International Petroleum Corporation Announces Third Quarter 2025 Financial and Operational Results and Blackrod Phase 1 Development Progressing Ahead of Schedule

International Petroleum Corporation (IPC or the Corporation) (TSX, Nasdaq Stockholm: IPCO) today released its financial and operational results and related management’s discussion and analysis (MD&A) for the three and nine months ended September 30, 2025. IPC also announces that the Blackrod Phase 1 development is progressing ahead of schedule with first steam now expected by year end 2025 and first oil by Q3 2026, a quarter earlier than originally guided.

William Lundin, IPC's President and Chief Executive Officer, comments: “We are pleased to report another strong quarter for IPC. We produced an average of 45,900 barrels of oil equivalent per day (boepd) during the third quarter, which was above the guidance range for the period. Strong operational performance translated into robust financial results for the third quarter.

At the Blackrod asset, significant progress has been made during the quarter on the transformational Phase 1 development. We now forecast first steam by year end 2025 and first oil by Q3 2026, a quarter earlier than the original sanction case. This is a testament to the quality of multidisciplinary teamwork and overall project execution. With this positive progress and earlier than planned start-up, we have accelerated the drilling of the final well pad into the fourth quarter of 2025. The growth capital budget for the Blackrod Phase 1 development remains intact at MUSD 850 to first oil in 2026.

During the third quarter of 2025, we completed the 2024/2025 NCIB program, reducing the outstanding number of common shares by about 6.2% since the beginning of the annual program in December 2024. In addition, we announced in the third quarter that our MUSD 450 of bonds were successfully refinanced with the new bond maturity in October 2030.“

Q3 2025 Business Highlights

• Average net production of approximately 45,900 boepd for Q3 2025, above guidance (53% heavy crude oil, 14% light and medium crude oil and 33% natural gas).⁽¹⁾
• Continued progress of Blackrod Phase 1 development activity with Central Processing Facility (CPF) construction almost complete, progressive commissioning advancing, and first steam and first oil forecast a quarter earlier than originally guided.
• At Onion Lake Thermal, Canada, the final two of four planned production infill wells and the final Pad L sustaining well pair were successfully brought online.
• Announced the refinancing of IPC’s MUSD 450 unsecured bonds, extending the maturity to October 2030.
• 1.1 million IPC common shares purchased and cancelled during Q3 2025 under the normal course issuer bid (NCIB), completing the full 2024/2025 NCIB of approximately 7.5 million IPC common shares.
• IPC plans to seek Toronto Stock Exchange (TSX) approval for the renewal of the NCIB in December 2025.

Q3 2025 Financial Highlights

• Operating costs per boe of USD 17.9 for Q3 2025, marginally below guidance.⁽³⁾
• Operating cash flow (OCF) generation of MUSD 66 for Q3 2025, in line with guidance.⁽³⁾
• Capital and decommissioning expenditures of MUSD 82 for Q3 2025, in line with guidance.
• Free cash flow (FCF) generation for Q3 2025 amounted to MUSD -23 (MUSD 36 pre-Blackrod capital expenditures).⁽³⁾
• Gross cash of MUSD 45 and net debt of MUSD 435 as at September 30, 2025.⁽³⁾
• Net result of MUSD 4 for Q3 2025.

Reserves and Resources

• Total 2P reserves as at December 31, 2024 of 493 MMboe, with a reserve life index (RLI) of 31 years.⁽¹⁾⁽²⁾
• Contingent resources (best estimate, unrisked) as at December 31, 2024 of 1,107 MMboe.⁽¹⁾⁽²⁾
• 2P reserves net asset value (NAV) as at December 31, 2024 of MUSD 3,083 (10% discount rate).⁽¹⁾⁽²⁾
  
  
  
  

