise as a new Board member. I would also like to welcome Aldo Perracini, our new CFO, and I am delighted to have the benefit of his years of experience at Prime. We look forward to leveraging our strong position to deliver long-term value for all our stakeholders.”

Africa Oil Chairman, Huw Jenkins commented: “On behalf of the Board I congratulate the teams at Africa Oil, Prime and BTG Pactual in closing this deal considerably ahead of the original timeline. The enlarged Africa Oil is uniquely well-positioned to drive long-term value through its existing portfolio of world-class assets as well as by leveraging its strong balance sheet to consider strategically complementary acquisitions in our target markets. The Company has ambitious growth targets and the vision is to continue growing into a leading full-cycle E&P, establishing it as a trusted and prominent industry partner. The management team has done an excellent job of preparing the Company for its next phase of growth and this completion effectively transforms the Company into one of considerably greater scale that is better placed to realise its vision.”

Highlights

Transformational deal which doubles reserves and production in high quality offshore assets that benefit from low lifting costs, premium Brent pricing and a favourable fiscal regime.
Consolidating full control of Prime’s cash flows and balance sheet with an enlarged cash position of USD 460.9 million as at December 31, 2024.
Anticipated substantial increase in free cash flows per share are expected to significantly enhance the Company’s capacity to support:
sustainable through-cycle returns to shareholders, underpinning an annual base dividend of USD 100 million (“Base Dividend”) that is deemed by the Board to be sustainable in a range of through-cycle oil price scenarios; and
an annual commitment to distribute at least 50 per cent. excess free cash flow after the Base Dividend distribution in the form of supplemental dividends and/or share buybacks.
Increased scale and balance sheet strength present the Company with considerable scope to optimise its capital structure and to pursue its organic and inorganic growth opportunities.
Issued 239,828,655 newly issued common shares in Africa Oil to BTG Pactual Oil & Gas S.a.r.l. (“BTG O&G”) representing approximately 35.5% of the outstanding share capital of the Company.
The introduction of BTG O&G as a shareholder that is strategically aligned with the Company and committed to growing a sustainable upstream oil and gas business, to deliver superior value creation and shareholder capital returns.
BTG O&G enhances Africa Oil’s access to business opportunities while supporting disciplined capital allocation through its Board participation.
Changes to the Board and Executive Management:
Keith Hill, Erin Johnston, Andrew Bartlett and Gary Guidry have stepped down from the Board;
Roger Tucker (President and CEO), John Craig, Michael Ebsary and Kimberley Wood remain on the Board and are joined by Huw Jenkins (new non-executive Chair), Pascal Nicodeme, Edwyn Neves, Ahonsi Unuigbe and Richard Norris; and
Pascal Nicodeme has ceased to be the Chief Financial Officer of the Company and Aldo Perracini has joined the Company as the new Chief Financial Officer, pursuant to BTG O&G’s nomination rights under its Investor Rights Agreement with the Company (“Investor Rights Agreement”).
Consolidated full-year 2025 Management Guidance incorporating:
working interest1 (“W.I.”) production guidance range of 28.0 – 33.0 thousand barrels of oil equivalent per day (“kboepd”) and entitlement2 production guidance range of 32.0 – 37.0 kboepd;
EBITDAX3 of USD 500 – 600 million;
cash flow from operations before working capital adjustments and interest payments3 guidance range of USD 320 – 370 million; and
capital investment of USD 150 – 190 million.
The Company plans to announce a new brand that will be launched with its First Quarter 2025 results scheduled for May 14, 2025, to project its focus on a total shareholder returns business model and a broader geographical mandate.
Dividend Declaration

The Company is pleased to announce that its Board has declared the distribution of the Company’s first quarterly cash dividend of USD 25 million or approximately USD 0.0371 per common share. This dividend will be payable on April 11, 2025, to shareholders of record at the close of business on March 27, 2025. This dividend qualifies as an ‘eligible dividend’ for Canadian income tax purposes.

