Slides
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Afentra plc 1 Afentra plc HY 2026 Results Presentation 15 September 2026 Value driven growth African Energy Transition
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2 Disclaimer The following applies to this presentation, including the slides, the information contained in the slides, any question and answer session, any oral presentation and any written or oral material discussed or distributed during the presentation meeting (together, the "Presentation"). This Presentation has been prepared by Afentra plc (the "Company") and is for information purposes only. This Presentation does not constitute an offer or invitation or a solicitation of any offer or invitation for the sale or purchase of any securities in the Company. In addition, it is not intended to form the basis of or act as an inducement to enter into any contract or investment activity and should not be considered as a recommendation by the Company to do so. This Presentation is not intended for distribution to, or use by, any person or entity in any jurisdiction or country where such distribution or use would be contrary to local law or regulation. The Presentation and the information contained herein must not be recorded, taken away, disclosed, copied, distributed, reproduced, transmitted or passed on, directly or indirectly, in whole or in part, to any other person or published in whole or in part, for any purpose or under any circumstances, without the prior written consent of the Company. This Presentation is not for release, publication or distribution, directly or indirectly, in whole or in part, in or into the United States of America, its territories or possessions, any state of the United States or the District of Columbia (collectively, the "United States"), Australia, Canada, Japan or South Africa. This Presentation is not an offer of securities for sale in the United States or any other jurisdiction. The Company has not registered and does not intend to register any of its securities under the US Securities Act of 1933, as amended (the “US Securities Act”). Securities may not be offered or sold in the United States absent registration or an exemption from the registration requirements of the US Securities Act. Certain statements in this document are forward-looking statements which are based on the Company's expectations, intentions and projections regarding its future performance, anticipated events or trends and other matters that are not historical facts. These statements are not guarantees of future performance and are subject to known and unknown risks, uncertainties and other factors that could cause actual results to differ materially from those expressed or implied by such forward-looking statements. Factors that would cause actual results or events to differ from current expectations, intentions or projections might include, amongst other things, changes in oil prices, changes in equity markets, failure to establish estimated petroleum reserves, political risks, changes to regulations affecting the Company's activities, delays in obtaining or failure to obtain any required regulatory approval, failure of equipment, uncertainties relating to the availability and costs of financing needed in the future, the uncertainties involved in interpreting drilling results and other geological, geophysical and engineering data, delays in obtaining geological results and other risks associated with offshore exploration, development and production. Given these risks and uncertainties, readers should not place undue reliance on forward-looking statements. Forward-looking statements speak only as of the date of such statements and, except as required by applicable law, the Company undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Certain industry and market data contained in this Presentation has come from official or third party sources. Third party industry publications, studies and surveys generally state that the data contained therein have been obtained from sources believed to be reliable, but that there is no guarantee of the accuracy or completeness of such data. While the Company believes that each of these publications, studies and surveys has been prepared by a reputable source, neither the Company nor its directors, officers, employees or advisers or any other person has independently verified the data contained therein. In addition, certain of the industry and market data contained in this Presentation come from the Company's own internal research and estimates based on the knowledge and experience of the Company's management in the market in which the Company operates. While the Company believes that such research and estimates are reasonable and reliable, they, and their underlying methodology and assumptions, have not been verified by any independent source for accuracy or completeness and are subject to change without notice. Accordingly, undue reliance should not be placed on any of the industry or market data contained in this Presentation. Certain financial information contained herein has not been audited, comforted, confirmed or otherwise covered by a report by independent accountants. When and if audited financial information for the Company is published or becomes available, the data could vary from the data set forth herein. In addition, past performance of the Company cannot be relied on as a guide to future performance. Unless specified otherwise, no statement in this Presentation is intended as a profit forecast or estimate for any period and no statement in this Presentation should be interpreted to mean that earnings or earnings per share for the Company for the current or future financial years would necessarily match or exceed the historical published earnings or earnings per share for the Company. Certain figures contained in this Presentation may have been subject to rounding adjustments. Accordingly, the actual arithmetic total of numbers may not conform exactly to the total figures and percentages may not conform exactly to percentages that would be derived if calculations were based on rounded numbers. The information in this Presentation, which does not purport to be comprehensive, has not been verified by the Company or any other person. No representation or warranty, express or implied, is or will be given by the Company or its directors, officers, employees or advisers or any other person as to the accuracy or completeness of the Presentation and, so far as permitted by law, no responsibility or liability is accepted for the accuracy or sufficiency thereof, or for any errors, omissions or miss- statements, negligent or otherwise, relating thereto. In particular, but without limitation, (subject as aforesaid) no representation or warranty, express or implied, is given as to the achievement or reasonableness of, and no reliance should be placed on, any projections, targets, estimates or forecasts and nothing in this Presentation is or should be relied on as a promise or representation as to the future. Accordingly, (subject as aforesaid), neither the Company, nor its directors, officers, employees or advisers, nor any other person, shall be liable for any direct, indirect or consequential loss or damage suffered by any person as a result of relying on any statement in or omission from the Presentation or any other written or oral communication with the recipient or its advisers in connection with the Presentation and (save in the case of fraudulent misrepresentation or wilful non-disclosure) any such liability is expressly disclaimed. The information contained in this Presentation should not be assumed to have been updated at any time subsequent to the date shown on the cover hereof. In furnishing this Presentation, the Company does not undertake any obligation to provide any additional information or to update this Presentation or to correct any inaccuracies that may become apparent.