2025 Annual Guidance

• Full year 2025 average net production guidance range forecast maintained at 43,000 to 45,000 boepd.⁽¹⁾
• Full year 2025 operating costs guidance range forecast maintained at USD 18 to 19 per boe.⁽³⁾
• Full year 2025 OCF guidance range tightened to between MUSD 245 and 255 (assuming Brent USD 55 to 65 per barrel for the remainder of 2025) from previous guidance of between MUSD 245 and 260 (which assumed Brent USD 60 to 75 per barrel for the second half of 2025).⁽³⁾⁽⁴⁾
• Full year 2025 capital and decommissioning expenditures guidance revised from MUSD 320 to MUSD 340 (including MUSD 250 for the Blackrod asset), following the advancement of Blackrod Phase 1 drilling activity into Q4 2025.
• Full year 2025 FCF revised guidance estimated at between MUSD -170 and -160 (assuming Brent USD 55 to 65 per barrel for the remainder of 2025) from previous guidance of between MUSD -135 and -120 (which assumed Brent USD 60 to 75 per barrel for the second half of 2025).⁽³⁾⁽⁴⁾
  
  
  
  

During the third quarter of 2025, the average Brent price was approximately USD 69 per barrel, as compared to approximately USD 68 per barrel for the second quarter of 2025. The Brent price remained relatively stable during the third quarter, with some downward pressure on prices post-quarter due to concerns over market oversupply and concerns around global trade between China and the US. Global observed petroleum inventories have increased, mainly driven by OPEC’s unwinding of voluntary production cuts, long-dated non-OPEC supply growth projects coming on-stream, and sanctioned countries’ production output being high relative to historical standard. Given the uncertainty and low-price strip outlook, it is unlikely near-term incremental upstream growth investment will be pursued by industry. Global oil demand is expected to be an all-time high in 2025 and is predicted to continue to rise in 2026. 

Alongside the more constructive factors for stronger oil prices in the medium to longer term, the need to alleviate poverty in emerging markets coupled with meeting the infrastructure build-out requirements for technological advancements, namely with data centres and AI, places a major emphasis on the need for metals and high-density forms of energy. The precious and base metal supply needs will go hand-in-hand with a reliance on oil and its irreplaceable byproducts in order to develop and transport more mined material. While uncertainty exists with respect to forecasting oil prices, IPC has strongly positioned itself with forecast sustained higher production levels in the years ahead which should positively coincide with a higher pricing cycle at a time likely not too far into the future.

IPC’s oil hedges in total represent around 50% of our aggregate forecast 2025 oil production at around USD 76 and USD 71 per barrel for Dated Brent and West Texas Intermediate (WTI), respectively, as well as a WTI collar between USD 65 and USD 75 per barrel, for the remainder of 2025.

The WTI to Western Canadian Select (WCS) price differential during the third quarter averaged less than USD 11 per barrel. The WTI to WCS differential continues to benefit from the TMX pipeline expansion, driving up competitive tension for Canadian oil and increased buying from Asia. The current and outlook of the WTI to WCS differential remains tight with excess egress capacity relative to the supply in the Western Canadian Sedimentary Basin (WCSB). There are currently no tariffs on Canadian crude oil exports to the United States, which remain covered by the US Mexico Canada trade agreement. IPC has hedged the WTI to WCS differential for approximately 50% of our forecast 2025 Canadian oil production at USD 14 per barrel for 2025. For 2026, IPC implemented WTI to WCS differential hedges in October 2025 for approximately 5,000 barrels per day at USD -12.50 per barrel.

The average Canadian gas benchmark price, AECO, was CAD 0.6 per Mcf for the third quarter of 2025 and IPC achieved an average realized price of CAD 0.8 per Mcf during the quarter. WCSB gas inventory levels remain elevated above the historical average. There is an expectation for storage levels to draw during the winter period and further supported by the ramp up of the LNG Canada project in 2026 which should drive higher natural gas prices. Approximately 50% of our net long gas exposure was hedged at CAD 2.4 per Mcf to end October 2025, with around 15% of net long gas exposure hedged for November and December at CAD 2.6 per Mcf. For 2026, IPC implemented hedges in the third quarter of 2025 for approximately 9,600 Mcf per day at CAD 2.80 per Mcf from April to October 2026.