Dividends for shares traded on the Toronto Stock Exchange (“TSX”) will be paid in Canadian dollars on April 11, 2025; however, all US and foreign shareholders will receive USD funds. Dividends for shares traded on Nasdaq Stockholm will be paid in Swedish Krona in accordance with Euroclear principles on April 16, 2025.

To execute the payment of the dividend, a temporary administrative cross border transfer closure will be applied by Euroclear from March 25, 2025, up to and including March 27, 2025, during which period shares of the Company cannot be transferred between the TSX and Nasdaq Stockholm.

Payment to shareholders who are not residents of Canada will be net of any Canadian withholding taxes that may be applicable. For further details, please visit: https://africaoilcorp.com/investor-summary/total-shareholder-returns/" target="_blank" rel="nofollow ugc noopener">https://africaoilcorp.com/investor-summary/total-shareholder-returns/ .

Board and Executive Management Changes

The Company’s new Board is comprised of nine directors:

the President and Chief Executive Officer of Africa Oil – Roger Tucker (non-independent);
three directors nominated by Africa Oil – Michael Ebsary (independent), Kimberley Wood (independent) and Pascal Nicodeme (non-independent);
three directors nominated by BTG O&G - Huw Jenkins (independent), Edwyn Neves (independent) and Ahonsi Unuigbe (independent); and
two additional independent non-executive directors nominated by Africa Oil and approved by BTG O&G – John Craig (independent) and Richard Norris (independent).
Keith Hill, Erin Johnston, Andrew Bartlett and Gary Guidry have stepped down from the Board.

Pascal Nicodeme has ceased to be the Chief Financial Officer of the Company and Aldo Perracini has joined the Company as the new Chief Financial Officer.

Please refer to the Company’s website (https://africaoilcorp.com) for the profiles of Africa Oil’s Board and Management.

Africa Oil’s Deepwater Nigerian Assets

With the completion of the Amalgamation, Africa Oil’s main assets are an 8% W.I. in Petroleum Mining Lease (“PML”) 52 and Petroleum Prospecting License (“PPL”) 2003, and a 16% W.I. in PMLs 2, 3 and 4 as well as PPL 261. PML 52 and PPL 2003 are operated by an affiliate of Chevron Corporation with PML 52 covering part of the producing Agbami field. PMLs 2, 3 and 4 and PPL 261 are operated by affiliates of TotalEnergies S.E. and contain the producing Akpo and Egina fields as well as the Preowei and Egina South Discoveries. Africa Oil’s assets are located over 100 km offshore Nigeria.

All three producing fields have high quality reservoirs and produce light to medium sweet crude oil through FPSO facilities. Akpo and Egina also export associated gas which feeds into the Nigerian liquified natural gas plant, whilst Agbami associated gas is mostly reinjected.

Africa Oil’s year-end 2024 pro forma Proved plus Probable (“2P”) reserves4, based on 100% shareholding in Prime, was estimated to be 70.8 million barrels of oil equivalent (“MMboe”) on the W.I. basis, and 101.6 MMboe on the net entitlement5 basis with an after-tax 2P NPV(10) of USD 2,128 million.

Full-Year 2025 Management Guidance

The Company’s full-year 2025 production will be generated solely by its deepwater Nigerian assets. The 2025 Management Guidance includes W.I. production guidance range of 28.0 – 33.0 kboepd and entitlement production range of 32.0 – 37.0 kboepd with approximately 75% expected to be light and medium crude oil and 25% conventional natural gas.

Africa Oil is expected to sell 11 - 13 cargoes of approximately one million barrels each during 2025 and to generate USD 500 – 600 million in EBITDAX and USD 320 – 370 million in cash flow from operations before working capital adjustments and interest payments. These estimates are based on a 2025 average Brent price of USD 75.0/bbl. At an average Brent price of USD 85/bbl the mid-point of the cash flow from operations guidance range is estimated to increase by approximately 19%, and at an average of USD 65/bbl the mid-point is estimated to decrease by approximately 12%.