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3 Delivering the Next Phase of Growth Balance sheet transformed, lower-cost refinancing and successful equity raise increase financial flexibility and capacity Independent growth strategy confirmed, following conclusion of the Strategic Review Offshore growth potential demonstrated, Pacassa SW discovery and Impala-1 results supporting production and reserves growth Onshore opportunities advancing, leads identified and targeted 2D seismic programme to commence across Kwanza portfolio Multiple near-term catalysts, Pacassa SW first oil, Impala-2 drilling, workover program, Etu completion and onshore potential A transformed balance sheet giving Afentra the financial capacity to pursue the material growth potential within its existing portfolio
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Afentra plc 4 H1 2026 Highlights Entitlement Sales ~1.0 mmbbls 2P Reserves & 2C Resources1 120 mmboe Net Cash / (Net Debt) $28.4 million (Dec 2025: $(21.8) million) Asset Performance Balance Sheet Total Debt / Annualised Adjusted EBITDAX 0.8x Working Interest Production 5,777 bopd Cash Balance $97.4million (Dec 2025: $10.2 million2) Total Debt $70.0 million (Dec 2025: $31.1 million) 2C Resource Growth1 >4x (20.9 to 87.3 mmboe) 1 2P Reserves as per YE 2025 CPR report for Block 3/05. 2C Contingent Resource as per January 2026 update. Resource estimates for Block 3/24 are based on management view. 2 Including restricted funds in 2025. Revenue is net of the state’s fiscal take (cost oil and profit oil allocation), but prior to deduction of petroleum income tax (PIT). Strong cash generation and a materially expanded resource base support the next phase of growth Financial Highlights Revenue $91.0 million (H1 2025: $52.0 million) Asset Level Cash Flow $32.2million (H1 2025: $-8.9 million) Operating Cash Inflow $33.2 million (H1 2025: $3.2 million outflow) Adjusted EBITDAX $41.9 million (H1 2025: $27.9 million)
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Afentra plc 5 10.2 32.2 27.5 40.3 110.3 (3.5) (7.2) (2.2) 97.4 35.7 (40.8) 92.3 Balance @ 01-Jan-26 Net Asset Cashflow Prepayment Facility (Net) Net Equity Proceeds Gross Cash Inflows Contingent Consideration G&A Non-recurring Overheads Balance @ 30-Jun-26 Revenue Received Cash Calls & Other Payments Cash Balance @ 31-Aug-26 H1 2026 Cash Reconciliation ($m) Net Debt $21.8m Net Cash $28.4m (3) (2) (4)(1) 1 Adjusted for Dec-25 revenue prepayment, offtake fees, & hedge payouts. 2 Reflects the net proceeds from the $70 million prepayment facility drawdown after RBL repayment, interest and refinancing-related fees. 3 Reflects net proceeds from the completed equity raise. 4 Includes costs associated with the strategic review and employee share schemes. 5 Post period-end, a ~$28m JV cash call was issued and paid in July, bringing funding broadly to the H1 budget run-rate. Net Cash $22.3m (5) POST-H1 CASH MOVEMENTS: ($6.0m) The refinancing and equity raise has transformed Afentra’s balance sheet, increasing resilience and providing greater flexibility to pursue growth
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Afentra plc 6 Structured Offtake Profile, Volumes Projected to Rise Production growth from drilling & development activities support lifting volumes through 2028 Active management of crude oil sales delivers regular revenues and enables averaging of commodity price cycle FY 2027–2028 volumes are indicative and subject to operational delivery and partner liftings scheduling. From 2026 onwards (inclusive), projected liftings assumes completion of Etu transaction and a 33.33% WI in Block 3/05 and 24.99% WI in Block 3/05A. FY 2026 ESTIMATED LIFTINGS ~2.3 mmbbls (includes ~0.36 mmbbls YE25 carried inventory) 517,643 479,609 452,024 450,000 450,000 Jan-26 Apr-26 Jul-26 Oct-26 Dec-26 Realised liftings Projected liftings Revenue $33.8m $57.2m $38.0m Less PIT ($2.2m) ($3.5m) ($2.3m) Post-Tax Revenue $31.6m $53.7m $35.7m Realised price $65.38/bbl $119.27/bbl $84.07/bbl FY 2027 / 2028 INDICATIVE ~3.5 – 4.0 mmbbls p.a. FY 2027 FY 2028 Up to ~3.5 mmbbls Sales from production growth Up to ~ 4.0 mmbbls
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Afentra plc 7 Commodity Price Risk Management Disciplined Hedging Strategy Secures Downside While Preserving Upside Exposure Hedging Position ▪ ~49% of remaining 2026 forecast sales hedged following selective execution ▪ Combination of puts and collars provides downside protection while retaining meaningful upside exposure ▪ Average weighted hedge premium cost to date of c.$1/bbl across 2026 hedges ▪ Further hedges will be progressively layered in line with market conditions and prepayment facility requirements Hedging strategy underpins cash flow resilience and supports funding of the development programme Hedge coverage by cargo period Hedge structure summary Collar range ($/bbl) $60–85 floors / $77.5–117.6 caps Put range ($/bbl) $60 - $68 floors DOWNSIDE PROTECTION UPSIDE EXPOSURE Q1-26 Apr-26 Jul-26 Q4-26 Q1-27 15% 85% 100% 52% 53% 47% 40% 60% 518 kbbl 480 kbbl 452 kbbl 450 kbbl 450 kbbl 36% 64% Oct-26 58% 42%450 kbbl Q2-27 450 kbbl 36% 64% Q3-27 450 kbbl 20% 80% Q4-27 900 kbbl 15% 85% 2027 forecast sales reflect only the current production base and exclude incremental production from new wells and future activities
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Afentra plc 8 Funding Secured to Underpin Next Phase of Growth All refinancing objectives delivered - improved margin and offtake economics, enhanced commercial flexibility and headroom to support future growth Gunvor selected as preferred lender following a competitive process with 12+ counterparties over 3-months. Secure >$100m facility Liquidity to fund the near-term development programme Lower cost of capital Pricing to reflect the de-risked, cash-generative asset base Realign offtake costs to market Improve netbacks and commercial flexibility Capital flexibility Secure headroom flexibility to fund organic growth, development, and selective inorganic opportunities HEADLINE TERMS — GUNVOR PREPAYMENT FACILITY $125m Prepayment facility 4 years Tenor SOFR + 6% Margin REFINANCING OBJECTIVES Refinancing objectives achieved, strengthening liquidity and capital flexibility
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Afentra plc 9 Gunvor Facility Refinancing provides flexible debt structure at lower cost of capital $125m prepayment facility replaces the existing RBL and working capital facilities, extends maturities and supports funding of the near-term work programme 1 Tranche 2 is subject to delivery of 1.8mmbbls in first 12 months of the facility and certain production hurdles. 2 Un-committed accordion to scale facility size based on future production growth. 3ALCR measures forecast future revenues from the secured assets relative to outstanding debt under the facility. Debt Maturity Profile Gunvor PPF Repayment Profile Facility Principal Tranches ($m) Rate Maturity2026 2027 Gunvor PPF 100 251 Term SOFR + 6% 2030 Facility Overview ▪ $125m committed ($100m + $25m), plus uncommitted accordion2; ▪ Term SOFR + 6% margin ▪ 4-year tenor ▪ 12-month principal repayment grace period Key Covenant ▪ Advance life coverage ratio (ALCR) covenant ≥1.3x3 Security ▪ Secured by Block 3/05 & 3/05A liftings Crude Offtake & Use of Proceeds ▪ Entitlement volumes marketed through Gunvor ▪ Total committed volume: 8 mmbbls ▪ Minimum annual commitment: 1.8 mmbbls ▪ Proceeds: refi existing RBL debt, fund work programme and G&A 16.7 33.3 33.3 16.7 2.3 9.1 9.1 4.5 2026 2027 2028 2029 2030 $100m $25m
