Certain statements included or incorporated by reference in this document may constitute forward-looking statements or information under applicable securities legislation. Such forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements or information in this document may include, but are not limited to: capital expenditures, including Vermilion's 2026 and 2027 guidance and outlook, and Vermilion's ability to fund such expenditures; the flexibility of Vermilion's capital program and operations; business strategies and objectives; operational and financial performance; wells expected to be drilled and the timing thereof; exploration and development plans and the timing thereof; future drilling prospects; the ability of our asset base to deliver modest production growth; the evaluation of international acquisition opportunities; statements regarding the return of capital; our asset petroleum and natural gas sales; future production levels and the timing thereof, including Vermilion's 2026 and 2027 guidance, and rates of average annual production growth; the effect of changes in crude oil and natural gas prices, changes in exchange and inflation rates; the payment and amount of future dividends, including management's intention to increase the Company's dividend and the timing thereof; the effect of possible changes in critical accounting estimates; the Company's review of the impact of potential changes to financial reporting standards; the potential financial impact of climate-related risks; Vermilion's goals regarding its debt levels, including maintenance of a ratio of net debt to four quarter trailing fund flows from operations; statements regarding Vermilion's hedging program and the stability of our cash flows; operating and other expenses; royalty and income tax rates and Vermilion's expectations regarding future taxes and taxability and the timing of regulatory proceedings and approvals; and timing of the divestitures of certain of the Company's operations and the use of such sale proceeds.
Such forward-looking statements or information are based on a number of current expectations and assumptions, all or any of which may prove to be incorrect. In addition to any other assumptions identified in this document, assumptions that have been made include, but are not limited to: the ability of Vermilion to obtain equipment, services and supplies in a timely manner to carry out its activities in Canada and internationally; the ability of Vermilion to market crude oil, natural gas liquids, and natural gas successfully to current and new customers; the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation; the timely receipt of required regulatory approvals; the ability of Vermilion to obtain financing on acceptable terms; foreign currency exchange rates and interest rates; future crude oil, natural gas liquids, and natural gas prices; management's expectations relating to the timing and results of exploration and development activities; the impact of Vermilion's dividend policy on its future cash flows; credit ratings; hedging program; expected earnings/(loss) and adjusted earnings/ (loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows and free cash flow and expected future cash flow and free cash flow per share; estimated future dividends; financial strength and flexibility; debt and equity market conditions; general economic and competitive conditions; ability of management to execute key priorities; and the effectiveness of various actions resulting from Vermilion's strategic priorities.
Although Vermilion believes that the expectations reflected in such forward-looking statements or information are reasonable as of the date hereof, undue reliance should not be placed on forward-looking statements because Vermilion can give no assurance that such expectations will prove to be correct. Financial outlooks are provided for the purpose of understanding Vermilion's financial position and business objectives, and the information may not be appropriate for other purposes. Forward-looking statements or information are based on current expectations, estimates, and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Vermilion and described in the forward-looking statements or information. These risks and uncertainties include, but are not limited to: the ability of management to execute its business plan; the risks of the oil and gas industry, both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil, natural gas liquids, and natural gas; risks and uncertainties involving geology of crude oil, natural gas liquids, and natural gas deposits; risks inherent in Vermilion's marketing operations, including credit risk; the uncertainty of reserves estimates and reserves life and estimates of resources and associated expenditures; the uncertainty of estimates and projections relating to production and associated expenditures; potential delays or changes in plans with respect to exploration or development projects; Vermilion's ability to enter into or renew leases on acceptable terms; fluctuations in crude oil, natural gas liquids, and natural gas prices, foreign currency exchange rates, interest rates and inflation; health, safety, and environmental risks; uncertainties as to the availability and cost of financing; the ability of Vermilion to add production and reserves through exploration and development activities; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; uncertainty in amounts and timing of royalty payments; risks associated with existing and potential future lawsuits and regulatory actions against or involving Vermilion; and other risks and uncertainties described elsewhere in this document or in Vermilion's other filings with Canadian securities regulatory authorities. In particular, please also see Vermilion's MD&A and Annual Information Form, each for the year ended December 31, 2025, available on SEDAR+ at https://www.sedarplus.ca or on Vermilion's website at https://www.vermilionenergy.com. References to Vermilion or the Company in this document include Westbrick Energy Ltd. ("Westbrick" or "Westbrick Energy") which was acquired by Vermilion Energy Inc. on February 26, 2025.
The forward-looking statements or information contained in this document are made as of the date hereof and Vermilion undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events, or otherwise, unless required by applicable securities laws.
This document may disclose certain oil and gas metrics, including capital spent to drill, complete, equip and tie-in a well ("DCET costs"), which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this MD&A to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the Company's performance in previous periods and therefore such metrics should not be unduly relied upon. Additional oil and gas metrics in this document may include, but are not limited to:
Boe Equivalency: Per barrel of oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent (6:1). Barrel of oil equivalents (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 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. In addition, 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 conversion on a 6:1 basis may be misleading as an indication of value.
Estimates of Drilling Locations: Unbooked drilling locations are the internal estimates of Vermilion based on Vermilion's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by Vermilion's management as an estimation of Vermilion's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Vermilion will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which Vermilion will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been de-risked by Vermilion drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management of Vermilion has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
Initial Production Rates: This document discloses initial production rates for certain wells over short periods of time (i.e. IP90, etc.), which are preliminary and not necessarily indicative of long-term well or reservoir performance, ultimate recovery, reserves or future profitability. Initial production rates are subject to a high degree of predictive uncertainty as a result of limited production history and may not be representative of stabilized production rates. Production over a longer period will experience natural decline rates, which may be significant and may not be consistent with the decline observed during the initial production period. Actual results will differ from those realized during an initial production period and the difference may be material. Readers should not assume that the performance of the wells referenced herein is representative of the performance of other wells or future drilling locations.
Financial data contained within this document are reported in Canadian dollars, unless otherwise stated.
Abbreviations$M thousand dollars
$MM million dollars
AECO the daily average benchmark price for natural gas at the AECO 'C' hub in Alberta bbl(s) barrel(s)
bbl(s)/d barrels per day
boe barrel of oil equivalent, including: crude oil, condensate, natural gas liquids, and natural gas (converted on the basis of one boe for six mcf of natural gas)
boe/d barrel of oil equivalent per day
CO2 carbon dioxide
CO2e carbon dioxide equivalent
GHG greenhouse gas
GJ gigajoules
mbbl(s) thousand barrel(s)
mmboe thousand barrels of oil equivalent
MMBtu million British Thermal Units
mcf thousand cubic feet
mmcf/d million cubic feet per day
MD measured depth
NBP the reference price paid for natural gas in the United Kingdom at the National Balancing Point Virtual Trading Point NCIB normal course issuer bid
NGLs natural gas liquids, which includes butane, propane, and ethane
PRRT Petroleum Resource Rent Tax, a profit-based tax levied on petroleum projects in Australia psi pounds per square inch
tCO2e tonne of carbon dioxide equivalent
Tcf trillion cubic feet
THE the price for natural gas in Germany, quoted in megawatt hours of natural gas, at the Trading Hub Europe
TTF the price for natural gas in the Netherlands, quoted in megawatt hours of natural gas, at the Title Transfer Facility Virtual Trading Point
US the United States of America
WTI West Texas Intermediate, the reference price paid for crude oil of standard grade in US dollars at Cushing, Oklahoma
Management's Discussion and AnalysisThe following is Management's Discussion and Analysis ("MD&A"), dated November 4, 2026, of Vermilion Energy Inc.'s ("Vermilion", "we", "our", "us" or the "Company") operating and financial results as at and for the three and nine months ended September 30, 2026 compared with the corresponding periods in the prior year.
This discussion should be read in conjunction with the unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2026, and the audited consolidated financial statements for the years ended December 31, 2025 and 2024, together with the accompanying notes. Additional information relating to Vermilion, including its Annual Information Form, is available on SEDAR+ at https://www.sedarplus.ca or on Vermilion's website at https://www.vermilionenergy.com.
The unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2026, and comparative information have been prepared in Canadian dollars, except where another currency has been indicated, and in accordance with IAS 34, "Interim Financial Reporting", as issued by the International Accounting Standards Board ("IASB").
The operating results attributable to the Company's Saskatchewan, United States and block SA-07 in Croatia operations have been presented as discontinued operations, with all other operating results presented as continuing operations. The prior period presented the results from the Saskatchewan and United States assets as discontinued operations and have been recast to include the SA-07 assets in Croatia as discontinued operations. See Note 3 "Discontinued operations" of the condensed consolidated interim financial statements for the three and nine months ended September 30, 2026 for additional information.
This MD&A includes references to certain financial measures which are not specified, defined, or determined under IFRS® Accounting Standards as issued by the IASB ("IFRS Accounting Standards") and are therefore considered non-GAAP and other specified financial measures. These financial measures are unlikely to be comparable to similar financial measures presented by other issuers. For a full description of these non-GAAP and other specified financial measures and a reconciliation of these measures to their most directly comparable GAAP measures, please refer to "Non-GAAP and Other Specified Financial Measures".
Product Type DisclosureUnder National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities", disclosure of production volumes should include segmentation by product type as defined in the instrument. In this report, references to "crude oil" and "light and medium crude oil" mean "light crude oil and medium crude oil", "tight oil" and "heavy oil" and references to "natural gas" mean "conventional natural gas", "shale gas" and "coal bed methane".
In addition, in Supplemental Table 4 "Production", Vermilion provides a reconciliation from total production volumes to product type and also a reconciliation of "crude oil and condensate" and "NGLs" to the product types "light crude oil and medium crude oil" and "natural gas liquids".
Production volumes reported are based on quantities as measured at the first point of sale.
GuidanceOn November 5, 2025, the Company released the 2026 capital budget and associated production guidance. Only July 29, 2026, production guidance was increased to reflect continued outperformance across Vermilion's asset base, and the Company provided guidance for interest expense. On November 4, 2026, the Company tightened 2026 production and E&D capital expenditure guidance, provided updated cost structure guidance, reflecting the impact of higher commodity prices on operating expenses and cash taxes, and released the 2027 capital budget and associated production guidance. The Company's guidance for 2026 and 2027 is as follows:
Category | 2026 Prior (1) | 2026 Current (1) | 2027 Current (1) |
Production (boe/d) | 121,000 - 123,000 | 122,400 | 122,000 - 126,000 |
E&D capital expenditures ($MM) | $600 - 630 | $620 | $675 - 725 |
Operating ($/boe) | $12.25 - 13.25 | $12.75 - 13.25 | $12.50 - 13.50 |
General and administration ($/boe) (2) | $1.65 - 2.15 | $1.65 - 2.15 | $1.65 - 2.15 |
Transportation ($/boe) | $3.00 - 3.50 | $3.00 - 3.50 | $3.00 - 3.50 |
Interest expense ($/boe) | $2.00 - 2.50 | $2.00 - 2.50 | $1.75 - 2.25 |
Royalty rate (% of sales) | 7 - 9 % | 7 - 9 % | 7 - 9 % |
Cash taxes (% of pre-tax FFO) | 2 - 6 % | 4 - 8 % | 7 - 11 % |
Asset retirement obligations settled ($MM) | $55 | $55 | $50 |
Payments on lease obligations ($MM) | $10 | $10 | $10 |
(1) Prior 2026 guidance reflects foreign exchange assumptions of CAD/USD 1.39, CAD/EUR 1.61, and CAD/AUD 0.97. Current 2026 guidance reflects foreign exchange assumptions of CAD/USD 1.39, CAD/EUR 1.60, and CAD/AUD 0.98. Current 2027 guidance reflects foreign exchange assumptions of CAD/USD 1.39, CAD/EUR 1.57, and CAD/AUD 0.97.
(2) General and administration expense exclusive of expected cash-settled equity based compensation of $0.15 - 0.20/boe.
Consolidated Results Overview | ||||||
Q3 2026 | Q3 2025 | Q3/26 vs. Q3/25 | YTD 2026 | YTD 2025 | 2026 vs. 2025 | |
Production (1) | ||||||
Crude oil and condensate (bbls/d) | 21,524 | 28,197 | (24)% | 23,315 | 32,662 | (29)% |
NGLs (bbls/d) | 12,267 | 10,985 | 12% | 12,009 | 10,943 | 10% |
Natural gas (mmcf/d) | 501.35 | 479.28 | 5% | 525.38 | 455.08 | 15% |
(Draw) build in inventory (mbbls) | (331) | (163) | (259) | 56 | ||
Financial metrics | ||||||
Fund flows from continuing operations ($M) (2) | 237,062 | 250,317 | (5)% | 701,154 | 687,044 | 2% |
Fund flows from discontinued operations ($M) (2) | (143) | 3,493 | N/A | (736) | 82,473 | N/A |
Fund flows from operations ($M) (2) | 236,919 | 253,810 | (7)% | 700,418 | 769,517 | (9)% |
Fund flows from operations per share | 1.55 | 1.65 | (6)% | 4.59 | 5.00 | (8)% |
Net (loss) earnings from continuing operations | (35,499) | (4,552) | 680% | (42,106) | 74,094 | N/A |
Net earnings (loss) from discontinued operations | 859 | 7,109 | (88)% | (3,834) | (290,042) | (99)% |
Net (loss) earnings ($M) | (34,640) | 2,557 | N/A | (45,940) | (215,948) | (79)% |
Net (loss) earnings per share - continuing operations | (0.23) | (0.03) | 667% | (0.28) | 0.48 | N/A |
Net earnings (loss) per share - discontinued operations | - | 0.05 | (100)% | (0.03) | (1.88) | (98)% |
Net (loss) earnings per share | (0.23) | 0.02 | N/A | (0.30) | (1.40) | (79)% |
Cash flows from operating activities ($M) | 273,429 | 389,453 | (30)% | 671,578 | 810,304 | (17)% |
Free cash flow ($M) (3) | 90,453 | 108,248 | (16)% | 309,796 | 326,347 | (5)% |
Long-term debt ($M) | 1,181,468 | 1,264,343 | (7)% | 1,181,468 | 1,264,343 | (7)% |
Net debt ($M) (4) | 1,165,387 | 1,384,753 | (16)% | 1,165,387 | 1,384,753 | (16)% |
Cash dividends ($/share) | 0.135 | 0.130 | 4% | 0.405 | 0.390 | 4% |
Activity | ||||||
Capital expenditures ($M) (5) | 146,466 | 145,562 | 1% | 390,622 | 443,170 | (12)% |
Acquisitions ($M) (6) | (22,780) | 1,068 | N/A | (16,407) | 1,123,657 | N/A |
Dispositions ($M) (7) | 26,533 | 483,525 | (95)% | 26,533 | 483,525 | (95)% |
(1) Please refer to Supplemental Table 4 "Production" for disclosure by product type.
(2) Fund flows from operations (FFO) and FFO per share are a total of segments measure and supplementary financial measure most directly comparable to net (loss) earnings and net (loss) earnings per share, respectively. The measures do not have a standardized meaning under IFRS Accounting Standards and therefore may not be comparable to similar measures presented by other issuers. FFO is comprised of sales less royalties, transportation, operating, general and administrative (G&A), corporate income tax, PRRT, interest expense, equity based compensation settled in cash, realized gain (loss) on derivatives, plus realized gain (loss) on foreign exchange and realized other income (expense). The measure is used to assess the contribution of each business unit to Vermilion's ability to generate income necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. A reconciliation to the primary financial statement measures can be found within the "Non-GAAP and Other Specified Financial Measures" section of this MD&A. Fund flows from continuing operations and fund flows from discontinued operations are calculated in the same manner as FFO and are most directly comparable to net (loss) earnings from continuing operations and net earnings (loss) discontinued operations, respectively.
(3) Free cash flow (FCF) is a non-GAAP financial measure most directly comparable to cash flows from operating activities; it does not have a standardized meaning under IFRS Accounting Standards and therefore may not be comparable to similar measures presented by other issuers. FCF is comprised of fund flows from operations less drilling and development costs and exploration and evaluation costs. FCF is used to determine the funding available for investing and financing activities including payment of dividends, repayment of long-term debt, reallocation into existing business units and deployment into new ventures. A reconciliation to primary financial statement measures can be found within the "Non-GAAP and Other Specified Financial Measures" section of this MD&A.