Third Quarter 2025 Highlights and Full Year 2025 Guidance

During the third quarter of 2025, our portfolio delivered average net production of 45,900 boepd, ahead of guidance. The strong performance in the quarter was supported by the sustaining capital investment activities undertaken at the Onion Lake Thermal asset and at the Bertam field in Malaysia. We maintain the full year 2025 average net production guidance range of 43,000 to 45,000 boepd.⁽¹⁾

Our operating costs per boe for the third quarter of 2025 was USD 17.9, marginally below guidance. Full year 2025 operating expenditure guidance of USD 18.0 to 19.0 per boe remains unchanged.⁽³⁾

Operating cash flow (OCF) generation for the third quarter of 2025 was MUSD 66. Full year 2025 OCF guidance is tightened to MUSD 245 to 255 (assuming Brent USD 55 to 65 per barrel for the remainder of 2025).⁽³⁾⁽⁴⁾

Capital and decommissioning expenditure for the third quarter of 2025 was MUSD 82, in line with guidance. Full year 2025 capital and decommissioning expenditure is revised to MUSD 340, from MUSD 320, mainly due to the acceleration of the drilling of the final well pad for the Blackrod Phase 1 project into the fourth quarter of 2025.

Free cash flow (FCF) generation was MUSD -23 (MUSD 36 pre-Blackrod capital expenditures) during the third quarter of 2025. Full year 2025 FCF guidance is revised to MUSD -170 to -160 (assuming Brent USD 55 to 65 per barrel for the remainder of 2025) after taking into account MUSD 340 of forecast full year 2025 capital expenditures (including MUSD 250 relating to the Blackrod asset) and costs incurred from the bond refinancing.⁽³⁾⁽⁴⁾

As at September 30, 2025, IPC’s net debt position increased to MUSD 435, from a net debt position of MUSD 375 as at June 30, 2025, mainly driven by the funding of capital expenditures and the share repurchase program (NCIB). Gross cash as at September 30, 2025 amounted to MUSD 45.

In the third quarter of 2025, IPC announced that it had taken advantage of favourable debt capital market conditions to successfully refinance its MUSD 450 of unsecured bonds. The new bonds issued in October 2025 have a maturity in October 2030, with a coupon of 7.5% per annum. IPC believes that this is a great outcome since the US 5-year swap rates increased by almost 2% compared to IPC’s inaugural bond issuance in the first quarter of 2022 while the coupon only increased by 0.25% to 7.5%. In addition, IPC continues to have access to a Canadian revolving credit facility of MCAD 250 (approximately MUSD 180), with MCAD 37 (approximately MUSD 27) drawn under that facility as at September 30, 2025. The access to liquidity supports IPC to follow through on its key strategic objectives of enhancing stakeholder value through organic growth, stakeholder returns, and pursuing value adding M&A.⁽³⁾

Blackrod

The Blackrod asset is 100% owned by IPC and contains 259 MMboe of 2P reserves and 1,025 MMboe of contingent resources (best estimate, unrisked) with regulatory approval to produce up to 80,000 bopd. In early 2023, IPC sanctioned the Phase 1 development targeting plateau production rates of 30,000 bopd with a growth capital expenditure guidance of MUSD 850. Since the Phase 1 project sanction to the end of the third quarter of 2025, capital expenditures of MUSD 785 have been incurred, or approximately 92% of the MUSD 850 growth capital guidance to first oil.⁽¹⁾

All major work activities continued to advance at the Blackrod asset during the third quarter. Construction activities are nearing completion and progressive commissioning of the CPF is ahead of schedule. While full commissioning works remain to be completed, IPC is now confident that first steam at the project should occur before the end of 2025 with first oil to follow in the third quarter of 2026, a quarter earlier than originally guided. As a result of an earlier expected startup for the Phase 1 project, drilling of the final well pad is planned to be started in the fourth quarter of 2025 from early 2026.