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Afentra plc 10 Equity Raise Accelerates Next Phase of Growth The transaction broadened Afentra's institutional shareholder base and positioned Afentra to improve liquidity and support long-term share price performance. Capital US$40 million raised – Strong institutional demand resulted in a heavily oversubscribed book Priced at 67p per share – 5.2% discount to closing price prior to launch Retail offer launched alongside placing – Oversubscribed vs. £2.0m offer size Register 21 new institutional investors added – 52% of placing allocated to new investors Long-only ownership materially increased – Long-only institutions increased from 21% to 32% of register Balanced shareholder base established – Increased depth and diversity across investor base Shareholder Base Existing shareholder support maintained – 11+ existing shareholders increased positions Director participation alongside investors – Demonstrating alignment with shareholders International shareholder base established – Participation from UK, Europe, North America, Asia and South Africa
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Afentra plc 11 Capital Allocation Framework Positioning Afentra for Scalable Growth and Long-Term Returns A strengthened balance sheet supports a balanced approach to organic and inorganic growth while preserving financial resilience and driving long-term value Inorganic Growth ▪ Pursue value accretive cash generative opportunities in Angola and other West African jurisdictions ▪ Use strengthened balance sheet to support credit financing for value accretive acquisitions ▪ Structure transactions to minimise equity dilution Balance Sheet Strength ▪ Retain a strong liquidity position to take advantage of the growth opportunities ▪ Maintain a prudent leverage position during period of oil price volatility ▪ Use debt selectively to fund strategic growth and build future capacity Shareholder Returns ▪ Focus remains on reinvesting cash into accretive growth opportunities ▪ Return of capital through dividends or buybacks remains under consideration ▪ Committed to minimising equity dilution and preserving long-term value Organic Growth ▪ Prioritise offshore reinvestment to grow production, reserves and future cash generation ▪ Progress short-cycle onshore redevelopment opportunities to target early low-cost production ▪ Invest selectively in onshore exploration to access significant wider upside potential
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12 0.0 5.0 10.0 15.0 20.0 25.0 30.0 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Existing Portfolio Driving Material Organic Upside Offshore scale and onshore fast-cycle optionality underpin Afentra’s growth strategy Offshore redevelopment provides visible multi-year production growth; onshore offers scalable, fast-cycle exploration and development potential Offshore Oil Rate kbopd (net) Gas production from 3/05A Upside/future work programmes Growth from 2026/27 campaigns Underlying production ▪ >20kbopd net production potential ▪ Infrastructure-led redevelopment programme ▪ Material resource conversion opportunity ▪ Significant exploration potential Onshore ▪ Material emerging Kwanza Basin optionality ▪ Early oil production from legacy field reactivation ▪ Underexplored proven hydrocarbon basin ▪ Proximity to refinery supports rapid monetisation Illustration of future production potential based on management estimate. From 2026 onwards (inclusive), production reflects a 33.33% WI in Block 3/05 and 24.99% WI in Block 3/05A.
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13 Multi-Billion bbl Shallow Water Assets Offshore Angola Significant recovery upside potential across Block 3/05 (30%), 3/05A (21.33%) & 3/24 (40% op) Vast underdeveloped asset with substantial potential to increase production and replace reserves through organic growth, whilst reducing emissions 12P Reserves as per YE 2025 CPR report for Block 3/05. 2C Contingent Resource as per January 2026 update. Resource estimates for Block 3/24 are based on management view. Estimates presented on gross basis. Source Data: Wood MacKenzie; All volumes shown as at 31 Dec 2025. Scale of the Prize Oil & Gas in Place >3.7 bbo ~ 1.2 Tcf Reserve & Resource Potential >250 mmbo >550 Bcf Greater Block 3/05 Area would be the 2nd Largest UKCS Asset Top 10 UK North Sea Assets by Remaining Volumes (mmboe) Current 2P reserves: 106 mmbo Bentley Halifax Foinaven Mariner Area Bressay (Future) Schiehallion Cambo Rosebank Greater Block 3/05 Area Clair Total >400 mmboe Greater Block 3/05 Area 2C Management View 2C 2P 0 1 bln
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14 Infrastructure Rejuvenation – 70% complete Substantial investment has upgraded core infrastructure and extended asset life Infrastructure investment almost complete transforming and de-risking the asset ~$400m Invested since 2022 ~$180m Remaining investment Asset Life Extension Integrity upgrades to complete Q3 2027 Power & Mechanical Revamping Reliability and uptime improvements Water Injection Restoration Recovery optimization. Targeting 100+kbwpd in 2026 ~70% Complete ~30% Remaining 2022 FSO Recertification Complete Out to 2035 All capex figures presented on a gross basis. Infrastructure capacity of ~200,000 blpd, Current throughput ~75,000 blpd
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15 Pacassa SW– Unlocking Large, Undrilled Potential Discovery on Pac SW-1 well; potential to open-up significant extension of the Pacassa Field 1 Sproule ERCE OIP range 27-150 mmbo within license area. 2 Production volumes and cost estimates are presented on a gross basis. 3 Excludes mobilisation of rig and pre-investment in drilling activities in 2025. Sonangol capped AFE $72mm. 4 Chance of Success (CoS) estimated at ~60%. Material discovery drilled from existing infrastructure with significant reserves upside and further development potential Q2 2026 Drill & Discovery PacSW-1 2027 Review potential for additional development Q4 2026 Completion & First Oil Pre-drill Oil in place1,2 32–210 mmbo Pacassa SW-1- Potential2 ▪ 5000+ bopd expected initial rate ▪ Well cost capped and carried by Sonangol3 ▪ First Oil target Q4 2026 subject to operational plan Development Potential ▪ Up to 2+ additional wells ▪ Resource potential of up to 70 mmbo 2,4 ▪ Discovery requires remapping & development planning Pac SW results: 217 Gross oil interval 136 meters net oil pay with fractures Better than expected reservoir quality Common oil water contact with Pacassa main field with some depletion
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16 0.0 5.0 10.0 15.0 20.0 25.0 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 Pacassa Field - Unlocking Large Undrilled Potential 1 Includes recoverable volumes up to license expiry, unless explicitly stated otherwise. Illustration of future production potential based on management estimate. 2 Sproule ERCE includes volumes for NFA and WI in the 5-year license extension total, whereas management includes all projects. Underlying reserves of 51.5 mmbo represents the Pacassa field component of total gross 2P reserves of 106.4 mmbo across producing assets. Underlying reserves: 51.5 mmbo expected from base production, supported by waterflood uplift and LWIs ~10 mmbbls to be delivered from two HWO campaigns Pac SW well could double existing field reserves. Infill drilling in attic & flank could increase recovery further Upside/future work programmes Growth from 2026/27 campaigns Underlying production Gross Production (kbopd) Underlying Production Pac SW LWI 2027 HWO future phases PAC SW North 5 year license extension Total Gross Recoverable Volumes (mmbo)(1) CPR Classification 51.5 106.1 Underlying Production Pac SW LWI 2027 HWO future phases PAC SW North 5 year license extension Total 2P 2C2U 2U2C 2C