(4) Net debt is a capital management measure in accordance with IAS 1 "Presentation of Financial Statements" and is most directly comparable to long-term debt. Net debt is comprised of long-term debt (excluding unrealized foreign exchange on swapped USD borrowings) plus adjusted working capital (defined as current assets less current liabilities, excluding current derivatives, current asset retirement obligations and current lease liabilities), and represents Vermilion's net financing obligations after adjusting for the timing of working capital fluctuations. Net debt excludes lease obligations which are secured by a corresponding right-of-use asset. A reconciliation to the primary financial statement measures can be found within the "Financial Position Review" section of this MD&A.
(5) Capital expenditures is a non-GAAP financial measure that does not have a standardized meaning under IFRS Accounting Standards and therefore may not be comparable to similar measures presented by other issuers. The measure is calculated as the sum of drilling and development costs and exploration and evaluation costs from the Consolidated Statements of Cash Flows. We consider capital expenditures to be a useful measure of our investment in our existing asset base. Capital expenditures are also referred to as E&D capital. A reconciliation to the primary financial statement measures can be found within the "Non-GAAP and Other Specified Financial Measures" section of this MD&A.
(6) Acquisitions is a non-GAAP financial measure that does not have a standardized meaning under IFRS Accounting Standards and therefore may not be comparable to similar measures presented by other issuers. The measure is calculated as the sum of acquisitions, net of cash and acquisitions of securities from the Consolidated Statements of Cash Flows, Vermilion common shares issued as consideration, the estimated value of contingent consideration, the amount of acquiree's outstanding long-term debt assumed, and net acquired working capital deficit or surplus. We believe that including these components
provides a useful measure of the economic investment associated with our acquisition activity. A reconciliation to the acquisitions line item in the Consolidated Statements of Cash Flows can be found in "Supplemental Table 3: Capital Expenditures and Acquisitions" section of this MD&A.
(7) Dispositions is a non-GAAP financial measure and is not a standardized financial measure under IFRS Accounting Standards and therefore may not be comparable to similar measures disclosed by other issuers. Dispositions is calculated as the sum of dispositions, and disposition of securities. Management believes that including these components provides a useful measure of the proceeds associated with our disposition activities and is most directly comparable to cash flows used in investing activities. More information and a reconciliation to dispositions and disposition of securities, the most directly comparable primary financial statement measures, can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
Production review Q3 2026 vs. Q3 2025Consolidated average production decreased 1% to 117,349 boe/d in Q3 2026 compared to 119,062 boe/d in Q3 2025, primarily due to the impact of dispositions in the United States and Saskatchewan in Q3 2025, planned turnarounds in Ireland, Germany and Canada, and cyclone-related downtime in Australia. These decreases were largely offset by production from new wells brought online in the Montney, as well as growth in Germany through organic development and an acquisition which closed in July 2026.
YTD 2026 vs. YTD 2025Consolidated average production increased 3% to 122,888 boe/d in the nine months ended September 30, 2026 from 119,451 boe/d in the comparable period of 2025. The increase was primarily attributable to nine months of production contribution from the Deep Basin acquisition in 2026 compared to seven months in 2025, strong drilling results in the Deep Basin and Montney, and growth in Germany through organic development and the recent acquisition. This more than offset the impact of the United States and Saskatchewan dispositions and cyclone-related downtime in Australia.
Activity reviewFor the three months ended September 30, 2026, capital expenditures were $146.5 million.
In Canada, capital expenditures of $90.8 million focused on our liquids-rich gas assets:
In the Deep Basin, drilled nine (7.9 net), completed five (5.0 net), and brought on production five (5.0 net) liquids-rich natural gas wells.
In the Montney, drilled one (1.0 net) and brought on production four (4.0 net) liquids-rich gas wells.
Internationally, capital expenditures were $55.7 million:
In Germany, invested $12.2 million, primarily on facilities activities and controllable inventory in advance of drilling activities planned on the Bommelsen license in 2027.
In the Netherlands, $6.6 million was invested primarily on pre-drilling activities, including rig mobilization, and controllable inventory in advance of drilling activities planned for Q4 2026.
In France, invested $13.4 million, primarily on subsurface maintenance and facilities activities.
In Australia, $12.0 million was invested primarily on facilities activities.
In Ireland, $9.6 million was invested on facilities activities, as Vermilion executed planned maintenance in the quarter.
Financial sustainability review Free cash flow
Free cash flow decreased by $16.6 million to $309.8 million for the nine months ended September 30, 2026 compared to the same period in the prior year. The decrease was primarily due to lower fund flows from operations driven by a $240.8 million year-over-year decrease in realized derivative settlements. The decrease was partially offset by higher fund flows from continuing operations, resulting from stronger underlying performance from the Deep Basin acquisition and ongoing organic production growth.
Long-term debt and net debtAs at September 30, 2026, long-term debt remained relatively flat at $1.2 billion (December 31, 2025 - $1.2 billion) primarily due to long-term debt repayments from excess cash flows generated during the quarter, partially offset by the timing of payments and the foreign exchange impact of the US dollar strengthening 4% against the Canadian dollar on our US denominated senior unsecured notes.
As at September 30, 2026, net debt totaled $1.17 billion, a decrease of $177.0 million from December 31, 2025. The decrease was primarily due to excess free cash flow generation and proceeds from the disposition of the SA-07 block in Croatia.
The ratio of net debt to four quarter trailing fund flows from operations(1) decreased to 1.2 as at September 30, 2026 (December 31, 2025 - 1.4) due to lower net debt, partially offset by slightly lower four quarter trailing funds from continuing operations impacted by realized derivative settlements.
(1) Net debt to four quarter trailing fund flows from operations is a supplementary financial measure that does not have a standardized meaning under IFRS Accounting Standards and therefore may not be comparable to similar measures presented by other issuers. It is calculated as net debt (capital measure) over the FFO from the preceding four quarters (total of segments measure). The measure is used to assess our ability to repay debt. Subsequent to February 26, 2025, net debt to four quarter trailing fund flows from operations is calculated inclusive of Westbrick Energy's pre-acquisition four quarter trailing fund flows from operations, as if the acquisition of Westbrick Energy occurred at the beginning of the four quarter trailing period, and exclusive of the four quarter trailing fund flows from discontinued operations to reflect the Company's ability to repay debt on a pro forma basis.
Q3 2026 | Q3 2025 | Q3/26 vs. Q3/25 | YTD 2026 | YTD 2025 | 2026 vs. 2025 |
Natural gas | |||||
North America | ||||||
AECO 7A (CAD/Mcf) | 1.54 | 1.00 | 54% | 1.85 | 1.70 | 9% |
Henry Hub (USD/Mcf) | 2.95 | 3.07 | (4)% | 3.63 | 3.39 | 7% |
Chicago (USD/Mcf) | 2.59 | 2.72 | (5)% | 2.89 | 3.33 | (13)% |
Europe (1) | ||||||
TTF MA (CAD/MMBtu) | 25.27 | 16.20 | 56% | 20.89 | 18.23 | 15% |
TTF MA (EUR/MMBtu) | 15.69 | 10.06 | 56% | 12.99 | 11.66 | 11% |
NBP MA (CAD/MMBtu) | 24.42 | 15.31 | 60% | 20.48 | 17.86 | 15% |
NBP MA (EUR/MMBtu) | 15.17 | 9.51 | 60% | 12.73 | 11.43 | 11% |
THE MA (CAD/MMBtu) | 25.52 | 16.69 | 53% | 21.37 | 18.67 | 14% |
THE MA (EUR/MMBtu) | 15.85 | 10.37 | 53% | 13.28 | 11.94 | 11% |
Crude oil | ||||||
Dated Brent (USD/bbl) | 97.00 | 69.07 | 40% | 94.05 | 70.85 | 33% |
WTI (USD/bbl) | 85.79 | 64.93 | 32% | 83.50 | 66.70 | 25% |
Edmonton Sweet index (CAD/bbl) | 119.13 | 86.41 | 38% | 114.80 | 88.63 | 30% |
Canadian C5+ Condensate index (CAD/bbl) | 115.20 | 86.62 | 33% | 115.06 | 91.50 | 26% |
Average exchange rates | ||||||
CAD/USD | 1.40 | 1.38 | 1% | 1.39 | 1.40 | (1)% |
CAD/EUR | 1.61 | 1.61 | -% | 1.61 | 1.56 | 3% |
Realized prices | ||||||
Crude oil and condensate ($/bbl) | 130.00 | 91.93 | 41% | 121.28 | 91.80 | 32% |
NGLs ($/bbl) | 30.99 | 22.99 | 35% | 27.28 | 26.01 | 5% |
Natural gas ($/mcf) | 5.60 | 4.36 | 28% | 5.36 | 5.48 | (2)% |
Total ($/boe) 53.37 42.18 27% 49.15 48.28 2%
(1) Natural gas in the Netherlands and Germany is benchmarked to the TTF and THE and production is generally equally split between day ahead ("DA") and month ahead ("MA") contracts. Natural gas in Ireland is benchmarked to the NBP and is sold on DA contracts.
As an internationally diversified producer, we are exposed to a range of commodity prices. In Canada, our crude oil is sold at benchmarks linked to WTI (including the Edmonton Sweet index and the Canadian C5+ index) and our natural gas is sold at benchmarks linked to the AECO index in Canada and a combination of Chicago Daily and Henry Hub ("HH") indices in the United States. In our International core region, our crude oil is sold with reference to Dated Brent and our natural gas is sold with reference to TTF, NBP, THE, or indices highly correlated to TTF.
Q3 2026 realized natural gas price was a $4.06/mcf premium to AECO 7A
NBP MA (5% of Q3 2026
sales volumes)
TTF MA (11% of Q3 2026
sales volumes)
Natural gas realized price
AECO (7A) (79% of Q3 2026
sales volumes)
Chicago CAD (5% of Q3 2026 sales volumes)
28.00
24.00
20.00
$/mcf
16.00
12.00
8.00
4.00
0.00
Q3 2025 Q4 2025 Q1 2026 Q2 2026 Q3 2026
In Canadian dollar terms, year-over-year month-ahead prices for European natural gas at NBP and TTF increased by 60% and 56%, respectively. European natural gas prices remained elevated during the quarter due to disruptions in the Strait of Hormuz, reduced Qatari LNG supply and tighter inventories entering the winter. Continued conflict in the Middle East and tighter supply and demand balances across Asia and Europe further supported global natural gas prices during Q3 2026.
Year-over-year, natural gas prices in Canadian dollar terms at NYMEX HH decreased by 3% and AECO 7A increased by 54%. Despite lower year-over-year AECO pricing, lower inventories, increased exports from the Western Canadian Sedimentary Basin ("WCSB") and lower receipts contributed to a tightening of the AECO differential to NYMEX HH during the quarter.
During Q3 2026, average European natural gas prices represented a premium of $23.31/mcf to AECO 7A. Approximately 16% of Vermilion's natural gas sales benefited from this premium European pricing (Q3 2025 - 22%).
Q3 2026 realized crude oil and condensate price was a $10.87/bbl premium to Edmonton Sweet Index
Dated Brent (49% of Q3 2026 sales volumes)
WTI Benchmark
Canadian C5+ (30% of Q3 2026 sales volumes)
Crude oil and condensate realized price
Edmonton Sweet index (21% of Q3 2026 sales volumes)
160.00
150.00
140.00
130.00
$/bbl
120.00
110.00
100.00
90.00
80.00
Q3 2025 Q4 2025 Q1 2026 Q2 2026 Q3 2026
Crude oil prices increased in Q3 2026 relative to Q3 2025 primarily due to continued disruptions in the Middle East and the resulting impact on global crude oil supply. Concerns regarding potential supply disruptions, reduced crude availability and increased transportation costs supported benchmark prices, with WTI rising 32% and Dated Brent increasing 40% compared to Q3 2025. Dated Brent strengthened relative to both ICE Brent and WTI as physical crude markets reflected elevated insurance and freight costs and increased risk premiums for spot barrels.
In Canadian dollar terms, year-over-year, the Edmonton Sweet differential tightened by $2.15/bbl to a discount of $0.88/bbl relative to WTI. Canadian crude oil differentials benefited from increased demand for alternative supplies as disruptions to crude oil and condensate exports from the Middle East increased demand from US West Coast and Asian refiners.
Approximately 49% of Vermilion's Q3 2026 crude oil and condensate sales volume was priced at the Dated Brent index, which averaged a premium to WTI of US$11.21/bbl. The remainder of our crude oil and condensate sales volume was priced at the Canadian C5+ and Edmonton Sweet indices.
The continuing operations in Canada consist of our Deep Basin and Mica Montney assets. The comparative period includes the operating results for non-core assets in Saskatchewan and the United States disposed of in 2025, presented as discontinued operations throughout this MD&A in accordance with IFRS 5 "Non-current Assets Held for Sale and Discontinued Operations". Please refer to Note 3 "Discontinued operations" of the condensed consolidated interim financial statements for the three and nine months ended September 30, 2026 for additional information.
Q3 2026 | Q3 2025 | YTD 2026 | YTD 2025 | |
Production (1) | ||||
Crude oil and condensate (bbls/d) | 12,707 | 13,896 | 13,754 | 12,674 |
NGLs (bbls/d) | 12,267 | 10,579 | 12,009 | 9,792 |
Natural gas (mmcf/d) | 419.89 | 367.36 | 433.92 | 337.25 |
Production from continuing operations (boe/d) | 94,955 | 85,698 | 98,085 | 78,673 |
Production from discontinued operations (boe/d) | - | 3,065 | - | 11,016 |
Total production volume (boe/d) 94,955 88,763 98,085 89,689
(1) Please refer to Supplemental Table 4 "Production" for disclosure by product type.
Fund Flows from OperationsQ3 2026
Q3 2025
YTD 2026
YTD 2025
Continuing Operations$M | $/boe | $M | $/boe | $M | $/boe | $M | $/boe | |
Sales | 241,167 | 27.61 | 177,462 | 22.51 | 777,833 | 29.05 | 556,095 | 25.89 |
Royalties | (23,476) | (2.69) | (10,932) | (1.39) | (70,039) | (2.62) | (45,911) | (2.14) |
Transportation | (31,043) | (3.55) | (23,302) | (2.96) | (79,168) | (2.96) | (62,496) | (2.91) |
Operating | (57,821) | (6.62) | (54,943) | (6.97) | (181,731) | (6.79) | (160,344) | (7.47) |
General and administration (1) | (7,407) | (0.85) | (7,117) | (0.90) | (25,756) | (0.96) | (36,514) | (1.70) |
Corporate income tax expense (1) | (11) | - | (2,132) | (0.27) | (795) | (0.03) | (4,892) | (0.23) |
Drilling and development | (90,806) | (92,293) | (278,092) | (257,656) |
Free cash flow from continuing operations 30,603 (13,257) 142,252 (11,718)
(1) General and administration and corporate income tax include amounts from our Corporate segment. General and administration expenses previously presented within the Corporate segment have been reclassified to our Canadian segment and the prior period results have been presented to conform with current period presentation. The decrease in general and administration was primarily due to non-recurring acquisition costs in 2025. Corporate income tax expense primarily relates to income taxes on Corporate segment activities.
Discontinued OperationsQ3 2026 | Q3 2025 | YTD 2026 | YTD 2025 | |||
$M | $/boe | $M | $/boe | $M $/boe | $M $/boe | |
Sales | - - | 19,349 | 68.62 | - - | 209,816 | 69.77 |
Royalties | - - | (4,387) | (15.56) | - - | (40,386) | (13.43) |
Transportation | - - | (1,025) | (3.64) | - - | (6,969) | (2.32) |
Operating | - - | (5,587) | (19.81) | - - | (59,285) | (19.71) |
General and administration | - | - | (4,608) | (16.34) | - | - | (19,814) | (6.59) |
Fund flows from discontinued operations | - | - | 3,742 | 13.27 | - | - | 83,362 | 27.72 |
Drilling and development | - | 1,879 | - | (21,609) | ||||
Free cash flow from discontinued operations | - | 5,621 | - | 61,753 |
Fund flows from continuing operations increased 54% to $121.4 million in Q3 2026 and 71% to $420.3 million for the nine months ended September 30, 2026. On a per boe basis, fund flows increased to $13.90/boe and $15.72/boe, respectively, reflecting higher production volumes, stronger realized commodity prices and a lower cost structure resulting from increased scale and portfolio high-grading efforts.
Production in Canada averaged 94,955 boe/d, a decrease of 5% from the prior quarter, driven by lower activity levels through mid-2026, as well as planned maintenance. In Q3 2026, the Company drilled nine (7.9 net), completed five (5.0 net), and brought on production five (5.0 net) liquids-rich gas wells in the Deep Basin. In the Montney, Vermilion drilled one (1.0 net) and brought on production four (4.0 net) liquids-rich gas wells.
