Annual Information Form
Dated February 25, 2026
Annual Information Form dated February 25, 2026 Table of Contents
1 Advisories
2 Abbreviations
3 Corporate Structure
4 General Development of the Business
6 Description of Suncor's Businesses
6 Oil Sands
Exploration and Production
Refining and Marketing
Other Suncor Businesses
Suncor Employees
14 Ethics, Social and Environmental Policies
15 Statement of Reserves Data and Other Oil and Gas Information
16 Oil and Gas Reserves Tables and Notes
20 Future Net Revenues Tables and Notes
25 Additional Information Relating to Reserves Data
31 Industry Conditions
34 Risk Factors
Dividends
Description of Capital Structure
Market for Securities
Directors and Executive Officers
43 Audit Committee Information
44 Legal Proceedings and Regulatory Actions
44 Interests of Management and Others in Material Transactions
44 Transfer Agent and Registrar
44 Material Contracts
44 Interests of Experts
44 Disclosure Pursuant to the Requirements of the NYSE
44 Additional Information
45 Advisory - Forward-Looking Statements and Non-GAAP Financial Measures
Schedules
A-1 SCHEDULE "A" - AUDIT COMMITTEE MANDATE
B-1 SCHEDULE "B" - SUNCOR ENERGY INC. POLICY AND PROCEDURES FOR PRE-APPROVAL OF AUDIT AND NON-AUDIT SERVICES
C-1 SCHEDULE "C" - FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
D-1 SCHEDULE "D" - FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION
In this Annual Information Form (AIF), references to "Suncor" or "the company" or "Suncor Energy" mean Suncor Energy Inc., its subsidiaries, partnerships and joint arrangements, unless otherwise specified or the context otherwise requires.
All financial information is reported in Canadian dollars, unless otherwise noted. Production volumes are presented on a working-interest basis, before royalties, except for production volumes from the company's Libyan operations, which are presented on an economic basis.
References to the 2025 audited Consolidated Financial Statements mean Suncor's audited Consolidated Financial Statements prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), the notes thereto and the auditor's report thereon, as at and for the years ended December 31, 2025 and 2024. References to the annual 2025 MD&A mean Suncor's Management's Discussion and Analysis for the year ended December 31, 2025, dated February 25, 2026.
This AIF contains forward-looking statements and forward-looking information based on Suncor's current plans, expectations, estimates, projections and assumptions. This information is subject to a number of risks and uncertainties, many of which are beyond the company's control. Many of these risk factors and other assumptions related to Suncor's forward-looking statements are discussed in further detail throughout this AIF and the company's annual 2025 MD&A under the heading Risk Factors, which section is incorporated by reference herein and available on Suncor's SEDAR+ profile at sedarplus.ca. Users of this information are cautioned that actual results may differ materially from those expressed or implied by the forward-looking statements contained herein. Refer to the Advisory - Forward-Looking Statements and Non-GAAP
Financial Measures section of this AIF for information on risk factors and the material assumptions underlying the forward-looking statements.
Information contained in or otherwise accessible through Suncor's website at https://www.suncor.com does not form a part of this AIF and is not incorporated into this AIF by reference.
Measurement, Products and Markets mbbls thousands of barrels
mbbls/d thousands of barrels per day mmbbls millions of barrels
GHG greenhouse gas
mmbtu millions of British thermal units
CO2carbon dioxide
CO2e carbon dioxide equivalent
NGL(s) natural gas liquid(s)
SAGD steam assisted gravity drainage
SCO synthetic crude oil
SO2sulphur dioxide
MW megawatts
Mt megatonnes
WCS Western Canadian Select
WTI West Texas Intermediate
Places and Currencies
U.S. United States
U.K. United Kingdom
$ or Cdn$ Canadian dollars US$ United States dollars
Name, Address and IncorporationSuncor Energy Inc. (formerly Suncor Inc.) was originally formed by amalgamation under the Canada Business Corporations Act (the CBCA) on August 22, 1979, of Sun Oil Company Limited, incorporated in 1923, and Great Canadian Oil Sands Limited, incorporated in 1953. On January 1, 1989, the company amalgamated with a wholly owned subsidiary under the CBCA. The company amended its Articles in 1995 to move its registered office from Toronto, Ontario, to Calgary, Alberta, and in April 1997 to adopt the name, "Suncor Energy Inc."
Pursuant to an arrangement under the CBCA, which was completed effective August 1, 2009, Suncor amalgamated with Petro-Canada to form a single corporation continuing under the name "Suncor Energy Inc." On January 1, 2017, November 20, 2023, and January 1, 2024, Suncor amalgamated with certain of its wholly owned subsidiaries under the CBCA.
Suncor's registered and head office is located at 150 - 6thAvenue S.W., Calgary, Alberta, T2P 3E3.
Intercorporate RelationshipsSuncor's material subsidiaries, the voting securities of which were held either directly or indirectly by the company as at December 31, 2025, are shown below.
Name | Jurisdiction Where Organized | Percentage Owned |
Canadian operations | ||
Suncor Energy Oil Sands Limited Partnership | Alberta | 100% |
Suncor Energy Products Partnership | Alberta | 100% |
Suncor Energy Marketing Inc. | Alberta | 100% |
Canadian Oil Sands Partnership #1 | Alberta | 100% |
Fort Hills Energy Limited Partnership | Alberta | 100% |
U.S. operations Suncor Energy (U.S.A.) Marketing Inc. | Delaware | 100% |
Suncor Energy (U.S.A.) Inc. | Delaware | 100% |
The company's remaining subsidiaries each accounted for (i) less than 10% of the company's consolidated assets as at December 31, 2025, and
(ii) less than 10% of the company's consolidated revenues for the fiscal year ended December 31, 2025. In aggregate, the company's remaining subsidiaries accounted for less than 20% of the company's consolidated assets as at December 31, 2025, and less than 20% of the company's consolidated revenues for the fiscal year ended December 31, 2025.
OverviewSuncor Energy is Canada's leading integrated energy company. Suncor's operations span the full energy value chain, including oil sands mining and in situ operations, upgrading, offshore production, petroleum refining in Canada and the U.S., marketing and trading, and nationwide Petro-Canada™ retail and wholesale networks - delivering reliable energy that fuels economic growth and meets the needs of customers across Canada and globally. With an unwavering focus on safety, operational excellence, and profitability, Suncor is committed to delivering industry-leading performance and long-term shareholder value. Suncor's common shares (symbol: SU) are listed on the TSX and NYSE.
Three-Year HistoryOver the last three years, the following events have influenced the general development of Suncor's business.
2023- Share repurchase program. In 2023, Suncor repurchased approximately 52.0 million of its common shares, or the equivalent of 3.9% of its issued and outstanding common shares as at December 31, 2022, at an average price of $42.96 per common share.
-
Sale of wind and solar assets. In the first quarter of 2023, Suncor completed the sale of its wind and solar assets for gross proceeds of
$730 million, before closing adjustments and other closing costs.
- Acquired additional interest in Fort Hills. On February 2, 2023, Suncor completed the acquisition of an additional 14.65% working interest in Fort Hills for $712 million from Teck Resources Limited, bringing the company's working interest to 68.76%. The effective date of the transaction was November 1, 2022.
- Rich Kruger appointed President and Chief Executive Officer. Mr. Kruger was named Suncor's President and Chief Executive Officer.
- Sale of U.K. assets. In the second quarter of 2023, Suncor completed the sale of its U.K. Exploration and Production (E&P) portfolio for gross proceeds of $1.1 billion, before closing adjustments and other closing costs.
- Co-ownership agreement with North Atlantic. In the first quarter of 2023, Suncor entered into a co-ownership agreement with North Atlantic to combine retail fuel networks and will include the rebranding of a number of North Atlantic's sites to the Petro-Canada™ brand.
- Petro-Canada™ and Canadian Tire Corporation partnership. In the second quarter of 2023, Petro-Canada™ and Canadian Tire Corporation entered into a partnership that will result in the rebranding of over 200 Canadian Tire retail fuel sites to the Petro-Canada™ brand, partnering of their loyalty programs, and make Suncor the primary fuel provider for Canadian Tire Corporation's retail fuel network.
- Workforce reductions. During the second half of 2023, Suncor completed workforce reductions of approximately 1,500 employees.
- Terra Nova returns to production. In the fourth quarter of 2023, the Terra Nova Floating, Production, Storage and Offloading (FPSO) vessel safely restarted production.
- Dividend increase. In the fourth quarter of 2023, the Board approved a quarterly dividend of $0.545 per share, an increase of approximately 5% over the prior quarter dividend.
- Acquired remaining interest in Fort Hills. On November 20, 2023, Suncor completed the acquisition of TotalEnergies EP Canada Ltd. (TotalEnergies Canada), which held the remaining 31.23% working interest in Fort Hills, for $1.468 billion before closing adjustments and other closing costs, making Suncor the sole owner of Fort Hills. The effective date of the transaction was April 1, 2023.
- Issuance of senior notes. During the fourth quarter of 2023, Suncor issued $1.0 billion aggregate principal amount of 5.60% senior unsecured medium term notes and $500 million aggregate principal amount of 5.40% senior unsecured medium term notes, due on November 17, 2025, and November 17, 2026, respectively, to finance the acquisition of TotalEnergies Canada. 2024
- Share repurchase program. In 2024, Suncor repurchased approximately 55.6 million of its common shares, or the equivalent of 4.3% of its issued and outstanding common shares as at December 31, 2023, at an average price of $52.33 per common share.