Africa Oil’s 2025 capital investment is expected to be in the range of USD 150 – 190 million with most of the expenditure to be incurred on the Company’s Nigerian assets including infill drilling program on Egina and Akpo oil fields. The following table summarises the Company’s full-year 2025 Management Guidance:



2025 Guidance

2024 Actuals

W.I. production (kboepd) (1)

28.0 – 33.0

34.0

Entitlement production (kboepd) (2)

32.0 – 37.0

38.8

EBITDAX (USD million) (3)

500 - 600

N/A(6)

Cash flow from operations (USD million) (3)

320 – 370

N/A(6)

Capital investment (USD million)

150 - 190

N/A(6)



Early Warning Disclosure Regarding BTG O&G

Pursuant to the Amalgamation, BTG O&G, an indirectly controlled subsidiary of Brazilian financial company Banco BTG Pactual S.A. (“Banco BTG”), acquired 239,828,655 newly issued shares from the Company in exchange for the shares of the entity that held BTG O&G’s interest in Prime. Based on the closing price of the Africa Oil shares (“Shares”) on the TSX on March 19, 2025 of CAD 2.09, this represents an aggregate value of approximately CAD 501.2 million.

Immediately prior to completion of the Amalgamation, which occurred on March 19, 2025 (Vancouver time) / March 20, 2025 (Luxembourg time), Banco BTG did not own, directly or indirectly, any Shares or any securities convertible into or exercisable for Shares. Immediately following the completion of the Amalgamation, Banco BTG owns, indirectly through BTG O&G, 239,828,655 Shares, representing approximately 35.5% of the outstanding share capital of the Company.

BTG O&G acquired the Shares as part of a strategic investment in the Company. Banco BTG intends to review its investment in the Company on a continuing basis and may, from time to time and at any time, acquire or dispose of equity or debt securities or instruments, through open market transactions, private placements and other privately negotiated transactions, or otherwise (including through exercising rights provided to BTG O&G in the Investor Rights Agreement), in each case, depending on a number of factors, including general market and economic conditions and other factors and conditions Banco BTG deems appropriate.

The Investor Rights Agreement provides BTG O&G with certain rights and privileges, including board nomination rights based on specific thresholds of BTG O&G’s continued shareholding in the Company, the right to nominate the CFO of the Company, certain consent rights and registration rights, certain participation and top-up rights to permit BTG O&G to acquire Shares to maintain its equity interest in the Company and certain customary information and inspection rights.

For a summary of the rights of BTG O&G under the Investor Rights Agreement, please refer to the Management Information Circular published on September 13, 2024 (https://africaoilcorp.com/investor-summary/financial-reports-meetings-filings/).

Banco BTG is a corporation existing under the laws of Brazil and its head office address is Praia De Botafogo, 501, 6th Floor, Sao Paulo, Brazil, 04538-133.

An early warning report will be filed by Banco BTG under applicable Canadian securities laws and once filed will be available on the Company’s SEDAR+ profile at www.sedarplus.com. A copy of such report may also be obtained from: Caina Rocha at [phone].



Notes

Aggregate oil equivalent production data comprised of light and medium crude oil and conventional natural gas production net to Prime’s W.I. in Agbami, Akpo and Egina fields. These production rates only include sold gas volumes and not those volumes used for fuel, reinjected or flared.
Entitlement production is calculated using the economic interest methodology and includes cost recovery oil, royalty oil and profit oil and is different from working interest production that is calculated based on project volumes multiplied by Prime’s effective working interest in each license.
This press release includes non-GAAP measures that do not have a standardized meaning prescribed by IFRS Accounting Standards and, therefore, may not be comparable with the calculation of similar measures by other companies. The Company believes that the presentation of these non-GAAP figures provides useful information to investors and shareholders as the measures provide increased transparency and the ability.
EBITDAX is a non-GAAP measure. This is used as a performance measure to understand the financial performance from Prime’s business operations without including the effects of the capital structure, tax rates, depreciation, depletion, amortization, impairment and exploration expenses.