SalesQ3 2026 Q3 2025 YTD 2026 YTD 2025 $M $/boe $M $/boe $M $/boe $M $/boe | ||||||||
Canada | 241,167 | 27.61 | 177,462 | 22.51 | 777,833 | 29.05 | 556,095 | 25.89 |
Discontinued operations:
Canada | - - | 7,663 | 73.64 | - - | 146,564 | 72.08 |
United States | - - | 11,686 | 65.67 | - - | 63,252 | 64.94 |
Total discontinued operations - - 19,349 68.62 - - 209,816 69.77 |
Total 241,167 27.61 196,811 24.10 777,833 29.05 765,911 31.28 |
On a dollar basis, sales from continuing operations increased 36% and 40% for the three and nine months ended September 30, 2026 compared to the prior year comparable periods, respectively, reflecting higher production volumes from the Deep Basin acquisition, new wells brought online in the Deep Basin and Montney and stronger crude oil pricing. On a per boe basis, sales increased 23% to $27.61 in Q3 and 12% to $29.05 year to date.
RoyaltiesQ3 2026 Q3 2025 YTD 2026 YTD 2025 $M $/boe $M $/boe $M $/boe $M $/boe | ||||||||
Canada | (23,476) | (2.69) | (10,932) | (1.39) | (70,039) | (2.62) | (45,911) | (2.14) |
Discontinued operations:
Canada | - - | (948) (9.11) | - - | (22,544) (11.09) |
United States | - - | (3,439) (19.33) | - - | (17,842) (18.32) |
Total discontinued operations | - | - | (4,387) | (15.56) | - | - | (40,386) | (13.43) |
Total | (23,476) | (2.69) | (15,319) | (1.88) | (70,039) | (2.62) | (86,297) | (3.52) |
Royalty rate (% of sales) | ||||||||
Canada | 9.7 % | 6.2 % | 9.0 % | 8.3 % |
Discontinued operations | - % | 22.7 % | - % | 19.2 % |
The royalty rate as a percentage of sales in Canada increased to 9.7% from 6.2% and to 9.0% from 8.3% for the three and nine months ended September 30, 2026, respectively, reflecting the combined impact of increased production and stronger realized commodity prices on the Canadian operations' sliding-scale royalty structures. These factors also resulted in an increase in royalties on a dollar basis for both periods.
TransportationQ3 2026 $M | $/boe | Q3 2025 $M | $/boe | YTD 2026 $M $/boe | YTD 2025 $M $/boe | |||
Canada | (31,043) | (3.55) | (23,302) | (2.96) | (79,168) | (2.96) | (62,496) | (2.91) |
Discontinued operations:
Canada | - - | (722) | (6.94) | - - | (6,347) | (3.12) |
United States | - - | (303) | (1.70) | - - | (622) | (0.64) |
Total discontinued operations - - (1,025) (3.64) - - (6,969) (2.32) |
Total (31,043) (3.55) (24,327) (2.98) (79,168) (2.96) (69,465) (2.84) |
Transportation expense on continuing operations in Canada increased 20% to $3.55 per boe for the three months ended September 30, 2026 compared to the same period in 2025 due to prior period adjustments to liquids transportation costs that are not expected to recur. For the nine months ended September 30, 2026, transportation expense per boe remained relatively unchanged compared to prior period, as the impact of the prior period adjustment to liquids transportation was offset by improved utilization of contracted natural gas transportation capacity resulting from higher Deep Basin production. These improvements demonstrate the benefits of increased scale with the Company's Canadian operations.
On a dollar basis, transportation expense on continuing operations in Canada increased 33% and 27% for the three and nine months ended September 30, 2026, respectively, compared to the prior year periods due to higher production.
Operating expenseQ3 2026 $M | $/boe | Q3 2025 $M | $/boe | YTD 2026 $M $/boe | YTD 2025 $M $/boe | |||
Canada | (57,821) | (6.62) | (54,943) | (6.97) | (181,731) | (6.79) | (160,344) | (7.47) |
Discontinued operations:
Canada | - - | (2,503) (24.05) | - - | (42,694) (21.00) |
United States | - - | (3,084) (17.33) | - - | (16,591) (17.03) |
Total discontinued operations - - (5,587) (19.81) - - (59,285) (19.71) |
Total (57,821) (6.62) (60,530) (7.41) (181,731) (6.79) (219,629) (8.97) |
Operating expenses on continuing operations in Canada decreased 5% and 9% to $6.62 per boe and $6.79 per boe for the three and nine months ended September 30, 2026, respectively, compared to the same periods in 2025. The decrease was primarily driven by increased scale and operating efficiencies within the Deep Basin and Montney, as higher production volumes allowed fixed costs to be spread over a larger production base.
On a dollar basis, continuing operating expense increased 5% and 13% for the three and nine months ended September 30, 2026, respectively, compared to the same periods in 2025 primarily due to higher production.
InternationalDuring the first quarter of 2026, Vermilion entered into an agreement for the sale of the SA-07 assets in Croatia which were subsequently sold in the third quarter of 2026. As a result of this agreement, the operating results for these assets have been presented as discontinued operations throughout this MD&A in accordance with IFRS 5 "Non-current Assets Held for Sale and Discontinued Operations". Please refer to Note 3 "Discontinued operations" of the condensed consolidated interim financial statements for the three and nine months ended September 30, 2026, for additional information.
Production (1)
YTD 2025
YTD 2026
Q3 2025
Q3 2026
Natural gas (mmcf/d) | 81.46 | 108.29 | 91.46 | 106.28 |
Total production volume (boe/d) | 22,399 | 30,299 | 24,803 | 29,762 |
Total sales volume (boe/d) | 25,998 | 32,069 | 25,749 | 29,561 |
Crude oil and condensate (bbls/d) 8,822 12,248 9,561 12,047
(1) Please refer to Supplemental Table 4 "Production" for disclosure by product type.
Fund Flows from OperationsQ3 2026
Q3 2025
YTD 2026
YTD 2025
Continuing Operations$M | $/boe | $M | $/boe | $M | $/boe | $M | $/boe | |
Sales | 352,689 | 147.46 | 272,040 | 92.21 | 883,697 | 125.71 | 805,934 | 99.87 |
Royalties | (19,993) | (8.36) | (16,466) | (5.58) | (48,893) | (6.96) | (40,846) | (5.06) |
Transportation | (12,459) | (5.21) | (11,550) | (3.91) | (35,874) | (5.10) | (34,209) | (4.24) |
Operating | (103,123) | (43.11) | (83,472) | (28.29) | (242,423) | (34.49) | (214,748) | (26.61) |
General and administration | (12,713) | (5.32) | (11,730) | (3.98) | (37,373) | (5.32) | (35,645) | (4.42) |
Corporate income tax expense | (17,079) | (7.14) | (2,544) | (0.86) | (39,583) | (5.63) | (29,959) | (3.71) |
PRRT | 2,781 | 1.16 | (1,663) | (0.56) | 5,215 | 0.74 | (5,436) | (0.67) |
Fund flows from continuing operations | 190,103 | 79.48 | 144,615 | 49.03 | 484,766 | 68.95 | 445,091 | 55.16 |
Drilling and development | (49,888) | (54,418) | (106,388) | (144,038) | ||||
Exploration and evaluation | (3,823) | (601) | (4,005) | (19,184) | ||||
Discontinued Operations | ||||||||
Q3 2026 $M | $/boe | Q3 2025 $M | $/boe | YTD 2026 $M | $/boe | YTD 2025 $M | $/boe | |
Operating | (2) | - | (69) | - | (236) | - | (296) | - |
General and administration | (141) | - | (180) | - | (500) | - | (593) | - |
Drilling and development | 1,949 | 41 | (1,823) | (190) |
Exploration and evaluation | - | (170) | (314) | (493) |
Free cash flow from discontinued operations | 1,806 | (378) | (2,873) | (1,572) |
Fund flows from continuing operations increased 31% to $190.1 million in Q3 2026 and increased 9% to $484.8 million for the nine months ended September 30, 2026. On a per boe basis, fund flows increased 62% and 25% for the three and nine month periods, respectively, reflecting significantly stronger realized European natural gas and crude oil prices, partially offset by lower sales volumes and higher royalty and operating costs.
Production from Vermilion's International operations averaged 22,399 boe/d in Q3 2026, a decrease of 14% from the prior quarter driven by planned maintenance activity in Ireland and Germany, comprising of a 32-day turnaround in Ireland and non-operated maintenance downtime in Germany. Vermilion also advanced preliminary work to support drilling activities planned on the Bommelsen license in Germany in 2027 in addition to preparing for drilling in the Netherlands in Q4 2026, including rig mobilization.
Q3 2026
Q3 2025
YTD 2026
YTD 2025
Sales$M | $/boe | $M | $/boe | $M | $/boe | $M | $/boe | |
Australia | 47,181 | 165.42 | 53,755 | 109.46 | 79,498 | 132.28 | 105,440 | 113.32 |
France | 90,442 | 140.72 | 56,583 | 92.97 | 225,945 | 131.58 | 172,126 | 94.01 |
Netherlands | 47,625 | 149.27 | 24,715 | 79.46 | 116,999 | 118.73 | 95,789 | 94.51 |
Germany | 95,628 | 139.79 | 50,924 | 86.39 | 218,766 | 121.76 | 149,063 | 95.08 |
Ireland | 61,805 | 154.51 | 66,250 | 88.48 | 217,631 | 126.02 | 235,030 | 103.68 |
Central and Eastern Europe | 10,008 | 164.66 | 19,813 | 98.38 | 24,858 | 122.76 | 48,486 | 105.23 |
International 352,689 147.46 272,040 92.21 883,697 125.71 805,934 99.87
As a result of changes in inventory levels, our sales volumes for crude oil in Australia, France, and Germany may differ from our production volumes in those business units. The following table provides the crude oil sales volumes (consisting entirely of "light crude oil and medium crude oil") for those jurisdictions.
Crude oil sales volumes (bbls/d) | Q3 2026 | Q3 2025 | YTD 2026 | YTD 2025 |
Australia | 3,100 | 5,338 | 2,201 | 3,408 |
France | 6,986 | 6,615 | 6,290 | 6,707 |
Germany 2,309 2,038 1,991 1,698 |
International 12,395 13,991 10,482 11,813 |
International sales for the three and nine months ended September 30, 2026 increased 60% to $147.46 per boe and 26% to $125.71 per boe, respectively, compared to the prior year periods, driven by stronger crude oil and European gas pricing. On a dollar basis, sales increased 30% and 10%, respectively, due to stronger realized pricing, partially offset by lower sales volumes in Australia due to cyclone-related downtime, lower well performance at SA-10 in Central and Eastern Europe and planned turnaround activities in Ireland, which were successfully completed with production restored to capacity near the end of the quarter.
Q3 2026
Q3 2025
YTD 2026
YTD 2025
Royalties$M | $/boe | $M | $/boe | $M | $/boe | $M | $/boe | |
France | (11,290) | (17.57) | (8,605) | (14.14) | (28,442) | (16.56) | (24,929) | (13.62) |
Netherlands | - | - | - | - | (3) | - | (10) | (0.01) |
Germany | (5,283) | (7.72) | (3,806) | (6.46) | (12,518) | (6.97) | (8,135) | (5.19) |
Central and Eastern Europe | (3,420) | (56.27) | (4,055) | (20.13) | (7,930) | (39.16) | (7,772) | (16.87) |
Royalty rate (% of sales) | 5.7 % | 6.1 % | 5.5 % | 5.1 % |
Royalties in our International core region are primarily incurred in France, the Netherlands, Germany and Croatia, where royalties, depending on jurisdiction, include charges based on a percentage of sales and fixed per boe charges. Our production in Australia and Ireland is not subject to royalties.
The International royalty rate decreased to 5.7% of sales in Q3 2026 from 6.1% in Q3 2025 and increased to 5.5% from 5.1% for the nine months ended September 30, 2026. The increase primarily reflects higher crude oil prices in France, which are subject to sliding-scale royalty structures, together with a greater contribution from production in Germany. On a dollar basis, total royalty expense increased due to stronger realized commodity prices.
TransportationQ3 2026 $M $/boe | Q3 2025 $M | $/boe | YTD 2026 $M $/boe | YTD 2025 $M $/boe | ||
France | (6,884) (10.71) | (5,223) | (8.58) | (19,277) (11.23) | (16,683) | (9.11) |
Ireland | (1,891) | (4.73) | (2,330) | (3.11) | (5,664) | (3.28) | (6,820) | (3.01) |
International | (12,459) | (5.21) | (11,550) | (3.91) | (35,874) | (5.10) | (34,209) | (4.24) |
Germany | (3,684) | (5.39) | (3,997) | (6.78) | (10,933) | (6.09) | (10,706) | (6.83) |
Transportation expense increased to $5.21 per boe and $5.10 per boe for the three and nine months ended September 30, 2026, respectively, primarily due to the timing of crude oil liftings and vessel costs in France, combined with fixed costs spread across lower volumes due to the planned turnaround in Ireland, partially offset by lower expense driven by infrastructure synergies gained on the German asset acquisition.
On a dollar basis, transportation expense increased for both the three and nine month periods primarily due to increased vessel costs in France, increased sales volumes in Germany and the absence of a one-time transportation credit recognized in Germany in the prior year. Production in Australia, the Netherlands and Central and Eastern Europe is not subject to transportation expense.
Operating expense | ||||||||
Q3 2026 $M $/boe | Q3 2025 $M $/boe | YTD 2026 $M $/boe | YTD 2025 $M $/boe | |||||
Australia | (44,838) (157.20) | (30,230) (61.56) | (82,871) (137.89) | (55,423) (59.56) | ||||
France | (16,544) | (25.74) | (16,251) | (26.70) | (47,011) | (27.38) | (49,385) | (26.97) |
Netherlands | (9,980) | (31.28) | (8,869) | (28.51) | (28,615) | (29.04) | (26,404) | (26.05) |
Germany | (17,734) | (25.92) | (14,388) | (24.41) | (44,858) | (24.97) | (40,174) | (25.62) |
Ireland | (13,528) | (33.82) | (13,196) | (17.62) | (36,934) | (21.39) | (41,014) | (18.09) |
Central and Eastern Europe | (499) | (8.21) | (538) | (2.67) | (2,134) | (10.54) | (2,348) | (5.10) |
Discontinued operations: | ||||||||
Central and Eastern Europe | (2) | - | (69) | - | (236) | - | (296) | - |
International (103,125) (43.12) (83,541) (28.32) (242,659) (34.52) (215,044) (26.65)
Operating expenses increased to $43.12 per boe and $34.52 per boe for the three and nine months ended September 30, 2026, respectively, primarily due to the timing of liftings and cyclone-related maintenance expenses in Australia, as well as increased maintenance activity in Ireland and the Netherlands.
On a dollar basis, operating expenses increased 23% during the three months ended September 30, 2026 primarily due to maintenance activity in Australia, combined with costs associated with the Germany acquisition. For the nine months ended September 30, 2026, operating expenses increased 13%, primarily reflecting cyclone-related maintenance costs in Australia, as well as costs associated with the Germany acquisition, partially offset by lower maintenance in Ireland in the current period.