- New cogeneration facility begins operating. In the fourth quarter of 2024, the company began operating an 800 MW cogeneration facility to replace the coke-fired boilers at Oil Sands Base Plant, which provides the steam generation required for extraction and upgrading activities at a lower cost. The cogeneration facility also generates lower-carbon-intensive power for Alberta's power grid.
- Executed debt tender offer. In the third quarter of 2024, the company completed a debt tender offer and repurchased $1.1 billion aggregate principal amount of certain series of the company's outstanding notes, capturing significant economic value and reducing future interest obligations.
- Dividend increase. In the fourth quarter of 2024, the Board approved a quarterly dividend of $0.57 per share, an increase of approximately 5% over the prior quarter dividend. 2025
- Share repurchase program. In 2025, Suncor repurchased approximately 55.3 million of its common shares, or the equivalent of 4.4% of its issued and outstanding common shares as at December 31, 2024, at an average price of $54.68 per common share.
- White Rose resumes production. Production at White Rose was safely restarted in the first quarter of 2025, with output returning to normal levels in the second quarter of the year.
- Syncrude Mildred Lake Mine Extension West (MLX-W) achieves first ore. In the second quarter of 2025, Syncrude reached a key milestone with first ore extraction from the MLX-W project.
- Upgrader 1 coke drum integrity project (CDIP) completed. This project, completed in 2025, is expected to extend Upgrader 1's life by 30 years and reduce future costs.
- Maintenance intervals extended. At Upgrader one the new coke drums and reliability improvements have enabled turnaround interval extensions from five to six years. At Fort Hills, primary separation cell outages have been extended from six-month to annual intervals. In the downstream, reliability improvements have also resulted in longer intervals between planned maintenance.
- Completion of Fort Hills mine improvement plan. In 2025, Fort Hills successfully completed the three-year mine improvement plan achieving 90% of nameplate capacity.
- Issuance of senior notes. During the fourth quarter of 2025, Suncor issued $500 million of 2.95% senior unsecured medium term notes and $500 million of 3.55% senior unsecured medium term notes, due on November 14, 2027, and November 14, 2030, respectively, to finance the repayment of existing debt.
- Investor Day targets achieved one year early. Suncor achieved its 2024 Investor Day three-year targets a full year ahead of schedule.
- Dividend increase. In the fourth quarter of 2025, the Board approved a quarterly dividend of $0.60 per share, an increase of approximately 5% over the prior quarter dividend.
Suncor has classified its operations into the following segments: Oil Sands, Exploration & Production (E&P), Refining & Marketing (R&M), and Corporate & Eliminations.
Oil SandsLocated in the Athabasca oil sands in northeast Alberta, Suncor's Oil Sands segment produces bitumen from mining operations at Base Plant Mine, Syncrude, and Fort Hills and In Situ operations at Firebag and MacKay River. Suncor has integrated upgrading facilities at Base Plant and Syncrude, where bitumen is either upgraded into synthetic crude oil (SCO) or blended with diluent for refinery feedstock or direct sale to market.
Regional IntegrationThe Oil Sands segment is regionally integrated, giving it the ability to transport bitumen and intermediate production between assets in the region. Base Plant acts as the hub, with both Fort Hills and In Situ having the ability to transport production directly to Base Plant. Syncrude's Mildred Lake site is connected to Base Plant by bi-lateral interconnecting pipelines. This integration allows Suncor to move production within the region to maximize value through upgrading and to minimize maintenance impacts.
Oil Sands ProductionProduction Summary (mbbls/d) | 2025 | 2024 |
Oil Sands Bitumen Production | ||
Base Plant Mine | 262.5 | 261.9 |
Fort Hills Mine | 175.4 | 168.0 |
Syncrude Mine | 221.5 | 211.0 |
In Situ | ||
Firebag | 244.7 | 233.8 |
MacKay River | 33.4 | 32.3 |
Total Oil Sands Bitumen Production | 937.5 | 907.0 |
Upgraded - Net SCO and Diesel Production | ||
Oil Sands Operations(1) | 343.7 | 345.8 |
Syncrude | 204.8 | 198.4 |
Inter-asset transfer and consumption | (29.4) | (28.1) |
Total Upgraded Net SCO and Diesel Production | 519.1 | 516.1 |
Non-Upgraded Bitumen Production | ||
Oil Sands Operations(1) | 160.9 | 141.8 |
Fort Hills | 175.4 | 168.0 |
Syncrude | 2.3 | 1.1 |
Inter-asset transfer and consumption | (58.3) | (53.2) |
Total Non-Upgraded Bitumen | 280.3 | 257.7 |
Total Oil Sands Production Volumes | 799.4 | 773.8 |
(1) Oil Sands operations consists of: Oil Sands Base operations and In Situ operations.
Mining OperationsSuncor has two wholly owned mining operations, Oil Sands Base and Fort Hills, and owns a 58.74% interest in the Syncrude joint operation, all of which are open-pit mining operations. Suncor has been the operator of the Syncrude joint operation since September 30, 2021.
Oil Sands Base Mining
Bitumen at Oil Sands Base Plant Mine is mined from the Millennium area, which began production in 2001, and the North Steepbank area, which began production in 2011. Shovels are used to excavate oil sands bitumen ore, which is trucked to primary extraction where a slurry of hot water, sand and bitumen is delivered via a pipeline to the extraction plants. Naphtha is added to the bitumen froth, which is then centrifuged to separate impurities, minerals and coarse tailings.
Suncor continues to progress the phased implementation of Autonomous Haulage Systems (AHS) at its mines to lower costs and improve productivity and safety performance. AHS has been deployed at Oil Sands Base mine and is expected to be deployed at Syncrude Mildred Lake in 2026, with Fort Hills to follow.
Fort Hills Mining
Fort Hills mine is north of Oil Sands Base operations. Fort Hills started production in 2018. Fort Hills operations are substantially similar to those of Suncor's Oil Sands Base mining and extraction assets; however, Fort Hills uses a paraffinic froth treatment process to produce a marketable
bitumen product that is partially decarbonized, resulting in a higher-quality bitumen requiring less diluent to transport and eliminating the need for on-site upgrading facilities.
Syncrude Mining
Syncrude mining and extraction operations are similar to those at Oil Sands Base. Syncrude began producing in 1978 and is located north and east of Oil Sands Base operation. It includes mining operations at Mildred Lake and Aurora North. In the second quarter of 2025, Syncrude achieved first ore extraction from the MLX-W project. The project is expected to sustain bitumen production levels at the Mildred Lake site, using existing mining and extraction facilities, as the Mildred Lake North Mine approaches its end of life. The Mildred Lake Extension East (MLX-E) program is expected to follow the MLX-W development with spending starting in 2026.
Other Mining Leases
Suncor directly owns interests in several other mineable oil sands leases, including Base Mine Extension (100%) and Audet (100%). Suncor undertakes exploratory drilling programs on such leases from time to time as part of its bitumen supply strategy. Suncor indirectly owns interests in other mineable oil sands leases, including Lease 29, Lease 30 and Lease 31, through the company's interest in Syncrude.
In Situ OperationsSuncor's In Situ operations include bitumen production from Firebag and MacKay River, as well as supporting infrastructure, including central processing facilities, cogeneration units, product transportation infrastructure, diluent import capabilities, storage assets and a cooling and blending facility. In Situ operations use SAGD technology for producing bitumen from oil sands deposits that are too deep to be mined. Steam and electricity for operations are supplied through Once Through Steam Generators (OTSGs) and cogeneration units fuelled by both purchased and produced natural gas.
Firebag
Production from Firebag commenced in 2004. The Firebag complex has central processing facilities with a nameplate capacity of 215 mbbls/d of bitumen.
MacKay River
Production from MacKay River commenced in 2002. The MacKay River central processing facilities have a bitumen processing capacity of
38 mbbls/d. Steam and power for operations are provided by a third-party owned and operated, on-site cogeneration unit as well as four OTSGs. Other In Situ Leases
Suncor holds a large portfolio of In Situ lands in proximity to Fort McMurray, including a 100% working interest in Lewis, a 100% working interest in Firebag South, a 77.78% working interest in OSLO, a 75% working interest in Meadow Creek, and interests varying from 25% to 50% in Chard. Lewis has received regulatory approval for future production.
Technology
Expanding Solvent SAGD (ES-SAGD) is an enhancement of SAGD technology that accelerates bitumen production, reduces the steam-to-oil ratio and lowers GHG emissions intensity. The technology is expected to be ready for deployment in Suncor's In Situ projects by 2027.
The Enhanced Bitumen Recovery Technology (EBRT) process involves the replacement of steam with a hydrocarbon solvent to reduce steam requirements. The combined solvent and thermal effect has potential to increase energy efficiency and reduce water use from oil sands operations.
Upgrading FacilitiesBase Plant
Base Plant upgrades bitumen to SCO with two upgraders with a combined nameplate capacity of 350 mbbls/d of SCO, producing both sour and sweet SCO. Upgrading processes also produce ultra-low sulphur diesel fuel and other byproducts. In 2025, the Upgrader 1 coke drum replacement project was completed, replacing eight coke drums and ancillary systems, and extending the life of the Upgrader 1 facility by an expected 30 years.
Syncrude
Upgrading technologies at Syncrude are similar to those used at Oil Sands Base, with the exception that Syncrude uses a fluid coking process that involves the continuous thermal cracking of the heaviest hydrocarbons. Upgrader nameplate capacity is 206 mbbls/d of SCO net to Suncor. At Mildred Lake, electricity is provided by a utility plant fuelled by natural gas and rich fuel gas from upgrading operations. Syncrude primarily produces a sweet SCO product, and each individual Syncrude owner is responsible for marketing its share of production.