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17 Impala Field – Proven Resource, Material Untapped Potential Impala-2 well planned for Q3 2026, potential for significant additional reserves 1 Production volumes and cost estimates are presented on a gross basis. Oil in place (OIP) is management estimate. 2 Excludes mobilisation of rig and pre-investment in drilling activities in 2025. Q4 2026 – Q1 2027 Drill & Complete Impala-2 2027 Review potential for additional development Q1 2027 First Oil Impala-2 drilled from existing infrastructure can unlock material existing undeveloped resource and deliver early production and reserves upside Oil in place1 60–200 mmbo lmpala 2 – Potential1 ▪ 4000 bopd expected initial rate ▪ US$50m well cost carried by Sonangol2 ▪ First Oil target for Q1 2027 subject to operational plan Impala Field Development ▪ Up to 3 additional wells ▪ Reserve potential of up to 50 mmbo1 ▪ Opportunity to replicate in other fields Recovery To Date 12 mmbo 4000 bopd peak 1 production well
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18 Impala Area – Scaling a Proven Resource Base Underlying reserves: 8.4 mmbo expected from base production, waterflood uplift and IMP-001R restart Impala-2 unlocks field redevelopment IPSE S Area redevelopment potential >5x resource potential Gross Production (kbopd) Upside/future work programmes Growth from 2026/27 campaigns Underlying production 0.0 5.0 10.0 15.0 20.0 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 1 Includes recoverable volumes up to license expiry, unless explicitly stated otherwise. Illustration of future production potential based on management estimate. 2 As per management estimate. 3 Sproule ERCE includes volumes for NFA and WI in the 5-year license extension total, whereas management includes all projects. Underlying reserves of 8.4 mmbo represents the Impala and Impala South East fields component of total gross 2P reserves of 106.4 mmbo across producing assets. Underlying … Impala-2 LWI 2027 Impala HWO … IPSE infill Impala Main … Impala East FFD 5 year license … Total Gross Recoverable Volumes (mmbo)(1) CPR Classification 8.4 48.3 Underlying Production Impala-2 LWI 2027 Impala HWO future phases IPSE infill Impala Main FFD Impala East FFD 5 year license extension Total 2P 2C(2) 2P 2C(3)2C 2C 2C 2C
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19 HWO Programme– Restoring Production from Shut-in Wells Low-cost interventions to unlock incremental reserves & resources 1 Production volumes and cost estimates are presented on a gross basis. Initial three heavy workovers (HWO) targeting 5 mmbbls; further four HWO campaigns across B3/05 required to deliver 25 mmbbls. 2HWU – Hydraulic workover unit. Q4 26/Q1 27 HWU mobilisation 2027+ Evaluation 20+ wells for Phase 2 H1 2027 First restarted well online Short-cycle, low-cost restoration of shut-in wells delivering near-term production uplift from 2027 Recoverable Potential1 10–25 mmbo Work Completed Well integrity review Candidate screening Phase 1 wells selection Preparation for HWU2 tender HWO-Phase 1 – 2026/27 Campaign1 ▪ 3 workovers (integrity + gas lift failures) ▪ ~3,500 bopd expected uplift in Yr 1 ▪ US$5-10m cost per workover ▪ First restarted well online H1 2027 Future Potential ▪ 20+ candidates screened in B 3/05 ▪ Repeatable low-cost HWO cycles
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20 Palanca Field– Restoring Shut-In Production Potential Underlying reserves: 13.1 mmbo expected via PAL-F1/F2; supported by a ramp-up in water-injection and 4 LWIs in 2026 to optimise near-term recovery Multi year HWO campaign planned Infill drilling to commence from 2027 ~3x resource potential Gross Production (kbopd) Upside/future work programmes Growth from 2026/27 campaigns Underlying production 0.0 5.0 10.0 15.0 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 1 Includes recoverable volumes up to license expiry, unless explicitly stated otherwise. Illustration of future production potential based on management estimate. 2 Sproule ERCE includes volumes for NFA and WI in the 5-year license extension total, whereas management includes all projects. Underlying reserves of 13.1 mmbo represents the Palanca field component of total gross 2P reserves of 106.4 mmbo across producing assets. Underlying Production HWO x 3 LWI 2027 Palanca South HWO future phases 5 year license extension Total Gross Recoverable Volumes (mmbo)(1) CPR Classification 13.1 35.3 Underlying Production HWO x 3 LWI 2027 Palanca South HWO future phases 5 year license extension Total 2P 2C 2C(2)
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21 GPQ – Infrastructure-Led Development Plan ▪ Discoveries ~5km from Palanca infrastructure, ▪ Palanca infrastructure has significant available processing capacity ▪ Shallow water depths suitable for small-scale platform deployment ▪ Well re-entry & subsurface optimisation underpin low-cost execution ▪ Phased execution planning to re-access wells and fast-track first oil Block 3/24 – Near-Term Development Opportunity Three Proven Discoveries, Low-Cost Operated Development, FID H1 2027 1 Production volumes and volume estimates are presented on a gross basis. OIP is management estimate. Operated development being fast-tracked toward ~10,000 bopd project, targeting FID in H1 2027 Block 3/24 Potential1 ▪ Portfolio diversity: 10 oil & gas discoveries, includes 3 previously produced fields ▪ All wells tested, with flow rates up to 6,000 bopd ▪ Estimated >190 mmbbls STOIIP and 400 BCF GIIP already discovered ▪ Reservoirs will be fully re-evaluated using modern techniques ▪ Future seismic acquisition to assess exploration potential across block
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22 0.0 5.0 10.0 15.0 20.0 25.0 30.0 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 Offshore Redevelopment Programme Phased execution to deliver material production growth Programme ▪ 2 wells drilling in 2026/27 (costs carried) ▪ Initial HWO campaign ▪ Additional HWOs + Palanca South ▪ Block 3/24 GPQ development Timing ▪ Production uplift beginning Q1 2027 ▪ Block 3/24 targeting First Oil 2028 ▪ Phased production growth through 2027+ Capex ▪ Fully carried on 2026 drilling ▪ 2026 to 2028 Capex ~$200m net Oil Rate kbopd (net) Gas production from 3/05A Upside/future work programmes Growth from 2026/27 campaigns Underlying production Targeting ~13kbopd near-term, with further upside to >20kbopd Infrastructure led redevelopment programme Targeting material growth in production and reserves Multi-year drilling, HWO and exploration programme Illustration of future production potential based on management estimate. From 2026 onwards (inclusive), production reflects a 33.33% WI in Block 3/05 and 24.99% WI in Block 3/05A. Combined programme targeting 13kbopd in 2028
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23 Increasing production lowers unit operating costs, driving a material uplift in asset level cash generation Block 3/05 Area - Production Growth Drives Lower Unit Costs Higher production reduces opex per barrel and increases cash generation 0 25 50 2025 2027 2030 Opex vs Production Production (kbopd) Opex range ($/bbl) Illustrative schematic of potential production, opex and pre-capex cash flow generation based on management assumptions. $23/bbl Fiscal Take $15/bbl Pre- Capex Asset Cash Generation $37/bbl Opex $23/bbl Fiscal Take $15/bbl Pre- Capex Asset Cash Generation $45/bbl Opex $15/bbl OPEX SYNERGIES FLOW TO CASH GENERATION at $75/bbl oil price +$8/bbl uplift in pre-capex cash generation Current (2025/26) Future (2030)
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24 ✓ Pacassa SW wells ✓ Impala infill well ✓ Palanca South infill well ✓ Hydraulic workovers ✓ Light well interventions ✓ GPQ development ~13 kbopd ~6 kbopd ~$200m net Capex1 Near-Term Investment Drives Step-Change in Cash Generation Production growth drives significant cash generation Near-term investment funds high-return development, delivering step-change in production and significant cash generation from 2028, with strong leverage to higher prices Cash Flow Inflection Material step-up in cash generation from 2028 Funding Visibility Secured Development programme supported by asset cash flow and committed liquidity Net WI Production Pre- Capex Asset Cash Generation ($M)2 @ $70/bbl 2025 Actuals 2028 Forecast3 $90/bbl$80@ $70 2025 Actuals 2028 Forecast 1Pac SW and Impala Capex to be recovered from well revenues upon success. 2Pre-Capex asset cash generation is after fiscal payments and operating costs, but before capex, G&A, and financing costs. 3Assumes Blocks 3/05 & 3/05A cost pool merger. $57m ~$190m ~$225m ~$260m
