Valeura Energy Inc.: Strong 2025 Delivery

SINGAPORE, March 18, 2026 (GLOBE NEWSWIRE) — Valeura Energy Inc. (TSX:VLE, OTCQX:VLERF) (“Valeura” or the “Company”) reports its financial and operating results for the three month period and year ended 31 December 2025.

The complete reporting package including audited financial statements, management’s discussion and analysis (“MD&A”), and the 2025 annual information form (“AIF”), will be filed on SEDAR+ at www.sedarplus.ca and posted to the Company’s website at www.valeuraenergy.com.

Operations Highlights

• Oil production of 23.2 mbbls/d⁽¹⁾ and oil sales of 8.5 million bbls for full year 2025;
• Successful development and appraisal drilling across the portfolio on the Jasmine/Ban Yen, Manora, and Nong Yao fields;
• Proved plus probable (“2P”) reserves replacement ratio of 192%;
• Reserves life index increased to a new Company record of 7.5 years, on a 2P basis; and
• Greenhouse gas (“GHG”) intensity reduced by 12% for full year 2025, yielding approximately a 30% reduction since Valeura originally acquired its Thailand portfolio in 2023.

Strategic Highlights

• Final investment decision taken on the Wassana field redevelopment, which will entail deployment of a new-build central processing platform (“CPP”) facility on the field;
• Strategic farm-in agreement with a subsidiary of PTT Exploration and Production Plc (“PTTEP”) to pursue exploration and infrastructure-led development opportunities on Blocks G1/65 and G3/65, offshore Gulf of Thailand⁽²⁾ (the “PTTEP Farm-In Agreement”); and
• Joint venture with a subsidiary of Transatlantic Petroleum LLC (“Transatlantic”) to explore and develop the deep rights formations of the Thrace basin of northwest Türkiye (the “Transatlantic JVA”).

Financial Highlights

• Revenue of US$594.4 million based on average full year realised price of US$70.2/bbl;
• Adjusted after tax cashflow from operations of US$247.4 million⁽³⁾;
• Adjusted Opex of US$222.7 million, equating to US$26.3/bbl⁽³⁾; and
• Cash and net cash balance as of 31 December 2025 of US$305.7 million^(3,4), with no debt.

      (1)   Working interest share production, before royalties.
      (2)   Subject to approval from the Government of Thailand.
      (3)   Non-IFRS financial measure or non-IFRS ratio – see “Non-IFRS Financial Measures and Ratios” section.
      (4)   Includes restricted cash of US$23.0 million.

Dr. Sean Guest, President and CEO commented:

“Valeura delivered an exceptional 2025, one that demonstrates the power of our strategy in action. We strive to add value through disciplined organic investment and targeted inorganic transactions, all underpinned by a commitment to operational excellence.

Our decision to re-invest into our portfolio by way of the Wassana field redevelopment project is a compelling example. It has not only strengthened our core business for the long run, but has immediately grown our reserves by unlocking the Wassana field’s potential for significantly longer field life. Combined with other life-extending works across the portfolio, the result is yet another significant increase in reserves. For the third consecutive year, we have achieved approximately 200% reserves replacement ratio on a 2P basis.

Strategic transactions like our farm-in to PTTEP’s Blocks G1/65 and G3/65 demonstrate that by building the right relationships, we can meaningfully expand our portfolio. This opportunity brings both exploration opportunities and discovered resources that are expected to convert quickly into production and cash flow. We have set the scene for significant further growth. With US$306 million in cash and zero debt, we are exceptionally well-positioned to pursue larger, transformational opportunities through M&A.

Our operational performance in 2025 was equally strong. We held Adjusted Opex⁽¹⁾ to approximately US$26/bbl, the product of countless continuous improvement initiatives and smart structural decisions such as owning, rather than leasing, key facilities across our operations. Critically, operational excellence goes beyond costs. Despite growing our production, we reduced our absolute greenhouse gas emissions, meaning our emissions intensity was reduced for the third year in a row.