Power GenerationSuncor operates cogeneration facilities at Oil Sands Base, Firebag, Fort Hills and Syncrude, generating excess electricity that is sold to the Alberta power grid. These facilities have an aggregate capacity of approximately 2,228 MW.
Sales of Principal ProductsPrimary markets for SCO and bitumen production from Suncor's Oil Sands segment include refining operations in North America and Asia. Diesel production from upgrading operations is sold primarily in Western Canada and the U.S.
2025 | 2024 | ||||
Sales Volumes and Operating Revenues - Principal Products | mbbls/d | % Operating Revenues | mbbls/d | % Operating Revenues | |
SCO and diesel | 520.4 | 62 | 513.2 | 65 | |
Bitumen | 278.6 | 35 | 260.8 | 34 | |
Byproducts and other operating revenues(1) | n/a | 3 | n/a | 1 | |
799.0 | 774.0 | ||||
Operating revenues include revenues associated with excess electricity from cogeneration units.
Distribution of ProductsProduction from Suncor's Oil Sands segment is gathered into facilities at the Enbridge Athabasca Terminal or the East Tank Farm, except for production from Syncrude, which is moved to market via the Pembina Alberta Oil Sands Pipeline.
Product moves from the Athabasca Terminal in the following ways:
To Edmonton, via the Oil Sands pipeline where the product is processed in Suncor's Edmonton refinery, or sold to other local refiners.
To Hardisty, Alberta, on the Enbridge Athabasca Pipeline or the Enbridge Wood Buffalo Pipeline and the Enbridge Wood Buffalo Pipeline Extension.
To Edmonton via the Enbridge Waupisoo Pipeline, originating at Cheecham.
From Edmonton and Hardisty, where Suncor owns storage capacity and has additional capacity under contract, there are various options for delivering SCO and bitumen to customers:
To Suncor's Commerce City Refinery via the Platte pipeline, and via the mainline from Rose Rock's Platteville Terminal. Suncor owns and operates the Rocky Mountain Pipeline, which originates from Guernsey, Wyoming.
To Suncor's Sarnia refinery on the Enbridge Mainline and to Suncor's Montreal refinery from Sarnia on Enbridge's Line 9.
To most major refining hubs via the Enbridge Mainline, Express/Platte, Keystone and Flanagan South pipeline systems.
To West Coast U.S refineries via the Trans Mountain Pipeline, and by rail.
Suncor's E&P segment consists of offshore operations off the east coast of Canada and onshore assets in Libya and Syria.
E&P Canada - Assets and OperationsBased in St. John's, Newfoundland and Labrador, this business includes interests in four producing fields and future developments and extensions. Suncor is the only company with interests in every field currently in production in this region.
E&P Canada ProductionCrude Oil Production (mbbls/d) | 2025 | 2024 |
Terra Nova | 10.7 | 11.4 |
Hibernia and Hibernia Southern Expansion | 14.0 | 14.2 |
White Rose and White Rose Extension | 3.8 | - |
Hebron | 29.0 | 24.1 |
Total | 57.5 | 49.7 |
Terra Nova
Suncor holds a 48% working interest in the Terra Nova oilfield. Terra Nova, which is approximately 350 kilometres southeast of St. John's. Operated by Suncor, the production system is developed using an FPSO vessel that is moored on location. The Terra Nova oilfield is divided into three distinct areas, the Graben, the East Flank and the Far East, and began production in January 2002.
Hibernia and the Hibernia Southern Extension Unit
Suncor holds a non-operated interest in Hibernia (20% in the base project and 19.485% in the Hibernia Southern Extension Unit). The Hibernia oilfield, encompassing the Hibernia and Ben Nevis Avalon reservoirs, is approximately 315 kilometres southeast of St. John's. Operated by Hibernia Management and Development Company Ltd., the production system is a fixed gravity-based structure that sits on the ocean floor.
Hibernia commenced production in November 1997. White Rose and the White Rose Extensions
White Rose is approximately 350 kilometres southeast of St. John's and is operated by Cenovus Energy Inc., White Rose began production in 2005 and uses the SeaRose FPSO. Suncor holds a 40% working interest in the field. White Rose was taken offline for the SeaRose FPSO Asset Life Extension Project and did not produce in 2024 while the FPSO was in dry dock. In the first quarter of 2025 production at White
Rose restarted and returned to normal production levels by the second quarter of 2025.
The White Rose Extensions include the North Amethyst, South White Rose Extension and West White Rose satellite fields (the Extensions). First oil was achieved at North Amethyst in May 2010 and at the South White Rose Extension in June 2015. Development of the West White Rose field has been divided into two stages. The first stage achieved first oil in September 2011 and the second stage, the West White Rose Project, was sanctioned in 2017, with production expected to commence in 2026. Suncor's working interest is 38.6% in the Extensions.
Hebron
Suncor holds a 21.034% interest in the Hebron oilfield, located approximately 340 kilometres southeast of St. John's and operated by ExxonMobil. The development includes a concrete gravity-based structure that sits on the ocean floor. First oil was achieved in November 2017.
Other Assets
Suncor holds interests in 48 significant discovery licences.
Distribution of ProductsField production is transported by shuttle tanker from offshore installations and delivered directly to customers or to the Newfoundland transshipment terminal in Placentia Bay, where it is loaded onto tankers for transport to markets in Eastern Canada, the U.S., Europe, Latin America and Asia. Suncor has a 14% ownership interest in the transshipment facility and marine transportation assets for East Coast Canada.
E&P International - Assets and Operations InternationalLibya
Suncor is a signatory to seven exploration and production sharing agreements (EPSAs) in Libya with the National Oil Corporation (NOC). Under the EPSAs, Suncor pays 100% of the exploration costs, 50% of the development costs and 12% of the operating costs. The development, operating and eligible exploration costs are recovered through a 12% share of production (cost recovery oil). Any cost recovery oil remaining after Suncor's costs have been recovered is shared between Suncor and the NOC based on several factors. The EPSAs expire on December 31, 2032, but include an initial five-year extension through the end of 2037.
Since 2013, production and liftings in Libya have been intermittent due to ongoing political unrest, and the remaining value of Suncor's assets in Libya was impaired in 2015. The timing of a return to normal operations in Libya remains uncertain due to continued political unrest.
The estimated cost of Suncor's remaining exploration work program commitment as at December 31, 2025, is US$349 million. Suncor declared force majeure for all exploration commitments in Libya effective December 14, 2014, and this declaration remains in effect.
In December 2011, sanctions were imposed due to political unrest in Syria, and Suncor declared force majeure under its contractual obligations, suspending its operations in the country. The company ceased recording all production and revenue associated with its Syrian assets and the remaining value of the Suncor assets in Syria was impaired to zero in 2013.
Sales of Principal ProductsSales arrangements are made on a spot basis and incorporate pricing that is generally determined on a daily or monthly basis in relation to a specified market reference price. Suncor does not typically enter into long-term supply arrangements to sell its production from its E&P segment.
In Libya, crude oil is marketed by the NOC on behalf of Suncor. Exploration and Production Sales Summary:
2025 2024
% Operating % Operating
Crude Oil Sales Volumes mbbls/d Revenues mbbls/d Revenues
E&P Canada 56.2 94 52.2 93
E&P International(1) 3.6 6 4.0 7
Total Exploration and Production 59.8 100 56.2 100
(1) Production volumes for Libya on an economic basis.
Refining and MarketingSuncor's R&M segment consists of two primary operations: the refining and supply operations and the sales and marketing operations, as well as the infrastructure supporting the marketing supply of refined products, crude oil, and byproducts.
Refining and Supply - Assets and OperationsRefinery Throughputs, Utilizations and Yields
Average Daily Crude Throughput Montreal Sarnia Edmonton Commerce City | ||||||||
(mbbls/d, except as noted) | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 |
Sweet SCO | 40.5 | 28.1 | 40.1 | 35.7 | 55.2 | 60.8 | - | - |
Sour SCO | - | - | 31.6 | 26.9 | 43.6 | 49.6 | 12.3 | 11.6 |
Diluted bitumen | 33.1 | 27.6 | - | - | 37.8 | 42.9 | 15.4 | 11.8 |
Sweet conventional | 73.7 | 70.5 | 0.5 | 3.1 | 6.1 | - | 65.9 | 65.4 |
Sour conventional | 1.7 | 7.4 | 17.3 | 14.4 | - | - | 5.5 | 9.3 |
Total | 149.0 | 133.6 | 89.5 | 80.1 | 142.7 | 153.3 | 99.1 | 98.1 |
Total Capacity | 137 | 137 | 85 | 85 | 146 | 146 | 98 | 98 |
Utilization (%) | 109 | 97 | 105 | 94 | 98 | 105 | 101 | 100 |
Refined Petroleum Production Yield Mix Montreal Sarnia Edmonton Commerce City | ||||||||
(%) | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 | 2025 | 2024 |
Gasoline | 40 | 40 | 47 | 46 | 43 | 43 | 50 | 50 |
Distillates | 41 | 42 | 40 | 37 | 52 | 52 | 33 | 33 |
Other | 19 | 18 | 13 | 17 | 5 | 5 | 17 | 17 |
Montreal Refinery
The Montreal refinery has a flexible configuration that allows processing of sweet SCO from the company's Oil Sands segment, WCS, conventional crude oil and intermediate feedstock. Crude oil for the refinery can be supplied through several channels, including via Enbridge's Line 9, by marine transportation and by rail.
Products from the Montreal refinery are distributed primarily across Quebec and Ontario. Refined products are delivered to distribution terminals and customers via the Trans-Northern Pipeline, truck, rail and marine vessels.