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25 Kwanza Onshore - Regional Comparison Untapped Hydrocarbon Potential Source: S&P EDIN and S&P Global. The onshore Kwanza basin is an under-explored hydrocarbon basin offering a unique opportunity with significant upside potential Creaming Curve Onshore West Africa Basins (oil, gas and condensate) Onshore Gabon Basin (~47k Sqkm) ▪ 3.5 Bn boe discovered (2P reserves) ▪ 2.5 Bn boe produced ▪ ~600 exploration wells drilled (1950s – now) Kwanza Basin ? Bn boe Lower Congo Basin >2 Bn boe Gabon Basin 3.5 Bn boe Onshore Lower Congo Basin (~25k Sqkm) ▪ >2 Bn boe discovered (2P reserves) ▪ 0.5 Bn boe produced ▪ ~350 exploration wells drilled (1950s – now) Onshore Kwanza Basin (~29k Sqkm) ▪ <100 MMboe discovered (2P reserves) ▪ 90 MMboe produced ▪ ~130 exploration wells drilled (1950s – 1982)
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26 High-Impact Exploration Pipeline - Kwanza Onshore Systematic prospect maturation underway across a proven underexplored hydrocarbon basin Kwanza Onshore adds material exploration optionality to Afentra’s core offshore growth strategy, with targets of up to 350mmbo1 OIIP currently mapped BASIN VALIDATION eFTG + Legacy Data Integration LEAD GENERATION 40+ Basin Leads Identified HIGH-GRADING & PRIORITISATION Prospect Screening & Ranking PROSPECT DEFINITION Target 2D seismic Acquisition DRILLING CANDIDATE SELECTION 2-4 Drill Ready Targets EXPLORATION DRILLING Target Exploration Well(s) 2027 Proven Working Hydrocarbon System Historic production, oil shows and legacy discoveries validate an active petroleum system across the basin Underexplored Relative to Peer Basins Limited historic exploration despite comparable geology to more mature West African onshore basins Disciplined First-Mover Advantage Applying modern subsurface techniques to systematically unlock overlooked basin potential 1 OIIP is management estimate from Bamvo-1 re-entry unrisked volumes
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27 Accelerated Path to Early Production–Quenguela Norte Large discovered resource supported by existing route-to-market infrastructure Clear redevelopment pathway positions Quenguela Norte as a near-term onshore value catalyst Source: ECL, “Prospectivity of the Onshore part of the Kwanza Basin” Report (Jan 2004). RESOURCE VALIDATION Discovered Resource Confirmation SUBSURFACE MODELLING Concept Modelling REDEVELOPMENT PLANNING Concept Selection EXECUTION PREPARATION Permitting, Logistics, Facilities, Well Works PRODUCTION READINESS Operational Mobilisation & Execution Large Discovered Resource Base 220 mmbo OIP across Quenguela Norte, Legua and Benfica previously produced fields Existing Route to Market 50km trucking route to Luanda refinery via established road with available capacity Fast Cycle Monetisation Opportunity Low-cost pathway to early cash flow EARLY PRODUCTION Target First Oil 2027
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28 Kwanza Onshore – Value Driven Strategic Opportunity Building a Strategic Acreage Position Afentra is well-positioned to unlock early production and untapped exploration opportunities Early Production Opportunity ▪ Previously produced oil fields offering considerable untapped potential ▪ Licenses benefit from favourable fiscal terms ▪ Potential for low-cost re-development of existing fields ▪ Cash flow generation through early production to Luanda refinery Low-Cost exploration in proven Basin ▪ Proven hydrocarbon basin with record of oil production ▪ Deploying team’s significant experience in low-cost onshore exploration ▪ Strengthening Angolan relationships by supporting local companies explore Kwanza onshore
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29 Activity Roadmap: Milestones & Catalysts Block Project 2026 2027 2028 OFFSHORE Block 3/05 Pacassa SW Block 3/05 Impala-2 Block 3/05 HWO Phase I Block 3/05 Future well(s) Block 3/05 HWO: Future Phases Block 3/24 Block 3/24: GPQ Development Block 3/05A Gas Management ONSHORE KON15 eFTG/2D Seismic KON15 Exploration Well KON19 Seismic KON19 Exploration Well KON4 Well Re-entries ExecutionFID First Oil eTFG Survey Seismic Well Re-entries/drilling
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30 Multiple Pathways to Long-Term Value Creation Material Offshore and Onshore portfolio with potential for expansion The current redevelopment programme underpins the base growth case, with additional upside across the broader business Angola Licence expansion First mover advantage in Angola Low-cost acreage additions Production 6K ➜ ~13k ➜ >20k bopd Early Revenue Quenguela Norte First Oil Targeting 2027 Of the ~160 wells drilled, 13 were exploration wells. Exploration Upside Only 1 dry hole in 160 wells drilled New 3D seismic planned 2P Reserves Maturation of 2C resources to 2P reserves Route-to-Market Validation Establishing repeatable onshore development model Exploration Platform Proven basin with material potential New country entry Same playbook Production acquisition Replicating Afentra model Disciplined, value-accretive OFFSHORE ONSHORE PORTFOLIO EXPANSION
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31 Afentra - Roadmap to Accelerated Value Creation Clear pathway to production growth, cash flow expansion and value driven growth Afentra is positioned to accelerate growth and unlock the next phase of shareholder value creation TODAY PHASE 2 DRIVERS Offshore Growth Pac SW/Impala 2/GPQ Development/ Further infill & satellite programmes/ Exploration upside Onshore Upside Quenguela Norte redevelopment/ Low cost high impact exploration M&A & New Licenses Continue Angola portfolio build/ Selective new country entry Enhanced Financing $125m scalable financing capacity/ $40m equity raise ~ 6kbopd net production 120 mmboe 2P + 2C $350 to 450M+ consensus NAV VALUATION CREATION OUTCOMES 6k ~13k >20k bopd net production $190-260m p.a. pre-capex asset cash generation at ~13k bopd Multiple pathways to long-term value creation
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32 APPENDIX
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33 Five Years of Delivery, Positioned to Accelerate Growth A unique strategic position built through disciplined execution Shareholder Value Focus Disciplined Execution Relationships & Reputation Scalable Producing Portfolio Strategic Angola Position Angola Embedded Organic Growth Proven Execution Team Relationships & Trusted Reputation Afentra enters next Phase of growth from a position of strength, supportive market backdrop further enhances value potential
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34 Proven Value Creation Through Disciplined Capital Allocation May 2021 $40m Initial Capital Disciplined M&A ▪ 4 acquisitions completed1 ▪ 4 licence awards secured Structured Financing ▪ $125m Gunvor facility secured ▪ Selective use of equity to support growth Capital Discipline ▪ Prudent leverage position through cycle ▪ Disciplined investment approach Team & Expertise ▪ Deep West Africa expertise ▪ Proven capital markets experience Building scale, production and cashflow through strategic investment Cash-generative production base, strengthened balance sheet and carried drilling programme support the next phase of production and resource growth 6kbopd Net Production 120mmboe 2P + 2C >$350-450m Consensus NAV 1 Including Etu transaction, subject to completion.
