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Valeura Energy Inc. PTTEP Farm-in and Q2 2025 Results Overview August 2025
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Disclaimers and Advisories 2 General Advisory The information contained in this present ation does not purport to be all-inclusive or contain all information that readers may require. Prospective invest ors are encouraged to conduct their own analysis and review of Valeura Energy Inc. (“Valeura”, “VLE”, the “Corporat ion”, the “Company”, “us”, “our” or “we”) and of the information contained in this present ation. Without limitat ion, prospective invest ors should read the entire record of publicly filed documents relating to the Corporation, consider the advice of their financial, legal, account ing, tax and ot her prof essional advisors and such ot her factors they consider appropriate in invest igating and analysing the Corporation. An invest or should rely only on the information provided by the Corporation and is not entit led to rely on part s of that information to the exclusion of ot hers. The Corporation has not authorised anyone to provide invest ors with addit ional or different information, and any such information, including statement s in media articles about Valeura, should not be relied upon. In this present ation, unless ot herwise indicated, all dollar amounts are expressed in United St ates dollars. An invest ment in the securities of Valeura is speculative and involves a high degree of risk that should be considered by potent ial invest ors. Valeura’s business is subject to the risks normally encountered in the oil and gas industry and, more specif ically, in the part icular jurisdict ions in which the Corporation operates, and certain ot her risks that are associated with Valeura’s stage of development. An invest ment in the Corporation’s securities is suit able only for those purchasers who are willing to risk a loss of some or all of their invest ment and who can af ford to lose some or all of their invest ment. This present ation does not constitute or form part of any of fer or invitation to sell or issue, or any solicit ation of any of fer to purchase or subscribe for any securities, or a proposal to make a takeover bid in any jurisdict ion. Neither this document nor the fact of its dist ribution nor the making of the present ation constitutes a recommendation regarding any securities. This present ation is being provided to you for information purposes only. Forward-Looking Information Certain information included in this present ation constitutes forward-looking information under applicable securities legislation. Such forward-looking information is for the purpose of explaining management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for ot her purposes, such as making invest ment decisions. Forward-looking information typically contains statement s with words such as “ant icipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project”, “target” or similar words suggest ing future outcomes or statement s regarding an outlook. Certain information included in this present ation constitutes forward-looking information under applicable securities legislation. Such forward-looking information is for the purpose of explaining management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for ot her purposes, such as making invest ment decisions. Forward-looking information typically contains statement s with words such as “ant icipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project”, “target” or similar words suggest ing future outcomes or statement s regarding an outlook. Forward-looking information in this present ation includes, but is not limited to, timing for anticipated product ion start from the Wassana redevelopment project, the future tie-on of satellite developments and future of the assets; the abilit y of the Company’s strong financial position to support its growt h projects and for its business to support invest ment plans; the expectation of no furt her cash tax payments in 2025; the timing of drilling on Jasmine/Ban Yen field; the expectation of product ion rates being weight ed to the second half of 2025; the expected reduction in diesel consumpt ion as a result of the Jasmine low-BTU gas generator; timing for completion of the Nong Yao drilling programme; completion of the Company’s purchase of the Manora FSO system; all of the Company’s guidance outlook expectations; and expectations regarding the Farm-in, Including receiving government approval of Thailand's minister of energy. Although the Company believes the expectations and assumptions reflected in such forward-looking information are reasonable, they may prove to be incorrect. Forward-looking information is based on management’s current expectations and assumptions regarding, among ot her things: political stability of the areas in which the Company is operating; continued safet y of operations and abilit y to proceed in a timely manner; continued operations of and approvals fort hcoming from governments and regulat ors in a manner consistent with past conduct; abilit y to achieve extensions to licences in Thailand and Türkiye to support at tract ive development and resource recovery; future drilling activity on the required/ expected timelines; the prospectivity of the Company’s lands; the continued favourable pricing and operating netbacks across its business; future product ion rates and associated operating netbacks and cash flow; decline rates; future sources of funding; future economic conditions; the impact of inflation of future cost s; future currency exchange rates; interest rates; the abilit y to meet drilling deadlines and fulfil commitments under licences and leases; future commodity prices; the impact of the Russian invasion of Ukraine; the impact of conflicts in the Middle East; royalt y rates and taxes; management’s estimate of cumulative tax losses being correct; future capital and ot her expenditures; the success obtained in drilling new wells and working over existing wellbores; the perf ormance of wells and facilities; the availability of the required capital to funds its exploration, development and ot her operations, and the abilit y of the Company to meet its commitments and financial obligat ions; the abilit y of the Company to secure adequate processing, transport ation, fractionation and storage capacity on acceptable terms; the capacity and reliability of facilities; the application of regulat ory requirements respecting abandonment and reclamation; the recoverability of the Company’s reserves and contingent resources; future growt h; the sufficiency of budget ed capital expenditures in carrying out planned