International Petroleum Corporation (IPC or the Corporation) (TSX, Nasdaq Stockholm: IPCO) today released its financial and operating results and related management’s discussion and analysis (MD&A) for the three and six months ended June 30, 2021. IPC also released its Sustainability Report 2020, which details the Corporation’s environmental, social and governance (ESG) performance.
Q2 2021 Business and Financial Highlights
Average net production of approximately 44,600 barrels of oil equivalent (boe) per day (boepd) for the second quarter of 2021 is above the high end of the 2021 Capital Markets Day (CMD) guidance range for the period (42% heavy crude oil, 20% light and medium crude oil and 38% natural gas)(1).
Full year 2021 average net production forecast revised upwards to above 44,000 boepd(1).
Operating costs(2) per boe of USD 15.6 for the second quarter of 2021, in line with CMD guidance. Full year guidance revised to USD 15.5 per boe from USD 14.6 per boe.
Capital and decommissioning expenditures of MUSD 21 for the first six months of 2021, in line with CMD guidance. Full year guidance has been increased to MUSD 73 from MUSD 37 following the addition of drilling projects in Malaysia and Canada in the second half of 2021.
Exceptionally strong free cash flow (FCF)(2) generation of MUSD 50 for the second quarter of 2021. FCF(2) generation of MUSD 99 for the first six months of 2021 represents close to 13% of IPC’s market capitalization as at July 30, 2021.
Increased working interest in the Bertam field, Malaysia from 75% to 100% from April 10, 2021.
Production commenced at the new Pad D’ at Onion Lake Thermal, Canada ahead of schedule and within budget.
Proved plus probable (2P) reserves as at December 31, 2020 of 272 million boe (MMboe), with a reserves life index (RLI) of 18 years(1).
Contingent resources (best estimate, unrisked) as at December 31, 2020 of 1,102 MMboe(1).
Forecast cumulative FCF(2) for 2021 to 2025 of approximately MUSD 600 to MUSD 1,200 (Brent USD 55 to 75 per barrel), generating estimated average annual free cash flow yield over the five year period of between 16% and 32%(3).
Operating cash flow (OCF)(2) and FCF(2) generation for the second quarter of 2021 amounted to MUSD 67 and MUSD 50 respectively, above the high end of the CMD guidance.
Full year OCF(2) guidance is revised upwards to between USD 235 million to USD 290 million (actual realized prices for the first half of 2021 and Brent USD 55 to 75 per barrel for the second half of 2021) from USD 165 million to USD 220 million (Brent USD 55 to 65 per barrel).
Full year FCF(2) guidance is revised upwards to between USD 135 million to USD 195 million (actual realized prices for the first half of 2021 and Brent USD 55 to 75 per barrel for the second half of 2021) from USD 100 million to USD 155 million (Brent USD 55 to 65 per barrel).
Net debt(2) of MUSD 241 as at June 30, 2021, down from MUSD 286 at the end of the first quarter of 2021.
Net debt(2) to 12 month rolling EBITDA(2) ratio as at June 30, 2021 was below 1.2 times.
Canadian reserve-based lending facility (RBL) amended and extended until the end of May 2023.
Net result of MUSD 22 for the second quarter of 2021.
Three months ended June 30
Six months ended June 30
Gross profit / (loss)
Operating cash flow
Free cash flow
(1) See “Supplemental Information regarding Product Types” below and the Corporation’s annual information form for the year ended December 31, 2020 (AIF), available on the SEDAR website (www.sedar.com) and IPC’s website (www.international-petroleum.com).
(2) See “Non-IFRS Measures” below.
(3) Free cash flow yield based on IPC market capitalization at July 30, 2021 (41.4 SEK/share, 8.6 SEK/USD, 750 MUSD). Assumptions described below in “Forward-Looking Statements”.
Mike Nicholson, IPC’s Chief Executive Officer, commented,
“Market conditions for oil and gas producers have continued to improve during the first half of 2021. Second quarter 2021 average Brent oil price was USD 69 per barrel, in excess of the first quarter 2021 price that averaged just above USD 60 per barrel.
Proactive supply management by the OPEC+ group, led by Saudi Arabia, is rebalancing the market. The International Energy Agency (“IEA“) is forecasting a net supply deficit during the second half of 2021 and excess oil inventory levels are reported to have drawn back down below pre-pandemic levels.