Cash flow from operations before working capital and interest payments is a non-GAAP measure. This represents cash generated by removing the impact from working capital from cash generated by operating activities and is a measure commonly used to better understand cash flow from operations across periods on a consistent basis and when viewed in combination with the Company’s results provides a more complete understanding of the factors and trends affecting the Company’s performance.

Please refer to the oil and gas advisory on page 6 for important information.
Net entitlement reserves are calculated using the economic interest methodology and include cost recovery oil and profit oil, but exclude royalty oil, and are different from working interest reserves that are calculated based on project volumes multiplied by Prime’s effective working interest.
Africa Oil’s 2024 Management Guidance was based on Prime’s production, cash flow from operations and capital investment net to the Company’s previous 50% shareholding in Prime. 2025 Management Guidance is based on a consolidated basis. Production metrics can be compared on a pro-forma basis; however, there is no direct comparison for the financial metrics in the table between this year’s guidance and the 2024 results.
Additional Information



This information is information that Africa Oil is obliged to make public pursuant to the EU Market Abuse Regulation. The information was submitted for publication, through the agency of the contact persons set out above, at 12:30 am EDT on March 20, 2025.





Advisory Regarding Oil and Gas Information



The terms boe (barrel of oil equivalent) and MMboe (millions of barrels of oil equivalent) are used throughout this press release. Such terms may be misleading, particularly if used in isolation. Year-end 2024 reserves estimates are based on a conversion ratio of six thousand cubic feet per barrel of oil equivalent (6 Mcf: 1 boe), which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication

of value.



The reserves estimates presented in this press release have been evaluated by RISC in accordance with NI 51-101 and the COGE Handbook, are effective December 31, 2024. The reserves presented herein have been categorized accordance with the reserves and resource definitions as set out in the COGE Handbook. The estimates of reserves in this press release may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.



RISC’s report was prepared using Brent oil price forecast of (USD/bbl): 2025 - USD 75.0; 2026 - USD 76.5; 2027 - USD 78.0; 2028- USD 79.6; 2029 – USD 81.2; 2030 and beyond escalation rate of 2.0%. There is no assurance that the forecast prices will be attained and variances could be material. The recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.



Reserves



Reserves are estimated remaining quantities of commercially recoverable oil, natural gas, and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data, the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Reserves are further categorized according to the level of certainty associated with the estimates and may be sub-classified based on development and production status.



Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.



Oil and gas reserves and production referred to in this release are for conventional light and medium gravity oil and conventional natural gas.



Forward Looking Information

Certain statements and information contained herein constitute "forward-looking information" (within the meaning of applicable Canadian securities legislation), including statements related to: the amount of the annual dividend distribution; the ability of the Company to deliver further growth or increased shareholder returns; the Company continuing to grow into a leading Independent E&P company; 2025 Management Guidance including production and cash flow from operation; the anticipated strategic and financial benefits; the timing for announcement of the Company’s First Quarter 2025 results and the new brand; expectations regarding free-cash flow; statements regarding access to business opportunities; BTG O&G’s support for new business development opportunities; and BTG O&G’s strategic alignment and long term support for the Company. Such statements and information (together, "forward-looking statements") relate to future events or the Company's future performance, business prospects or opportunities.