activities; the impact of increasing compet it ion; the availability and ident if ication of mergers and acquisition opportunit ies; the abilit y to successfully negotiate and complete any mergers and acquisition opportunit ies; the abilit y to ef ficiently integrate assets and employees acquired through acquisitions; global energy policies going forward; international trade policies; future debt levels; and the Company’s continued abilit y to obtain and retain qualified staff and equipment in a timely and cost ef ficient manner. In addit ion, the Company’s work programmes and budget s are in part based upon expected agreement among joint venture part ners and associated exploration, development and marketing plans and anticipated cost s and sales prices, which are subject to change based on, among ot her things, the actual result s of drilling and related activity, availability of drilling, of fshore storage and of floading facilities and ot her specialised oilf ield equipment and service providers, changes in part ners’ plans and unexpected delays and changes in market conditions. Although the Company believes the expectations and assumptions reflected in such forward-looking information are reasonable, they may prove to be incorrect. Forward-looking information involves signif icant known and unknown risks and uncertainties. Exploration, appraisal, and development of oil and natural gas reserves and resources are speculative activities and involve a degree of risk. A number of factors could cause actual result s to differ mat erially from those anticipated by the Company including, but not limited to: the abilit y of management to execute its business plan or realise anticipated benefits from acquisitions; the risk of disruptions from public healt h emergencies and/or pandemics; compet it ion for specialised equipment and human resources; the Company’s abilit y to manage growt h; the Company’s abilit y to manage the cost s related to inflation; disruption in supply chains; the risk of currency fluctuations; changes in interest rates, oil and gas prices and netbacks; the risk that the Company’s tax advisors’ and/or audit ors’ assessment of the Company’s cumulative tax losses varies signif icant ly from management’s expectations of the same; potent ial changes in joint venture part ner strategies and part icipation in work programmes; uncertainty regarding the contemplated timelines and cost s for work programme execution; the risks of disruption to operations and access to worksites; potent ial changes in laws and regulat ions, including international treaties and trade policies; the uncertainty regarding government and ot her approvals; count erparty risk; the risk that financing may not be available; risks associated with weat her delays and natural disast ers; and the risk associated with international activity. See the most recent annual information form and management’s discussion and analysis of the Company for a detailed discussion of the risk factors. Certain forward-looking information in this present ation may also constitute “financial outlook” within the meaning of applicable securities legislation. Financial outlook involves statement s about Valeura’s prospective financial perf ormance or position and is based on and subject to the assumptions and risk factors described above in respect of forward-looking information generally as well as any ot her specif ic assumptions and risk factors in relation to such financial outlook noted in this present ation. Such assumptions are based on management’s assessment of the relevant information currently available, and any financial outlook included in this present ation is made as of the date hereof and provided for the purpose of helping readers underst and Valeura’s current expectations and plans for the future. Readers are cautioned that reliance on any financial outlook may not be appropriate for ot her purposes or in ot her circumstances and that the risk factors described above or ot her factors may cause actual result s to differ mat erially from any financial outlook. The forward-looking information contained in this present ation is made as of the date hereof and the Company undertakes no obligat ion to update publicly or revise any forward-looking information, whet her as a result of new information, future event s or ot herwise, unless required by applicable securities laws. The forward-looking information contained in this present ation is expressly qualified by this cautionary statement. Maps The Gulf of Thailand maps featured in this press release has been compiled by Valeura based on various public and proprietary data sources. Polygons ident if ied as oil fields and gas fields are not necessarily indicative of commercial viability, nor does the Company represent that aerial extent of such polygons correlates to ultimate potent ial recovery of oil and gas from such accumulations. Oil and Gas Advisories Reserves and contingent resources disclosed in this present ation are based on an independent evaluat ion conduct ed by the incumbent independent petroleum engineering firm, NSAI with an ef fective date of December 31, 2024 and a preparation date of May 14, 2025 post-FID and February 13, 2025 pre-FID. The NSAI estimates of reserves and resources were prepared using guidelines outlined in the Canadian Oil and Gas Evaluat ion Handbook and in accordance with National Instrument 51-101 - St andards of Disclosure for Oil and Gas Activities. The reserves and contingent resources estimates disclosed in this present ation are estimates only and there is no guarantee that the estimated reserves and contingent resources will be recovered. This present ation contains a number of oil and gas met rics, including “NAV”, “RLI”, “EOFL”, and “IRR” which do not have standardised meanings or standard met hods of calculation and therefore such measures may not be comparable to similar measures used by ot her companies. Such met rics are commonly used in the oil and gas industry and have been included herein to provide readers with addit ional measures to evaluat e the Company’s perf ormance; how ever, such measures are not reliable indicators of the future perf ormance of the Company and future perf ormance may not compare to the perf ormance in previous periods. “NAV” is calculated by adding the estimated future net revenues based on a 10% discount rate to net cash, (which is comprised of cash less debt) as of December 31, 2024. NAV is expressed on a per share basis by dividing the total by basic common shares outst anding. NAV per share is not predictive and may not be reflective of current or future market prices for Valeura. “RLI” is calculated by dividing reserves by management’s estimated total product ion before royalt ies for 2025. “EOFL” is calculated by NSAI as the date at which the monthly net revenue generated by the field is equal to or less than the asset’s operating cost. “IRR” is used by management as a measure of the prof itability of a potent ial invest ment. It is calculated as the discount rate that would result in a net present value of zero. 