Continued execution across our business has established Valeura as one of the top-performing companies in our sector, delivering year-on-year share price growth. That delivery is amplified by the dramatically different oil price environment we find ourselves facing today, which is in stark contrast to the relatively low prices we saw through much of 2025. Our industry is no stranger to volatility, and we maintain a suite of strategic plans for how best to respond to such changes.

We have today opted to accelerate some projects, which will see us immediately invest more into our largest and most profitable producing field to facilitate more infill drilling. The US$7 million project entails adding four additional well slots to the Nong Yao A facility, which will allow us to more aggressively pursue development drilling targets at the Nong Yao field later this year. At the same time, we are reviewing various exploration and development opportunities across the portfolio to potentially accelerate as well, while remaining committed as always to our strict investment criteria.

Our strategy is working and we have laid a compelling foundation for what promises to be an even more exciting 2026 and beyond.”

       (1)   Non-IFRS financial measure or non-IFRS ratio – see “Non-IFRS Financial Measures and Ratios” section below.

Financial and Operating Results Summary

       (1)   Working interest share production before royalties.
       (2)   Non-IFRS financial measure or non-IFRS ratio – see “Non-IFRS Financial Measures and Ratios” section below.
       (3)   Includes restricted cash

Financial Update

Valeura’s 2025 financial performance was characterised by the combined effect of a relatively heavy investment phase, coupled with low benchmark oil prices. Full year Adjusted Capex⁽¹⁾ was US$188.7 million, which was within the Company’s spending guidance for the year, but 41% higher than 2024. Adjusted Capex⁽¹⁾ was largely driven by a full year of drilling operations as well as the start of the Wassana redevelopment project. While the business has remained robust and generated meaningful Adjusted Cashflow from Operations of US$247.4 million, the impact of lower benchmark oil prices is apparent in comparison to 2024 on various metrics.

The Company’s Q4 2025 oil production averaged 24,721 bbls/d (working interest share before royalties), down 5% from Q4 2024. The modest quarter-over-quarter reduction reflects the timing of the active drilling campaign, with new wells coming on production toward the end of the year and the benefit becoming visible in early 2026. For the full year, production averaged 23,242 bbls/d, broadly in line with the prior year, with output gains at the Jasmine/Ban Yen and Nong Yao fields offsetting natural declines at the Manora and Wassana fields. Full year oil sales were 8.5 million bbls, essentially flat versus 8.4 million bbls in 2024.

The Company generated Q4 2025 revenue of US$161.4 million, down 29% from Q4 2024, reflecting a weaker oil price environment. Full year 2025 revenue was US$594.4 million, also reflecting the impact of lower prices versus the prior year’s revenue of US$678.8 million. Valeura’s oil continues to attract a premium to the Brent benchmark: Q4 2025 realisations averaged US$64.0/bbl, representing a US$0.4/bbl premium, while the full year average of US$70.2/bbl reflected a US$1.6/bbl premium to Brent.

The Company’s Adjusted Opex per barrel⁽¹⁾ has remained well below rates at the time of Valeura’s acquisition of its Thailand portfolio, demonstrating the Company’s focus on efficiency. Q4 2025 Adjusted Opex was modestly elevated at US$28.1/bbl, primarily due to a planned underwater inspection work at the Wassana mobile offshore producing unit (“MOPU”). For the full year 2025, Adjusted Opex per barrel⁽¹⁾ was US$26.3/bbl, in line with US$25.7/bbl in 2024. On a year-over-year basis, Adjusted Opex⁽¹⁾ reflects increased maintenance expenses of the Nong Yao MOPU, for which the lease commenced in July 2024 and therefore contributed only partially to the 2024 cost base, plus expenses associated with extending the life of the Jasmine field’s Floating production storage and offloading system. These increases were largely offset by lower operating expenses in various other areas of the portfolio.

Valeura incurred total corporate and petroleum income taxes of US$2.4 million and special remuneratory benefit (“SRB”) tax of US$19.8 million, during the full year 2025. This compares favourably to US$68.3 million and US$29.2 million in the previous year. The substantial reduction in petroleum income taxes is a direct result of the Company’s more optimised tax structure, implemented through its internal restructuring of subsidiaries effective 01 November 2024. Under the new structure, Valeura is using income tax loss carry-forwards originating from its acquisition of the Wassana field to offset taxable income from all of its Thai III petroleum concessions, being Wassana, Nong Yao, and Manora. As at 31 December 2025, Valeura had cumulative tax loss carry-forwards of US$282.8 million. The decrease in SRB was driven by reduced selling prices, resulting in lower taxable income for SRB purposes.