Sarnia Refinery
The Sarnia refinery processes SCO from the company's Oil Sands segment and conventional crude oil purchased from third parties. Crude oil is supplied to the refinery primarily via the Enbridge Mainline and Lakehead pipeline systems. Suncor procures conventional crude oil feedstock primarily from Western Canada and can supplement supply with purchases from the U.S.
Products from the Sarnia refinery are primarily distributed in Ontario. Refined products are delivered to distribution terminals in Ontario via the Sun-Canadian Pipeline or delivered to customers directly via marine vessel and rail. The Sarnia refinery also has limited access to pipelines
delivering refined products into the U.S. Other Facilities
Suncor operates Canada's largest ethanol facility, the St. Clair ethanol plant in the Sarnia-Lambton region of Ontario. In 2025, the plant produced 390 million litres of ethanol (2024 - 402 million litres).
Edmonton Refinery
The Edmonton refinery processes a wide range of feedstocks sourced from Suncor's Oil Sands segment and other producers in Alberta's Wood Buffalo and Cold Lake regions. Crude oil is supplied to the refinery via company-owned and third-party pipelines.
Products from the Edmonton refinery are delivered to distribution terminals across Canada via the Alberta Products Pipeline, the Trans Mountain Pipeline, the Enbridge pipeline system, by rail, or delivered to customers directly via truck and rail.
Commerce City Refinery
The Commerce City Refinery, which is comprised of two small refineries and three plants, processes crude feedstocks that are sourced from the U.S., Suncor's Oil Sands segment and other Canadian sources. Crude oil is supplied to the Commerce City Refinery primarily by pipeline, with the remainder transported via truck.
Products from the refinery are mostly sold to commercial, retail and wholesale customers in Colorado and Wyoming. Refined products are distributed by truck, rail and pipeline.
Other Facilities
Suncor imports, primarily ethanol and hydrotreated renewable diesel, and exports refined products through its Burrard distribution terminal located on the west coast of British Columbia and exports refined products through the Parachem facility located in Montreal, Quebec. The Burrard distribution terminal has total export capacity of 40 mbbls/d. Parachem has an export capacity of 12 mbbls/d.
Distribution Terminals and Pipelines
Suncor owns and operates 14 major refined product terminals across Canada (including terminals adjacent to refineries) and three product terminals in Colorado. Combined with access to facilities under long-term contractual arrangements with other parties, Suncor's North American assets are sufficient to meet the R&M segment's current storage and distribution needs.
As at December 31, 2025, Suncor's ownership interests in certain pipelines were as follows:
Pipeline | Ownership | Type | Origin | Destinations |
Portland-Montreal Pipeline | 100.00% | Crude oil | Portland, Maine | Montreal, Quebec |
Trans-Northern Pipeline | 33.30% | Refined product | Montreal, Quebec | Ontario - Ottawa, Toronto & Oakville |
Sun-Canadian Pipeline | 55.00% | Refined product | Sarnia, Ontario | Ontario - Toronto, London & Hamilton |
Alberta Products Pipeline | 35.00% | Refined product | Edmonton, Alberta | Calgary, Alberta |
Rocky Mountain Crude Pipeline | 100.00% | Crude oil | Guernsey, Wyoming | Denver, Colorado |
Centennial Pipeline | 100.00% | Crude oil | Guernsey, Wyoming | Cheyenne, Wyoming |
Oil Sands Pipeline | 100.00% | Crude oil | Fort McMurray, Alberta | Edmonton, Alberta |
Suncor's retail network operates nationally in Canada primarily under the Petro-Canada™brand. Selected locations along the Trans-Canada Highway are part of Canada's Electric Highway™, a network of fast-charging electric vehicle stations. Suncor's Canadian retail network averaged approximately 4.3 million litres per site of gasoline sales in 2025 (2024 - 4.2 million litres).
Suncor's Colorado retail network consists of 44 owned or leased Shell™, Exxon™ or Mobil™ branded outlets. Suncor also has product supply agreements with 94 Shell-branded sites in both Colorado and Wyoming, and with 55 Exxon and Mobil-branded sites in Colorado.
Marketing activities from the retail network also generate revenues from convenience store sales and car washes.
Suncor has continued high-grading its retail network by investing in top-tier locations, enhancing quick serve restaurant offerings and rebranding of additional sites to the Petro-Canada™brand through the Canadian Tire Corporation arrangement.
Suncor's wholesale operations sell refined products into farm, home heating, paving, small industrial, commercial and truck markets, and directly to large industrial and commercial customers and independent marketers. Through its PETRO-PASS™network, Suncor is a national marketer to the commercial road transport segment in Canada.
Retail and Wholesale Summary
Suncor's retail network consists of the following branded outlets supplied with Suncor fuel. These outlets are comprised of Suncor owned or
As at December 31
Locations | 2025 | 2024 |
Retail Stations - Canada(2) | ||
Suncor Owned Locations | 765 | 765 |
Branded Dealer Locations | 967 | 873 |
1 732 | 1 638 | |
Retail Stations - U.S. | ||
Shell-branded retail stations - Colorado/Wyoming | 129 | 124 |
Exxon-branded retail stations - Colorado | 42 | 65 |
Mobil-branded retail stations - Colorado | 22 | 27 |
193 | 216 | |
Wholesale Cardlock Sites - Canada | ||
Petro-Canada-branded sites (PETRO-PASS) | 319 | 320 |
Shell™ is a registered U.S. trademark of Shell Trademark Management B.V., and Exxon™ and Mobil™ are registered U.S. trademarks of Exxon Mobil Corporation.
Within retail stations located in Canada, Suncor holds the license for the Sunoco brand in Canada and operates one Sunoco-branded site.
Refined Products Sales Volumes
2025 % Operating | 2024 % Operating | |||
Sales Volumes | mbbls/d | Revenues | mbbls/d | Revenues |
Gasoline (includes motor and aviation gasoline) | ||||
Eastern North America | 129.5 | 118.6 | ||
Western North America | 133.0 | 134.7 | ||
262.5 | 42 | 253.3 | 43 | |
Distillates (includes diesel and heating oils, and aviation jet fuels) | ||||
Eastern North America | 130.7 | 116.3 | ||
Western North America | 143.1 | 145.6 | ||
273.8 | 44 | 261.9 | 48 | |
Other (includes heavy fuel oil, asphalts, petrochemicals, other) | ||||
Eastern North America | 45.9 | 52.7 | ||
Western North America | 41.1 | 32.5 | ||
87.0 | 14 | 85.2 | 9 | |
Total Sales Volume | 623.3 | 600.4 | ||
Sales volumes for specific products are moderately affected by seasonal cycles: gasoline sales are typically higher during the summer driving season; heating oil sales are typically higher during the winter season; diesel sales are typically higher during the drilling season at the beginning of the year in Western Canada and during agricultural planting and harvest seasons in early spring and late summer, respectively; and asphalt sales are typically higher during the summer construction paving period. Suncor has the flexibility to modify refinery inputs and outputs to match production yields with anticipated product demands. Suncor also has the flexibility to import and export refined products to optimize domestic seasonal cycles and to capture incremental margins from market dislocations.
Sales volumes can also be impacted when refineries undergo maintenance events. Suncor is able to mitigate this impact through its integrated facilities, inventory management and by purchasing refined products from third parties.
Other Suncor Businesses Supply, Trading and Optimization (ST&O)Suncor's ST&O organization manages commodity supply, trading, logistics, and price exposure across the value chain, operating across seven major commodity groups with trading offices in Canada, the U.S., and the U.K. It supports both upstream and downstream businesses by maximizing price realizations, managing inventories, mitigating market and operational risks, and ensuring efficient delivery through access to key midstream infrastructure. ST&O also optimizes crude and feedstock supply to refineries, moves refined products to domestic and international markets, facilitates reciprocal exchange agreements, secures reliable natural gas supply, and generates incremental margin through trading and asset optimization.
Corporate and EliminationsThe Corporate and Eliminations segment includes activities not directly attributable to any other operating segment. Corporate activities include Suncor's debt and borrowing costs, expenses not allocated to the company's businesses, and investments in certain clean technologies.
Intersegment activity includes the sale of product between the company's segments, primarily relating to crude refining feedstock sold from Oil Sands to R&M.
Suncor EmployeesSuncor's full- and part-time employees:
As at December 31 | 2025 | 2024 |
Oil Sands | 10 105 | 9 702 |
Exploration and Production | 205 | 213 |
Refining and Marketing | 2 497 | 2 502 |
Corporate | 2 617 | 2 593 |
Total | 15 424 | 15 010 |
Approximately 26% of the company's employees are covered by collective agreements.
Ethics, Social and Environmental PoliciesSuncor has adopted several policies focused on ethics, social and environmental matters, which are reviewed regularly and accessible to employees and contractors.
Suncor's standards for the ethical conduct of business are set forth in its Standards of Business Conduct Code (the Code). Topics addressed in the Code include: accounting and business controls, competition and trade; confidentiality; conflict of interest; equal opportunity and respect for people; improper payments; protection and proper use of corporate assets and opportunities; trading in shares and securities; and reports and communications. The Code is supported by a compliance program, under which every Suncor director, officer, employee and contract worker is required to annually complete a training course, and affirm their understanding of the requirements of the Code, and provide confirmation of compliance since their last affirmation or confirmation that any instance of non-compliance has been resolved with the individual's supervisor. Compliance is reported to Suncor's Governance Committee of the Board of Directors.
Suncor also has a supplier code of conduct that highlights the values that are important to Suncor and is a guide to the standard of behavior Suncor expects of all suppliers, contractors, consultants and other third parties Suncor does business with. The supplier code of conduct addresses topics such as safety, human rights, harassment, bribery and corruption and confidential information, among others. Compliance with the supplier code of conduct is a standard term of all Suncor supply chain contracts.