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 specif ied economic conditions, which are generally accepted as being reasonable. Reserves are furt her categorised according to the level of certainty associated with the estimates and may be sub-classif ied based on development and product ion 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. Developed reserves are those reserves that are expected to be recovered from existing wells and inst alled facilities or, if facilities have not been inst alled, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on product ion. Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on product ion, and the date of resumpt ion of product ion must be known with reasonable certainty. Developed non-producing reserves are those reserves that either have not been on product ion, or have previously been on product ion, but are shut in, and the date of resumpt ion of product ion is unknown. Undeveloped reserves are those reserves expected to be recovered from known accumulations where a signif icant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of product ion. They must fully meet the requirements of the reserves classif ication (proved, probable, possible) to which they are assigned. Probable reserves are those addit ional 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. Possible reserves are those addit ional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves. The estimated future net revenues disclosed in this present ation do not necessarily represent the fair market value of the reserves associated therewit h. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the ef fects of aggregat ion. Cont ingent Resources Cont ingent resources are those quantities of petroleum estimated, as of a given date, to be potent ially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Cont ingencies are conditions that must be satisf ied for a port ion of contingent resources to be classif ied as reserves that are: (a) specif ic to the project being evaluat ed; and (b) expected to be resolved within a reasonable timeframe. Cont ingent resources are furt her categorised according to the level of certainty associated with the estimates and may be sub‐classif ied based on a project mat urit y and/or characterised by their economic status. There are three classif ications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a classif ication of estimated resources described in the Canadian Oil and Gas Evaluat ion Handbook as the best estimate of the quantity that will be actually recovered; it is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilist ic met hods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the best estimate. The project mat urit y subclasses include development pending, development on hold, development unclarif ied and development not viable. The contingent resources disclosed in this present ation are classif ied as either development on hold, development unclarif ied, or development not viable. Development on hold is defined as a contingent resource where there is a reasonable chance of development, but there are major non-technical contingencies to be resolved that are usually beyond the control of the operator. Development unclarif ied is defined as a contingent resource that requires furt her appraisal to clarify the potent ial for development and has been assigned a lower chance of development until commercial considerations can be clearly defined. Chance of development is the likelihood that an accumulation will be commercially developed. Conversion of the development unclarif ied resources referred to in this present ation is dependent upon (1) the expected timetable for development; (2) the economics of the project; (3) the marketability of the oil and gas product ion; (4) the availability of infrastructure and technology; (5) the political, regulat ory, and environmental conditions; (6) the project mat urit y and definit ion; (7) the availability of capital; and, ultimately, (8) the decision of joint venture part ners to undertake development. The major positive factor relevant to the estimate of the contingent development unclarif ied resources referred to in this present ation is the successful discovery of resources encountered in appraisal and development wells within the existing fields. The major negative factors relevant to the estimate of the contingent development unclarif ied resources referred to in this present ation are: (1) the outst anding requirement for a definit ive development plan; (2) current economic conditions do not support the resource development; (3) limited field economic life to develop the resources; and (4) the outst anding requirement for a final invest ment decision and commitment of all joint venture part ners. Development not viable is defined as a contingent resource where no furt her data acquisition or evaluat ion is currently planned and hence there is a low chance of development, there is usually less than a reasonable chance of economics of development being positive in the foreseeable future. The major negative factors relevant to the estimate of development not viable referred to in this present ation are: (1) current economic conditions do not support the resource development; and (2) availability of technical knowledge and technology within the industry to economically support resource development. If these contingencies are successfully addressed, some port ion of these contingent resources may be reclassif ied as reserves. Of the best estimate 2C contingent resources estimated in the NSAI Wassana FID Report , on a risked basis: 100% of the estimated volumes are heavy oil; less than 1% are categorised as Development Not Viable, with the remainder categorised as Development Unclarified. There are no Development On Hold resources within the 2C category. MAKING AN INVESTMENT DECI SION, INVESTORS MUST RELY ON THEIR OWN EXAMI NATION OF THE CORPORATION AND THE TERMS OF THE OFFERI NG, INCLUDI N G THE MER I TS AND RISKS INVOLVED. THE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR BY ANY STATE SECURITIES COMMISSION OR REGULATORY AUTHORITY, NOR HAVE ANY OF THE FOREGOING AUTHORITIES OR ANY SECURITIES REGULATOR PASSED ON THE ACCURACY OR ADEQUACY OF THIS PRESENTATION. ANY REPRESENTATION TO THE CONTRARY IS A CRIMI NAL OFFEN SE.