The pace of recovery in oil demand is accelerating as we see the easing of restrictions on mobility following the continued roll-out of Covid-19 vaccination programs to the wider population. With demand still not expected to fully recover to pre-Covid-19 levels until next year, and new variants on the rise, continued proactive supply management on the part of OPEC+ members remains crucial. It is encouraging to see the OPEC+ cooperation agreement extended until the end of 2022.
In Canada, second quarter 2021 Western Canadian Select (“WCS“) crude price differential averaged below USD 12 per barrel and forward markets into 2022 and 2023 are pricing the WCS differential at around USD 13 per barrel. Clearly the positive construction progress on both Enbridge’s Line 3 replacement as well as the TransMountain pipeline expansion project is providing a much more constructive outlook for Canadian oil market egress relative to the tightness we have witnessed over the past five years. IPC has positioned itself well to benefit from this situation.
Gas markets have also been much stronger driven by a combination of increasing demand, lower supply and warmer than average temperatures diverting gas supply away from injecting into storage which could lead to further tightness during winter if cold temperatures prevail.
Given the very strong start to the year, IPC is well placed to deliver results above our high case free cash flow guidance and as a result, we plan to add some additional capital expenditure activities that are expected to enable us to grow production as we move into 2022. Details are set out below in our revised guidance.
In addition, IPC remains opportunistic in our approach with respect to further Mergers and Acquisitions (“M&A“) activity and we have witnessed an uptick in activity levels that we anticipate will continue in the months ahead.
Second Quarter 2021 Highlights
During the second quarter of 2021, our assets delivered average net production of 44,600 boepd. This sits above the top end of our guidance range for the second quarter in succession and was largely driven by the very high uptime performance across all our assets as well as increasing our working interest in the Bertam field from 75% to 100% in April 2021. The decision was taken to defer the Bertam turnaround to the third quarter 2021 in order to optimize the planned maintenance activities. Production would have remained above high end guidance had we adjusted for the original second quarter turnaround timing. First half 2021 production averaged 44,200 boepd.
As a result of the robust production performance in the first half, we are revising upwards our full year guidance to above 44,000 boepd which represents a 1,000 boepd increase above our previous high case guidance. With Pad D’ production ramping up at Onion Lake Thermal during the second half of 2021, we expect IPC to exit 2021 with production in excess of 45,000 boepd, some 2,000 boepd higher than our previous guidance.
Our operating costs per boe for the second quarter of 2021 was USD 15.6, in line with guidance. Full year operating costs per boe are expected to increase from USD 14.6 per boe to USD 15.5 per boe to take account of higher energy costs (gas and electricity) and the restart of some higher cost production in Canada.
Operating cash flow generation for the second quarter of 2021 amounted to USD 67 million, stronger than our February 2021 Capital Markets Day (“CMD“) high case (Brent USD 65 per barrel) forecast as a result of stronger than forecast production, tighter Canadian crude price differentials and stronger realized Canadian gas prices. This takes our first half operating cash flow generation to USD 135 million or more than 60% of our full year CMD high case.
Full year operating cash flow guidance is now revised upwards to between USD 235 million to USD 290 million (actual realized prices for the first half of 2021 and Brent USD 55 to 75 per barrel for the second half of 2021) from USD 165 million to USD 220 million (Brent USD 55 to 65 per barrel).
Capital and decommissioning expenditures during the first half of 2021 of MUSD 21 was in line with forecast, representing just below 60% of our originally guided full year expenditure program of USD 37 million.
Following the improved oil and gas prices in 2021, we now believe it is prudent to expand the 2021 program to position IPC to capture some additional high return, quick payback opportunities that are forecast to add production growth as we move into 2022.
As a result, we are increasing our full year 2021 capital expenditure budget by USD 36 million to USD 73 million. In Malaysia, we now plan to drill the A15 sidetrack well in the Bertam field during the fourth quarter 2021. We have also elected to take advantage of having a rig on location to upgrade the size of three Electrical Submersible Pumps (“ESPs“) on existing producing Bertam field wells to be able to operate at higher liquid rates as well as to execute other well maintenance activities. In Canada, we plan to drill five infill wells at Onion Lake Thermal as well as to perform optimization work at the Suffield Oil property. Undertaking this activity in the fourth quarter of 2021 is expected to add more than 2,500 boepd of production potential in 2022 which will assist in achieving our forecast five year average production level of 45,000 boepd.
Free cash flow generation was exceptionally strong at USD 50 million during the second quarter 2021 and just below USD 100 million for the first half 2021. This represents close to 13% of IPC’s current market capitalization.