Suncor's Human Rights Policy is intended to ensure that Suncor is not complicit in human rights abuses. The policy makes clear that the scope of Suncor's human rights due diligence should include its own operations and, where it can influence its third-party business relationships, the operations of others.
Suncor's Indigenous Relations Policy commits to productive, long-term, and mutually beneficial relationships with Indigenous Peoples. The relationships we build and foster and the interactions we share are based on the principles of honesty, respect, transparency, inclusion, and integrity.
The Environment, Health and Safety (EH&S) policy states that Suncor's number one priority and core value is Safety Above All Else. The policy affirms Suncor's commitments to a safe and healthy workplace for all through fostering a culture of safety and environmental responsibility while complying with all applicable EH&S and regulatory requirements to protect the environment and communities in which we operate. Our Operational Excellence Management System (OEMS) is the framework that enables us to meet our EH&S Policy commitments.
Statement of Reserves Data and Other Oil and Gas Information Date of StatementThe Statement of Reserves Data and Other Oil and Gas Information outlined below is dated February 25, 2026, with an effective date of December 31, 2025. Reserves evaluations have not been updated since the effective date and, therefore, do not reflect changes in the company's reserves since that date. The preparation date of the Statement of Reserves Data and Other Oil and Gas Information outlined below is January 10, 2026.
Disclosure of Reserves DataSuncor is subject to the reporting requirements of Canadian securities laws, including the reporting of reserves data in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (NI 51-101).
The reserves data included in this section of the AIF is based upon evaluations conducted by GLJ Ltd. (GLJ), contained in its report dated February 18, 2026 (the GLJ Report). GLJ is an independent qualified reserves evaluator as defined in NI 51-101.
The reserves data summarizes Suncor's SCO, bitumen, light crude oil and medium crude oil (combined, including immaterial amounts of heavy crude oil) reserves and the net present values of future net revenues for these reserves using forecast prices and costs prior to provision for interest and general and administrative expense. All of Suncor's reserves are located in Canada as at December 31, 2025.
Advisories - Reserves DataClassifications of reserves as proved or probable are only attempts to define the degree of certainty associated with the estimates. There are numerous uncertainties inherent in estimating quantities of petroleum reserves. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. There is no guarantee that the estimates for SCO, bitumen, light, medium and heavy crude oil reserves provided herein will be recovered. Actual SCO, bitumen, light, medium and heavy crude oil volumes recovered may be greater than or less than the estimates provided herein. Readers should review the Abbreviations and definitions and information contained in the notes in the following tables. For additional information, see the section entitled Risk Factors in the company's annual 2025 MD&A, which section is incorporated by reference into this AIF, and is available on SEDAR+ at sedarplus.ca and EDGAR at sec.gov.
Oil and Gas Reserves Tables and Notes Summary of Oil and Gas Reserves(1) | ||||||||
as at December 31, 2025 (forecast prices and costs)(2) | ||||||||
SCO(3)Bitumen | Light Crude Oil & Medium Crude Oil(4) | Total | ||||||
(mmbbls) (mmbbls) | (mmbbls) | (mmbbls) | ||||||
Gross Net Gross | Net | Gross Net | Gross | Net | ||||
Proved Developed Producing | ||||||||
Mining 1 764 1 621 833 | 770 | - - | 2 597 | 2 391 | ||||
In Situ 244 200 146 | 116 | - - | 390 | 316 | ||||
E&P Canada - - - | - | 71 59 | 71 | 59 | ||||
Total Proved Developed Producing 2 009 1 822 979 | 886 | 71 59 | 3 058 | 2 767 | ||||
Proved Developed Non-Producing | ||||||||
Mining - - - | - | - - | - | - | ||||
In Situ - - 24 | 18 | - - | 24 | 18 | ||||
E&P Canada - - - | - | 7 6 | 7 | 6 | ||||
Total Proved Developed Non- - | - | 24 | 18 | 7 | 6 | 31 | 24 | |
Proved Undeveloped | ||||||||
Mining | - | - | - | - | - | - | - | - |
In Situ | 1 146 | 917 | 445 | 359 | - | - | 1 591 | 1 276 |
E&P Canada | - | - | - | - | 62 | 57 | 62 | 57 |
Total Proved Undeveloped | 1 146 | 917 | 445 | 359 | 62 | 57 | 1 653 | 1 334 |
Proved | ||||||||
Mining | 1 764 | 1 621 | 833 | 770 | - | - | 2 597 | 2 391 |
In Situ | 1 391 | 1 118 | 615 | 493 | - | - | 2 006 | 1 610 |
E&P Canada | - | - | - | - | 140 | 123 | 140 | 123 |
Total Proved | 3 155 | 2 739 | 1 448 | 1 263 | 140 | 123 | 4 743 | 4 125 |
Probable | ||||||||
Mining | 516 | 447 | 344 | 299 | - | - | 860 | 746 |
In Situ | 1 422 | 1 083 | 309 | 228 | - | - | 1 730 | 1 311 |
E&P Canada | - | - | - | - | 107 | 83 | 107 | 83 |
Total Probable | 1 938 | 1 530 | 653 | 527 | 107 | 83 | 2 698 | 2 141 |
Proved Plus Probable | ||||||||
Mining | 2 280 | 2 068 | 1 177 | 1 069 | - | - | 3 457 | 3 138 |
In Situ | 2 812 | 2 200 | 924 | 721 | - | - | 3 736 | 2 921 |
E&P Canada | - | - | - | - | 247 | 206 | 247 | 206 |
Total Proved Plus Probable | 5 092 | 4 269 | 2 101 | 1 790 | 247 | 206 | 7 440 | 6 265 |
Producing
Please see Notes (1) through (4) at the end of the reserves data section for important information about volumes in this table.
Reconciliation of Gross Reserves(1)as at December 31, 2025 (forecast prices and costs)(2)
Light Crude Oil & Medium
SCO(3) Bitumen Crude Oil(4)Total
Proved Proved Proved Proved
Plus Plus Plus Plus
Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | Proved | Probable | Probable | |
mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | mmbbls | |
Mining | ||||||||||||
December 31, 2024 | 1 766 | 431 | 2 197 | 1 014 | 383 | 1 397 | - | - | - | 2 780 | 813 | 3 593 |
Extensions & Improved Recovery(5) | - | - | - | - | - | - | - | - | - | - | - | - |
Technical Revisions(6) | 149 | 85 | 234 | (131) | (39) | (169) | - | - | - | 18 | 46 | 65 |
Discoveries(7) | - | - | - | - | - | - | - | - | - | - | - | - |
Acquisitions(8) | - | - | - | - | - | - | - | - | - | - | - | - |
Dispositions(9) | - | - | - | - | - | - | - | - | - | - | - | - |
Economic Factors(10) | - | - | - | - | - | - | - | - | - | - | - | - |
Production(11) | (150) | - | (150) | (51) | - | (51) | - | - | - | (201) | - | (201) |
December 31, 2025 | 1 764 | 516 | 2 280 | 833 | 344 | 1 177 | - | - | - | 2 597 | 860 | 3 457 |
In Situ | ||||||||||||
December 31, 2024 | 1 138 | 1 424 | 2 562 | 581 | 343 | 923 | - | - | - | 1 718 | 1 767 | 3 485 |
Extensions & Improved Recovery(5) | 233 | (23) | 210 | 112 | (8) | 104 | - | - | - | 345 | (31) | 314 |
Technical Revisions(6) | 55 | 20 | 75 | (20) | (25) | (46) | - | - | - | 34 | (5) | 29 |
Discoveries(7) | - | - | - | - | - | - | - | - | - | - | - | - |
Acquisitions(8) | - | - | - | - | - | - | - | - | - | - | - | - |
Dispositions(9) | - | - | - | - | - | - | - | - | - | - | - | - |
Economic Factors(10) | - | - | - | - | - | - | - | - | - | - | - | - |
Production(11) | (35) | - | (35) | (57) | - | (57) | - | - | - | (92) | - | (92) |
December 31, 2025 | 1 391 | 1 422 | 2 812 | 615 | 309 | 924 | - | - | - | 2 006 | 1 730 | 3 736 |
E&P Canada | ||||||||||||
December 31, 2024 | - | - | - | - | - | - | 133 | 103 | 236 | 133 | 103 | 236 |
Extensions & Improved Recovery(5) | - | - | - | - | - | - | 22 | 5 | 27 | 22 | 5 | 27 |
Technical Revisions(6) | - | - | - | - | - | - | 6 | (1) | 5 | 6 | (1) | 5 |
Discoveries(7) | - | - | - | - | - | - | - | - | - | - | - | - |
Acquisitions(8) | - | - | - | - | - | - | - | - | - | - | - | - |
Dispositions(9) | - | - | - | - | - | - | - | - | - | - | - | - |
Economic Factors(10) | - | - | - | - | - | - | - | - | - | - | - | - |
Production(11) | - | - | - | - | - | - | (21) | - | (21) | (21) | - | (21) |
December 31, 2025 | - | - | - | - | - | - | 140 | 107 | 247 | 140 | 107 | 247 |
Total Canada | ||||||||||||
December 31, 2024 | 2 903 | 1 855 | 4 759 | 1 595 | 725 | 2 320 | 133 | 103 | 236 | 4 631 | 2 684 | 7 315 |
Extensions & Improved Recovery(5) | 233 | (23) | 210 | 112 | (8) | 104 | 22 | 5 | 27 | 367 | (26) | 341 |
Technical Revisions(6) | 203 | 105 | 308 | (151) | (64) | (215) | 6 | (1) | 5 | 59 | 40 | 99 |
Discoveries(7) | - | - | - | - | - | - | - | - | - | - | - | - |
Acquisitions(8) | - | - | - | - | - | - | - | - | - | - | - | - |
Dispositions(9) | - | - | - | - | - | - | - | - | - | - | - | - |
Economic Factors(10) | - | - | - | - | - | - | - | - | - | - | - | - |
Production(11) | (185) | - | (185) | (108) | - | (108) | (21) | - | (21) | (314) | - | (314) |
December 31, 2025 | 3 155 | 1 938 | 5 092 | 1 448 | 653 | 2 101 | 140 | 107 | 247 | 4 743 | 2 698 | 7 440 |
Please see Notes (1) through (11) at the end of the reserves data section for important information about volumes in this table. Suncor's resources in Libya and Syria are classified as contingent resources and are not disclosed above.