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Recognised Value Delivery Market Data (TSX: VLE) Share price(2) C$8.67/ share Market cap(2) US$670 mm EV(2) US$428 mm Brokers’ 2025F CFO(2) US$265 mm Brokers’ Avg Target Price(2) C$13.0/ Share Shares o/s(2) 106.2 mm Average Daily Volume(3) 521 k shares US$4.7 mm Shareholders(2) Thoresen Thai: 16.5% Baillie Gifford: 15.5% Executive & Board: 6.9% Share Price Performance Since Jan 1, 2022 (TSX: VLE) 0 1 2 3 4 5 6 7 8 9 10 0 1 2 3 4 5 6 7 8 9 10 Volume (mm shares) C$/share C$/share 0 1 2 3 – Acquisition KrisEnergy Thailand Acquisition Mubadala Energy Thailand Key Metrics Production(4) 21.4 mbbls/d LTM oil revenue(5) US$643 mm Cash at bank(6) US$242 mm Debt(6) Nil NAV 2024YE 2P Reserves(7) US$1,103 mm 3 Farm-in PTTEP Thailand Major Recent Achievements Strategic Farm-in(1) ▪ Strategic Partnership with Thailand’s largest operator ▪ Low entry costs ▪ Substantial acreage increase ▪ Initial focus on development of existing discoveries Wassana Redevelopment ▪ FID on major field expansion ▪ Field life extension to 2043 ▪ Compelling economics ▪ Creates a hub for future satellite tie-ins ▪ Construction commenced Q2 Financial Performance ▪ Revenue US$129 million, on lower liftings, lower prices ▪ Capex(8) US$49 million ▪ After tax cash flow from operations US$51 million ▪ Cash(8) US$242 million
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Strategic partnership ▪ PTTEP is the largest oil and gas operator in Thailand ▪ Valeura earns a 40% non-operated working interest(1) ▪ Strategically positioned near major producing gas fields and Valeura’s producing oil fields ▪ Portfolio diversity: adds gas opportunities and infrastructure- led exploration potential ▪ Blocks contain 15 existing oil and gas discoveries Low entry costs ▪ US$14.7 million (Net) in back costs to June 30, 2025 – including block initiation fees and 4 wells drilled to date ▪ Carry PTTEP on cost of extra 3D seismic acquisition next to Valeura’s Nong Yao Field – capped at US$2.2 million (Net) Substantial acreage expansion ▪ Gross acreage increases from 2,623 km2 to 22,757 km2 ▪ Infrastructure-led development/appraisal opportunities in 4 focus areas (2 gas / 2 oil) ▪ Substantial exploration prospectivity Immediate activity ▪ De-risked by historic discoveries and 4 recent wells drilled ▪ 3D Seismic acquisition commencing in Q3 2025 ▪ Near-term development planning ongoing in both blocks Strategic Farm-in with PTTEP: Blocks G1/65 and G3/65 4 Cambodi a/Thai land Overlapping Cl aims Area M alaysia/Thailand Joint Devel opment A r ea Gulf of Thailand Block G3/65 Block G1/65 Valeura (op) Valeura (PTTEP op) PTTEP Chevron Medco Northern Gulf Pet. Overlapping claims Oil field Gas field
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Block G1/65: Near-term Development and Exploration Opportunities 5 Jarmjuree South Gas Discovery Area ▪ Substantially de-risked gas prospect ▪ Between producing Benchamas (Chevron operated) and Platong fields (PTTEP operated) ▪ Recently completed three-well programme to delineate the opportunity ▪ Development planning in the near-term to evaluate tie-back of discoveries ▪ Oil discoveries also in area with potential for mixed-phase tie-backs ▪ Three-way closure structure with several structural/stratigraphic traps ▪ Oil-prone fairway on trend with several fields ▪ Near production infrastructure ▪ Existing 3D seismic to be expanded with acquisition ▪ Project maturation / exploration drilling late 2026 / early 2027 Maratee-Bussaba Oil Prospect Area 3D Seismic Acq’n ▪ 40% working interest (partner/operator PTTEP)(1) ▪ Production Sharing Contract terms: – 6-year exploration period to May 2029 (possible 3 -year extension) – 20-year production phase for fields (possible 10 -year extension) – 10% royalty, cost recovery up to 50%, profit sharing 50%, 20% tax rate ▪ Large block on trend with many prospects: – 8,487km2, over 250km north -south – West of PTTEP-operated gas field producing 774 mmcf/d – 8 oil and gas discoveries, including 12 wells with hydrocarbon pay Benchamas cluster Produced 906 bcf gas + 238 mmbbls oil(2) Platong cluster Produced 2,036 bcf gas + 67 mmbbls oil and condensate (2) Oil fields Gas fields Prospects Block G1/65 Erawan Producing 774 mmcf/d gas (2)