IPC intends to fund the remaining Blackrod capital expenditure with forecast cash flow generated by its operations, cash on hand and drawing under the existing Canadian credit facility as needed.⁽³⁾

Stakeholder Returns: Normal Course Issuer Bid

In the fourth quarter of 2024, IPC announced the implementation of the 2024/2025 NCIB to purchase up to approximately 7.5 million common shares over the period of December 5, 2024 to December 4, 2025. Under the 2024/2025 NCIB, IPC repurchased and cancelled approximately 0.8 million common shares in December 2024 and over 6.6 million common shares during the first nine months of 2025 under the NCIB, as well as a further 0.3 million common shares under other exemptions in Canada. The average price of common shares repurchased under the 2024/2025 NCIB during the first nine months of 2025 was around SEK 144 / CAD 20 per share.

IPC completed the 2024/2025 NCIB by the end of September 2025, purchasing and cancelling approximately 7.5 million common shares. This resulted in the cancellation of 6.2% of the common shares outstanding as at the beginning of December 2024.

As at September 30, 2025, IPC had a total of 112,180,065 common shares issued and outstanding, of which IPC held 24,538 common shares in treasury. As at November 4, 2025, IPC had a total of 112,155,527 common shares issued and outstanding and IPC held no common shares in treasury.

The IPC Board of Directors has approved, subject to acceptance by the Toronto Stock Exchange (TSX), the renewal of IPC’s NCIB for a further twelve months from December 2025 to early December 2026. We expect that the 2025/2026 NCIB will permit IPC to purchase on the TSX and/or Nasdaq Stockholm, and cancel, up to a further approximately 6.5 million common shares, representing approximately 5.8% of the total current outstanding common shares (or 10% of IPC’s “public float” under applicable TSX rules). IPC continues to believe that reducing the number of shares outstanding in combination with investing in long-life production growth at the Blackrod project will prove to be a winning formula for our stakeholders.

Notes:

(1) See “Supplemental Information regarding Product Types” in “Reserves and Resources Advisory” below. See also the annual information form for the year ended December 31, 2024 (AIF) available on IPC’s website at -petroleum.com and under IPC’s profile on SEDAR+ at

(2) See “Reserves and Resources Advisory“ below. Further information with respect to IPC’s reserves, contingent resources and estimates of future net revenue, including assumptions relating to the calculation of net present value (NPV), are described in the AIF. NAV is calculated as NPV less net debt of MUSD 209 as at December 31, 2024.

(3 Non-IFRS measures, see “Non-IFRS Measures” below and in the MD&A.

(4) OCF and FCF forecasts at Brent USD 55 to 65 per barrel assume Brent to WTI and WTI to WCS differentials of USD 3 and 10 per barrel, respectively, for the remainder of 2025. OCF and FCF forecasts assume gas price on average of CAD 1.75 per Mcf for the fourth quarter of 2025.

International Petroleum Corp. (IPC) is an international oil and gas exploration and production company with a high quality portfolio of assets located in Canada, Malaysia and France, providing a solid foundation for organic and inorganic growth. IPC is a member of the Lundin Group of Companies. IPC is incorporated in Canada and IPC’s shares are listed on the Toronto Stock Exchange (TSX) and the Nasdaq Stockholm exchange under the symbol "IPCO".

For further information, please contact:

This information is information that International Petroleum Corporation is required to make public pursuant to the EU Market Abuse Regulation and the Securities Markets Act. The information was submitted for publication, through the contact persons set out above, at 07:30 CET on November 4, 2025. The Corporation's unaudited interim condensed consolidated financial statements (Financial Statements) and management's discussion and analysis (MD&A) for the three and nine months ended September 30, 2025 have been filed on SEDAR+ () and are also available on the Corporation's website (-petroleum.com).



Forward-Looking Statements

This press release contains statements and information which constitute "forward-looking statements" or "forward-looking information" (within the meaning of applicable securities legislation). Such statements and information (together, "forward-looking statements") relate to future events, including the Corporation's future performance, business prospects or opportunities. Actual results may differ materially from those expressed or implied by forward-looking statements. The forward-looking statements contained in this press release are expressly qualified by this cautionary statement. Forward-looking statements speak only as of the date of this press release, unless otherwise indicated. IPC does not intend, and does not assume any obligation, to update these forward-looking statements, except as required by applicable laws.