All statements other than statements of historical fact may be forward-looking statements. Statements concerning proven and probable reserves and resource estimates may also be deemed to constitute forward-looking statements and reflect conclusions that are based on certain assumptions that the reserves and resources can be economically exploited. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate", "expect, "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe" and similar expressions) are not statements of historical fact and may be "forward-looking statements". Forward-looking statements involve known and unknown risks, ongoing uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements, including statements pertaining to share repurchase programs, cashflow from operation and capital investment estimates, performance of commodity hedges, the results, schedules and costs of exploratory drilling activity, uninsured risks, regulatory and fiscal changes, availability of materials and equipment, unanticipated environmental impacts on operations, duration of the drilling program, availability of third party service providers and defects in title. No assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. The Company does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws. These forward-looking statements involve risks and uncertainties relating to, among other things, changes in macro-economic conditions and their impact on operations, changes in oil prices, reservoir and production facility performance, hedging counterparty contractual performance, results of exploration and development activities, cost overruns, uninsured risks, regulatory and fiscal changes, defects in title, claims and legal proceedings, availability of materials and equipment, availability of skilled personnel, timeliness of government or other regulatory approvals, actual performance of facilities, joint venture partner underperformance, availability of financing on reasonable terms, availability of third party service providers, equipment and processes relative to specifications and expectations and unanticipated environmental, health and safety impacts on operations. Actual results may differ materially from those expressed or implied by such forward-looking statements.


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For further information, please contact:

Shahin Amini
Head of Investor Relations and Communications
[e-mail]
T: [phone]

Burson Buchanan
Financial PR & Communications Advisor
[e-mail]

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Aber zumindest scheint Total das Venus Projekt weiter voranzutreben

TotalEnergies reveals big scale of Venus project's subsea system

"TotalEnergies has fired up the environmental approval process on its huge Venus oil project offshore Namibia, making public for possibly the first time the potential scale of the development’s subsea system. Located in 3000 metres of water, Venus will be exploited via subsea wells tied back to a 150,000 barrels per day floating production, storage and offloading vessel. A final investment decision on the ultra-deepwater development is due to be taken in 2025 or 2026, targeting first oil in 2029 or 2030.

A background information document (BID) filed with Namibia’s authorities stated that TotalEnergies and its partners Impact Oil & Gas, Namcor and QatarEnergy want to "move toward the development" of Venus. This big discovery lies 300 kilometres from a helicopter base in Oranjemund, 320 kilometres from Luderitz port and 700 kilometres from the huge Walvis Bay port. The document said the project calls for the drilling of up to 40 subsea wells, some of which will be used to reinject the gas. An indication of the total value of subsea orders that could be awarded at Venus can be gleaned for similar size developments elsewhere, remarks made by officials at subsea contractors and recent presentations.

The chief executives of the three big subsea contractors all name-checked Namibia during their fourth-quarter results calls with analysts at the end of last month. In its quarterly presentation, TechnipFMC estimated that the value of the Venus subsea contract will be upwards of $1 billion, with chief executive Doug Pferdehirt saying: “You're beginning to see tendering activity happen in Namibia.” For comparison, in 2024, TechnipFMC was awarded a contract worth between $500 million and $1 billion to provide a 48-well subsea system for ExxonMobil’s Whiptail project in Guyana, which lies in 2000 metres of water, one kilometre less than Venus. Also focused on Namibia is Saipem, whose chief executive Alessandro Puliti said: “We expect that engineering, procurement and construction works in the country will be tendered in the coming quarters.” Saipem is providing the subsea-umbilical riser and flowlines system for Whiptail and has valued its contract at up to $1.5 billion. Subsea7 chief executive John Evans said: “We've seen Namibia open up this year. There'll be opportunities to build at least two projects in Namibia this year, which is a new province for the industry.” Evans did not name the projects, but they are Venus and Galp Energia’s initial Mopane development.

Based on the contract values for Whiptail, the water depth at Venus and market capacity issues, it appears likely that the subsea orders for Venus, which may be developed in phases, will surpass $2.5 billion. According to the BID, drilling of Venus’ wells and installation of the offshore production facilities is expected to take about five years and then “production will start and last for 20 years plus,” added the documentation. Oil stored on the FPSO will be offloaded to dynamically positioned shuttle tankers which will then transfer the oil to conventional tankers in a nearshore area. Venus, discovered in 2022, is located in Block 2913B."

https://www.upstreamonline.com/field-development/totalenergi…