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35 Board and Team Deep experience and expertise across Africa Paul McDade Chief Executive Officer Paul’s 35 years within the international Oil & Gas business has provided him with a rich and diverse set of relevant experiences. From his, social, security and safety environmentearly international experience in challenging operationals, to his 19 years as COO and then CEO of Tullow Oil, he has essential first-hand experience of what is required to build a successful African-focused, responsible oil & gas company. His strong focus on delivering stakeholder value, shared prosperity, environmental performance and strong governance, coupled with his understanding of the role that Oil & Gas has to play in both the global and African energy transitions, makes him the ideal leader to deliver Afentra’s ambitious growth strategy, a company that will have stakeholder objectives and ESG embedded at its core. Joined 2021 Ian Cloke Chief Operating Officer Ian has over 25 years experience of working in international Oil & Gas with a proven track record of delivering operational, technical and commercial results. His focus and background of deploying innovative technologies across global upstream has delivered significant value for all stakeholders. As EVP at Tullow Oil, he led multi-cultural and diverse teams delivering operations safely and at pace across Africa and South America, from remote onshore to ultra deepwater, effectively managing risk and social-environmental sensitivities whilst embedding strong financial discipline. He has first-hand experience in making a difference in countries having discovered and delivered commercial oil & gas in Uganda, Kenya and Guyana. Having lived and travelled throughout Africa, he has enjoyed the full spectrum of life and business on the continent, making him an ideal founding partner and COO of Afentra. Joined 2021 Anastasia Deulina Chief Financial Officer Anastasia’s multicultural upbringing and over 25 years of working in the energy sector within global, tier-1 investment banks, private equity and corporates has given her extensive experience in strategy development, deal origination, structuring and execution, M&A and business transformation. Her primary focus is always on driving sustainable business growth that has a visible positive impact on the bottom-line. This, along with her significant prior board experience, both as a NED and committee member, and her strong global business development and financial network means that Anastasia provides expert leadership as Afentra’s CFO. Joined 2021 Gavin Wilson Non-Executive Director Gavin Wilson has held the position of Investment Director at Meridian Capital Limited, a Hong Kong based international investment firm, for over a decade, managing an Oil & Gas portfolio focused on world-class assets in emerging markets. Mr Wilson founded and managed, for over seven years, two successful investment funds - RAB Energy and RAB Octane. Previously he was Managing Partner of Canaccord Capital London’s Oil & Gas division, responsible for Sales and Corporate Brokering/Finance. Joined 2021 Thierry Tanoh Chairman Thierry Tanoh is an experienced senior director with global experience, a strong track record in both public and private sectors and has held senior positions within African Government ministries. Relevant experience includes various roles within International Finance Corporation (IFC) as Vice President within the Senior Executive Team and a member of IFC's credit committee based in Washington, and Director of Sub-Saharan Africa based in Johannesburg. Following 12 years with IFC, Mr Tanoh was appointed as CEO of Ecobank Group, a pan-African banking conglomerate with banking operations in 33 African countries. Following his departure in 2014, Mr Tanoh was appointed a member of the office of the President of the Republic of Cote d'Ivoire, serving initially as Minister, Deputy Chief of Staff before being appointed as Minister for Oil, Energy and Renewable Energies between 2017-18. Joined 2023 Andrew Osborne Non-Executive Director Andrew Osborne has over 30 years’ experience in senior executive and board leadership roles across the global oil & gas industry and investment banking. He has a strong track record in business transformation, M&A, capital markets and strategic financing. Most recently, he served as EVP (Special Projects) at Harbour Energy, leading major growth and transformation initiatives, including the $11.2 billion acquisition of Wintershall Dea’s portfolio. Previously, as CFO of Chrysaor, he played a key role in building the company from a start-up into the U.K.’s leading independent oil & gas producer, securing private equity investment, executing multi- billion-dollar acquisitions and leading its public listing through the reverse takeover of Premier Oil. Earlier in his career, Andrew held senior investment banking roles with Merrill Lynch, advising FTSE 100 and 250 boards on strategy, capital raising and corporate transactions. His extensive financial and strategic experience supports Afentra’s continued growth and value creation. Joined 2025 Wider Afentra Team Highly experienced individuals across technical, commercial, legal and finance disciplines
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36 2026/27 Hedging Portfolio Hedge structures, volumes and strike prices by expected sales period (as at 8th September 2026) Cargo period Total sales volume (bbls) Total hedged volume (bbls / %) Collar volume (bbls / %) Put volume (bbls / %) Collar ($/bbl) Put floor ($/bbl) Q1-26 Actuals 518 k 80 k (15%) 80 k (15%) — $60 – $87 — Apr-26 Actuals 480 k 490 k (100%) 240 k (48%) 250 k (52%) $60.8 – $90.0 $65 Jul-26 Actuals 452 k 240 k (53%) 240 k (53%) — $64.1 – $77.8 — Oct-26 450 k 260 k (58%) 260 k (58%) — $63.4 – $81.1 — Q4-26 450 k 180 k (40%) 180 k (40%) — $71.3 – $110.5 — Q1-27 450 k 160 k (36%) 160 k (36%) — $70 – $99.7 — Q2-27 450 k 160 k (36%) 160 k (36%) — $70 – $92.2 — Q3-27 450 k 90 k (20%) 90 k (20%) — $70 – $85.9 — Q4-27 900 k 135 k (15%) 135 k (15%) — $70 – $83.9 — Total / Wtd. Avg. 4,600 k 1,795 k (39%) 1,545 k (34%) 250 k (5%) $60 – $115 range $65
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37 Afentra Increases Exposure to Blocks 3/05 and 3/05A Building Scale and Alignment in Core Angola Assets Acquisition Highlights ▪ Increases Afentra interest to: ‒ 33.33% in Block 3/05 ‒ 24.99% in Block 3/05A ▪ Consideration: ‒ Upfront - $15.20 million1, ‐ subject to customary completion adjustments ‒ Contingent payments – up to $6.74 million ‐ $4m across 20252 & 2026 on sliding scale $75/bbl - $123/bbl ‐ $2.74m subject to development of 3/05A discoveries ▪ Deal metrics mirror previous transactions c. $4/2P mmbbls ▪ Effective date 31 December 2023 ▪ Further consolidation of joint venture partnership Disciplined, step-by-step expansion of Afentra’s working interest in world-class, producing and development assets through smart value accretive acquisitions Post completion interests INA deal Sonangol deal Azule deal Etu deal Block 3/05 Sonangol (op.) 50% 36% 36% 39.34% Afentra 4% 18% 30% 33.33% Maurel & Prom 20% 20% 20% 23.33% Etu Energias 10% 10% 10% 0% NIS Naftagas 4% 4% 4% 4% Block 3/05A Sonangol (op.) 33.33% 33.33% 33.33% 39.34% Maurel & Prom 26.67% 26.67% 26.67% 30.33% Afentra 5.33% 5.33% 21.33% 24.99% Etu Energias 13.33% 13.33% 13.33% 0% NIS Naftagas 5.33% 5.33% 5.33% 5.33% Impact of Etu Acquisition Net Average Production 2025 6,324 bopd 7,035 bopd Net 2P+2C Reserves & Resources YE 2025 120 mmboe 130 mmboe 2025 Revenue $114.4 million $126.0 million 1The upfront and contingent considerations represents Afentra’s pro-rata share of the total considerations agreed by Afentra, M&P and Sonangol to acquire 100% of ETU’s interests in Block 3/05 and 3/05A The upfront consideration is subject to customary completion adjustments. 2The 2025 contingent payment of up to $2m has lapsed. While production threshold was met, the Brent price trigger was not reached; therefore, no contingent payment is due for 2025.