Full year 2021 free cash flow guidance is now revised upwards to between USD 135 million to USD 195 million (actual realized prices for the first half of 2021 and Brent USD 55 to 75 per barrel for the second half of 2021) from USD 100 million to USD 155 million (Brent USD 55 to 65 per barrel). The increased capital program is more than fully funded from excess free cash flow generation. This revised guidance translates into a full year free cash flow yield of between 18 to 26%.
Over the 2021 to 2025 period, we retain our longer term guidance of generating between USD 600 and 900 million of free cash flow with average Brent prices between USD 55 to 65 per barrel. In a more bullish world, with Brent at USD 75 per barrel, our five year cumulative free cash flow would increase to approximately USD 1,200 million. At this level, the entire enterprise value of IPC would be liquidated in less than five years.
Net debt was reduced during the second quarter of 2021 by MUSD 45 to MUSD 241. Net debt to EBITDA drops to below 1.2 times from 3 times at the year-end 2020 (trailing 12 months) or to below 1.0 times on an annualized basis. We have continued to delever through the first half of 2021 and the momentum should continue into next year with the second half of 2021 increased capital program providing additional production growth as we enter 2022.
Environmental, Social and Governance (“ESG“) Performance
Health, Safety & Environmental performance remains a priority for all operational assets. Our objective is to reduce risk and eliminate hazards to prevent the occurrence of accidents, ill health and environmental damage, as these are essential to the success of our operations. During the second quarter of 2021, IPC recorded no material safety or environmental incidents. In response to the Covid-19 pandemic, we remain focused on protecting the health and safety of our employees, contractors and other stakeholders, while also working to ensure business continuity. In the second quarter of 2021, IPC continued the health protocols implemented throughout the organization.
Responsible operatorship and ensuring that we adhere to the highest principles of business conduct have been an integral part of how we do business since the creation of IPC in 2017. An important part of our sustainability journey involves the measurement and transparent reporting of a broad range of ESG metrics. Alongside the publication of our second quarter 2021 financial report, we are very pleased that IPC is today presenting to our stakeholders our second Sustainability Report.
The Sustainability Report 2020 details the Corporation’s ESG performance. The Sustainability Report 2020 advances the Corporation’s non-financial sustainability disclosures and provides stakeholders with relevant operational and sustainability context in which IPC operates, as well as the Corporation’s management approach and performance with respect to these areas. The report is available on IPC’s website at www.international-petroleum.com.
Highlights of IPC’s sustainability performance for 2020 include:
Zero severe incidents
Lost time incident rate of 0.6 in 2020 vs 1.8 in 2019
Proactive COVID-19 health and safety management
On track with our commitment to reducing net GHG emissions intensity by 50% by the end of 2025
35,000 tonnes of CO2e credits generated through emission reduction initiatives
Doubled carbon offsets compared to 2019 with 100,000 tonnes of CO2e
Workforce drawn 99% from local hiring and composed of 29% women
Meaningful support and engagement with the Onion Lake Cree Nation (OLCN) community and MUSD 12.7 contracted with First Nations businesses
Support to local communities’ mental health programs, including by partnering with the United Way in Canada
Participation in community projects in Malaysia, including youth internships and coral reef preservation
We encourage everyone to read the IPC’s second Sustainability Report and see first-hand the good work that is being done within our company.”
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”.
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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 CEST on August 3, 2021. The Corporation’s unaudited interim condensed consolidated financial statements (Financial Statements) and management’s discussion and analysis (MD&A) for the six months ended June 30, 2021 have been filed on SEDAR (www.sedar.com) and are also available on the Corporation’s website (www.international-petroleum.com).
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.
The Covid-19 virus and the restrictions and disruptions related to it have had a material effect on the world demand for, and prices of, oil and gas as well as the market price of the shares of oil and gas companies generally, including the Corporation’s common shares. There can be no assurance that these effects will not continue or that commodity prices will not decrease or remain volatile in the future. These factors are beyond the control of the Corporation and it is difficult to assess how these, and other factors, will continue to affect the Corporation and the market price of IPC’s common shares. In light of the current situation, as at the date of this press release, the Corporation continues to review and assess its business plans and assumptions regarding the business environment, as well as its estimates of future production, cash flows, operating costs and capital expenditures.