Notes to Reserves Data Tablesas at December 31, 2025
Reserves data tables may not add due to rounding.
See the Notes to the Future Net Revenues tables for information on forecast prices and costs.
SCO reserves figures include the company's diesel sales volumes.
Gross volumes of light crude oil and medium crude oil for E&P Canada includes immaterial quantities of heavy crude oil from Hebron, which produces a commingled blend of light, medium and heavy crude oil.
Extensions & improved recovery are additions to the reserves resulting from stepout drilling, infill drilling and implementation of improved recovery schemes. Negative volumes, if any, for probable reserves result from the transfer of probable reserves to proved reserves. In Situ changes were primarily the result of improved recovery estimates. Additionally, the changes reflect the inclusion of newly approved development lands at MacKay River and an increase of facility capacity at Firebag. E&P changes are primarily due to new wells in Hebron and Hibernia and enhanced recovery in Terra Nova.
Technical revisions include changes in previous estimates resulting from new technical data, revised interpretations, or changes to upgrading volume forecasts. Changes in 2025 are primarily due to new information, including drilling results and ongoing field performance. Mining changes are primarily due to mine plan, geological risks updates, and increased upgrading of bitumen volumes. In Situ and E&P changes are primarily due to production performance updates.
Discoveries are additions to reserves in reservoirs where no reserves were previously booked as a result of the confirmation of the existence of an accumulation of a significant quantity of potentially recoverable petroleum. There were no discoveries in 2025.
Acquisitions are additions to reserves estimates as a result of purchasing interests in oil and gas properties. There were no acquisitions in 2025.
Dispositions are reductions in reserves estimates as a result of selling interests in oil and gas properties. There were no dispositions in 2025.
Economic factors are changes due primarily to price forecasts, inflation rates or regulatory changes.
Production quantities may include estimated production for periods near the end of the year when actual production quantities were not available at the time the reserves evaluations were conducted.
Definitions for Reserves Data TablesIn the tables set forth above and elsewhere in this AIF, the following definitions and other notes are applicable:
Gross means:in relation to Suncor's interest in production or reserves, Suncor's working-interest share before deduction of royalties and without including any royalty interests of Suncor;
in relation to Suncor's interest in wells, the total number of wells in which Suncor has an interest; and
in relation to Suncor's interest in properties, the total area of properties in which Suncor has an interest.
in relation to Suncor's interest in production or reserves, Suncor's working-interest share after deduction of royalty obligations, plus the company's royalty interests in production or reserves;
in relation to Suncor's interest in wells, the number of wells obtained by aggregating Suncor's working interest in each of the company's gross wells; and
in relation to Suncor's interest in a property, the total area in which Suncor has an interest multiplied by the working interest owned by Suncor.
The reserves estimates presented are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation (COGE) Handbook. A summary of those definitions is set forth below.
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on analyses 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 classified according to the degree of certainty associated with the estimates:
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.Proved and probable reserves categories may be divided into developed and undeveloped categories:
Developed reserves are those reserves that are expected to be recovered (i) 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, or (ii) for mining assets, through installed extraction equipment and infrastructure that is operational at the time of the reserves estimate. 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 category (proved or probable) to which they are assigned.
Future Net Revenues Tables and Notes
Net Present Values of Future Net Revenues Before Income Taxes(1)
as at December 31, 2025 (forecast prices and costs)
(in $ millions, discounted at % per year)
Unit Value(2)
0%
5%
10%
15%
20%
($/bbl)
Proved Developed Producing
Mining
16 380
25 615
21 448
17 126
13 860
8.97
In Situ
12 822
11 186
9 848
8 762
7 879
31.17
E&P Canada
787
1 029
1 140
1 186
1 200
19.26
Total Proved Developed Producing
29 990
37 830
32 435
27 075
22 939
11.72
Proved Developed Non-Producing
Mining
-
-
-
-
-
-
In Situ
753
599
484
398
332
26.61
E&P Canada
253
248
227
201
175
36.97
Total Proved Developed Non-Producing
1 006
846
711
599
507
29.23
Proved Undeveloped
Mining
-
-
-
-
-
-
In Situ
60 816
28 965
15 137
8 507
5 037
11.86
E&P Canada
3 110
2 807
2 489
2 192
1 926
43.43
Total Proved Undeveloped
63 926
31 772
17 626
10 699
6 963
13.22
Proved
Mining
16 380
25 615
21 448
17 126
13 860
8.97
In Situ
74 391
40 750
25 468
17 667
13 248
15.81
E&P Canada
4 150
4 084
3 856
3 579
3 302
31.45
Total Proved
94 922
70 448
50 772
38 373
30 410
12.31
Probable
Mining
20 666
11 837
6 881
4 438
3 131
9.22
In Situ
107 739
27 019
9 547
4 709
2 968
7.28
E&P Canada
6 206
4 808
3 748
2 975
2 411
44.92
Total Probable
134 611
43 664
20 175
12 122
8 509
9.42
Proved Plus Probable
Mining
37 046
37 452
28 329
21 564
16 991
9.03
In Situ
182 131
67 769
35 015
22 376
16 215
11.99
E&P Canada
10 356
8 892
7 603
6 554
5 713
36.90
Total Proved Plus Probable
229 533
114 113
70 948
50 494
38 919
11.32
Please see the Notes at the end of the Future Net Revenues Tables.
(in $ millions, discounted at % per year)
Total Future Net Revenues(1)0%
5%
10%
15%
20%
Proved Developed Producing
Mining
8 300
19 552
16 731
13 331
10 719
In Situ
10 133
8 837
7 769
6 901
6 195
E&P Canada
758
984
1 083
1 120
1 127
Total Proved Developed Producing
19 191
29 374
25 583
21 353
18 041
Proved Developed Non-Producing
Mining
-
-
-
-
-
In Situ
579
461
372
306
255
E&P Canada
218
217
201
179
155
Total Proved Developed Non-Producing
797
678
573
484
410
Proved Undeveloped
Mining
-
-
-
-
-
In Situ
46 656
21 888
11 223
6 153
3 519
E&P Canada
2 261
2 049
1 815
1 592
1 391
Total Proved Undeveloped
48 917
23 937
13 038
7 744
4 911
Proved
Mining
8 300
19 552
16 731
13 331
10 719
In Situ
57 368
31 186
19 365
13 360
9 970
E&P Canada
3 237
3 251
3 099
2 891
2 673
Total Proved
68 905
53 989
39 195
29 582
23 362
Probable
Mining
15 622
9 154
5 220
3 287
2 270
In Situ
82 779
20 636
7 302
3 628
2 304
E&P Canada
4 882
3 774
2 921
2 300
1 849
Total Probable
103 283
33 564
15 443
9 215
6 422
Proved Plus Probable
Mining
23 923
28 707
21 951
16 618
12 989
In Situ
140 147
51 821
26 667
16 987
12 273
E&P Canada
8 118
7 026
6 020
5 190
4 522
Total Proved Plus Probable
172 188
87 554
54 638
38 796
29 784
Please see the Notes at the end of the Future Net Revenues Tables.
as at December 31, 2025 (forecast prices and costs)
Future Net
Revenues
Future Net
Abandonment
Before
Revenues After
and
Deducting
Deducting
Operating
Development
Reclamation
Future Income
Future Income
Future Income
(in $ millions, undiscounted)
Revenue
Royalties
Costs
Costs
Costs
Tax Expenses
Tax Expenses
Tax Expenses
Proved Developed Producing
Mining
248 157
19 694
133 722
32 926
45 435
16 380
8 079
8 300
In Situ
32 300
5 747
10 256
2 475
1 000
12 822
2 689
10 133
E&P Canada
7 137
1 136
2 380
135
2 698
787
30
758
Total Proved Developed Producing
287 594
26 576
146 358
35 536
49 134
29 990
10 799
19 191
Proved Developed Non-Producing
Mining
-
-
-
-
-
-
-
-
In Situ
1 522
366
337
39
27
753
174
579
E&P Canada
758
125
309
37
34
253
35
218
Total Proved Developed Non-Producing
2 280
490
646
76
61
1 006
210
797
Proved Undeveloped
Mining
-
-
-
-
-
-
-
-
In Situ
175 724
34 242
54 443
24 613
1 611
60 816
14 160
46 656
E&P Canada
6 552
518
1 524
1 234
166
3 110
849
2 261
Total Proved Undeveloped
182 276
34 759
55 968
25 847
1 776
63 926
15 008
48 917
Proved
Mining
248 157
19 694
133 722
32 926
45 435
16 380
8 079
8 300
In Situ
209 546
40 354
65 036
27 126
2 638
74 391
17 023
57 368
E&P Canada
14 447
1 779
4 213
1 407
2 898
4 150
914
3 237
Total Proved
472 150
61 826
202 971
61 459
50 971
94 922
26 016
68 905
Probable
Mining
99 867
13 223
44 194
10 450
11 334
20 666
5 044
15 622
In Situ
269 561
61 862
69 069
29 304
1 587
107 739
24 960
82 779
E&P Canada
11 899
2 810
2 088
547
248
6 206
1 324
4 882
Total Probable
381 327
77 895
115 350
40 302
13 168
134 611
31 328
103 283
Proved Plus Probable
Mining
348 024
32 917
177 916
43 377
56 769
37 046
13 124
23 923
In Situ
479 107
102 216
134 105
56 431
4 224
182 131
41 984
140 147
E&P Canada
26 346
4 589
6 301
1 954
3 146
10 356
2 237
8 118
Total Proved Plus Probable
853 477
139 722
318 322
101 761
64 139
229 533
57 345
172 188
Please see the Notes at the end of the Future Net Revenues Tables.