Consolidated Financial Performance ReviewQ3 2026
Q3 2025
YTD 2026
YTD 2025
Continuing Operations$M | $/boe | $M | $/boe | $M | $/boe | $M | $/boe | |
Sales | 593,856 | 53.37 | 449,502 | 41.49 | 1,661,530 | 49.15 | 1,362,029 | 46.10 |
Royalties | (43,469) | (3.91) | (27,398) | (2.53) | (118,932) | (3.52) | (86,757) | (2.94) |
Transportation | (43,502) | (3.91) | (34,852) | (3.22) | (115,042) | (3.40) | (96,705) | (3.27) |
Operating | (160,944) | (14.46) | (138,415) | (12.78) | (424,154) | (12.55) | (375,092) | (12.69) |
General and administration (1) | (20,120) | (1.81) | (18,847) | (1.74) | (63,129) | (1.87) | (72,159) | (2.44) |
Corporate income tax expense | (17,090) | (1.54) | (4,676) | (0.43) | (40,378) | (1.19) | (34,851) | (1.18) |
Petroleum resource rent tax | 2,781 | 0.25 | (1,663) | (0.15) | 5,215 | 0.15 | (5,436) | (0.18) |
Interest expense | (26,593) | (2.39) | (34,408) | (3.18) | (79,404) | (2.35) | (105,078) | (3.56) |
Equity based compensation | (536) | (0.05) | - | - | (11,240) | (0.33) | (5,692) | (0.19) |
Realized (loss) gain on derivatives | (46,865) | (4.21) | 61,793 | 5.70 | (120,227) | (3.56) | 120,611 | 4.08 |
Realized foreign exchange (loss) gain | (585) | (0.05) | (882) | (0.08) | (5,362) | (0.16) | 1,130 | 0.04 |
Realized other income (expense) | 129 | 0.01 | 163 | 0.02 | 12,277 | 0.36 | (14,956) | (0.51) |
Equity based compensation | (4,921) | (5,937) | (4,326) | (13,154) | ||||
Unrealized (loss) gain on derivative instruments (2) | (245,187) | 5,511 | (356,581) | 62,405 | ||||
Unrealized foreign exchange gain (loss) (2) | 12,178 | (41,499) | (22,348) | (71,491) | ||||
Accretion | (14,530) | (18,901) | (52,760) | (52,402) | ||||
Depletion and depreciation | (148,724) | (174,030) | (478,659) | (488,070) | ||||
Deferred tax recovery (expense) | 115,317 | (20,312) | 159,292 | (48,824) | ||||
Gain on acquisition | 16,221 | - | 16,221 | - |
Unrealized other (expense) income (2) (2,915) 299 (4,099) (1,414) |
Net (loss) earnings from continuing operations (35,499) (4,552) (42,106) 74,094 |
(1) General and administration expenses previously presented within the Corporate segment have been reclassified to our Canadian segment. The prior period results have been presented to conform with current period presentation.
(2) Unrealized (loss) gain on derivative instruments, Unrealized foreign exchange gain (loss), and Unrealized other (expense) income are line items from the respective Consolidated Statements of Cash Flows.
General and administration | (141) | - | (4,788) | (16.98) | (500) | - | (20,407) | (6.79) |
Fund flows from discontinued operations | (143) | - | 3,493 | 12.38 | (736) | - | 82,473 | 27.42 |
Unrealized gain on derivative instruments (1) | - | 11,047 | - | - |
Q3 2026 | Q3 2025 | YTD 2026 | YTD 2025 | |||||
$M | $/boe | $M $/boe | $M $/boe | $M $/boe | ||||
Sales | - | - | 19,349 | 68.62 | - | - | 209,816 | 69.77 |
Royalties | - | - | (4,387) | (15.56) | - | - | (40,386) | (13.43) |
Transportation | - | - | (1,025) | (3.64) | - | - | (6,969) | (2.32) |
Operating | (2) | - | (5,656) | (20.06) | (236) | - | (59,581) | (19.81) |
Unrealized foreign exchange gain (loss) (1) | - | 328 | 7 | (129) |
Accretion | - | (9) | - | (4,260) |
Depletion and depreciation | 1,190 | (3) | (3,947) | (46,518) |
Deferred tax recovery (expense) | (188) | (3,761) | 842 | 54,764 |
Impairment expense | - | - | - | (372,386) |
Fund flows from operations 236,919 21.29 253,810 22.82 700,418 20.72 769,517 23.63
Net (loss) earnings (34,640) 2,557 (45,940) (215,948)
Net earnings (loss) from discontinued operations 859 7,109 (3,834) (290,042)
(1) Unrealized gain on derivative instruments and Unrealized foreign exchange gain (loss) are line items from the respective Consolidated Statements of Cash Flows.
$32.6
$6.3
$3.1
$273.4
$(47.3)
$(8.0)
$(3.6)
$236.9
$253.8
400
$389.5
Q3 2026 vs. Q3 2025 FFO$MM
300
Q3 2025 - FFO
Pricing net of derivatives
Other
Sales volume
Royalties, transportation and operating
Taxes
Discontinued operations FFO
Q3 2026 - FFO
200
"Other" includes items not separately presented. Significant changes are discussed throughout this MD&A.
Cash flows from operating activities
2026 YTD vs. 2025 YTD FFO$135.8
$25.7
$24.2
$5.1
$163.7
$810.3
$(240.8)
$769.5
$(99.6)
$700.4
$(83.2)
$671.6
1,200
1,100
1,000
$MM
900
800
700
600
2025 - FFO
Sales volume
Pricing
Interest
Other
Taxes
Realized derivatives
Royalties, Transportation and Operating
Discontinued operations FFO
2026 - FFO
500
"Other" includes items not separately presented. Significant changes are discussed throughout this MD&A.
Cash flows from operating activities
Consolidated Financial Performance ReviewFluctuations in fund flows from operations may occur as a result of changes in production levels, commodity prices, and costs to produce petroleum and natural gas. In addition, fund flows from operations may be affected by the timing of crude oil shipments in Australia and France. When crude oil inventory is built up, the related operating expense, royalties, and depletion expense are deferred and carried as inventory on the consolidated balance sheet. When the crude oil inventory is subsequently drawn down, the related expenses are recognized within profit or loss.
General and administrationFor the three and nine months ended September 30, 2026, total general and administration expense decreased compared to the same periods in the prior year primarily due to transaction costs related to the 2025 acquisition and disposition activity combined with the impact of 2025 restructuring activities.
Equity based compensationEquity based compensation included within fund flows from operations primarily relates to cash settlements of withholding taxes on longterm incentive awards granted to directors, officers, and employees under security-based arrangements. These obligations were previously settled through the issuance and sale of treasury shares. Cash-settled equity based compensation increased for the three months ended September 30, 2026 compared with the prior-year period, due to additional DSU redemptions during the quarter. For the nine months ended September 30, 2026, cash-settled equity based compensation increased compared with the prior-year period, primarily due to a higher share price on LTIP awards settled in cash and a greater number of LTIP awards vesting.
PRRT and corporate income taxesPRRT for the three and nine months ended September 30, 2026 decreased compared to the same periods in the prior year due to recoveries of prior year PRRT tax expense from the application of 2026 PRRT tax losses.
Corporate income taxes for the three and nine months ended September 30, 2026 increased compared to the same periods in the prior year mainly due to higher revenues in the International segments partially offset with lower Corporate segment taxes due to reduced Pillar 2 global minimum tax estimates.
Interest expenseInterest expense for the three and nine months ended September 30, 2026 decreased compared with the prior-year periods, primarily due to lower debt levels following repayment of the $450 million term loan drawn and repaid in 2025 and a lower average revolving credit facility balance in 2026. Repurchases of the 2030 and 2033 senior unsecured notes also reduced interest expense.
Realized gain or loss on derivativesFor the three and nine months ended September 30, 2026, we recorded realized losses on our crude oil and European natural gas hedges due to higher commodity pricing compared to the strike prices, partially offset by realized gains on our North American natural gas hedges due to lower commodity pricing compared to the strike prices.
A listing of derivative positions as at September 30, 2026 is included in "Supplemental Table 2" of this MD&A.
Realized other income or expenseRealized other income for the three months ended September 30, 2026 remained relatively flat compared to the prior year. For the nine months ended September 30, 2026, realized other income primarily related to insurance claim recoveries in Australia and a US$3.5 million contingent payment recognized on the US disposition after the applicable conditions were met on June 30, 2026. In the comparative period, realized other expense primarily related to a provision for work commitments.
$53.7
$25.3
$16.2
$135.6
$2.6
$(250.7)
$(13.3)
$(4.0)
$(34.6)
300
200
$MM
100
Q3 2025
Deferred tax
Gain on acquisition
Fund flows
Other
Q3 2026
0
Unrealized foreign exchange
Depletion and depreciation
Unrealized derivatives
from operations
"Other" includes the net impact of remaining items not separately presented. Significant changes are discussed throughout this MD&A.
2026 YTD vs. 2025 YTD$208.1
$49.1
$16.2
$15.3
$14.1
$286.2
$(419.0)
$(45.9)
$(215.9)
400
300
200
$MM
100
0
-100
-200
YTD 2025
Net loss from
Deferred tax
Unrealized foreign exchange
Gain on acquisition
Other
Fund flows from operations
Unrealized derivatives
YTD 2026
-300
discontinued operations
"Other" includes the net impact of remaining items not separately presented. Significant changes are discussed throughout this MD&A.
Fluctuations in net (loss) earnings from period-to-period are caused by changes in both cash and non-cash based income and charges. Cash based items are reflected in fund flows from operations. Non-cash items include: equity based compensation expense, unrealized gains and losses on derivative instruments, unrealized foreign exchange gains and losses, accretion, depletion and depreciation expense, and deferred taxes. In addition, non-cash items may also include gains or losses resulting from acquisition or disposition activity or charges resulting from impairment or impairment reversals.
Equity based compensationEquity based compensation expense included within net (loss) earnings and excluded from fund flows from operations represents non-cash compensation expense on long-term incentives granted to directors, officers, and employees under security-based arrangements. Expense for the three months ended September 30, 2026 decreased compared with the prior-year period, reflecting expense recognized on current-year LTIP awards. For the nine months ended September 30, 2026, expense decreased compared with the prior-year period, primarily because the prior-year period included a recovery from the cash settlement of awards previously classified as share-settled, partially offset by the lower value of LTIP awards outstanding in the current year.
Unrealized gain or loss on derivative instrumentsUnrealized gain or loss on derivative instruments arises as a result of changes in forecasts for future prices and rates. As Vermilion uses derivative instruments to manage the commodity price exposure of our future crude oil and natural gas production, we will normally recognize unrealized gains on derivative instruments when future commodity price forecasts decline and vice-versa. As derivative instruments are settled, the unrealized gain or loss previously recognized is reversed, and the settlement results in a realized gain or loss on derivative instruments.
Cross currency interest rate swaps and foreign exchange swaps may be entered into to manage foreign exchange and interest rate exposures on USD denominated debt. Unrealized gains and losses on these instruments are partially offset by the unrealized foreign exchange losses and gains on the underlying debt.
For the three months ended September 30, 2026, we recognized a net unrealized loss on derivative instruments of $245.2 million. This primarily consists of unrealized losses of $164.7 million on our European natural gas commodity derivative instruments, $72.5 million on our crude oil and liquids commodity derivative instruments, and $16.7 million on our North American gas commodity derivative instruments, partially offset by unrealized gains of $9.2 million on our equity swaps.
For the nine months ended September 30, 2026, we recognized a net unrealized loss on derivative instruments of $356.6 million. This primarily consists of unrealized losses of $276.4 million on our European natural gas commodity derivative instruments, $120.2 million on our crude oil and liquids commodity derivative instruments, partially offset by unrealized gains of $20.7 million on our equity swaps, $12.6 million on our North America gas commodity derivative instruments and $8.6 million on our Cross Currency Interest Rate Swaps.
Unrealized foreign exchange gains or lossesAs a result of Vermilion's international operations, Vermilion has monetary assets and liabilities denominated in currencies other than the Canadian dollar. These monetary assets and liabilities include cash, receivables, payables, long-term debt, derivative instruments and intercompany loans. Unrealized foreign exchange gains and losses result from translating these monetary assets and liabilities from their underlying currency to the Canadian dollar.
In 2026, unrealized foreign exchange gains and losses primarily resulted from:
The translation of Euro and US dollar denominated intercompany loans to and from our international subsidiaries to Vermilion Energy Inc. An appreciation in the Euro and/or the US dollar against the Canadian dollar will result in an unrealized foreign exchange loss (and vice-versa). Under IFRS Accounting Standards, the offsetting foreign exchange loss or gain is recorded as a currency translation adjustment within other comprehensive income. As a result, consolidated comprehensive income reflects the offsetting of these translation adjustments while net (loss) earnings reflects only the parent company's side of the translation.
The translation of our USD denominated 2030 senior unsecured notes and USD denominated 2033 senior unsecured notes.
The translation of USD borrowings on our revolving credit facility. The unrealized foreign exchange gains or losses on these borrowings are offset by unrealized derivative gains or losses on associated USD-to-CAD cross currency interest rate swaps.
For the three months ended September 30, 2026, we recognized a net unrealized foreign exchange gain of $12.2 million, primarily driven by the effects of the Euro weakening 0.8% against the Canadian dollar on our Euro denominated intercompany loans combined with the effects of the US dollar weakening 0.2% against the Canadian dollar on our US denominated debt.
For the nine months ended September 30, 2026, we recognized a net unrealized foreign exchange loss of $22.3 million, primarily driven by the effects of the US dollar strengthening 3.5% against the Canadian dollar on our US denominated debt, partially offset by the impact on our US dollar denominated intercompany loans.
AccretionAccretion expense is recognized to update the present value of asset retirement obligations. For the three months ended September 30, 2026, accretion expense decreased primarily due to lower asset retirement obligations driven by changes in estimates related to the Germany acquisition.
For the nine months ended September 30, 2026, accretion expense decreased primarily due to lower asset retirement obligations driven by changes in estimates related to the Germany acquisition combined with dispositions in the prior year, partially offset by the impact of the Euro and Australian dollar strengthening against the Canadian dollar.
Depletion and depreciationDepletion and depreciation expense is recognized to allocate the cost of capital assets over the useful life of the respective assets. Depletion and depreciation expense per unit of production is determined for each depletion unit (which are groups of assets within a specific production area that have similar economic lives) by dividing the sum of the net book value of capital assets and future development costs by total proved plus probable reserves.
Fluctuations in depletion and depreciation expense are primarily the result of changes in produced crude oil and natural gas volumes, and changes in depletion and depreciation per unit. Fluctuations in depletion and depreciation per unit are the result of changes in reserves, depletable base (net book value of capital assets and future development costs), and relative production mix.
Depletion and depreciation expense per boe was $13.26 and $14.28 for the three and nine months ended September 30, 2026, respectively, compared with $15.66 and $16.42 in the prior-year periods. The decreases primarily reflect lower depletable bases following increased reserves in British Columbia and changes in the asset portfolio arising from 2025 and 2026 acquisition and disposition activity. In particular, the dispositions of the higher-depletion-rate U.S. and Saskatchewan assets and the acquisitions of the lower-depletion-rate Westbrick and German assets reduced depletion rates in the Alberta and Germany cash generating units. In addition, impairments recognized at the end of 2025 in Australia, Ireland, and France reduce the carrying value of these cash generating units.
Deferred taxDeferred tax assets arise when the tax basis of an asset exceeds its accounting basis (known as a deductible temporary difference). Conversely, deferred tax liabilities arise when the tax basis of an asset is less than its accounting basis (known as a taxable temporary difference). Deferred tax assets are recognized only to the extent that it is probable that there are future taxable profits against which the deductible temporary difference can be utilized. Deferred tax assets and liabilities are measured at the enacted or substantively enacted tax rate that is expected to apply when the asset is realized, or the liability is settled.
As such, fluctuations in deferred tax expenses and recoveries primarily arise as a result of: changes in the accounting basis of an asset or liability without a corresponding tax basis change (e.g. when derivative assets and liabilities are marked-to-market or when accounting depletion differs from tax depletion), changes in available tax losses (e.g. if they are utilized to offset taxable income), changes in estimated future taxable profits resulting in a derecognition or recognition of deferred tax assets, and changes in enacted or substantively enacted tax rates.
The Company recorded deferred tax recovery of $115.3 million and $159.3 million on continuing operations for the three and nine months ended September 30, 2026 compared to deferred tax expense of $20.3 million and $48.8 million for the same periods in the prior year. The deferred tax recovery in the current year and quarter were driven by the recognition of deferred tax assets in Ireland and Canada and unrealized derivative losses on increased commodity pricing.
For the three and nine months ended September 30, 2026, the Company recorded deferred tax expense of $0.2 million and recovery of $0.8 million, respectively, on discontinued operations compared to deferred tax expense of $3.8 million and recovery of $54.8 million for the same periods in the prior year. The deferred tax recovery in the nine month comparative period was driven by the impairment recorded in Canada attributable to the sale of Saskatchewan assets.
Financial Position Review Balance sheet strategyWe regularly review whether our forecast of fund flows from operations is sufficient to finance planned capital expenditures, dividends, share buybacks, and abandonment and reclamation expenditures. To the extent that fund flows from operations forecasts are not expected to be sufficient to fulfill such expenditures, we will evaluate our ability to finance any shortfall by reducing some or all categories of expenditures, with issuances of equity, and/or with debt (including borrowing using the unutilized capacity of our existing revolving credit facility). We have a long-term goal of maintaining a ratio of net debt to four quarter trailing fund flows from operations of approximately 1.0.