Valeura closed 2025 with a cash position of US$305.7 million, including US$23.0 million in restricted cash, an 18% increase year-on-year. The Company remains entirely debt-free and is optimally positioned to pursue both organic portfolio investment and value-accretive strategic acquisitions.

Operations Update and Outlook

During 2025, Valeura had ongoing production operations at all of its Gulf of Thailand fields including Jasmine, Manora, Nong Yao, and Wassana. Total working interest share oil production before royalties averaged 24,721 bbls/d during Q4 2025 and 23,242 bbls/d for the full year (all production figures are working interest share before royalties). One drilling rig was under contract for the full year.

Jasmine/Ban Yen

Oil production before royalties from the Jasmine/Ban Yen field, in Licence B5/27 (100% operated interest) averaged 8,711 bbls/d during Q4 2025. The Company drilled one deviated and eight horizontal wells on the Jasmine and Ban Yen fields, targeting unswept oil accumulations within producing reservoirs. All nine wells were successful and have been completed as producers. Production rates increased from approximately 7,300 bbls/d over the seven-day period prior to the drilling programme to approximately 8,600 bbls/d over the seven-day period immediately after, and have since continued to climb, reaching an average of approximately 9,000 bbls/d over the first 10 days of March 2026.

Licence B5/27 continues to deliver strong production performance, despite being the most mature asset in the Company’s portfolio. In addition to driving higher production rates, ongoing drilling efforts are identifying further oil accumulations that create opportunities for potential development. This incremental resource growth enhances the Jasmine/Ban Yen field’s ultimate recovery potential and supports an extended economic life for the field.

In addition, Valeura is assessing additional exploration prospects within other parts of the concession area to be incorporated into a future drilling campaign.

Nong Yao

The Company’s Q4 2025 working interest share oil production before royalties from the Nong Yao field, in Licence G11/48 (90% operated working interest), averaged 11,009 bbls/d. Although no wells were drilled during Q4 2025, oil production rates continue to demonstrate the impact of the successful ten-well drilling programme completed in Q3 2025.

The Nong Yao field is the Company’s largest source of oil production and offers several opportunities for further growth. This includes the 2024 discovery of the Nong Yao D accumulation, additional prospects to the south of the field, and the potential to access accumulations on the adjacent Block G3/65, within an oil prone fairway known as Nong Yao Northeast.

In addition, Valeura sees further opportunities to add to production in the vicinity of the Nong Yao A facility. As a result, the Company has decided to pursue a production acceleration strategy which will entail expanding the Nong Yao A facility with four additional well slots and related flow lines. This will enable further infill drilling without requiring existing wells to reach the end of their productive lives before being repurposed as donor slots for new wells. The project is budgeted at approximately US$7 million (Valeura’s working interest share). Engineering work will commence immediately, leading to construction in the second half of 2025 and a slot readiness target of November 2026.

Wassana

During Q4 2025, oil production before royalties from the Wassana field, in Licence G10/48 (100% operated interest) averaged 2,856 bbls/d. No wells were drilled on the licence in Q4 2025. Ongoing work on the production facility (the MOPU Ingenium) consists of routine maintenance and repairs to maintain the facility in good working order prior to the Wassana field redevelopment project coming online.

In May 2025, Valeura took a final investment decision on the Wassana field redevelopment project, which entails building and deploying a CPP facility on the Wassana field. As at 31 December 2025, the project was approximately 45% complete, and has since progressed to approximately 56% completion. The Wassana field redevelopment project is on schedule and on budget for installation of the new CPP facility in late 2026 with first production targeted for Q2 2027. The Wassana redevelopment project is expected to more than double the production from the Wassana field, reduce unit costs, and importantly extend production from the field into the 2040’s. In addition, the new Wassana CPP is expected to serve as a hub for eventual tie-in of potential additional satellite wellhead platforms.