(before income taxes, discounted at 10% per year)
$ millions
Unit Value
$/bbl(2)
Proved Developed Producing
SCO
23 753
13.04
Bitumen
7 542
8.51
Light Crude Oil & Medium Crude Oil(3)
1 140
19.26
Total Proved Developed Producing
32 435
11.72
Proved
SCO
36 493
13.32
Bitumen
10 424
8.25
Light Crude Oil & Medium Crude Oil(3)
3 856
31.45
Total Proved
50 772
12.31
Proved Plus Probable
SCO
51 270
12.01
Bitumen
12 074
6.74
Light Crude Oil & Medium Crude Oil(3)
7 603
36.90
Total Proved Plus Probable
70 948
11.32
Figures may not add due to rounding.
Unit values are net present values of future net revenues before deducting estimated cash income taxes payable, discounted at 10%, divided by net reserves.
Light crude oil and medium crude oil includes immaterial quantities of heavy crude oil from Hebron, which produces a commingled blend of light, medium and heavy crude oil.
Future net revenues for SCO include upgraded In Situ and Fort Hills bitumen volumes based on estimated available upgrading capacity and the company's bitumen supply strategy. The future net revenues include SCO volumes and estimates for upgrader operating and capital costs. For net proved plus probable reserves, approximately 100% of Firebag bitumen production is expected to be upgraded to SCO by 2037.
Approximately 44% of Fort Hills bitumen production is expected to be upgraded to SCO.
Power sale revenues and the natural gas fuel expense associated with excess electricity generated from cogeneration facilities at Firebag, Fort Hills, Syncrude and Base Mine are included in future net revenues.
Forecast Prices and CostsCrude oil, natural gas and other important benchmark reference pricing, as well as inflation and exchange rates utilized in the GLJ Report, were derived using averages of forecasts developed by GLJ (dated January 1, 2026), Sproule Associates Limited (dated December 31, 2025) and McDaniel & Associates Consultants Ltd. (dated January 1, 2026), all of whom are independent qualified reserves evaluators. Benchmark forecast prices have been adjusted for quality differentials and transportation costs applicable to the specific evaluation areas and products. The inflation rates utilized in cost forecasts were 0.0% in 2026 and 2.0% thereafter.
The carbon cost for Alberta based operations is assumed to escalate from $110/tonne in 2026, to $125/tonne in 2027, and then capped at
$130/tonne from 2028 onwards. This cap is consistent with the Alberta-Canada Memorandum of Understanding dated November 27, 2025 which provide for the TIER system to ramp up to a minimum effective credit price of $130/tonne. Outside of Alberta, the carbon cost is based on the legislated Greenhouse Gas Pollution Pricing Act (Canada).
Prices Impacting Reserves TablesWTI Cushing | WCS Hardisty | Light Sweet Edmonton | Pentanes Plus Edmonton | ||||
Forecast | Brent North Sea(1) | Oklahoma(2) | Alberta(3) | Alberta(4) | Alberta(5) | AECO Gas(6) | Exchange Rate |
Year | US$/bbl | US$/bbl | Cdn$/bbl | Cdn$/bbl | Cdn$/bbl | Cdn$/mmbtu | US$/Cdn$ |
2026 | 63.92 | 59.92 | 65.12 | 77.54 | 80.01 | 3.00 | 0.7275 |
2027 | 69.13 | 65.10 | 70.43 | 83.60 | 86.19 | 3.30 | 0.7367 |
2028 | 74.36 | 70.28 | 76.90 | 90.18 | 92.83 | 3.49 | 0.7400 |
2029 | 76.10 | 71.93 | 78.71 | 92.32 | 95.05 | 3.58 | 0.7400 |
2030 | 77.62 | 73.37 | 80.29 | 94.17 | 96.94 | 3.65 | 0.7400 |
2031 | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | +2.0%/yr | 0.7400 |
Price used when determining offshore light, medium and heavy crude oil reserves for E&P Canada.
Price used when determining portions of bitumen reserves presented as In Situ and Mining reserves that are sold at the U.S. Gulf Coast, as well as for determining portions of bitumen pricing for royalty calculation purposes.
Price used when determining portions of bitumen reserves presented as In Situ and Mining reserves that are sold in Canada, as well as for determining bitumen pricing for royalty calculation purposes.
Price used when determining SCO reserves presented as In Situ and Mining reserves.
Price used when determining the cost of diluent associated with bitumen reserves, as well as in determining bitumen pricing for royalty calculation purposes. A bitumen/diluent ratio of approximately two barrels of bitumen for one barrel of diluent was used for In Situ reserves and a ratio of approximately three barrels of bitumen for one barrel of diluent was used for Mining reserves.
Price used when determining natural gas input costs for production of SCO and bitumen reserves.
Values presented in the table for Net Present Values of Future Net Revenues After Income Taxes reflect income tax burdens of assets at a business area or legal entity level based on tax pools associated with that business area or legal entity. Suncor's actual corporate legal entity structure for income taxes and income tax planning has not been considered, and, therefore, the total value for income taxes presented in the total future net revenues table may not provide an estimate of the value at the corporate entity level, which may be significantly different.
Additional Information Relating to Reserves Data Future Development Costs(1)as at December 31, 2025 (forecast prices and costs)
Discounted at | ||||||||
($ millions) | 2026 | 2027 | 2028 | 2029 | 2030 | Remainder | Total | 10% |
Proved | ||||||||
Mining | 3 082 | 3 078 | 3 104 | 2 462 | 2 577 | 18 622 | 32 926 | 18 906 |
In Situ | 1 148 | 1 405 | 1 348 | 635 | 1 067 | 21 522 | 27 126 | 10 166 |
E&P Canada | 400 | 231 | 211 | 233 | 207 | 125 | 1 407 | 1 110 |
Total Proved | 4 631 | 4 715 | 4 663 | 3 330 | 3 852 | 40 270 | 61 459 | 30 181 |
Proved Plus Probable | ||||||||
Mining | 3 415 | 3 432 | 3 437 | 2 607 | 2 856 | 27 629 | 43 377 | 21 825 |
In Situ | 1 162 | 1 335 | 1 126 | 745 | 499 | 51 563 | 56 431 | 11 058 |
E&P Canada | 444 | 311 | 285 | 304 | 247 | 364 | 1 954 | 1 110 |
Total Proved Plus Probable | 5 021 | 5 077 | 4 848 | 3 656 | 3 602 | 79 556 | 101 761 | 33 992 |
Figures may not add due to rounding.
Management believes that internally generated cash flows, existing and future credit facilities and access to capital markets will be sufficient to fund future development costs. Failure to develop those reserves would have a negative impact on future cash flow provided by operating activities.
Interest expense or other costs of external funding are not included in the reserves and future net revenues estimates and could reduce future net revenues. Suncor does not anticipate the costs of funding would make development of any property uneconomic.
Abandonment and Reclamation CostsThe company completes an annual review of its consolidated abandonment and reclamation cost estimates. The estimates are limited to current disturbances and based on the anticipated method and extent of restoration, consistent with legal requirements and the possible future use of the site.
As at December 31, 2025, Suncor estimates its undiscounted, uninflated abandonment and reclamation costs for the current disturbance of its upstream assets to be approximately $21.8 billion (discounted at 10%, approximately $5.1 billion). Suncor estimates that it will incur $1.6 billion of its identified abandonment and reclamation costs during the next three years.
The abandonment and reclamation costs for current and future disturbances of $64.1 billion (inflated and undiscounted) have been deducted from the net present values of the company's proved and probable reserves.
Gross Proved and Probable Undeveloped ReservesThe tables below outline the gross proved and probable undeveloped reserves and represent undeveloped reserves additions resulting from acquisitions, discoveries, infill drilling, improved recovery and/or extensions in the year when the events first occurred.
Gross Proved Undeveloped Reserves(1)(forecast prices and costs)
2023 2024 2025
Total as at
Total as at
Total as at
First | December | First | December | First | December 31, | |
Attributed | 31, 2023 | Attributed | 31, 2024 | Attributed | 2025 | |
SCO (mmbbls) | ||||||
Mining | - | 281 | - | 277 | - | - |
In Situ | 181 | 854 | - | 911 | 127 | 1 146 |
Total SCO | 181 | 1 135 | - | 1 188 | 127 | 1 146 |
Bitumen (mmbbls) | ||||||
Mining | - | 14 | - | - | - | - |
In Situ | 151 | 563 | 9 | 447 | 53 | 445 |
Total bitumen | 151 | 577 | 9 | 447 | 53 | 445 |
Light crude oil & medium crude oil (mmbbls) | ||||||
E&P Canada(2) | - | 60 | - | 60 | 13 | 62 |
Total light crude oil & medium crude oil | - | 60 | - | - | 13 | 62 |
Total (mmbbls) | 333 | 1 772 | 9 | 1 694 | 193 | 1 653 |
Figures may not add due to rounding.