All statements other than statements of historical fact may be forward-looking statements. Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, forecasts, guidance, budgets, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", “forecast”, "predict", "potential", "targeting", "intend", "could", "might", "should", "believe", "budget" and similar expressions) are not statements of historical fact and may be "forward-looking statements".

Forward-looking statements include, but are not limited to, statements with respect to:

• 2025 production ranges (including total daily average production), production composition, cash flows, operating costs and capital and decommissioning expenditure estimates;
• Estimates of future production, cash flows, operating costs and capital expenditures that are based on IPC’s current business plans and assumptions regarding the business environment, which are subject to change;
• IPC’s financial and operational flexibility to continue to react to recent events and navigate the Corporation through periods of volatile commodity prices;
• The ability to fully fund future expenditures from cash flows and current borrowing capacity;
• IPC’s intention and ability to continue to implement strategies to build long-term shareholder value;
• The ability of IPC’s portfolio of assets to provide a solid foundation for organic and inorganic growth;
• The continued facility uptime and reservoir performance in IPC’s areas of operation;
• Development of the Blackrod project in Canada, including estimates of resource volumes, future production, timing, regulatory approvals, third party commercial arrangements, breakeven prices and net present value;
• Current and future production performance, operations and development potential of the Onion Lake Thermal, Suffield, Brooks, Ferguson and Mooney operations, including the timing and success of future oil and gas drilling and optimization programs;
• The potential improvement in the Canadian oil egress situation and IPC’s ability to benefit from any such improvements;
• The ability to maintain current and forecast production in France and Malaysia;
• The ability of IPC to renew the NCIB and the number of common shares which may be purchased under a renewed NCIB;
• The intention and ability of IPC to acquire further common shares under the NCIB, including the timing of any such purchases;
• The return of value to IPC’s shareholders as a result of the NCIB;
• The ability of IPC to implement further shareholder distributions in addition to the NCIB;
• IPC’s ability to implement its greenhouse gas (GHG) emissions intensity and climate strategies and to achieve its net GHG emissions intensity reduction targets;
• IPC’s ability to implement projects to reduce net emissions intensity, including potential carbon capture and storage;
• Estimates of reserves and contingent resources;
• The ability to generate free cash flows and use that cash to repay debt;
• IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the Corporation;
• IPC’s ability to maintain operations, production and business in light of any future pandemics and the restrictions and disruptions related thereto, including risks related to production delays and interruptions, changes in laws and regulations and reliance on third-party operators and infrastructure;
• IPC’s ability to identify and complete future acquisitions;
• Expectations regarding the oil and gas industry in Canada, Malaysia and France, including assumptions regarding future royalty rates, regulatory approvals, legislative changes, and ongoing projects and their expected completion; and
• Future drilling and other exploration and development activities.

Statements relating to "reserves" and "contingent resources" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and that the reserves and resources can be profitably produced in the future. Ultimate recovery of reserves or resources is based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.

Although IPC believes that the expectations and assumptions on which such forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because IPC can give no assurances that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks.

These include, but are not limited to general global economic, market and business conditions; the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses; health, safety and environmental risks; commodity price fluctuations; interest rate and exchange rate fluctuations; marketing and transportation; loss of markets; environmental and climate-related risks; competition; innovation and cybersecurity risks related to our systems, including our costs of addressing or mitigating such risks; the ability to attract, engage and retain skilled employees; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; the ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; geopolitical conflicts, including the war between Ukraine and Russia and the potential for further conflict in the Middle East, and their potential impact on, among other things, global market conditions; and changes in legislation, including but not limited to tax laws, royalties, environmental and abandonment regulations.

Additional information on these and other factors that could affect IPC, or its operations or financial results, are included in the MD&A (See “Risk Factors”, "Cautionary Statement Regarding Forward-Looking Information" and “Reserves and Resources Advisory” therein), the Corporation’s Annual Information Form (AIF) for the year ended December 31, 2024, (See “Cautionary Statement Regarding Forward-Looking Information”, “Reserves and Resources Advisory” and “Risk Factors”) and other reports on file with applicable securities regulatory authorities, including previous financial reports, management’s discussion and analysis and material change reports, which may be accessed through the SEDAR+ website () or IPC's website (-petroleum.com).