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Block G3/65: Near-term Development and Exploration Opportunities 6 3D Seismic Acquisition ▪ Oil-bearing fairway between Nong Yao and Ubon oil fields ▪ 3D seismic acquisition in 2025 ▪ Exploration and appraisal drilling planned for early 2027 ▪ Within tie-in distance to Valeura’s (90%) Nong Yao infrastructure ▪ Multiple gas discoveries ▪ Immediately west of PTTEP’s Bongkot gas field ▪ Recent successful gas well drilled by PTTEP ▪ Potential for a fast-track gas development tied back to Bongkot ▪ Immediately progressing to development planning phase ▪ 40% working interest (partner/operator PTTEP)(1) ▪ Production Sharing Contract terms: – 6-year exploration period to May 2029 (possible 3 -year extension) – 20-year production phase for fields (possible 10 -year extension) – 10% royalty, cost recovery up to 50%, profit sharing 50%, 20% tax rate ▪ Large block on trend with many prospects: – 11,647km2, 194km north-south – West of PTTEP -operated gas field – 7 oil and gas discoveries, including 15 wells with hydrocarbon pay Nong Yao Producing 10 mbbls/d oil(2) Ubon Undeveloped oil Bongkot Producing 821 mmcf/d gas, 23.5 mbbls/d cond. (2) 3D Seismic Acquisition Oil fields Gas fields Prospects Licence G3/65 Licence G11/48 MTJDA Bussabong Gas Discovery Area Nong Yao North-East Oil Prospect
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Nong Yao: Block G11/48, 90% (op) 8.8 mbbls/d(1) Wassana: Block G10/48, 100% (op) 3.4 mbbls/d(1) Jasmine: Block B5/27, 100% (op) 8.1 mbbls/d(1) Manora: Block G1/48, 70% (op) 2.3 mbbls/d(1) Material Producing Portfolio With Upside 7 ▪ Reserves increased from 2.5 to 20.5 mmbbls(2) ▪ Major field redevelopment work underway, with first oil Q2 2027 ▪ Field life extended into the 2043, with further satellite developments possible ▪ Most profitable field with >50% of 2P reserves value ▪ Significant production increase in 2024 after new facility, infill drilling in 2025 ▪ New oil discovery at Nong Yao D in H1 2024 with followup drilling planned ▪ Production and Reserves continue to greatly exceed expected recovery – current produced oil ~13X FID 2P Reserves ▪ 13 further development and appraisal wells planned in 2025 ▪ Field life extended by >4 years under Valeura operatorship ▪ Multiple oil accumulations encountered in 2023 & 2024 drilling Thailand Myanmar Cambodia Malaysia Block G3/65, 40% (non-op) Exploration/development ▪ Very large block adjacent to major producing fields and within tie-in range ▪ Nong Yao NE a logical oil satellite for Valeura’s Nong Yao field, 3D seismic planned ▪ Bussabong gas area immediately west of large Bongkot gas field Block G1/65, 40% (non-op) Exploration/development ▪ Very large block adjacent to major producing fields and within tie-in range ▪ Jarmjuree South area substantially de-risked and disclosed as gas discovery ▪ Maratee-Bussaba area in an oil-prone fairway south of Rossukon, 3D seismic planned Oil Production Gas/Oil exploration/development(3)
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Wassana Redevelopment 35 62 MOPU CPP Optimum Design 3.7 10.0 1Q 2025 2H 2027 with CPP Production Growth Nameplate Capacity (mbbls/d) Reserves Increase Life Extension 1.0 17.0 MOPU CPP (2) (3) Production (bbls/d)(1) Lifespan from Jan 1, 2027 (years) Strong & Resilient Economics IRR(4) @ US$60/bbl Brent: 40% 2P NPV10(5): US$218 million Payback @ US$60/bbl Brent: 18 months Adjusted Opex(4)/bbl US$12-16 /bbl 8 (2) (3) 2P Reserves (mmbbl) 2.5 20.5 No further action Redevelopment Final Investment Decision in May 2025 ▪ Major Wassana field expansion ▪ New central processing platform, higher capacity ▪ Longer design life, to 2043+ ▪ De-risked development to commercialise new reserves ▪ Rapid development: 24-months FID to first oil ▪ Highly compelling and resilient economics ▪ Significant upside through hub-and-spoke development potential Project Progress Update ▪ Project is on track ▪ Purchase Orders placed for all major packages ▪ Construction underway ▪ Aggregate progress: approximately 20% complete