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:
IPC’s ability to maximize liquidity and financial flexibility in connection with the current and any future Covid-19 outbreaks and reductions in commodity prices;
The potential for an improved economic environment resulting from a lack of capital investment and drilling in the oil and gas industry;
2021 production range, 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 low or volatile commodity prices;
IPC’s ability, as market conditions evolve and if determined necessary from time to time, to reduce expenditures and curtail production, and then to resume such production;
IPC’s continued access to its existing credit facilities, including current financial headroom, on terms acceptable to the Corporation;
The ability to fully fund 2021 expenditures from cash flows and current borrowing capacity;
IPC’s ability to maintain operations, production and business in light of the current and any future Covid-19 outbreaks 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 intention and ability to continue to implement our 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;
Future development potential of the Suffield and Ferguson operations, including the timing and success of future oil and gas optimization programs;
Development of the Blackrod project in Canada;
Current and future drilling pad production and timing and success of facility upgrades and tie-in work at Onion Lake Thermal;
The timing and success of the planned five well infill drilling program at Onion Lake Thermal;
The ability to maintain current and forecast production in France;
The ability of IPC to implement alternative transportation arrangements for Paris Basin production in connection with the closure of the Total-operated Grandpuits refinery, including at costs estimated by the Corporation;
The ability to maintain current and forecast production in Malaysia;
The timing and success of the drilling of the A15 sidetrack well and of the production well pump rate optimisation project in Malaysia;
IPC’s ability to implement its GHG emissions intensity and climate strategies and to achieve its net GHG emissions intensity reduction targets;
Estimates of reserves and contingent resources;
The ability to generate free cash flows and use that cash to repay debt; 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.
The forward-looking statements are based on certain key expectations and assumptions made by IPC, including expectations and assumptions concerning: prevailing commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future well production rates and reserve and contingent resource volumes; operating costs; the timing of receipt of regulatory approvals; the performance of existing wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions; the benefits of acquisitions; the state of the economy and the exploration and production business in the jurisdictions in which IPC operates and globally; the availability and cost of financing, labour and services; and the ability to market crude oil, natural gas and natural gas liquids successfully.
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:
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;
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; and
changes in legislation, including but not limited to tax laws, royalties, environmental and abandonment regulations.
Readers are cautioned that the foregoing list of factors is not exhaustive.
Estimated free cash flow generation is based on IPC’s current business plans over the period of 2021 to 2025. Assumptions include average net production of approximately 45 Mboepd, average Brent oil prices of USD 55 to 75 per boe escalating by 2% per year, average gas prices of CAD 2.50 per thousand cubic feet, and average Brent to Western Canadian Select differentials as estimated by IPC’s independent reserves evaluator and as further described in the AIF. IPC’s current business plans and assumptions, and the business environment, are subject to change. Actual results may differ materially from forward-looking estimates and forecasts.
Additional information on these and other factors that could affect IPC, or its operations or financial results, are included in the MD&A (See “Cautionary Statement Regarding Forward-Looking Information” therein), the Corporation’s Annual Information Form (AIF) for the year ended December 31, 2020 (See “Cautionary Statement Regarding Forward-Looking Information”, “Reserves and Resources Advisory” and ” Risk Factors” therein) 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 (www.sedar.com) or IPC’s website (www.international-petroleum.com).
The current and any future Covid-19 outbreaks may increase IPC’s exposure to, and magnitude of, each of the risks and uncertainties identified above that result from a reduction in demand for oil and gas consumption and/or lower commodity prices and/or reliance on third parties. The extent to which Covid-19 impacts IPC’s business, results of operations and financial condition will depend on future developments, which are highly uncertain and are difficult to predict, including, but not limited to, the duration and spread of the current and any future Covid-19 outbreaks, their severity, the actions taken to contain such outbreaks or treat their impact, and how quickly and to what extent normal economic and operating conditions resume and their impacts to IPC’s business, results of operations and financial condition which could be more significant in upcoming periods as compared with previous periods. Even after the Covid-19 outbreaks have subsided, IPC may continue to experience materially adverse impacts to IPC’s business as a result of the global economic impact.
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”, 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 Corporation uses non-IFRS measures to provide investors with supplemental measures to assess the cash generated by and the financial performance and position of the Corporation. Management also uses non-IFRS measures internally in order to facilitate operating performance comparisons from period to period, prepare annual operating budgets and assess the Corporation’s ability to meet its future capital expenditure and working capital requirements. Management believes these non-IFRS measures are important supplemental measures of operating performance because they highlight trends in the core business that may not otherwise be apparent when relying solely on IFRS financial measures. Management believes such measures allow for assessment of the Corporation’s operating performance and financial condition on a basis that is more consistent and comparable between reporting periods. The Corporation also believes that securities analysts, investors and other interested parties frequently use non-IFRS measures in the evaluation of issuers. Forward-looking statements are provided for the purpose of presenting information about management’s current expectations and plans relating to the future and readers are cautioned that such statements may not be appropriate for other purposes.