As at September 30, 2026, we have a ratio of net debt to four quarter trailing fund flows from operations of 1.2.
Net debtNet debt is reconciled to long-term debt, as follows:
($M) | As at Sep 30, 2026 | Dec 31, 2025 |
Long-term debt | 1,181,468 | 1,243,397 |
Adjusted working capital (deficit) (1) (12,784) 96,091
Unrealized FX on swapped USD borrowings (2) | (3,297) | 2,902 |
Net debt | 1,165,387 | 1,342,390 |
Ratio of net debt to four quarter trailing fund flows from operations (3) | 1.2 | 1.4 |
(1) Adjusted working capital is a non-GAAP financial measure that is not standardized under IFRS Accounting Standards and may not be comparable to similar measures disclosed by other issuers. It is defined as current assets less current liabilities, excluding current derivatives, current asset retirement obligations and current lease liabilities. The measure is used to calculate net debt, a capital measure disclosed above. Reconciliation to the primary financial statement measures can be found in the "Non-GAAP and Other Specified Financial Measures" section of this document.
(2) Vermilion may enter into cross currency interest rate swaps to hedge the foreign exchange movements on USD borrowings on our revolving credit facility. Unrealized FX on swapped USD borrowings relates to the unrealized gains and losses on our cross currency interest swaps. At September 30, 2026, there was
$152.8 million of swapped USD borrowings on our revolving credit facility. (December 31, 2025 - $196.7 million).
(3) Subsequent to February 26, 2025, net debt to four quarter trailing fund flows from operations is calculated inclusive of Westbrick Energy's pre-acquisition four quarter trailing fund flows from operations, as if the acquisition of Westbrick Energy occurred at the beginning of the four quarter trailing period, and exclusive of the four quarter trailing fund flows from discontinued operations to reflect the Company's ability to repay debt on a pro forma basis.
As at September 30, 2026, net debt decreased to $1.17 billion (December 31, 2025 - $1.34 billion) primarily due to strong cash flow generation and the proceeds from the disposition of the SA-07 assets in Croatia. The decrease was partially offset by the US dollar strengthening against the Canadian dollar on our US dollar denominated notes.
The ratio of net debt to four quarter trailing fund flows from operations decreased to 1.2 as at September 30, 2026 (December 31, 2025 - 1.4), primarily due to lower net debt driven by strong free cash flow and proceeds from the disposition of the SA-07 assets in Croatia.
Long-term debt | ||
The balances recognized on our balance sheet are as follows: | ||
As at Sep 30, 2026 | Dec 31, 2025 | |
Revolving credit facility | 182,736 | 222,724 |
2030 senior unsecured notes | 478,267 | 504,962 |
2033 senior unsecured notes | 520,465 | 515,711 |
Long-term debt 1,181,468 1,243,397
Revolving credit facilityAs at September 30, 2026, Vermilion had in place a bank revolving credit facility maturing May 30, 2030 with terms and outstanding positions as follows:
($M) | As at Sep 30, 2026 | Dec 31, 2025 |
Total facility amount | 1,350,000 | 1,350,000 |
Amount drawn (182,736) (222,724)
Letters of credit outstanding (41,224) (49,263) |
Unutilized capacity 1,126,040 1,078,013 |
The facility is secured by various fixed and floating charges against the subsidiaries of Vermilion. As at September 30, 2026, $182.7 million of the revolving credit facility was drawn (December 31, 2025 - $222.7 million).
On April 24, 2026, the maturity date of the revolving credit facility was extended to May 30, 2030 (previously May 25, 2029) with no other changes to the existing terms and conditions.
As at September 30, 2026, the revolving credit facility was subject to the following financial covenants:
Financial covenant | Limit | As at Sep 30, 2026 | Dec 31, 2025 |
Consolidated total debt to consolidated EBITDA | Less than 4.0 | 1.12 | 1.14 |
Consolidated total senior debt to consolidated EBITDA | Less than 3.5 | 0.17 | 0.21 |
Consolidated EBITDA to consolidated interest expense | Greater than 2.5 | 10.21 | 8.44 |
Our financial covenants include financial measures defined within our revolving credit facility agreement that are not defined under IFRS Accounting Standards. These financial measures are defined by our revolving credit facility agreement as follows:
Consolidated total debt: Includes all amounts classified as "Long-term debt", "Current portion of long-term debt", and "Lease obligations" (including the current portion included within "Accounts payable and accrued liabilities" but excluding operating leases as defined under IAS 17) on our consolidated balance sheet.
Consolidated total senior debt: Consolidated total debt excluding unsecured and subordinated debt.
Consolidated EBITDA: Consolidated net (loss) earnings before interest, income taxes, depreciation, accretion and certain other non-cash items, adjusted for the impact of the acquisition of a material subsidiary.
Total interest expense: Includes all amounts classified as "Interest expense", but excludes interest on operating leases as defined under IAS 17.
As at September 30, 2026 and December 31, 2025, Vermilion was in compliance with the above covenants.
2030 senior unsecured notesOn April 26, 2022, Vermilion closed a private offering of US $400.0 million of senior unsecured notes, priced at 99.241% of par. The notes bear interest at a rate of 6.875% per annum, to be paid semi-annually on May 1 and November 1. The notes mature on May 1, 2030. As direct senior unsecured obligations of Vermilion, the notes rank equally with existing and future senior unsecured indebtedness of the Company.
The senior unsecured notes were recognized at amortized cost and include the transaction costs directly related to the issuance.
On or after May 1, 2025, Vermilion may redeem some or all of the senior unsecured notes at the redemption prices set forth below, together with accrued and unpaid interest.
Year | Redemption price |
2025 | 103.438 % |
2026 | 102.292 % |
2027 | 101.146 % |
2028 and thereafter | 100.000 % |
On February 11, 2025 Vermilion closed a private offering of US $400.0 million of senior unsecured notes at par. The notes bear interest at a rate of 7.250% per annum, to be paid semi-annually on February 15 and August 15. The notes mature on February 15, 2033. As direct senior unsecured obligations of Vermilion, the notes rank equally with existing and future senior unsecured indebtedness of the Company.
The senior unsecured notes were recognized at amortized cost and include the transaction costs directly related to the issuance. Vermilion may, at its option, redeem the notes prior to maturity as follows:
Prior to February 15, 2028, Vermilion may redeem up to 40% of the original principal amount of the notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price of 107.250% of the principal amount of the notes, together with accrued and unpaid interest.
Prior to February 15, 2028, Vermilion may also redeem some or all of the notes at a price equal to 100% of the principal amount of the notes, plus a "make-whole premium," together with applicable premium, accrued and unpaid interest.
On or after February 15, 2028, Vermilion may redeem some or all of the senior unsecured notes at the redemption prices set forth below, together with accrued and unpaid interest.
Year | Redemption price |
2028 | 103.625 % |
2029 | 101.813 % |
2030 and thereafter | 100.000 % |
On March 13, 2017, Vermilion issued US $300.0 million of senior unsecured notes at par. The notes bore interest at a rate of 5.625% per annum paid semi-annually on March 15 and September 15. The notes matured on March 15, 2025 and the balance was repaid in full.
Term loanConcurrent with the completion of the Westbrick acquisition on February 26, 2025, Vermilion's credit facility agreement was amended to incorporate a new $450.0 million term loan (the "Term Loan") which was immediately drawn. The Term Loan balance was repaid in full in 2025.
Shareholders' capitalThe following table outlines our dividend payment history:
Date | Frequency | Dividend | per unit or share |
April 2022 to July 2022 | Quarterly | $0.060 | |
August 2022 to March 2023 | Quarterly | $0.080 | |
April 2023 to March 2024 | Quarterly | $0.100 | |
April 2024 to March 2025 | Quarterly | $0.120 | |
April 2025 to March 2026 | Quarterly | $0.130 | |
April 2026 onwards | Quarterly | $0.135 | |
The following table reconciles the change in shareholders' capital: | |||
Shareholders' Capital | Shares ('000s) | Amount ($M) | |
Balance at January 1 | 152,950 | 3,871,914 | |
Vesting of equity based awards | 598 | 9,346 | |
Share-settled dividends on vested equity based awards | 121 | 2,317 | |
Repurchase of shares (1) | (1,847) | (47,242) |
Balance at September 30 151,822 3,836,335
(1) Share capital is reduced on the repurchase of shares at the weighted-average carrying value.
As at September 30, 2026, there were approximately 4.9 million equity based compensation awards outstanding. As at November 3, 2026, there were approximately 151.4 million common shares issued and outstanding.
On July 8, 2026, the Toronto Stock Exchange approved the Company's notice of intention to renew its normal course issuer bid ("the NCIB"). The NCIB renewal allows Vermilion to purchase up to 15,157,179 common shares (representing approximately 10% of outstanding common shares) beginning July 12, 2026 and ending July 11, 2027. Common shares purchased under the NCIB will be cancelled.
In the three months ended September 30, 2026, Vermilion purchased 1.2 million common shares under the NCIB for total consideration of $19.7 million. In the nine months ended September 30, 2026 Vermilion purchased 1.8 million shares under the NCIB for total consideration of $29.8 million. The common shares purchased under the NCIB were cancelled.
Subsequent to September 30, 2026, Vermilion purchased and cancelled 0.5 million shares under the NCIB for total consideration of $8.2 million.
Asset Retirement ObligationsThe present value of the obligation is calculated using a credit-adjusted risk-free rate, calculated using a credit spread added to risk-free rates based on long-term, risk-free government bonds. Vermilion's credit spread is determined using the Company's expected cost of borrowing at the end of the reporting period.
As at September 30, 2026, asset retirement obligations were $1.2 billion compared to $1.0 billion as at December 31, 2025. The increase in asset retirement obligations is primarily attributable to changes in rates combined with obligations recognized in the Germany acquisition. The credit spread decreased to 2.6% at September 30, 2026 compared to 4.4% at December 31, 2025, primarily due to a lower expected cost of borrowing, partially offset by higher bond yields.
The risk-free rates and credit spread used as inputs to discount the obligations were as follows: | |||
Sep 30, 2026 | Dec 31, 2025 | Change | |
Credit spread added to below noted risk-free rates | 2.6 % | 4.4 % | (1.8)% |
Country specific risk-free rate | |||
Canada | 4.3 % | 3.9 % | 0.4 % |
France | 5.0 % | 4.5 % | 0.5 % |
Netherlands | 4.1 % | 3.2 % | 0.9 % |
Germany | 4.0 % | 3.4 % | 0.6 % |
Ireland | 3.8 % | 3.2 % | 0.6 % |
Australia | 5.5 % | 4.9 % | 0.6 % |
Central and Eastern Europe | 4.9 % | 4.8 % | 0.1 % |
Current cost estimates are inflated to the estimated time of abandonment using inflation rates of between 1.4% and 3.5% (as at December 31, 2025
- between 1.4% and 3.5%).
Risks and UncertaintiesVermilion is exposed to various market and operational risks. For a discussion of these risks, please see Vermilion's MD&A and Annual Information Form, each for the year ended December 31, 2025 available on SEDAR+ at https://www.sedarplus.ca or on Vermilion's website at https://www.vermilionenergy.com.
Critical Accounting EstimatesThe preparation of consolidated financial statements in accordance with IFRS Accounting Standards requires management to make estimates, judgments and assumptions that affect reported assets, liabilities, revenues and expenses, gains and losses, and disclosures of any possible contingencies. These estimates and assumptions are developed based on the best available information which management believed to be reasonable at the time such estimates and assumptions were made. As such, these assumptions are uncertain at the time estimates are made and could change, resulting in a material impact on Vermilion's consolidated financial statements. Estimates are reviewed by management on an ongoing basis and as a result may change from period to period due to the availability of new information or changes in circumstances. Additionally, as a result of the unique circumstances of each jurisdiction that Vermilion operates in, the critical accounting estimates may affect one or more jurisdictions. There have been no material changes to our critical accounting estimates used in applying accounting policies for the nine months ended September 30, 2026. Further information, including a discussion of critical accounting estimates, can be found in the notes to the Consolidated Financial Statements and annual MD&A for the year ended December 31, 2025, available on SEDAR+ at https://www.sedarplus.ca or on Vermilion's website at https://www.vermilionenergy.com.
Off Balance Sheet ArrangementsWe have not entered into any guarantee or off balance sheet arrangements that would materially impact our financial position or results of operations.
Internal Control Over Financial ReportingThere has been no change in Vermilion's internal control over financial reporting ("ICFR") during the period covered by this MD&A that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Recently Adopted Accounting Pronouncements Amendments to IFRS 9 - Financial Instruments and IFRS 7 Financial Instruments: DisclosureOn January 1, 2026, Vermilion adopted the amendments to IFRS 9 - Financial Instruments and IFRS 7 Financial Instruments: Disclosure, as issued by the International Accounting Standards Board ("IASB") that contained guidance related to settling financial liabilities using an electronic payment system and assessing contractual cash flow characteristics of financial assets. There was no impact to Vermilion's financial statements.
Vermilion did not adopt any new accounting pronouncements as at September 30, 2026 that would have a material impact on these Condensed consolidated interim financial statements.
Regulatory Pronouncements Not Yet Adopted Issuance of IFRS Sustainability Standards - IFRS S1 "General Requirements for Disclosure of Sustainability-related Financial Information" and IFRS S2 "Climate-related Disclosures" and European Corporate Sustainability Reporting Directive (CSRD)In June 2023, the International Sustainability Standards Board (ISSB) issued its inaugural standards - IFRS S1 and IFRS S2, and continues to advance its sustainability disclosure agenda, including work related to nature-related disclosure. In March 2026, the European Corporate Sustainability Reporting Directive's Omnibus 1 entered into force.
The Canadian Sustainability Standards Board has issued a Canada-specific version of IFRS S1 and S2 as Canadian Sustainability Disclosure Standards 1 and 2. While Canadian securities regulators have not mandated these standards, they have referenced them as a useful voluntary disclosure framework for sustainability and climate-related disclosure, and noted that securities legislation already requires issuers to disclose material climate-related risks. Australia has adopted AASB S2 climate-related disclosures based on IFRS S2 as part of its mandatory climate-related reporting framework. Mandatory reporting for Vermilion commenced in 2025, with the first reporting in 2026. Under the revised CSRD requirements, Vermilion may be required to report as a non-EU parent if it meets the applicable scope thresholds. While the legislative amendments have entered into force, certain implementation requirements, including reporting standards applicable to non-EU companies, remain under development. Based on currently available guidance, Vermilion's reporting date is currently projected as 2029 for the 2028 fiscal year. Vermilion is continuing to review the impact of the standards on its financial reporting.
IFRS 18 "Presentation and Disclosure in Financial Statements issued"In April 2024, the IASB issued the new accounting standard, IFRS 18 'Presentation and Disclosure in Financial Statements'. IFRS 18 will replace IAS 1 'Presentation of Financial Statements' and provides a defined structure to the statement of net (loss) earnings and comprehensive income and related disclosure requirements. Key changes include a new operating profit subtotal and require income and expenses to be classified into operating, investing, and financing categories, based on the entity's main business activities. The new standard is effective for annual reporting periods beginning on or after January 1, 2027 and is required to be adopted retrospectively. Preparations for the standard's adoption are underway, as Vermilion is currently reviewing income and expense classifications, management-defined performance measures, and contractual arrangements to assess the impact the standard will have on the consolidated financial statements. Vermilion has implemented adjustments to its accounting system and draft financial statements are being prepared, including retrospective disclosures for the comparative period.
Disclosure Controls and ProceduresOur officers have established and maintained disclosure controls and procedures and evaluated the effectiveness of these controls in conjunction with our filings. As of September 30, 2026, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures. Based on this evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded and certified that our disclosure controls and procedures are effective.
Supplemental Table 1: Operating NetbacksCurrent income taxes (6.77) (3.39) 0.64 0.17 |
Fund flows from operations ($/boe) 73.70 65.84 38.19 38.93 |
The following table includes financial statement information on a per unit basis by business unit. Liquids includes crude oil, condensate, and NGLs. Natural gas sales volumes have been converted on a basis of six thousand cubic feet of natural gas to one barrel of oil equivalent.