Valeura is evaluating development options for additional oil accumulations on Block G10/48 and is considering additional exploration and appraisal opportunities to be potentially included in its 2026 drilling programme. Valeura is evaluating drilling targets to further appraise the size of potential satellite oil accumulations, subject to its approach of continually optimising the exploration and appraisal drilling programme.

Manora

Valeura’s working interest share production before royalties from the Manora field, in Licence G1/48 (70% operated working interest) averaged 2,145 bbls/d during Q4 2025.

No wells were drilled on Licence G1/48 during Q4 2025, but the Company drilled a three-well campaign on the Block in January and February 2026 comprised of two infill development targets and one appraisal well. On 09 March 2026, Valeura announced that all wells were successful and notably the appraisal well was found to be optimally positioned for use as a production well. As a result, all three wells have been completed as oil producers and are now on stream.
  
Blocks G1/65 and G3/65

On 25 July 2025, Valeura announced that it had entered into the PTTEP Farm-In Agreement to earn a 40% non-operated working interest in Blocks G1/65 and G3/65 (the “Blocks”), in the offshore Gulf of Thailand. To earn its interest, Valeura will pay 40% of actual back costs related to the Blocks and will carry PTTEP on an additional seismic survey to the northeast of the Nong Yao field. Upon completion (which is subject to the approval of the Government of Thailand), the PTTEP Farm-in Agreement will result in a substantial expansion of Valeura’s gross acreage position in Thailand from 2,623 km² to 22,757 km² and will provide access to discoveries and exploration prospects that can be tied back quickly to existing oil and gas infrastructure.

During Q4 2025, Valeura and PTTEP progressed development planning pertaining to the gas discovery made on Block G3/65 earlier in 2025 in combination with several historic discoveries, all which are covered by existing 3D seismic data. In addition, newly acquired 3D seismic data covering several other focus areas on the Blocks is being processed and results are expected to be delivered in mid-2026. This new 3D seismic data will inform further discussions about potential exploration, appraisal, and development opportunities on the Blocks.

Valeura is currently working in partnership with PTTEP and independent experts to assess the full resource potential of the Blocks and intends to disclose its findings in the first half of 2026.

Türkiye Deep Gas Play

On 15 October 2025, Valeura announced that it had entered into the Transatlantic JVA to explore for and develop hydrocarbons in the deep gas play in the Thrace basin of northwest Türkiye. Transatlantic was granted an opportunity to earn a 50% working interest in Valeura’s lands in Türkiye through two phases of operations; first, through the re-entry and testing of the Company’s Devepinar-1 exploration well, and second, by an option to drill a new deep appraisal well.

Activity began in the Thrace Basin lands in Q4 2025 including hydraulic stimulation and testing of the Devepinar-1 well. Following gas flowing to surface through the well’s casing, Transatlantic has opted to equip the well with production tubing to conduct a longer-term production test, which is currently underway. As a result of the work performed to date on the Devepinar-1 well, Transatlantic is entitled to a 50% undivided working interest in the western portion of the Company’s lands, as more fully described in Valeura’s 15 October 2025 press release, with the actual assignment of interest to occur in due course.

Reserves and Resources Summary

The results of Valeura’s third-party independent reserves and resources assessment for its Thailand assets as of 31 December 2025 were announced on 13 February 2026. Below are summary tables associated with the reserves.

Summary of Reserves Replacement, Value, and Field Life

 
Summary of NPV and NAV

      (1)   Proved reserves (“1P”)
      (2)   Proved plus probable plus possible reserves (“3P”)
      (3)   Cash at 31 December 2025 of US$305.7 million
      (4)   Issued and outstanding common shares of Valeura as at 31 December 2025
      (5)   US$/C$ exchange rate of 1.3722 at 31 December 2025

Webcast

Valeura’s management team will host an investor and analyst webcast at 08:00 Calgary / 14:00 London / 21:00 Bangkok / 22:00 Singapore on Thursday, 19 March 2026 to discuss today’s announcement. Please register in advance via the link below.