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Wassana Redevelopment Construction Underway EPCC Contract and First Steel Cutting Ceremony First Steel Cutting Platforms Under Construction at TNS’ Facility 9
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2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 … 2043 +2.7 years+2.5 yearsJasmine +2.8 years+1.5 yearsManora +5.0 years+1.4 yearsNong Yao +5.2 years +4.3 years +6.4 years +17.0 years Field Life Extended for Every Field 10 NSAI 2022 Report NSAI 2023 Report NSAI 2024 Report Wassana field redevelopment: ▪ Redevelopment expands reserves ▪ Increases anticipated production ▪ Extends field life to 2043 ▪ Facilitates satellite field development for further extensions Organic growth drives multiple years of additional cash flow generation 2P End of Field Life(1) +3.5 years+4.8 yearsWassana
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Q2 2025 Financial Results Highlights 11 Q2 2025 Production 21.4 mbbl/d Q2 2025 Oil Revenue US$129 mm Q2 2025 Adj CFO(1) US$51 mm FINANCIAL HIGHLIGHTS Q2 2025 Lifting 1.90 mmbbls Q2 2025 Adj EBITDAX(1) US$62 mm Book Value (1) US$542 mm Up 71% vs Q2 2024 Adj WC (1,2) US$262 mm Up 81% vs Q2 2024 Net Cash (2) US$242 mm Up 65% vs Q2 2024 BALANCE SHEET at June 30, 2025 Q2 2025 Opex / Opex per bbl (1) US$55 mm /US$28.0/bbl Q2 2025 Capex(1) US$49 mm Revenues Drivers Expenses Drivers Q2 2025 Realised Price US$67.9/bbl Q2 2025 Highlights Q2 2025 Adj Pre -Tax CFO(1) US$52 mm
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129 51 (17) (55) (6) (1) Revenues Royalties Adj Opex SG&A PITA & SRB Adj CFO Q2 2025 Cashflow Bridge: High Margin Barrels 12 Q2 2025 Financials (US$ mm) Lifting: 1.90 mmbbls Realised Price: US$67.9/bbl▪ Lifted/Sold 1.90 mmbbls of oil at an average realised price of US$67.7/bbl - Lifting/sales timing led to a slight oil inventory further build-up at quarter end (0.93 million bbls) - Realised price continues to achieve a premium vs. Brent - US$0.7/bbl premium in Q2 2025 ▪ Q2 Revenues of US$129 mm ▪ No accrued PITA tax liability, due to tax consolidation - Utilised US$22 mm of tax losses in the quarter ▪ Adj CFO of US$51 mm (1) (1)
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Q2 2025 Cash Bridge: Strong Balance Sheet 13 Q2 2025 Financials (US$ mm) ▪ Capex of US$49 mm which includes US$11.2 mm associated with Wassana Redevelopment ▪ Exploration expense of US$4 mm, mostly related to Ratree well ▪ Other income of ~US$2 mm(2) ▪ Paid US$16 mm related to prior year taxes ▪ Deployed US$4.3 mm on NCIB and anti-dilution purchases during the quarter(3) ▪ Cash balance at quarter end of US$242 mm (1) (2) 239 262 242 51 (49) (4) 2 23 (16) (4) Cash Balance @ 31 Mar 2025 Adj CFO Capex Expex Other income/ revenues Change in WC Profrma Cash Balance @ 30 Jun 2025 2024 Tax payment NCIB + anti dilution purcheses Cash Balance @ 30 Jun 2025 (3)
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Reaffirming 2025 Guidance 14 Recent 2025 Guidance H1 2025 Production(1) 23.0 – 25.5 mbbls/d 22.6 mbbls/d Opex(2) US$215 – 245 million US$106 million Capex(2) & Exploration expense US$175 – 195 million US$86 million Free Cash Flow (3) US$80 – 195 million US$65/bbl – US$85/bbl Brent US$43 million ▪ Previous guidance reaffirmed ▪ Production weighted to 2nd half of the year - Recent facilities & drilling has increased production to 23.2 mbbls/d(4) - Up 8% on Q2 2025 average ▪ Combined Capex and Exploration expense - Includes addition of ~US$40 million Wassana FID spending in 2025 - Focus on development drilling for remainder of 2025 given large exploration farm-in To be further updated following closing of the G1/65 and G3/65 Farm-in
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NAV (After Tax) (US$ million) • 2P NAV of over US$1.1 billion • Equates to C$14.84/share ✓ Net cash ~C$3.49 /share and underlying NPV10 more than C$11/share • Valeura delivered a NAV CAGR of over 80% Valeura Delivered a NAV CAGR of +80% Since Taking Over the Assets 15 NAV (After Tax) Per Share vs Share Price (C$/share) 4.17 7.56 13.61 14.84 - 3.00 6.00 9.00 12.00 15.00 18.00 NAV / Share (CAD$) Share Price (CAD$) (3) (2) 2023 YE 2024 YE 2022 YE (1) 10.12 14.843.49NAV/share (C$) (4) Revised 2024 YE 752 1,012 92 1,104 2024YE NPV10 31 Dec 2024 Net Cash 2024YE NAV10 FID Adjustment - Post Wassan FID Revised 2024YE NAV10(3) (4)(4) 13.61 1.24 9%