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38 ▪ INA Transaction – Block 3/05A up to $2.5m subject to future Punja development4 ▪ Sonangol Transaction – Up to $28m over 8 years, paid as $3.5m per annum, subject to oil price and production hurdles5 ▪ Azule Transaction – Up to $15m subject to Block 3/05A future developments6 Value Driven Deal Making Upfront Consideration Asset Cashflow Contribution2 Net Completion Payment Stock Entitlement (bbls) $12.0m (Sep-21) $48.5m$56.5m ($1.8m) ($15.8m)($35.4m) $27.0m $28.4m$21.1m 207,868 480,000158,691 Transaction Timeline (Effective Date) $117.0m ($53.0m) $76.5m 846,559 Aggregate Adjustments1 $16.8m ($4.3m)- $12.5m Stock Value Inherited @ Completion3 ~$18.3m ~$40.2m~$13.5m (Apr-22) (Oct-22) ~$72.0m 1 Relates to materialised contingent considerations, working capital adjustments and interests accumulated from effective date to completion date. 2 Asset cashflow generation from effective date to completion, comprising crude oil sales less PIT and cash calls paid. 3 Stock value computed based on realized oil prices of $88/bbl for INA, $85/bbl for Sonangol and $84/bbl for Azule. 4 Subject to development of Punja and a minimum Brent price of $65/bbl. 5 Brent price threshold of $65/bbl and requires minimum gross annual production of 15 kbopd. 6 Subject to development of existing discoveries and a minimum Brent price of $75/bbl. Future contingent considerations (YE 2025)
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Afentra plc 39 30 Years Delivering an Industry Transition in Angola Angola North Sea Industry Transition > 150 Transactions ~ $50 Billion Value of Transactions 2023 1.1 Mmbopd Production ~15 Bn Reserves & Resources (boe) ~ 95% Production from IOC’s/NOC’s UK 1993 1.9 Mmbopd Production ~25 Bn Reserves & Resources (boe) > 70% Production from IOC’s Positive Investment Environment ▪ Stable Government focused on reforms ▪ O&G industry core to Angolan economy ▪ Improved fiscal environment ▪ Abundant resources & opportunity pipeline ▪ Majority of production today managed by Independents ▪ Improved Recovery ▪ Life Extension of Assets ▪ Increased Reserves & Resources ▪ Value creation for shareholders Opportunity for Afentra ▪ First mover advantage ▪ Partner with local companies ▪ Deploy operating expertise ▪ Supporting energy transition Source: IHS Markit and Mergermarket Data. 2023
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40 Partnerships for Success Afentra adopts a technical led approach that adds value to the operator and wider partnership by presenting initiatives that maximise asset value Partnership Model ▪ Strategic alignment on asset outlook and sustainability agenda ▪ Aligning with operators with proven capabilities ▪ Materiality of interest to ensure relevance and influence ▪ Influence through leveraging of technical expertise ▪ Partner credibility and ability or all partners to fund exposure to work programme ▪ Strong operating capabilities within the group, when operating partner
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41 History of the Asset RF % as at 30 June 2023 - CPR Palanca FSO Built in 1991 Storage: ~2 mmbbl Impala First Oil: 1992 STOIIP: 60 mmbbls RF at 19% Impala SE First Oil: 1988 STOIIP: 320 mmbbls RF at 38% Bufalo First Oil: 1988 STOIIP: 358 mmbbls RF at 40% Oombo First Oil: 1997 STOIIP: 163 mmbbls RF at 42% Cobo First Oil: 1993 OIP: 396 mmbbls RF at 43% Pambi First Oil: 1995 OIP: 170 mmbbls RF at 31% Pacassa First Oil: 1986 STOIIP: 1103 mmbbls RF at 46% Palanca First Oil: 1985 STOIIP: 587 mmbbls RF at 47% Cefo Disc. date: 1988 Test rate: 1,150bcpd + 32 mmscfd GIIP: 400 bscf Palanca NE Disc. date: 1988 Test rate: 6,000 bopd OIIP: 24 mmbbl Quissama Disc. date: 1987/1992 Test rate: 3,500 bopd OIIP: 20 mmbbl Golungo Disc. date: 1988 Test rate: 2,400 bopd OIIP: 24 mmbbl Canuku Cluster Production 2001-2008 Peak Production.: 12,000 bopd OIIP: 53 mmbbl Kuma Disc. date: 1988 Test rate: 1,800 bopd OIIP: 15 mmbbl 3/05 ▪ Initial development phase 1983 – 1997 by ELF/Total ▪ Sonangol P&P operator since 2005 ▪ Located 37km offshore, 60-100m water depth ▪ 4 processing platforms and 17 support structures ▪ First oil 1985 from Palanca ▪ Peak oil production ~ 200,000 bopd in 1998 ▪ Peak water injection ~365,000 bwpd in 1999 ▪ Water injection curtailed in 2015, restarted late 2020 ▪ Last infill campaign closed out in 2010 (Pacassa) 3/05A ▪ First oil from Gazela field in 2015 ▪ Wellbore shutdown in 2017 ▪ Production restored March 2023 3/24 ▪ >130 mmbbls discovered by ELF in the late 1980's ▪ Commerciality proven by Canuku development and production 2001-2008 Palanca terminal ▪ Floating storage and offloading facility ‘FSO’ sales point with a maximum storage capacity of ~2 mmbbls
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42 Production Sharing Contract (PSC) Mechanics Schematic Representation Gross Revenue (100%) Cost OilProfit Oil Contractor GroupState Contractor post-tax revenue Contractor Share State Share Petroleum Income Tax (PIT) * Block 3.05A (Punja) assumes a cost oil limit of 80% for first 4 years following first oil, reducing to 65% from year 5 onwards. Key Fiscal Terms Block 3.05 Block 3.05A Block 3.05A (Caco Gazela) (Punja) Cost Oil Limit 75% 50% 80% Profit Oil Sharing State Profit Oil Share 60% 30% 30% C ontractor Group (C G) profit oil share 40% 70% 70% Petroleum Income Tax (PIT) 50% 50% 25% Illustrative Breakdown Gross Revenue 100% 100% 100% Cost Oil Recovered 75% 50% 80% Profit Oil 25% 50% 20% State Profit Share 15% 15% 6% C G Profit Share 10% 35% 14% CG Pre-Tax Revenue 85% 85% 94% PIT Payable 5% 18% 4% CG Post-Tax Revenue 80% 68% 91% Illustrative Scenario Assuming Full Cost Recovery