Management of IPC approved the production, operating costs, operating cash flow, capital and decommissioning expenditures and free cash flow guidance and estimates contained herein as of the date of this press release. The purpose of these guidance and estimates is to assist readers in understanding IPC’s expected and targeted financial results, and this information may not be appropriate for other purposes.

Non-IFRS Measures

References are made in this press release to "operating cash flow" (OCF), “free cash flow” (FCF), "Earnings Before Interest, Tax, Depreciation and Amortization" (EBITDA), "operating costs" and "net debt"/”net cash”, which are not generally accepted accounting measures under International Financial Reporting Standards (IFRS) and do not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with similar measures presented by other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS.

The definition of each non-IFRS measure is presented in IPC's MD&A (See "Non-IFRS Measures" therein).

Operating cash flow

The following table sets out how operating cash flow is calculated from figures shown in the Financial Statements:

¹ Includes net sales of diluent to third party amounting to USD 91 thousand for the third quarter of 2025 and USD 510 thousand for the first nine months of 2025.

Free cash flow

The following table sets out how free cash flow is calculated from figures shown in the Financial Statements:

¹ See notes 11 and 16 to the Financial Statements.

² Depreciation is not specifically disclosed in the Financial Statements.

³ See notes 4 and 5 to the Financial Statements.

EBITDA

The following table sets out the reconciliation from net result from the consolidated statement of operations to EBITDA:

¹ Sale of assets is included under “Other income/(expense)” but not specifically disclosed in the Financial Statements.

² Item is not shown in the Financial Statements.

Operating costs

The following table sets out how operating costs is calculated:

Net cash/(debt)

The following table sets out how net cash/(debt) is calculated:

¹ The bond amount represents the redeemable value at maturity (February 2027).

Reserves and Resources Advisory

This press release contains references to estimates of gross and net reserves and resources attributed to the Corporation's oil and gas assets. For additional information with respect to such reserves and resources, refer to “Reserves and Resources Advisory” in the MD&A. Light, medium and heavy crude oil reserves/resources disclosed in this press release include solution gas and other by-products. Also see “Supplemental Information regarding Product Types” below.

Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in Canada are effective as of December 31, 2024, and are included in the reports prepared by Sproule Associates Limited (Sproule), an independent qualified reserves evaluator, in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook (the COGE Handbook) and using Sproule’s December 31, 2024 price forecasts.

Reserve estimates, contingent resource estimates and estimates of future net revenue in respect of IPC’s oil and gas assets in France and Malaysia are effective as of December 31, 2024, and are included in the report prepared by ERC Equipoise Ltd. (ERCE), an independent qualified reserves auditor, in accordance with NI 51-101 and the COGE Handbook, and using Sproule’s December 31, 2024 price forecasts.

The price forecasts used in the Sproule and ERCE reports are available on the website of Sproule (sproule.com) and are contained in the AIF. These price forecasts are as at December 31, 2024 and may not be reflective of current and future forecast commodity prices.

The reserve life index (RLI) is calculated by dividing the 2P reserves of 493 MMboe as at December 31, 2024 by the mid-point of the 2025 CMD production guidance of 43,000 to 45,000 boepd.

IPC uses the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). A BOE conversion ratio of 6:1 is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value.

Supplemental Information regarding Product Types

The following table is intended to provide supplemental information about the product type composition of IPC’s net average daily production figures provided in this press release:

This press release also makes reference to IPC’s forecast total average daily production of 43,000 to 45,000 boepd for 2025. IPC estimates that approximately 53% of that production will be comprised of heavy crude oil, approximately 14% will be comprised of light and medium crude oil and approximately 33% will be comprised of conventional natural gas.

Currency

All dollar amounts in this press release are expressed in United States dollars, except where otherwise noted. References herein to USD mean United States dollars and to MUSD mean millions of United States dollars. References herein to CAD mean Canadian dollars.

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