Includes immaterial amounts of heavy crude oil from Hebron, which produces a commingled blend of light, medium and heavy crude oil.
(forecast prices and costs)
2023 2024 2025
Total as at
Total as at
Total as at
First Attributed | December 31, 2023 | First Attributed | December 31, 2024 | First Attributed | December 31, 2025 | |
SCO (mmbbls) | ||||||
Mining | - | 132 | 46 | 193 | - | 157 |
In Situ | 42 | 1 085 | 326 | 1 342 | - | 1 348 |
Total SCO | 42 | 1 217 | 372 | 1 534 | - | 1 505 |
Bitumen (mmbbls) | ||||||
Mining | - | 2 | - | - | - | - |
In Situ | 7 | 133 | 69 | 277 | 21 | 236 |
Total bitumen | 7 | 135 | 69 | 277 | 21 | 236 |
Light crude oil & medium crude oil (mmbbls) | ||||||
E&P Canada(2) | 1 | 77 | - | 72 | 11 | 70 |
Total light crude oil & medium crude oil | 1 | 77 | - | 72 | 11 | 70 |
Total (mmbbls) | 49 | 1 428 | 442 | 1 884 | 32 | 1 811 |
Figures may not add due to rounding.
Includes immaterial amounts of heavy crude oil from Hebron, which produces a commingled blend of light, medium and heavy crude oil.
Proved undeveloped and proved plus probable undeveloped reserves are attributed in accordance with COGE Handbook guidelines.
In SituUndeveloped In Situ reserves are related only to sustaining pads and well pairs required for current producing or sanctioned projects. Proved undeveloped reserves have been assigned to areas delineated with vertical wells on 80-acre well spacing with 3D seismic control or 40-acre
spacing without 3D seismic control. Probable undeveloped areas are limited to areas delineated with vertical wells on 320-acre spacing with seismic control or 160-acre spacing without seismic control. Development of undeveloped In Situ reserves is an ongoing process and is a function of estimating excess processing capacity and production decline forecasts from existing In Situ wells. These forecasts align current production and processing constraints (which, in the case of processing constraints, do not permit Suncor to develop all of its undeveloped In Situ reserves within two years), capital spending commitments and future development for the next 10 years, and are updated and approved annually. The production level increase in Firebag has resulted in additional probable undeveloped reserves.
MiningUndeveloped Mining reserves relate to the Syncrude MLX-E mining area, which received regulatory approval in 2020, and the Lease 934 extension to Aurora North. Construction activities at MLX-E were restarted in 2021 and will continue through 2026. Development of MLX-E requires the relocation of infrastructure and construction of a production haul road from the lease. MLX-E reserves will remain as undeveloped until its major infrastructure components are completed. Further ore body delineation drilling will continue in 2026. Like MLX-W, MLX-E will utilize existing ore processing and extraction facilities at Syncrude's Mildred Lake operation and is expected to sustain bitumen production levels at Mildred Lake after resource depletion at the Mildred North Mine. The Lease 934 extension will remain as undeveloped until regulatory approval of the amendment application. Lease 934 will extend bitumen production at the Aurora North Mine.
E&PUndeveloped conventional reserves are mainly associated with future drilling at Hebron, Hibernia and White Rose. Attribution of proved undeveloped and probable undeveloped reserves reflect, where applicable, the respective degrees of certainty with respect to various reservoir parameters, primarily drainage areas and recovery factors. In developing undeveloped conventional reserves, Suncor considers existing facility capacity, capital allocation plans, and remaining reserves availability.
Properties with no Attributed ReservesSummary of properties to which no reserves are attributed as at December 31, 2025. For lands in which Suncor holds interests in different formations under the same surface area pursuant to separate leases, the area has been counted for each lease.
Country | Gross Hectares | Net Hectares |
Canada | 1 334 070 | 634 067 |
Libya | 3 117 800 | 1 422 900 |
Syria | 345 194 | 345 194 |
Total | 4 797 064 | 2 402 161 |
Suncor's properties with no attributed reserves range from exploration properties in a preliminary phase of evaluation to discovery areas where tenure to the property is held indefinitely on the basis of hydrocarbon test results, but where economic development is not currently possible or has not yet been sanctioned. Certain properties may be in a relatively mature phase of evaluation, where a significant amount of appraisal or even development has occurred; however, reserves cannot be attributed due to one or more contingencies, such as project sanction, or, in the case of Libya and Syria, political unrest. In many cases where reserves are not attributed to lands containing one or more discovery wells, the key limiting factor is the lack of available production infrastructure. As part of the company's ongoing process to review the economic viability of its properties, some properties are selected for further development activities, while others are temporarily deferred, sold, swapped or relinquished back to the mineral rights owner.
In 2026, Suncor's rights to 46,959 net hectares in Canada are scheduled to expire. The lands expiring in 2026 include approximately 21,103 net hectares in East Coast Offshore, 24,320 net hectares in In Situ and 1,536 net hectares in Mining. Substantial portions of expiring lands may have their tenure continued beyond 2026 through the conduct of work programs and/or the payment of prescribed fees to the mineral rights owner.
Work Commitments
Suncor's properties in Libya have no attributed reserves. Suncor has work commitments primarily for conducting seismic programs and drilling exploration wells, which is common in Libya. As at December 31, 2025, Suncor estimates that the value of the work commitment was
US$349 million. Due to the political unrest in Libya, it is uncertain when the work commitments will be incurred.
Oil and Gas Properties and WellsOil and gas wells as at December 31, 2025.
Oil Wells(1)Natural Gas Wells(1)
Producing Non-producing(2)(3)Producing Non-producing(2)(3)
Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||
Alberta - In Situ(4) | 524.0 | 524.0 | 84.0 | 84.0 | - | - | - | - | |||
Newfoundland and Labrador | 94.0 | 27.0 | 9.0 | 3.3 | - | - | - | - | |||
Other International(5) | - | - | 423.0 | 213.1 | - | - | 6.0 | 6.0 | |||
Total | 618.0 | 551.0 | 516.0 | 300.4 | - | - | 6.0 | 6.0 |
Alberta oil wells and Other International oil and gas wells are onshore, and Newfoundland and Labrador are offshore.
Non-producing wells include, but are not limited to, wells where there is no near-term plan for abandonment, wells where drilling has finished but the well has not been completed, wells requiring maintenance or workover where the resumption of production is not known, and wells that have been shut in and the date of
resumption of production is not known with reasonable certainty.
Non-producing wells do not necessarily lead to classification of non-producing reserves.
SAGD well pairs and multilateral wells are each counted as one well.
Other International includes wells associated with the company's operations in Syria and Libya.
Costs Incurred
($ millions) | Exploration Costs | Proved Property Acquisition Costs | Unproved Property Acquisition Costs | Development Costs | Total | ||
Canada - Mining and In Situ | 104 | - | - | 4 271 | 4 375 | ||
Canada - E&P Canada | 51 | - | - | 827 | 878 | ||
Total Canada | 155 | - | - | 5 098 | 5 253 | ||
Other International | 4 | - | - | - | 4 | ||
Total | 159 | - | - | 5 098 | 5 257 | ||
Exploration and Development Wells | Exploratory Wells | Development Wells | |||||
Total Number of Wells Completed | Gross | Net | Gross | Net | |||
Canada - Oil Sands | |||||||
Oil | - | - | 36.0 | 36.0 | |||
Service(1) | - | - | 20.0 | 20.0 | |||
Stratigraphic test(2) | - | - | 947.0 | 771.6 | |||
Total | - | - | 1 003.0 | 827.6 | |||
Canada - E&P Canada | |||||||
Oil | - | - | 4.0 | 0.8 | |||
Service(1) | - | - | 4.0 | 0.8 | |||
Total | - | - | 8.0 | 1.6 | |||
Total Canada | |||||||
Oil | - | - | 40.0 | 36.8 | |||
Service | - | - | 24.0 | 20.8 | |||
Stratigraphic test | - | - | 947.0 | 771.6 | |||
Total | - | - | 1 011.0 | 829.3 | |||
Service wells for Oil Sands include the injection well in a SAGD well pair, in addition to observation wells, disposal wells and hydrogeological monitoring wells if they have a licence. Service wells for E&P Canada include water and gas injection wells, disposal wells and cuttings reinjection wells.
Stratigraphic test wells for Oil Sands include core hole drilling wells.
Significant exploration and development activities in 2025 included:
For Mining, at Oil Sands Base Mine, asset sustainment activities, the continued development of tailings infrastructure and completion of a new cogeneration facility. At Fort Hills, construction of tailings infrastructure and mine advancement activities. At Syncrude, asset sustainment expenditures, a scheduled turnaround, and the ongoing development of MLX-E.
For In Situ, the drilling of new well pairs, infill and sidetracked wells at Firebag and MacKay River are expected to assist in maintaining production levels in future years. Also included are stratigraphic test well and observation well drilling programs.
For E&P Canada, spending on the development work at the West White Rose Project and drilling activities at Hebron and Hibernia.
For significant exploration and development activities expected to occur in 2026 and beyond, refer to the Description of Suncor's Businesses and Additional Information Relating to Reserves Data - Future Development Costs sections in this AIF.
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Suncor Energy Inc. published this content on February 26, 2026, and is solely responsible for the information contained herein. Distributed via Public Technologies (PUBT), unedited and unaltered, on February 26, 2026 at 22:24 UTC.