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43 Angola Onshore: Risk Service Contracts in Context Definition & Key Characteristics: ▪ RSCs – similar to PSCs - offer a clear commercial framework. ▪ In an RSC the contractor is compensated on a fee- based structure through a share of production. ▪ The state retains full ownership of resources, while the contractor focuses on efficient delivery. ▪ Exploration and development costs are paid by the contractor. Examples of RSCs in Angola: ▪ Risk Service Contracts are an established part of Angola’s upstream framework, used across multiple basins. Leading international operators, including Chevron, ExxonMobil, Azule Energy and Equinor, currently operate under RSCs in the Lower Congo, and Kwanza basins. ▪ Recent contracts include: ‒ Chevron (Blocks 49 & 50, Lower Congo, 2024) ‒ Red Sky + ACREP + Sonangol (Block 6/24, Kwanza, Dec 2024) ‒ Azule Energy + Equinor + Sonangol (Blocks 18/15, 46, 47, Lower Congo, Dec 2023) Gross Revenue / Production (100%) State Contractor Share (Tiered, ROR Driven) Royalty Petroleum Transaction Tax (PTT) Gross Revenue / Production (100%) Cost OilProfit Oil State Contractor post-tax revenue Petroleum Income Tax (PIT) Production Sharing Contract (PSC) Mechanics Contractor Share State ShareContractor post-tax revenue Petroleum Income Tax Risk Service Contract (RSC) Mechanics Contractor Group
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44 Block 3/24 Risk Sharing Contract (RSC) Fiscal Terms – Standard Terms ▪ Royalty or Petroleum Production Tax (“PPT”): 20% ▪ Petroleum Income Tax (“PIT”): 65.75% ▪ Petroleum Transaction Tax (“PTT”): 70% ▪ Depreciation: 4 years (before production) & 6 years (after production) ▪ Investment Premium: 30% Marginal Field Incentives ▪ Royalty or Petroleum Production Tax (“PPT”): 10% ▪ Petroleum Income Tax (“PIT”): 25% ▪ Petroleum Transaction Tax (“PTT”): 70% ▪ Depreciation:3 years ▪ Investment Premium: 20% Gross Revenue (100%) Contractor Share State Share State Contractor Share (Tiered, ROR Driven) Royalty Petroleum Income Tax Petroleum Transaction Tax (PTT) Contractor post-tax revenue ROR (Rate of Return) Threshold Payment in Kind to the Contractor Group (%) Production Allowance (%) <15% 95% 86% 15%<20% 94% 84% 20%<25% 93% 83% 25%<30% 92% 81% >30% 90% 78% ROR (Rate of Return) Threshold Payment in Kind to the Contractor Group (%) Production Allowance (%) <10% 95% 95% 10%<15% 95% 85% 15%<20% 94% 75% 20%<25% 93% 65% 25%<30% 92% 50% >30% 90% 35% Schematic Representation
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45 Why Angola? Abundant Resources Angola is Africa's second-largest oil producer, with vast untapped reserves. High quality mid-life assets primed for optimisation following prolonged period of underinvestment. Government Support The Angolan government is actively seeking to attract foreign direct investment, offering incentives such as tax breaks and partnerships with the state-owned oil company, Sonangol. Stable political environment A stable political environment has led to reforms which have improved economic stability and transparency in Angola's business environment. New Venture Opportunities Undeveloped and high-impact blocks being made available (eg Onshore Kwanza Basin Licensing Round). Improved fiscal environment The Angolan government continues to reduce the burden on international oil companies to attract foreign investments. Improved governance The establishment of the ANPG regulates the industry in line with global best practice.
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46 Angola’s Positive Transition GDP: $113.2bn (World ranking 66, World Bank 2024) Population: 36.75mn (World ranking 42, World Bank 2023) Head of government: João Lourenço (President) Next elections: 2027, presidential and legislative Oil sector continues to play significant role (2024): ▪ Represents 95% of Angola’s total exports ▪ Contributes over 50% of government revenue ▪ Accounts for ~15% of GPD 2017 ▪ Mr Lourenço becomes president in elections replacing José Eduardo dos Santos, who ruled Angola for nearly four decades after independence in 1975 and through a long civil war that ended in 2002. 2018 ▪ IMF approved a three-year, $3.7bn loan. The IMF loan was contingent on Angola implementing multiple reforms including the ‘Strategic Plan for the Prevention and Fight against Corruption’ (2018-2022). ▪ Foreign Exchange Reforms: Repatriation of Capital; Foreign Exchange Liberalization. 2023 ▪ National Development Plan (2023-2027) approved, which includes investments in education, reducing gender gaps, increasing access to finance, strengthening climate resilience, and sustaining efforts to improve governance. 2019 ▪ Creation of ANPG to act as the regulator and concessionaire for the sector, separating these roles from the national oil company. ▪ Privatisation programme (2019-2022) launched, which entails the transfer of assets of nearly two hundred state-owned or state-controlled companies to the private sector — including several assets of Sonangol’s economic group —and companies in the agribusiness, finance, transportation, and telecom industries. ▪ Tax and Fiscal Reforms: New Tax Incentives; Customer Regimes Improvements. Corruption Perception Index (2024): Angola received a score of 32 (on a scale from 0-100) and has shown significant improvements over the past years, gaining 13 points on the CPI since 2018. 2020 - 2022 ▪ Ratified the Paris Agreement on climate change (2020). ▪ Accepted as an ‘Extractive Industry Transparency Initiative’ implementing country. S&P Global, Trading Economics, International Monetary Fund, Extractive Industries Transparency Initiative, World Bank and Angola Government Data.
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47 Afentra’s Founding Principles Hydrocarbons are part of the transition and will continue to remain important in the overall energy mix. Current global energy environment make these principles more relevant today than when Afentra was founded in 2021 The Global Energy Transition will take time. It is vitally important that we responsibly manage what has already been found. The socio-economic impact of the energy transition needs to be considered alongside the climate impact. Afentra was formed to deliver this balance and create significant value for shareholders.
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48 Uniquely positioned to capitalise on the African Energy Transition 1. Significant hydrocarbon resource base in Africa with material M&A pipeline 2. Gap in market for credible operators to facilitate safe and responsible transition 3. Proven team with significant experience of working in Africa 4. Committed to responsible stewardship and positive stakeholder outcomes 5. African Energy Transition provides compelling investment opportunity