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Q&A Session Dr. Sean Guest President and CEO Yacine Ben-Meriem CFO Dr. Greg Kulawski COO Robin Martin VP, Communications and Investor Relations Speakers: Moderator:
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Government Company Thailand Production Sharing Contract Fiscal Regime 17 Fiscal Terms ▪ Fixed royalty of 10% on production revenue ▪ Cost recovery up to 50% of production revenue – Unrecovered (excess) costs may be carried forward – Includes operating costs, capex, exploration spending, and G&A, as agreed in annual work programme and budget ▪ Remaining profit shared 50% government / 50% company – Government/company entitlements calculated quarterly ▪ Corporate income tax 20% of net profit – Deductions for DD&A – Taxes payable in August (for H1) and May (for prev year’s H2) Key Attributes ▪ 6-year exploration period, with 3-year extension possible – 25% acreage relinquishment required upon extension – Remaining acreage to be relinquishe d at end of exploration period ▪ 20-year production period, with 10-year extension possible ▪ No ring-fencing (costs incurred anywhere on the block can be included in cost recovery) ▪ Annual work programme and budget subject to approval by upstream regulator (Department of Mineral Fuels) Production (Revenue) Sharing Illustration (Costs Incurred) Production Royalty Cost Oil/Gas Profit Share Profit Share Tax Pre-tax Entitlement Production Sharing Project Profit Oil/Gas Post-tax Entitlement 10% of Production 50% 50% Up to 50% Production 20% on taxable income
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1.6x 0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 12.0x 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 1.4x 0.0x 2.0x 4.0x 6.0x 8.0x 10.0x 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 6.1x 0.0x 5.0x 10.0x 15.0x 20.0x 25.0x 30.0x 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Peer Group Trading multiples Material Upside to the Current Valuation 18 Peer Group EV / 2025E FCF (x)(1,2) Current Valuation Indicates A Significant Upside Peer Group EV / 2025E CFO (x)(1,2) (4) Peers’ Median: 3.5x Valeura traders at a significant discount to Peers Current share price not reflective of inherent value Peers’ Median: 2.3x Peer Group EV / 2025E EBITDA (x)(1,2) Peers’ Median: 9.1x (3) 8.67 14.84 12.98 - 2.00 4.00 6.00 8.00 10.00 12.00 14.00 16.00 18.00 Current Share Price (Aug 5, 2025) Implied NSAI 2P NAV Analysts Concensus
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Footnotes 19 Slide 3: Recognised Value Delivery 1) Completion of Farm -in subject to Government of Thailand approval Note: Map based on various public and proprietary sources. See disclaimers in July 25, 2025 press release Slide 4: Strategic Farm-in with PTTEP: Blocks G1/65 and G3/65 1) Completion of Farm -in subject to Government of Thailand approval 2) Source: Thailand Department of Mineral Fuels Note: Map based on various public and proprietary sources. See disclaimers in July 25, 2025 press release Slide 5: Block G1/65: Near-term Development and Exploration Opportunities 1) Completion of Farm -in subject to Government of Thailand approval 2) Source: Thailand Department of Mineral Fuels Note: Map based on various public and proprietary sources. See disclaimers in July 25, 2025 press release Slide 6: Block G3/65: Large Exploration Block with Immediate Focus Areas 1) H1 2025 average working interest share production before royalties 2) Proved plus probable gross (before royalties) per Company’s internal assessment (non -independent) effective December 31, 2021 an d per Netherland Sewell and Associates (“NSAI”) effective December 31, 2024 3) Subject to closing of PTTEP Farm -in, pending government approval Slide 7: Material Producing Portfolio With Upside 1) Production before royalties 2) Management’s estimate of remaining recoverable oil before MOPU decommissioning at end 2027. 3) NSAI Wassana FID Report, as of December 31, 2024, more fully described in May 14, 2025 press release. 