Registration link: https://events.teams.microsoft.com/event/af43254e-4f10-4c6e-b6fa-f6ed38abe3f4@a196a1a0-4579-4a0c-b3a3-855f4db8f64b

As an alternative, an audio only feed of the event is available by phone using the Conference ID and dial-in numbers below.

Thailand: +66 2 026 9035,,922648874#
Singapore: +65 6450 6302,,770 821 822#
Canada: (833) 845-9589,,770 821 822#
Türkiye: 0800 142 034779,,770 821 822#
United States: (833) 846-5630,,770 821 822#
United Kingdom: 0800 640 3933,,770 821 822#

Phone conference ID: 770 821 822#

For further information, please contact:

Valeura Energy Inc. (General Corporate Enquiries)                +65 6373 6940
Sean Guest, President and CEO
Yacine Ben-Meriem, CFO
Contact@valeuraenergy.com  

Valeura Energy Inc. (Investor and Media Enquiries)                +1 403 975 6752 / +44 7392 940495
Robin James Martin, Vice President, Communications and Investor Relations
IR@valeuraenergy.com

Contact details for the Company’s advisors, covering research analysts and joint brokers, including Auctus Advisors LLP, Beacon Securities Limited, Canaccord Genuity Ltd (UK), Cormark Securities Inc., Research Capital Corporation, Roth Canada Inc., and Stifel Nicolaus Europe Limited, are listed on the Company’s website at www.valeuraenergy.com/investor-information/analysts/.

About the Company

Valeura Energy Inc. is a Canadian public company engaged in the exploration, development and production of petroleum and natural gas in Thailand and Türkiye. The Company is executing a growth-oriented strategy, reinvesting into its producing asset portfolio while deploying capital toward further organic and inorganic growth across Southeast Asia. Valeura is committed to delivering value-accretive growth for all stakeholders, underpinned by high standards of environmental, social and governance responsibility.

Additional information relating to Valeura is also available on SEDAR+ at www.sedarplus.ca.

Oil and Gas Advisories

Reserves and contingent resources disclosed in this news release are based on an independent evaluation conducted by the incumbent independent petroleum engineering firm, NSAI with an effective date of 31 December 2025. The NSAI estimates of reserves and resources were prepared using guidelines outlined in the Canadian Oil and Gas Evaluation Handbook and in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. The reserves and contingent resources estimates disclosed in this news release are estimates only and there is no guarantee that the estimated reserves and contingent resources will be recovered.

This news release contains a number of oil and gas metrics, including “NAV”, “reserves replacement ratio”, “RLI”, and “end of field life” which do not have standardised meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies. Such metrics are commonly used in the oil and gas industry and have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance 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 31 December 2025. NAV is expressed on a per share basis by dividing the total by basic common shares outstanding. NAV per share is not predictive and may not be reflective of current or future market prices for Valeura.

“Reserves replacement ratio” for 2025 is calculated by dividing the difference in reserves between the NSAI 2025 Report and the previous independent engineering evaluation of the reserves attributable to the Company’s four licences in the offshore Gulf of Thailand prepared by NSAI, plus actual 2025 production, by the assets’ total production before royalties for the calendar year 2025.

“RLI” is calculated by dividing reserves by management’s estimated total production before royalties for 2026.

“End of field life” 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.

Reserves

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

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production.

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 production, and the date of resumption of production must be known with reasonable certainty.

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Possible reserves are those additional 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 news release do not necessarily represent the fair market value of the reserves associated therewith.

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 effects of aggregation.

Contingent Resources

Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially 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. Contingencies are conditions that must be satisfied for a portion of contingent resources to be classified as reserves that are: (a) specific to the project being evaluated; and (b) expected to be resolved within a reasonable timeframe.

Contingent resources are further categorised according to the level of certainty associated with the estimates and may be sub‐classified based on a project maturity and/or characterised by their economic status. There are three classifications of contingent resources: low estimate, best estimate and high estimate. Best estimate is a classification of estimated resources described in the Canadian Oil and Gas Evaluation 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 probabilistic methods 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 maturity subclasses include development pending, development on hold, development unclarified and development not viable. The contingent resources disclosed in this news release are classified as either development unclarified, development not viable, or development on hold.        