Liquids $/bbl | Q3 2026 Natural Gas $/mcf | Total $/boe | Liquids $/bbl | YTD 2026 Natural Gas $/mcf | Total $/boe | Q3 2025 Total $/boe | YTD 2025 Total $/boe |
Continuing Operations | |||||||
Canada | ||||||||
Sales | 74.27 | 1.83 | 27.61 | 73.68 | 2.19 | 29.05 | 22.51 | 25.89 |
Royalties | (9.02) | (0.07) | (2.69) | (8.41) | (0.09) | (2.62) | (1.39) | (2.14) |
Transportation | (8.75) | (0.28) | (3.55) | (6.27) | - | (2.96) | (2.96) | (2.91) |
Operating | (17.87) | (0.43) | (6.62) | (17.31) | (0.51) | (6.79) | (6.97) | (7.47) |
Operating netback | 38.63 | 1.05 | 14.75 | 41.69 | 1.59 | 16.68 | 11.19 | 13.37 |
General and administration (1) | (0.85) | (0.96) | (0.90) | (1.70) | ||||
Corporate income taxes ($/boe) | - | (0.03) | (0.27) | (0.23) |
Fund flows from operations ($/boe) | 13.90 | 15.70 | 10.02 | 11.44 |
France | ||||||||
Sales | 140.72 | - | 140.72 | 131.58 | - | 131.58 | 92.97 | 94.01 |
Royalties | (17.57) | - | (17.57) | (16.56) | - | (16.56) | (14.14) | (13.62) |
Transportation | (10.71) | - | (10.71) | (11.23) | - | (11.23) | (8.58) | (9.11) |
Operating | (25.74) | - | (25.74) | (27.38) | - | (27.38) | (26.70) | (26.97) |
Operating netback | 86.70 | - | 86.70 | 76.41 | - | 76.41 | 43.55 | 44.31 |
General and administration | (6.23) | (7.18) | (6.00) | (5.55) | ||||
Netherlands | ||||||||
Sales | 165.75 | 24.85 | 149.27 | 149.27 | 19.75 | 118.73 | 79.46 | 94.51 |
Royalties | - | - | - | - | - | - | - | (0.01) |
Operating | (34.25) | (5.21) | (31.28) | (41.81) | (4.83) | (29.04) | (28.51) | (26.05) |
Operating netback | 131.50 | 19.64 | 117.99 | 107.46 | 14.92 | 89.69 | 50.95 | 68.45 |
General and administration | (2.57) | (3.00) | (1.82) | (3.37) | ||||
Current income taxes | (16.14) | (16.40) | (0.50) | (13.80) | ||||
Germany | ||||||||
Sales | 126.11 | 24.33 | 139.79 | 124.91 | 20.07 | 121.76 | 86.39 | 95.08 |
Royalties | (3.78) | (1.58) | (7.72) | (3.08) | (1.44) | (6.97) | (6.46) | (5.19) |
Transportation | (5.14) | (0.92) | (5.39) | (8.14) | (0.87) | (6.09) | (6.78) | (6.83) |
Operating | (23.38) | (4.51) | (25.92) | (25.58) | (4.12) | (24.97) | (24.41) | (25.62) |
Operating netback | 93.81 | 17.32 | 100.76 | 88.11 | 13.64 | 83.73 | 48.74 | 57.44 |
General and administration | (4.55) | (5.76) | (5.37) | (6.35) | ||||
Current income taxes | (12.91) | (10.17) | (0.25) | (6.64) | ||||
Ireland | ||||||||
Sales | - | 25.75 | 154.51 | - | 21.00 | 126.02 | 88.48 | 103.68 |
Transportation | - | (0.79) | (4.73) | - | (0.55) | (3.28) | (3.11) | (3.01) |
Operating | - | (5.64) | (33.82) | - | (3.56) | (21.39) | (17.62) | (18.09) |
Operating netback | - | 19.32 | 115.96 | - | 16.89 | 101.35 | 67.75 | 82.58 |
General and administration | (5.93) | (2.56) | (2.14) | (2.01) | ||||
Current income taxes 3.78 0.68 (0.24) (0.30) |
Fund flows from operations ($/boe) 113.81 99.47 65.37 80.27 |
Q3 2026 | YTD 2026 | Q3 2025 | YTD 2025 | |||||
Liquids | Natural Gas | Total | Liquids | Natural Gas | Total | Total | Total | |
$/bbl | $/mcf | $/boe | $/bbl | $/mcf | $/boe | $/boe | $/boe | |
Australia | ||||||||
Sales | 165.42 | - | 165.42 | 132.28 | - | 132.28 | 109.46 | 113.32 |
Operating | (157.20) | - | (157.20) | (137.89) | - | (137.89) | (61.56) | (59.56) |
PRRT (2) | 9.75 | - | 9.75 | 8.68 | - | 8.68 | (3.39) | (5.84) |
Operating netback | 17.97 | - | 17.97 | 3.07 | - | 3.07 | 44.51 | 47.92 |
General and administration | (5.64) | (7.31) | (3.23) | (4.78) |
Current income taxes | (0.92) | (0.86) | (0.47) | (0.85) |
Fund flows from operations ($/boe) | 11.41 | (5.10) | 40.81 | 42.29 |
Central and Eastern Europe
Sales 11.04 27.25 164.66 (253.01) 20.43 122.76 98.38 105.23
Operating - (1.36) (8.21) - (1.76) (10.54) (2.67) (5.10)
Royalties - (9.31) (56.27) - (6.52) (39.16) (20.13) (16.87)
General and administration (13.05) (14.41) (5.72) (6.76)
Operating netback 11.04 16.58 100.18 (253.01) 12.15 73.06 75.58 83.26
Fund flows from operations ($/boe) 87.13 58.65 58.81 66.91
Current income taxes - - (11.05) (9.59)
Sales - - - - - - 65.67 64.94
Discontinued Operations
United States
Transportation - - - - - - (1.70) (0.64)
Royalties - - - - - - (19.33) (18.32)
Operating - - - - - - (17.33) (17.03)
Operating netback - - - - - - 27.31 28.95
Fund flows from operations ($/boe) - - 18.27 23.00
General and administration - - (9.04) (5.95)
Royalties - - - - - - (9.11) (11.09)
Canada - Saskatchewan
Sales - - - - - - 73.64 72.08
Operating - - - - - - (24.05) (21.00)
Transportation - - - - - - (6.94) (3.12)
Operating netback - - - - - - 33.54 36.87
General and administration | - | - | (28.83) | (6.89) |
Fund flows from operations ($/boe) | - | - | 4.71 | 29.98 |
Total Company | ||||||||
Sales | 97.52 | 5.60 | 53.37 | 90.16 | 5.36 | 49.15 | 42.18 | 48.28 |
Realized hedging (loss) gain | (8.14) | (0.41) | (4.21) | (10.51) | (0.11) | (3.56) | 5.56 | 3.70 |
Royalties | (9.54) | (0.23) | (3.91) | (9.01) | (0.21) | (3.52) | (2.86) | (3.91) |
Transportation | (8.31) | (0.32) | (3.91) | (6.96) | (0.32) | (3.40) | (3.23) | (3.18) |
Operating | (26.20) | (1.54) | (14.46) | (23.14) | (1.36) | (12.55) | (12.96) | (13.35) |
PRRT (2) | 0.81 | - | 0.25 | 0.53 | - | 0.15 | (0.15) | (0.17) |
Operating netback | 46.14 | 3.10 | 27.13 | 41.07 | 3.36 | 26.27 | 28.54 | 31.37 |
General and administration | (1.82) | (1.88) | (2.13) | (2.84) | ||||
Interest expense | (2.39) | (2.35) | (3.10) | (3.23) | ||||
Equity based compensation | (0.05) | (0.33) | - | (0.17) | ||||
Realized foreign exchange (loss) gain | (0.05) | (0.16) | (0.08) | 0.03 | ||||
Realized other income (expense) | 0.01 | 0.36 | 0.01 | (0.46) | ||||
Corporate income taxes | (1.54) | (1.19) | (0.42) | (1.07) | ||||
Fund flows from operations ($/boe) 21.29 20.72 22.82 23.63
(1) General and administration expenses previously presented within the Corporate segment have been reclassified to our Canadian segment. The prior period results have been presented to conform with current period presentation.
(2) Vermilion considers Australian PRRT to be an operating item and, accordingly, has included PRRT in the calculation of operating netbacks. Current income taxes presented above excludes PRRT.
Supplemental Table 2: HedgesThe prices in these tables may represent the weighted averages for several contracts with foreign currency amounts translated to the disclosure currency using forward rates as at the month-end date. The weighted average price for the portfolio of options listed below may not have the same payoff profile as the individual contracts. As such, the presentation of the weighted average prices is purely for indicative purposes.
The following tables outline Vermilion's outstanding risk management positions as at September 30, 2026:
Weighted Weighted Weighted Weighted Daily Weighted Daily Average Daily Sold Average Daily Sold Average Daily Sold Average Bought Average Bought Put Bought Put Call Sold Call Put Sold Put Swap Sold Swap Swap Bought Unit Currency Volume Price Volume Price Volume Price Volume Price Volume Swap Price | ||||||||||||
AECO | ||||||||||||
Q4 2026 | mcf | CAD | 39,303 | 2.76 | 39,303 | 4.57 | - - | 113,944 | 3.24 | - - | ||
Q1 2027 | mcf | CAD | 52,130 | 2.71 | 52,130 | 4.61 | - - | 99,521 | 3.16 | - - | ||
Q2 2027 | mcf | CAD | - | - | - | - | - - | 127,955 | 2.88 | - - | ||
Q3 2027 | mcf | CAD | - | - | - | - | - - | 127,955 | 2.88 | - - | ||
Q4 2027 | mcf | CAD | 37,707 | 2.37 | 37,707 | 4.40 | - - | 102,818 | 3.02 | - - | ||
Q1 2028 | mcf | CAD | 56,869 | 2.37 | 56,869 | 4.40 | - - | 28,435 | 3.15 | - - | ||
Q2 2028 | mcf | CAD | - | - | - | - | - - | 18,956 | 2.43 | - - | ||
Q3 2028 | mcf | CAD | - | - | - | - | - - | 18,956 | 2.43 | - - | ||
Q4 2028 | mcf | CAD | - | - | - | - | - - | 6,387 | 2.43 | - - | ||
AECO Basis (AECO less NYMEX Henry Hub) | ||||||||||||
Q4 2026 | mcf | USD | - | - | - | - | - | - | 13,261 | (1.46) | - | - |
Q1 2027 | mcf | USD | - | - | - | - | - | - | 6,889 | (1.35) | - | - |
Q2 2027 | mcf | USD | - | - | - | - | - | - | 43,407 | (1.45) | - | - |
Q3 2027 | mcf | USD | - | - | - | - | - | - | 30,000 | (1.49) | - | - |
Q4 2027 | mcf | USD | - | - | - | - | - | - | 10,109 | (1.49) | - | - |
Q2 2028 | mcf | USD | - | - | - | - | - | - | 16,500 | (1.50) | - | - |
Q3 2028 | mcf | USD | - | - | - | - | - | - | 16,500 | (1.50) | - | - |
Q4 2028 | mcf | USD | - | - | - | - | - | - | 5,560 | (1.50) | - | - |
NYMEX Henry Hub | ||||||||||||
Q4 2026 | mcf | USD | 24,000 | 3.50 | 24,000 | 4.49 | - | - | - | - | - | - |
Q2 2027 | mcf | USD | - | - | 30,000 | 4.50 | - | - | - | - | - | - |
Q3 2027 | mcf | USD | - | - | 30,000 | 4.50 | - | - | - | - | - | - |
Q4 2027 | mcf | USD | - | - | 10,109 | 4.50 | - | - | - | - | - | - |
Q1 2028 | mcf | USD | - | - | 24,000 | 6.29 | - | - | - | - | - | - |
Q2 2028 | mcf | USD | - | - | 40,500 | 5.56 | - | - | - | - | - | - |
Q3 2028 | mcf | USD | - | - | 40,500 | 5.56 | - | - | - | - | - | - |
Q4 2028 | mcf | USD | - | - | 29,560 | 5.96 | - | - | - | - | - | - |
NBP | ||||||||||||
Q4 2026 | mcf | EUR | - | - | - | - | - | - | 20,132 | 17.51 | - | - |
Q1 2027 | mcf | EUR | - | - | - | - | - | - | 15,013 | 17.51 | - | - |
TTF | ||||||||||||
Q4 2026 (1) | mcf | EUR | 34,736 | 8.01 | 34,736 | 16.61 | 28,253 | 4.46 | 17,197 | 8.87 | 37,192 | 16.85 |
Q1 2027 (1) | mcf | EUR | 28,253 | 7.43 | 28,253 | 13.75 | 28,253 | 3.95 | 7,370 | 9.35 | 26,956 | 16.87 |
Q2 2027 | mcf | EUR | 6,722 | 10.65 | 9,179 | 15.54 | 6,722 | 7.72 | 19,654 | 8.08 | - | - |
Q3 2027 | mcf | EUR | 6,722 | 10.65 | 9,179 | 15.54 | 6,722 | 7.72 | 19,654 | 8.08 | - | - |
Q4 2027 | mcf | EUR | - | - | 2,457 | 7.74 | - | - | 19,654 | 8.08 | - | - |
Weighted Weighted Weighted Weighted Daily Weighted Daily Average Daily Sold Average Daily Sold Average Daily Sold Average Bought Average Bought Put Bought Put Call Sold Call Put Sold Put Swap Sold Swap Swap Bought Unit Currency Volume Price Volume Price Volume Price Volume Price Volume Swap Price | |||||||||||
Q1 2028 Q2 2028 | mcf mcf | EUR EUR | - 2,457 | - 7.33 | - 2,457 | - 10.55 | - 2,457 | - 4.40 | 14,740 - | 7.43 - | - - - - |
Q3 2028 | mcf | EUR | 2,457 | 7.33 | 2,457 | 10.55 | 2,457 | 4.40 | - | - | - - |
THE | |||||||||||
Q4 2026 | mcf | EUR | - | - | - | - | - | - | 17,061 | 16.45 | - - |
Q1 2027 | mcf | EUR | - | - | - | - | - | - | 11,942 | 16.45 | - - |
WTI | |||||||||||
Q4 2026 | bbl | USD | 11,000 | 62.82 | 11,000 | 71.29 | 11,000 | 50.80 | 1,000 | 62.50 | - - |
Q1 2027 (1) | bbl | USD | 4,000 | 62.50 | 4,000 | 71.54 | 4,000 | 53.13 | - | - | - - |
Q2 2027 | bbl | USD | 4,000 | 62.50 | 4,000 | 70.30 | 4,000 | 52.50 | - | - | - - |
Q3 2027 | bbl | USD | 4,000 | 67.75 | 4,000 | 79.59 | 4,000 | 57.75 | - | - | - - |
Q4 2027 | bbl | USD | 4,000 | 67.75 | 4,000 | 79.59 | 4,000 | 57.75 | - | - | - - |
Dated Brent | |||||||||||
Q4 2026 | bbl | USD | 2,000 | 66.50 | 2,000 | 81.75 | 2,000 | 59.50 | - | - | - - |
Q1 2027 (1) | bbl | USD | 3,000 | 67.17 | 3,000 | 81.72 | 3,000 | 59.17 | - | - | - - |
Q2 2027 | bbl | USD | 3,000 | 67.17 | 3,000 | 77.33 | 3,000 | 57.17 | - | - | - - |
Q3 2027 | bbl | USD | 3,000 | 70.67 | 3,000 | 84.14 | 3,000 | 60.67 | - | - | - - |
Q4 2027 | bbl | USD | 3,000 | 70.67 | 3,000 | 84.14 | 3,000 | 60.67 | - | - | - - |
(1) Contracts include deferred premiums to be paid throughout the contract term, the weighted average premium is $1.50 USD/bbl for WTI, €1.55 EUR/mcf for TTF, and $4.40 USD/bbl for Dated Brent.