The definition and reconciliation of each non-IFRS measure is presented in IPC’s MD&A (See “Non-IFRS Measures” therein).
Disclosure of Oil and Gas Information
This press release contains references to estimates of gross and net reserves and resources attributed to the Corporation’s oil and gas assets. Gross reserves / resources are the working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests. Net reserves / resources are the working interest (operating or non-operating) share after deduction of royalty obligations, plus royalty interests in reserves/resources, and in respect of PSCs in Malaysia, adjusted for cost and profit oil. Unless otherwise indicated, reserves / resource volumes are presented on a gross basis.
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, 2020, 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, 2020 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, 2020, 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, 2020 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.
The reserves life index (RLI) is calculated by dividing the 2P reserves of 272 MMboe as at December 31, 2020, by the mid-point of the initial 2021 average net daily production guidance of 41,000 to 43,000 boepd.
The product types comprising the 2P reserves and contingent resources described in this press release are contained in the AIF. See also “Supplemental Information regarding Product Types” below. Light, medium and heavy crude oil reserves/resources disclosed in this press release include solution gas and other by-products.
“2P reserves” means proved plus probable reserves. “Proved reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. “Probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
Each of the reserves categories reported (proved and probable) may be divided into developed and undeveloped categories. “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 (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. “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 (for example, 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) to which they are assigned.
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. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent resources are further classified in accordance with the level of certainty associated with the estimates and may be sub-classified based on a project maturity and/or characterized 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 COGE Handbook as being considered to be 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% probability that the quantities actually recovered will equal or exceed the best estimate.
Contingent resources are further classified based on project maturity. The project maturity subclasses include development pending, development on hold, development unclarified and development not viable. All of the Corporation’s contingent resources are classified as either development on hold or development unclarified. 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 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 contingencies can be clearly defined. Chance of development is the probability of a project being commercially viable.
References to “unrisked” contingent resources volumes means that the reported volumes of contingent resources have not been risked (or adjusted) based on the chance of commerciality of such resources. In accordance with the COGE Handbook for contingent resources, the chance of commerciality is solely based on the chance of development based on all contingencies required for the re-classification of the contingent resources as reserves being resolved. Therefore unrisked reported volumes of contingent resources do not reflect the risking (or adjustment) of such volumes based on the chance of development of such resources.
The contingent resources reported in this press release are estimates only. The estimates are based upon a number of factors and assumptions each of which contains estimation error which could result in future revisions of the estimates as more technical and commercial information becomes available. The estimation factors include, but are not limited to, the mapped extent of the oil and gas accumulations, geologic characteristics of the reservoirs, and dynamic reservoir performance. There are numerous risks and uncertainties associated with recovery of such resources, including many factors beyond the Corporation’s control. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources referred to in this press release. References to “contingent resources” do not constitute, and should be distinguished from, references to “reserves”.
2P reserves and contingent resources included in the reports prepared by Sproule and ERCE in respect of IPC’s oil and gas assets in Canada, France and Malaysia have been aggregated by IPC. Estimates of reserves, resources and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves, resources and future net revenue for all properties, due to aggregation. This press release contains estimates of the net present value of the future net revenue from IPC’s reserves. The estimated values of future net revenue disclosed in this press release do not represent fair market value. There is no assurance that the forecast prices and cost assumptions used in the reserve evaluations will be attained and variances could be material.
BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 thousand cubic feet (Mcf) per 1 barrel (bbl) 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 document:
Heavy Crude Oil (Mboepd)
Light and Medium Crude Oil (Mboepd)
Conventional Natural Gas (per day)
Six months ended
June 30, 2021
June 30, 2020
Three months ended
June 30, 2021
June 30, 2020
December 31, 2020
This press release also makes reference to IPC’s forecast average net daily production of above 44,000 boepd for 2021. IPC estimates that approximately 45% of that production will be comprised of heavy oil, approximately 18% will be comprised of light and medium crude oil and approximately 37% will be comprised of conventional natural gas.
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. References herein to CAD mean Canadian dollars.