Development unclarified is defined as a contingent resource that requires further appraisal to clarify the potential 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 unclarified resources referred to in this news release is dependent upon (1) the expected timetable for development; (2) the economics of the project; (3) the marketability of the oil and gas production; (4) the availability of infrastructure and technology; (5) the political, regulatory, and environmental conditions; (6) the project maturity and definition; (7) the availability of capital; and, ultimately, (8) the decision of joint venture partners to undertake development.

The major positive factor relevant to the estimate of the contingent development unclarified resources referred to in this news release 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 unclarified resources referred to in this news release are: (1) the outstanding requirement for a definitive development plan; (2) current economic conditions do not support the resource development; (3) limited field economic life to develop the resources; and (4) the outstanding requirement for a final investment decision and commitment of all joint venture partners.

Development not viable is defined as a contingent resource where no further data acquisition or evaluation 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 news release 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.

Development on hold is defined as a contingent resource where there is a reasonable chance of development, but there are contingencies to be resolved before the project can move forward.  
If these contingencies are successfully addressed, some portion of these contingent resources may be reclassified as reserves.

Of the best estimate 2C contingent resources estimated in the NSAI 2025 Report, on a risked basis: 63% of the estimated volumes are light/medium crude oil, with the remainder being heavy oil; 42% are categorised as Development Unclarified, with the remainder being Development Not Viable. Development Unclarified 2C resources have been assigned an average chances of development for the four fields ranging from 5% to 85%, while 2C Development Not Viable resources have been assigned an average chance of development ranging from 10% to 15%.

Contingent resources within the Development on hold category are only in the 1C certainty estimate (low or conservative).

 
The NSAI estimates have been risked, using the chance of development, to account for the possibility that the contingencies are not successfully addressed.

Glossary

 
Non-IFRS Financial Measures and Rations

Adjusted EBITDAX: is a non-IFRS financial measure which does not have a standardised meaning prescribed by IFRS Accounting Standards. This non-IFRS financial measure is included because management uses the information to analyse the financial performance of the Company. Adjusted EBITDAX is a non-IFRS and non-standardised variant of EBITDAX, adjusted to remove non-cash items as well as certain non-recurring costs including severance payments and other one-off items in relation to the Company’s recent acquisitions. Adjusted EBITDAX is calculated by adjusting profit for the year before other items as reported under IFRS Accounting Standards to exclude the effects of other income, exploration, SRB, finance income and expense, depletion, depreciation & amortisation (“DD&A”), other costs, and certain non-cash items (such as impairments, foreign exchange, unrealised risk management contracts, reassessment of contingent consideration and gains or losses arising from the disposal of capital assets). In addition, share-based compensation is excluded from Adjusted EBITDAX, as they are not indicative of the underlying financial performance of the Company.

      (1)   Items are not shown in the consolidated financial statements of the Company for the year ended 31 December 2025 (the “Financial Statements”).
      (2)   Items are not shown in the Financial Statements.

Adjusted Opex and Adjusted Opex per barrel: are a non-IFRS financial measure and a non-IFRS financial ratio respectively, which do not have standardised meanings prescribed by IFRS Accounting Standards. This non-IFRS financial measure and ratio are included because management uses the information to analyse cash generation and financial performance of the Company. Operating cost represents the operating cash expenses incurred by the Company during the period including the leases that are associated with operations, such as bareboat contracts for key operating equipment, such as floating storage and offloading vessels, floating production, storage and offloading vessels, MOPUs, and warehouses. Adjusted Opex is calculated by effectively adjusting non-cash items from the operating cost and adding lease costs.

Adjusted Opex is divided by production in the period to arrive at Adjusted Opex per barrel. Valeura calculates Adjusted Opex per barrel to provide a more consistent indication of the cost of field operations. Adjusted Opex, as opposed to operating expenses, excludes the impacts of non-recurring, non-cash items such as prior period adjustments, and adds back lease costs in relation to floating storage and offloading vessels, floating production, storage and offloading vessels, MOPUs and other facilities.