VET Equity Swaps Initial Share Price Share Volume | ||||
Swap | Jan 2020 - Apr 2028 | 20.9788 | CAD | 1,650,000 |
Swap | Jan 2020 - Jul 2028 | 22.4587 | CAD | 1,500,000 |
Foreign Monthly Bought Put Weighted Average Weighted Average Exchange Period Amount Bought Put Price Monthly Sold Call Amount Sold Call Price | ||||||||
Put | Sell USD, buy CAD | Oct - Dec 2026 | 1,000,000 | USD | 1.3500 | - | - | |
Collar | Sell USD, buy CAD | Oct - Dec 2026 | 12,000,000 | USD | 1.3537 | 12,000,000 | USD | 1.4364 |
Collar | Sell USD, buy CAD | Jan - Jun 2027 | 4,000,000 | USD | 1.3500 | 2,000,000 | USD | 1.4389 |
Collar | Sell USD, buy CAD | Jul - Dec 2027 | 2,000,000 | USD | 1.3500 | 2,000,000 | USD | 1.4428 |
Cross Currency Interest Rate | Receive Notional Amount | Receive Rate | Pay Notional Amount | Pay Rate | |
Swap | Feb 2033 | 250,000,000 USD | 7.250% | 357,870,000 CAD | 6.099% |
Swap | Sep - Oct 2026 | 107,735,402 USD | SOFR + 2.250% | 150,000,000 CAD | CORRA + 2.14% |
The following sold option instruments allow the counterparties, at the specified date, to enter into a derivative instrument contract with Vermilion at the detailed terms:
Weighted Weighted Weighted Weighted Daily Average Daily Sold Average Daily Sold Average Daily Sold Average Option Expiration Bought Put Bought Put Call Sold Call Put Sold Put Swap Sold Swap Period if Option Exercised Unit Currency Date Volume Price Volume Price Volume Price Volume Price | ||||||
WTI | ||||||
Jan 2027 - Dec 2027 | bbl | USD | 31-Dec-2026 | - - - - - - | 1,000 | 75.00 |
Jan 2027 - Dec 2027 | bbl | USD | 31-Dec-2026 | - - - - - - | 1,000 | 72.50 |
Jul 2027 - Jun 2028 | bbl | USD | 30-Jun-2027 | - - - - - - | 2,800 | 70.00 |
Jul 2028 - Jun 2029 | bbl | USD | 30-Jun-2028 | - - - - - - | 1,000 | 68.00 |
TTF | ||||||
Jan 2027 - Dec 2027 | mcf | EUR | 31-Dec-2026 | - - - - - - | 4,913 | 10.26 |
Jan 2028 - Dec 2028 | mcf | EUR | 30-Sep-2027 | - - - - - - | 4,913 | 8.79 |
Jan 2028 - Dec 2028 | mcf | EUR | 24-Dec-2027 | - - - - - - | 4,913 | 8.79 |
Jan 2028 - Dec 2028 | mcf | EUR | 30-Dec-2027 | - - - - - - | 4,913 | 8.06 |
Supplemental Table 3: Capital Expenditures and Acquisitions | ||||
By classification ($M) | Q3 2026 | Q3 2025 | YTD 2026 | YTD 2025 |
Drilling and development | 142,643 | 144,791 | 386,303 | 423,493 |
Exploration and evaluation | 3,823 | 771 | 4,319 | 19,677 |
Capital expenditures 146,466 145,562 390,622 443,170 | ||||
Acquisitions ($M) | Q3 2026 | Q3 2025 | YTD 2026 | YTD 2025 |
Acquisitions, net of cash acquired | (10,554) | 1,068 | (4,181) | 1,087,115 |
Shares issued for acquisition | - | - | - | 13,363 |
Acquired working capital (surplus) deficit | (12,226) | - | (12,226) | 23,179 |
Acquisitions (22,780) 1,068 (16,407) 1,123,657 | ||||
Dispositions ($M) | Q3 2026 | Q3 2025 | YTD 2026 | YTD 2025 |
Canada | - | 392,619 | - | 392,619 |
United States | - | 90,906 | - | 90,906 |
Central and Eastern Europe | 26,533 | - | 26,533 | - |
Dispositions 26,533 483,525 26,533 483,525 | ||||
By category ($M) | Q3 2026 | Q3 2025 | YTD 2026 | YTD 2025 |
Drilling, completion, new well equip and tie-in, workovers and recompletions | 74,261 | 95,810 | 261,262 | 287,691 |
Production equipment and facilities | 57,296 | 43,731 | 97,847 | 136,991 |
Seismic, studies, land and other | 14,909 | 6,021 | 31,513 | 18,488 |
Capital expenditures | 146,466 | 145,562 | 390,622 | 443,170 |
Acquisitions | (22,780) | 1,068 | (16,407) | 1,123,657 |
Total capital expenditures and acquisitions 123,686 146,630 374,215 1,566,827 | ||||
Capital expenditures by country ($M) | Q3 2026 | Q3 2025 | YTD 2026 | YTD 2025 |
Canada | 90,806 | 92,293 | 278,092 | 257,656 |
France | 13,428 | 10,619 | 29,962 | 27,621 |
Netherlands | 6,562 | 19,421 | 16,094 | 41,041 |
Germany | 12,211 | 12,226 | 22,610 | 55,548 |
Ireland | 9,550 | 1,027 | 15,113 | 2,172 |
Australia | 12,031 | 10,888 | 26,397 | 29,345 |
Central and Eastern Europe | (71) | 838 | 217 | 8,178 |
Capital expenditures on continuing operations | 144,517 | 147,312 | 388,485 | 421,561 |
Canada | - | (4,141) | - | 6,724 |
United States | - | 2,262 | - | 14,885 |
Central and Eastern Europe | 1,949 | 129 | 2,137 | 683 |
Capital expenditures on discontinued operations | 1,949 | (1,750) | 2,137 | 22,292 |
Capital expenditures 146,466 145,562 390,622 443,170 | ||||
Acquisitions by country ($M) | Q3 2026 | Q3 2025 | YTD 2026 | YTD 2025 |
Canada | 1,465 | 1,068 | 7,838 | 1,123,657 |
Germany | (24,245) | - | (24,245) - |
Acquisitions | (22,780) | 1,068 | (16,407) 1,123,657 |
Q3/26 | Q2/26 | Q1/26 | Q4/25 | Q3/25 | Q2/25 | Q1/25 | Q4/24 | Q3/24 | Q2/24 | Q1/24 | Q4/23 | |
Continuing Operations | ||||||||||||
Canada | ||||||||||||
Light and medium crude oil (bbls/d) | 5,231 | 5,916 | 5,592 | 5,494 | 6,092 | 5,812 | 4,136 | 4,102 | 4,843 | 4,288 | 3,252 | 3,294 |
Condensate (1) (bbls/d) | 7,476 | 8,355 | 8,708 | 8,230 | 7,804 | 8,366 | 5,768 | 3,546 | 3,338 | 3,595 | 3,815 | 3,696 |
Other NGLs (1) (bbls/d) | 12,267 | 11,714 | 12,044 | 12,099 | 10,579 | 11,072 | 7,695 | 4,980 | 5,715 | 5,374 | 5,200 | 5,390 |
NGLs (bbls/d) | 19,743 | 20,069 | 20,752 | 20,329 | 18,383 | 19,438 | 13,463 | 8,526 | 9,053 | 8,969 | 9,015 | 9,086 |
Conventional natural gas (mmcf/d) | 419.89 | 441.73 | 440.41 | 391.39 | 367.36 | 394.07 | 249.02 | 151.64 | 148.38 | 148.37 | 140.93 | 148.20 |
Total (boe/d) | 94,955 | 99,605 | 99,746 | 91,053 | 85,698 | 90,926 | 59,104 | 37,898 | 38,625 | 37,987 | 35,753 | 37,081 |
France
Light and medium crude oil (bbls/d) | 6,491 | 6,684 | 6,729 | 6,985 | 6,811 | 6,827 | 6,810 | 7,083 | 7,115 | 7,246 | 7,308 | 7,395 |
Total (boe/d) | 6,491 | 6,684 | 6,729 | 6,985 | 6,811 | 6,827 | 6,810 | 7,083 | 7,115 | 7,246 | 7,308 | 7,395 |
Netherlands | ||||||||||||
Condensate (1) (bbls/d) | 32 | 21 | 22 | 45 | 27 | 35 | 34 | 44 | 39 | 51 | 165 | 119 |
NGLs (bbls/d) | 32 | 21 | 22 | 45 | 27 | 35 | 34 | 44 | 39 | 51 | 165 | 119 |
Conventional natural gas (mmcf/d) | 20.62 | 20.78 | 23.15 | 25.20 | 20.12 | 22.25 | 23.91 | 24.20 | 25.06 | 26.84 | 31.02 | 32.06 |
Total (boe/d) | 3,468 | 3,485 | 3,880 | 4,245 | 3,381 | 3,744 | 4,020 | 4,078 | 4,216 | 4,524 | 5,336 | 5,462 |
Germany | ||||||||||||
Light and medium crude oil (bbls/d) | 1,334 | 1,532 | 1,593 | 1,650 | 1,717 | 1,731 | 1,512 | 1,596 | 1,598 | 1,698 | 1,722 | 1,775 |
Conventional natural gas (mmcf/d) | 30.76 | 25.89 | 25.91 | 28.61 | 26.21 | 25.49 | 21.05 | 21.71 | 21.41 | 18.41 | 22.87 | 19.62 |
Total (boe/d) 6,461 5,847 5,912 6,419 6,086 5,979 5,020 5,215 5,167 4,766 5,533 5,046
Ireland
Total (boe/d) 4,348 7,241 7,423 7,840 8,139 7,959 8,820 9,220 9,844 9,616 10,057 10,673
Conventional natural gas (mmcf/d) 26.09 43.44 44.54 47.04 48.83 47.75 52.92 55.32 59.06 57.70 60.34 64.04
Australia
Total (boe/d) 965 2,243 1,045 2,941 3,693 3,460 3,477 3,778 2,040 3,713 4,264 4,715
Light and medium crude oil (bbls/d) 965 2,243 1,045 2,941 3,693 3,460 3,477 3,778 2,040 3,713 4,264 4,715
Central and Eastern Europe
Conventional natural gas (mmcf/d) 3.99 4.09 5.28 10.22 13.13 9.90 7.24 11.21 11.13 0.69 0.29 0.54
Total (boe/d) 666 682 881 1,707 2,189 1,654 1,208 1,869 1,855 122 48 90
Q3/26 | Q2/26 | Q1/26 | Q4/25 | Q3/25 | Q2/25 | Q1/25 | Q4/24 | Q3/24 | Q2/24 | Q1/24 | Q4/23 | |
Discontinued Operations | ||||||||||||
United States | ||||||||||||
Light and medium crude oil (bbls/d) | - | - | - | 3 | 1,151 | 2,977 | 2,261 | 2,449 | 2,909 | 3,817 | 3,483 | 3,187 |
Condensate (1) (bbls/d) | - | - | - | 9 | 4 | 12 | 19 | 34 | 12 | 27 | 29 | 27 |
Other NGLs (1) (bbls/d) | - | - | - | 39 | 308 | 792 | 795 | 848 | 1,064 | 988 | 1,078 | 1,131 |
NGLs (bbls/d) | - | - | - | 48 | 312 | 804 | 814 | 882 | 1,076 | 1,015 | 1,107 | 1,158 |
Conventional natural gas (mmcf/d) | - | - | - | 0.11 | 2.83 | 5.83 | 5.78 | 5.88 | 7.08 | 7.27 | 8.23 | 7.49 |
Total (boe/d) | - | - | - | 70 | 1,934 | 4,752 | 4,039 | 4,311 | 5,164 | 6,044 | 5,962 | 5,593 |
Canada - Saskatchewan | |||||||||
Light and medium crude oil (bbls/d) | - - - 44 | 862 | 7,961 | 8,039 | 7,512 | 7,682 | 8,180 | 8,397 | 8,320 |
Condensate (1) (bbls/d) | - - - - | 36 | 266 | 328 | 182 | 260 | 258 | 260 | 338 |
Other NGLs (1) (bbls/d) | - - - 1 | 98 | 792 | 677 | 784 | 768 | 834 | 768 | 891 |
NGLs (bbls/d) | - - - 1 | 134 | 1,058 | 1,005 | 966 | 1,028 | 1,092 | 1,028 | 1,229 |
Conventional natural gas (mmcf/d) | - | - | - | 0.02 | 0.80 | 10.09 | 9.44 | 9.63 | 8.62 | 10.11 | 10.91 | 11.96 |
Total (boe/d) | - | - | - | 48 | 1,131 | 10,701 | 10,617 | 10,084 | 10,147 | 10,956 | 11,244 | 11,542 |
Consolidated | ||||||||||||
Light and medium crude oil (bbls/d) | 14,016 | 16,375 | 14,962 | 17,117 | 20,326 | 28,768 | 26,235 | 26,521 | 26,188 | 28,948 | 28,426 | 28,685 |
Condensate (1) (bbls/d) | 7,508 | 8,378 | 8,730 | 8,284 | 7,871 | 8,681 | 6,151 | 3,806 | 3,649 | 3,931 | 4,269 | 4,180 |
Other NGLs (1) (bbls/d) | 12,267 | 11,714 | 12,044 | 12,140 | 10,985 | 12,656 | 9,167 | 6,612 | 7,547 | 7,196 | 7,046 | 7,412 |
NGLs (bbls/d) | 19,775 | 20,092 | 20,774 | 20,424 | 18,856 | 21,337 | 15,318 | 10,418 | 11,196 | 11,127 | 11,315 | 11,592 |
Conventional natural gas (mmcf/d) | 501.35 | 535.93 | 539.29 | 502.60 | 479.28 | 515.38 369.36 | 279.59 | 280.73 | 269.39 | 274.59 | 283.91 |
Total (boe/d) | 117,349 | 125,789 | 125,618 | 121,308 | 119,062 | 136,002 103,115 | 83,536 | 84,173 | 84,974 | 85,505 | 87,597 |
YTD 2026 | 2025 | 2024 | 2023 | 2022 | 2021 | |
Continuing Operations | ||||||
Canada | ||||||
Light and medium crude oil (bbls/d) | 5,579 | 5,389 | 4,124 | 558 | 2,713 | 2,136 |
Condensate (1) (bbls/d) | 8,175 | 7,550 | 3,573 | 3,761 | 4,280 | 4,475 |
Other NGLs (1) (bbls/d) | 12,009 | 10,374 | 5,317 | 4,981 | 5,772 | 5,857 |
NGLs (bbls/d) | 20,184 | 17,924 | 8,890 | 8,742 | 10,052 | 10,332 |
Conventional natural gas (mmcf/d) | 433.92 | 350.89 | 147.35 | 144.26 | 130.44 | 122.90 |
Total (boe/d) 98,085 81,794 37,570 33,344 34,505 32,951
France
Light and medium crude oil (bbls/d) 6,634 6,859 7,188 7,584 7,639 8,799
Total (boe/d) 6,634 6,859 7,188 7,584 7,639 8,799
Netherlands | ||||||
Light and medium crude oil (bbls/d) | - | - | - | - | - | 3 |
Condensate (1) (bbls/d) | 25 | 35 | 75 | 71 | 66 | 97 |
NGLs (bbls/d) | 25 | 35 | 75 | 71 | 66 | 97 |
Conventional natural gas (mmcf/d) | 21.51 | 22.87 | 26.77 | 28.18 | 32.66 | 43.40 |
Total (boe/d) | 3,609 | 3,847 | 4,536 | 4,768 | 5,510 | 7,334 |
Germany
Light and medium crude oil (bbls/d) | 1,485 | 1,653 | 1,653 | 1,654 | 1,435 | 1,044 |
Conventional natural gas (mmcf/d) | 27.54 | 25.36 | 21.10 | 21.93 | 26.18 | 15.81 |
Total (boe/d) 6,075 5,880 5,170 5,310 5,798 3,679
YTD 2026 2025 2024 2023 2022 2021
Ireland
Conventional natural gas (mmcf/d) | 37.96 | 49.12 | 58.10 | 51.12 | 27.48 | 29.25 |
Total (boe/d) | 6,326 | 8,187 | 9,683 | 8,520 | 4,579 | 4,875 |
Australia
Light and medium crude oil (bbls/d) | 1,417 | 3,392 | 3,446 | 1,492 | 3,995 | 3,810 |
Total (boe/d) | 1,417 | 3,392 | 3,446 | 1,492 | 3,995 | 3,810 |
Central and Eastern Europe
Conventional natural gas (mmcf/d) | 4.45 | 10.14 | 5.86 | 0.38 | 0.57 | 0.31 |
Total (boe/d) | 742 | 1,692 | 978 | 63 | 95 | 51 |
Discontinued Operations
United States | ||||||
Light and medium crude oil (bbls/d) | - | 1,591 | 3,162 | 3,445 | 2,908 | 2,597 |
Condensate (1) (bbls/d) | - | 11 | 25 | 21 | 34 | 8 |
Other NGLs (1) (bbls/d) | - | 481 | 994 | 1,076 | 1,066 | 1,146 |
NGLs (bbls/d) | - | 492 | 1,019 | 1,097 | 1,100 | 1,154 |
Conventional natural gas (mmcf/d) | - | 3.62 | 7.11 | 7.28 | 7.20 | 6.84 |
Canada - Saskatchewan | ||||||
Light and medium crude oil (bbls/d) | - | 4,195 | 7,941 | 12,735 | 14,117 | 14,818 |
Condensate (1) (bbls/d) | - | 156 | 240 | 405 | 341 | 356 |
Other NGLs (1) (bbls/d) | - | 389 | 789 | 1,239 | 1,123 | 1,322 |
NGLs (bbls/d) | - | 545 | 1,029 | 1,644 | 1,464 | 1,678 |
Conventional natural gas (mmcf/d) | - | 5.05 | 9.81 | 16.68 | 13.66 | 15.13 |
Consolidated | ||||||
Light and medium crude oil (bbls/d) | 15,114 | 23,079 | 27,514 | 27,469 | 32,809 | 33,208 |
Condensate (1) (bbls/d) | 8,201 | 7,753 | 3,913 | 4,258 | 4,721 | 4,936 |
Other NGLs (1) (bbls/d) | 12,009 | 11,244 | 7,100 | 7,296 | 7,961 | 8,325 |
NGLs (bbls/d) | 20,210 | 18,997 | 11,013 | 11,554 | 12,682 | 13,261 |
Conventional natural gas (mmcf/d) | 525.38 | 467.06 | 276.10 | 269.83 | 238.18 | 233.64 |
Total (boe/d) 122,888 119,919 84,543 83,994 85,187 85,408
(1) Under National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities", disclosure of production volumes should include segmentation by product type as defined in the instrument. This table provides a reconciliation from "crude oil and condensate", "NGLs" and "natural gas" to the product types. In this report, references to "crude oil" and "light and medium crude oil" mean "light crude oil and medium crude oil" and references to "natural gas" mean "conventional natural gas". Production volumes reported are based on quantities as measured at the first point of sale.