4) Non-IFRS Measure – Please refer to Management’s Discussion and Analysis dated August 7, 2025 for reconciliation with financial s tatement 5) NPV10 of 2P reserves as of December 31, 2024, as per NSAI Wassana FID Report as described in the May 14, 2025 press release. Slide 8: Wassana Redevelopment 1) Farm-in closing subject to government approval 2) August 6, 2025 3) ADTV 30 as of August 6, 2025 4) Q2 2025 average working interest share production before royalties 5) 12-months to June 30, 2025 6) June 30, 2025 7) NPV10 of 2P reserves as of December 31, 2024, as per NSAI 2024 Report and NSAI Wassana FID Report plus December 31, 2024 cash bala nce of US$259mm. 8) Non-IFRS Measure – Please refer to Management’s Discussion and Analysis dated August 7, 2025 for reconciliation with financial s tatement
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20 Footnotes (continued) 1) Based on Dec 31, 2024 2P gross (before royalties) working interest share reserves Slide 10: Field Life Extended for Every Field 1) Non-IFRS Measure – Please refer to Management’s Discussion and Analysis dated August 7, 2025 for reconciliation with financial s tatement 2) Includes restricted cash Slide 11: Q2 2025 Financial Results Highlights 1) Non-IFRS Measure – Please refer to Management’s Discussion and Analysis dated August 7, 2025 for reconciliation with financial s tatement Slide 12: Q2 2025 Cashflow Bridge: High Margin Barrels 1) Non-IFRS Measure – Please refer to Management’s Discussion and Analysis dated August 7, 2025 for reconciliation with financial s tatement 2) Represents Other Income as per the FS minus refund from prior owner of the Thai assets related to tax adjustment payments acc rued prior to Valeura take over of the assets, and FX gain/loss 3) Anti dilution purchases represents cash out and cancelation/non issuance of options and PSUs & RSUs, that would have otherwis e led to an increase in share count Slide 13: Q2 2025 Cash Bridge: Strong Balance Sheet Slide 14: Reaffirming 2025 Guidance 1) Based on Dec 31, 2022 2P NPV 10 after tax plus net cash of US$6.4 million at Dec 31, 2022, and assuming US$/C$ exchange rate of 1.359 and 87.15 million commo n shares outstanding 2) Based on Dec 31, 2023 2P NPV 10 after tax plus net cash of US$151.2 million at Dec 31, 2023 (no debt), and assuming US$/C$ exchange rate of 1.342 and 102.96 million common shares outstanding 3) Based on Dec 31, 2024 2P NPV 10 after tax plus net cash of US$259.4 million at Dec 31, 2024 (no debt), and assuming US$/C$ exchange rate of 1.435, and 106.65 million common shares outstanding 4) NSAI Wassana FID Report, as of December 31, 2024, more fully described in May 14, 2025 press release Slide 15: Valeura Delivered a NAV CAGR of +80% Since Taking Over the Assets Slide 18: Valeura Trades at a Discount to Peers 1) Peer group comprised of 19 upstream companies (IPC, Africa Oil,, Frontera Energy, Amplitude Energy, Tullow Oil, Vaalco Energy, Hibiscus Petroleum, Enquest, Jadestone Energy, PetroTal, Gran Tierra Energy, Canacol Energy, Genel Energy, Parex, Capricorn Energy, Pharos Energy, Karoon Energy, Panoro Energy 2) As per Factset as of Aug 5, 2025 – Certain peer group companies excluded due negative/not available EBITDA or CFO 3) Refer to Wassana Redevelopment announcement details. NAV adjusted for current FX and outstanding share count 4) Latest Analysts' targets dated Aug5, 2025, Analysts consists of Cormark, Auctus, Stiflel, Canaccord, and Research Capital 1) Average working interest share production before royalties. 2) Adjusted Opex and Adjusted Capex are Non -IFRS Measures – Please refer to Management’s Discussion and Analysis dated August 7, 2025 for reconc iliation with financial statement 3) Assumes, production = Lifting; assumes mid point of the production, adj Opex, and adj Capex & Expex; Assumes realised premium of US$2.3/ bbl over Brent 4) August production, ending August 5, 2025
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General Corporate Inquiries Sean Guest, President and CEO Yacine Ben-Meriem, CFO +65 6373 6940 Contact@valeuraenergy.com Investor / Media Inquiries Robin Martin, VP , Communications and Investor Relations +1 403 975 6752 / +44 7392 940495 IR@valeuraenergy.com