      (1)    Write down inventory to net realisable value.
     (2)   The item is not shown in the Financial Statements. The cost of crude inventory is capitalised from operating costs. As a result, the Company has excluded the effect of crude inventory capitalisation.
     (3)   The item is not shown in the Financial Statements. The cost of crude inventory is capitalised from operating costs. As a result, the Company has excluded the effect of crude inventory capitalization.
     (4)   In accordance with IFRS 16 Leases, the Company recognised cost related to its operating leases – attributed to floating storage and offloading vessels, floating production, storage and offloading vessels and MOPUs used at its Jasmine/Ban Yen, Nong Yao, Manora, and Wassana fields, as well as onshore warehouse facilities costs to its balance sheet and finance cost in the profit and loss statement. In order to report a more relevant lifting cost, the Company has included costs associated with these leases in the adjusted operating cost calculation. This will be a recurring adjustment.

Adjusted cashflow from operations and adjusted cashflow from operations per barrel: are a non-IFRS financial measure and a non-IFRS financial ratio respectively, which do not have a standardised meaning prescribed by IFRS Accounting Standards. This non-IFRS finance measure and ratio are included because management uses the information to analyse cash generation and financial performance of the Company. Adjusted cashflow from operations is calculated using two methods which generate the same figures: a) by subtracting from oil revenues, Adjusted Opex, royalties, general and administrative costs which are adjusted for non-recurring charges (generating the adjusted pre-tax cashflow), and accrued Petroleum Income Tax Act taxes and SRB expenses, and b) to enhance and facilitate to the reader a reconciliation of this non-IFRS measure, the Company also presented the Adjusted cash flow from operations by calculating from cash generated from (used in) operating activities in the consolidated statement of cash flows, adjusting with non-cash items, Adjusted Opex, general and administrative costs which are adjusted for non-recurring charges (generating the adjusted pre-tax cashflow), and accrued PITA tax and SRB expenses.

Adjusted cashflow from operations is divided by production in the period to arrive at adjusted cashflow from operations per bbl. Valeura calculates Adjusted cashflow from operations per barrel, to provide a more consistent indication of cashflow generated from operations by the Company.

 
Outstanding debt and net cash: are non-IFRS financial measures which do not have a standardised meaning prescribed by IFRS Accounting Standards. These non-IRFS financial measures are provided because management uses the information to a) analyse financial strength and b) manage the capital structure of the Company. These non-IFRS measures are used to ensure capital is managed effectively in order to support the Company’s ongoing operations and needs.

 
Net working capital and adjusted net working capital: are non-IFRS financial measures which do not have a standardised meaning prescribed by IFRS Accounting Standards. These non-IFRS financial measures are included because management uses the information to analyse liquidity and financial strength of the Company. Net working capital is calculated by deducting current liabilities from current assets. Adjusted net working capital is calculated by adding back the current leases liabilities and including non-current restricted cash in net working capital.

The leases are associated with operations, such as bareboat contracts for key operating equipment, such as floating storage and offloading vessels, floating production, storage and offloading vessels, MOPUs and warehouses which are included in the Company’s disclosed Adjusted Opex (and Adjusted Opex guidance). Management believes the adjusted net working capital provides a useful data point to the reader to ascertain the business’ next-twelve-months surplus or deficit capital requirement. It is also a data point that management uses for cash management.

 
Adjusted Capex: is a non-IFRS measure which does not have a standardised meaning prescribed by IFRS Accounting Standards. Adjusted Capex is defined as the addition in capital expenditure for capital work in progress, drilling, brownfield, and other PP&E. Management uses this non-IFRS measure to analyse the capital spending of the Company and assess investments in its assets.

      (1)   Capital work in progress represents expenditures related to the Wassana redevelopment project incurred prior to the commencement of production.

Advisory and Caution Regarding Forward-Looking Information

Certain information included in this news release 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 other purposes, such as making investment decisions. Forward-looking information typically contains statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project”, “target” or similar words suggesting future outcomes or statements regarding an outlook.

Forward-looking information in this news release includes, but is not limited to, the Wassana field redevelopment project including the deployment of a newly built CPP Facility and the Wassana redevelopment project strengthening the Company’s core business for the long run; the Wassana field redevelopment project more than doubling the production from the Wassana field, reducing costs and extending the production life of the Wassana field into the 2040s; the PTTEP Farm-In Agreement’s discovered resources converted quickly into production and cash flow; the Jasmine field’s ongoing drilling efforts identifying further oil accumulations that create opportunities for potential development; the timing for construction and slot readiness of the Nong Yao A facility expansion project and the anticipated cost thereof; the timing for installation of the new Wassana CPP and for first production; the Company’s management strategy resulting in an even more exciting 2026 and beyond; the potential for the new Wassana CPP to serve as a hub for eventual tie-in of potential satellite wellhead platforms; timing for results of the Company’s evaluation of development options for Block G10/48 and potential drilling targets thereon; completion of the PTTEP Farm-In Agreement resulting in a substantial expansion of Valeura’s gross acreage position in Thailand; and timing for delivery of processed 3D seismic data covering other focus areas on the Blocks; timing to disclose finding of the full resource potential of the Blocks; and timing of the assignment of a 50% undivided working interest in the western portion of the Company’s lands to Transatlantic.

Forward-looking information is based on management’s current expectations and assumptions regarding, among other things: political stability of the areas in which the Company is operating; continued safety of operations and ability to proceed in a timely manner; continued operations of and approvals forthcoming from governments and regulators in a manner consistent with past conduct; 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 production rates and associated operating netbacks and cash flow; decline rates; future sources of funding; future economic conditions; the impact of inflation of future costs; future currency exchange rates; interest rates; the ability to meet drilling deadlines and fulfil commitments under licences and leases; future commodity prices; the impact of the Russian invasion of Ukraine; royalty rates and taxes; future capital and other expenditures; the success obtained in drilling new wells and working over existing wellbores; the performance of wells and facilities; the availability of the required capital to funds its exploration, development and other operations, and the ability of the Company to meet its commitments and financial obligations; the ability of the Company to secure adequate processing, transportation, fractionation and storage capacity on acceptable terms; the capacity and reliability of facilities; the application of regulatory requirements respecting abandonment and reclamation; the recoverability of the Company’s reserves and contingent resources; future growth; the sufficiency of budgeted capital expenditures in carrying out planned activities; the impact of increasing competition; the ability to efficiently integrate assets and employees acquired through acquisitions; global energy policies going forward; future debt levels; and the Company’s continued ability to obtain and retain qualified staff and equipment in a timely and cost efficient manner. In addition, the Company’s work programmes and budgets are in part based upon expected agreement among joint venture partners and associated exploration, development and marketing plans and anticipated costs and sales prices, which are subject to change based on, among other things, the actual results of drilling and related activity, availability of drilling, offshore storage and offloading facilities and other specialised oilfield equipment and service providers, changes in partners’ 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 significant 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 results to differ materially from those anticipated by the Company including, but not limited to: the ability of management to execute its business plan or realise anticipated benefits from acquisitions; the risk of disruptions from public health emergencies and/or pandemics; competition for specialised equipment and human resources; the Company’s ability to manage growth; the Company’s ability to manage the costs related to inflation; disruption in supply chains; the risk of currency fluctuations; changes in interest rates, oil and gas prices and netbacks; potential changes in joint venture partner strategies and participation in work programmes; uncertainty regarding the contemplated timelines and costs for work programme execution; the risks of disruption to operations and access to worksites; potential changes in laws and regulations, the uncertainty regarding government and other approvals; counterparty risk; the risk that financing may not be available; risks associated with weather delays and natural disasters; 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.

The forward-looking information contained in this new release is made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward-looking information contained in this new release is expressly qualified by this cautionary statement.

This news release does not constitute an offer to sell or the solicitation of an offer to buy securities in any jurisdiction, including where such offer would be unlawful. This news release is not for distribution or release, directly or indirectly, in or into the United States, Ireland, the Republic of South Africa or Japan or any other jurisdiction in which its publication or distribution would be unlawful.

Neither the Toronto Stock Exchange nor its Regulation Services Provider (as that term is defined in the policies of the Toronto Stock Exchange) accepts responsibility for the adequacy or accuracy of this news release.

This information is provided by Reach, the non-regulatory press release distribution service of RNS, part of the London Stock Exchange. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.