Supplemental Table 5: Operational and Financial Data by Core Region Production volumes (1)Q3/26 | Q2/26 | Q1/26 | Q4/25 | Q3/25 | Q2/25 | Q1/25 | Q4/24 | Q3/24 | Q2/24 | Q1/24 | Q4/23 | |
Continuing operations: | ||||||||||||
Canada | ||||||||||||
Crude oil and condensate (bbls/d) | 12,707 | 14,271 | 14,300 | 13,726 | 13,894 | 14,178 | 9,904 | 7,648 | 8,181 | 7,883 | 7,067 | 6,990 |
NGLs (bbls/d) | 12,267 | 11,714 | 12,044 | 12,099 | 10,579 | 11,072 | 7,695 | 4,980 | 5,715 | 5,374 | 5,200 | 5,390 |
Natural gas (mmcf/d) | 419.89 | 441.72 | 440.40 | 391.39 | 367.34 | 394.06 | 249.02 | 151.64 | 148.38 | 148.37 | 140.93 | 148.20 |
Total (boe/d) | 94,956 | 99,605 | 99,744 | 91,056 | 85,696 | 90,926 | 59,104 | 37,898 | 38,625 | 37,987 | 35,753 | 37,081 |
International | ||||||||||||
Crude oil and condensate (bbls/d) | 8,822 | 10,480 | 9,389 | 11,621 | 12,248 | 12,055 | 11,835 | 12,502 | 10,792 | 12,714 | 13,459 | 14,004 |
Natural gas (mmcf/d) | 81.46 | 94.20 | 98.88 | 111.07 | 108.29 | 105.39 | 105.12 | 112.44 | 116.66 | 103.64 | 114.53 | 116.25 |
Total (boe/d) | 22,399 | 26,182 | 25,870 | 30,137 | 30,299 | 29,623 | 29,355 | 31,243 | 30,237 | 29,987 | 32,546 | 33,381 |
Discontinued operations: | ||||||||||||
Crude oil and condensate (bbls/d) | - | - | - | 56 | 2,052 | 11,216 | 10,647 | 10,177 | 10,863 | 12,282 | 12,169 | 11,872 |
NGLs (bbls/d) | - | - | - | 40 | 406 | 1,584 | 1,472 | 1,632 | 1,832 | 1,822 | 1,846 | 2,022 |
Natural gas (mmcf/d) | - | - | - | 0.13 | 3.63 | 15.93 | 15.22 | 15.51 | 15.70 | 17.38 | 19.14 | 19.45 |
Consolidated | ||||||||||||
Crude oil and condensate (bbls/d) | 21,524 | 24,753 | 23,692 | 25,401 | 28,197 | 37,449 | 32,386 | 30,327 | 29,837 | 32,879 | 32,695 | 32,865 |
NGLs (bbls/d) | 12,267 | 11,714 | 12,044 | 12,140 | 10,985 | 12,656 | 9,167 | 6,612 | 7,547 | 7,196 | 7,046 | 7,412 |
Natural gas (mmcf/d) | 501.35 | 535.93 | 539.29 | 502.60 | 479.28 | 515.38 | 369.36 | 279.59 | 280.73 | 269.39 | 274.59 | 283.91 |
Total (boe/d) | 117,349 | 125,789 | 125,618 | 121,308 | 119,062 | 136,002 | 103,115 | 83,536 | 84,173 | 84,974 | 85,505 | 87,597 |
(1) Please refer to Supplemental Table 4 "Production" for disclosure by product type.
Sales volumes | ||||||||||||
Q3/26 | Q2/26 | Q1/26 | Q4/25 | Q3/25 | Q2/25 | Q1/25 | Q4/24 | Q3/24 | Q2/24 | Q1/24 | Q4/23 | |
Continuing operations: | ||||||||||||
Canada | ||||||||||||
Crude oil and condensate (bbls/d) | 12,707 | 14,271 | 14,300 | 13,726 | 13,894 | 14,178 | 9,904 | 7,648 | 8,181 | 7,883 | 7,067 | 6,990 |
NGLs (bbls/d) | 12,267 | 11,714 | 12,044 | 12,099 | 10,579 | 11,072 | 7,695 | 4,980 | 5,715 | 5,374 | 5,200 | 5,390 |
Natural gas (mmcf/d) | 419.89 | 441.72 | 440.40 | 391.39 | 367.34 | 394.06 | 249.02 | 151.64 | 148.38 | 148.37 | 140.93 | 148.20 |
Total (boe/d) | 94,956 | 99,605 | 99,744 | 91,056 | 85,696 | 90,926 | 59,104 | 37,898 | 38,625 | 37,987 | 35,753 | 37,081 |
International | ||||||||||||
Crude oil and condensate (bbls/d) | 12,422 | 8,441 | 10,641 | 12,168 | 14,018 | 10,344 | 11,145 | 11,360 | 12,580 | 11,998 | 15,938 | 9,221 |
Natural gas (mmcf/d) | 81.46 | 94.20 | 98.88 | 111.07 | 108.29 | 105.39 | 105.12 | 112.44 | 116.66 | 103.64 | 114.52 | 116.26 |
Total (boe/d) | 25,998 | 24,143 | 27,121 | 30,681 | 32,069 | 27,911 | 28,668 | 30,101 | 32,024 | 29,271 | 35,026 | 28,598 |
Discontinued operations: | ||||||||||||
Crude oil and condensate (bbls/d) | - | - | - | 56 | 2,052 | 11,216 | 10,647 | 10,177 | 10,863 | 12,282 | 12,169 | 11,872 |
NGLs (bbls/d) | - | - | - | 40 | 406 | 1,584 | 1,472 | 1,632 | 1,832 | 1,822 | 1,846 | 2,022 |
Natural gas (mmcf/d) | - | - | - | 0.13 | 3.63 | 15.93 | 15.22 | 15.51 | 15.70 | 17.38 | 19.14 | 19.45 |
Consolidated | ||||||||||||
Crude oil and condensate (bbls/d) | 25,129 | 22,713 | 24,941 | 25,946 | 29,968 | 35,738 | 31,698 | 29,185 | 31,624 | 32,163 | 35,174 | 28,083 |
NGLs (bbls/d) | 12,267 | 11,714 | 12,044 | 12,140 | 10,985 | 12,656 | 9,167 | 6,612 | 7,547 | 7,196 | 7,046 | 7,412 |
Natural gas (mmcf/d) | 501.35 | 535.93 | 539.29 | 502.60 | 479.28 | 515.38 | 369.36 | 279.59 | 280.73 | 269.39 | 274.59 | 283.91 |
Total (boe/d) | 120,954 | 123,748 | 126,867 | 121,852 | 120,833 | 134,290 | 102,427 | 82,394 | 85,960 | 84,258 | 87,985 | 82,814 |
Financial results | ||||||||||||
Q3/26 | Q2/26 | Q1/26 | Q4/25 | Q3/25 | Q2/25 | Q1/25 | Q4/24 | Q3/24 | Q2/24 | Q1/24 | Q4/23 | |
Continuing operations: | ||||||||||||
Canada | ||||||||||||
Crude oil and condensate sales ($/bbl) | 116.05 | 131.49 | 95.10 | 78.31 | 85.26 | 83.86 | 91.67 | 93.50 | 94.81 | 101.35 | 89.71 | 99.69 |
NGL sales ($/bbl) | 30.99 | 27.70 | 23.00 | 20.99 | 22.63 | 23.37 | 29.75 | 27.76 | 25.96 | 27.93 | 31.21 | 30.77 |
Natural gas sales ($/mcf) | 1.83 | 1.80 | 2.94 | 2.60 | 1.37 | 2.25 | 2.77 | 1.99 | 0.97 | 1.31 | 2.11 | 2.64 |
Sales ($/boe) | 27.61 | 30.09 | 29.40 | 25.75 | 22.51 | 25.67 | 31.26 | 30.81 | 28.11 | 30.60 | 31.01 | 34.46 |
Royalties ($/boe) | (2.69) | (2.93) | (2.23) | (2.14) | (1.39) | (1.97) | (3.51) | (1.96) | (3.22) | (2.83) | (3.42) | (3.98) |
Transportation ($/boe) | (3.55) | (2.92) | (2.42) | (2.66) | (2.96) | (2.77) | (3.06) | (3.42) | (3.46) | (3.07) | (2.47) | (2.56) |
Operating ($/boe) | (6.62) | (7.18) | (6.55) | (6.49) | (6.97) | (7.55) | (8.07) | (11.10) | (8.88) | (11.98) | (10.39) | (9.47) |
General and administration ($/boe) (1) | (0.85) | (1.20) | (0.83) | (1.17) | (0.90) | (1.42) | (3.33) | (0.99) | 0.20 | (1.86) | (0.60) | 2.94 |
Corporate income taxes ($/boe) | - | 0.13 | (0.22) | 0.06 | (0.27) | (0.28) | (0.08) | 0.60 | (0.47) | 1.19 | (0.89) | 6.70 |
Fund flows from operations ($/boe) | 13.90 | 15.99 | 17.15 | 13.35 | 10.02 | 11.68 | 13.21 | 13.94 | 12.28 | 12.05 | 13.24 | 28.09 |
Fund flows from operations 121,409 144,922 154,013 111,763 79,036 96,654 70,248 48,598 43,633 41,638 43,105 95,875
Drilling and development | (90,806) | (73,389) | (113,897) | (134,523) | (92,293) | (45,211) | (121,851) | (85,682) | (54,522) | (43,594) | (110,864) | (40,674) |
Free cash flow | 30,603 | 71,533 | 40,116 | (22,760) | (13,257) | 51,443 | (51,603) | (37,084) | (10,889) | (1,956) | (67,759) | 55,201 |
International | ||||||||||||
Crude oil and condensate sales ($/bbl) | 144.28 | 138.18 | 108.00 | 88.68 | 98.71 | 90.82 | 108.97 | 110.31 | 114.16 | 116.24 | 119.66 | 123.79 |
Natural gas sales ($/mcf) | 25.06 | 20.47 | 16.40 | 14.07 | 14.53 | 15.22 | 20.41 | 18.11 | 14.55 | 12.72 | 11.63 | 16.92 |
Sales ($/boe) | 147.46 | 128.17 | 102.19 | 86.09 | 92.21 | 91.13 | 117.22 | 109.27 | 97.85 | 92.68 | 92.48 | 108.70 |
Royalties ($/boe) | (8.36) | (8.03) | (4.61) | (5.12) | (5.58) | (5.10) | (4.43) | (5.38) | (4.16) | (4.49) | (4.60) | (3.41) |
Transportation ($/boe) | (5.21) | (5.37) | (4.76) | (4.92) | (3.91) | (4.22) | (4.63) | (3.37) | (3.81) | (4.20) | (3.65) | (3.91) |
Operating ($/boe) | (43.11) | (25.67) | (33.96) | (27.86) | (28.29) | (23.80) | (27.46) | (25.08) | (27.11) | (26.56) | (25.30) | (22.64) |
General and administration ($/boe) | (5.32) | (5.52) | (5.13) | (5.52) | (3.98) | (4.67) | (4.67) | (6.21) | (5.56) | (5.20) | (4.86) | (9.18) |
Corporate income taxes ($/boe) | (7.14) | (5.82) | (3.98) | 2.96 | (0.86) | (3.46) | (7.22) | (6.53) | (3.74) | (6.08) | (7.06) | (7.81) |
PRRT ($/boe) | 1.16 | 1.11 | - | 2.97 | (0.56) | (0.30) | (1.17) | 1.16 | (0.17) | (1.37) | (3.38) | 7.93 |
Fund flows from operations ($/boe) | 79.48 | 78.87 | 49.75 | 48.60 | 49.03 | 49.58 | 67.64 | 63.86 | 53.30 | 44.78 | 43.63 | 69.68 |
Fund flows from operations | 190,103 | 173,256 | 121,407 | 137,175 | 144,615 | 125,955 | 174,521 | 176,883 | 157,048 | 119,310 | 139,052 | 183,353 |
Drilling and development | (49,888) | (36,125) | (20,375) | (59,785) | (54,418) | (53,055) | (36,565) | (42,341) | (40,638) | (47,830) | (45,789) | (73,604) |
Exploration and evaluation | (3,823) | (62) | (120) | 2,011 | (601) | (4,210) | (14,373) | (22,161) | (260) | (1,260) | (5,123) | (7,612) |
Discontinued operations | ||||||||||||
Crude oil and condensate sales ($/bbl) | - | - | - | 88.70 | 90.96 | 81.28 | 93.64 | 91.88 | 95.57 | 104.51 | 90.61 | 97.61 |
NGL sales ($/bbl) | - | - | - | 77.17 | 32.39 | 33.83 | 47.63 | 37.41 | 35.94 | 46.43 | 46.90 | 45.49 |
Natural gas sales ($/mcf) | - | - | - | 7.19 | 2.90 | 1.71 | 3.01 | 1.89 | 0.24 | 1.13 | 2.38 | 2.42 |
Sales ($/boe) | - | - | - | 76.83 | 68.62 | 64.23 | 75.93 | 71.23 | 72.36 | 81.63 | 71.77 | 75.74 |
Royalties ($/boe) | - | - | - | (19.04) | (15.56) | (11.95) | (14.56) | (13.83) | (13.53) | (16.09) | (14.54) | (14.35) |
Transportation ($/boe) | - | - | - | (3.53) | (3.64) | (2.13) | (2.23) | (2.04) | (2.26) | (2.26) | (2.11) | (2.18) |
Operating ($/boe) | - | - | - | 6.78 | (20.06) | (18.44) | (21.23) | (23.73) | (19.44) | (18.14) | (22.27) | (15.89) |
General and administration ($/boe) | - | - | - | (78.97) | (16.98) | (7.61) | (3.73) | (5.15) | (4.36) | (4.06) | (4.00) | (3.62) |
Fund flows from operations ($/boe) | - | - | - | (17.93) | 12.38 | 24.10 | 34.18 | 26.48 | 32.77 | 41.07 | 28.85 | 39.70 |
Fund flows from operations | (143) | (441) | (152) | (193) | 3,493 | 33,893 | 45,087 | 35,064 | 46,160 | 63,549 | 45,171 | 62,595 |
Drilling and development | (1,949) | - | 126 | 551 | 1,920 | (12,972) | (9,048) | (48,482) | (23,649) | (17,926) | (25,645) | (18,030) |
Exploration and evaluation | - | - | (314) | (6) | (170) | (41) | (282) | (1,993) | (2,200) | - | (3,021) | (2,967) |
Free cash flow (2,092) (441) (340) 352 5,243 20,880 35,757 (15,411) 20,311 45,623 16,505 41,598
Q3/26 | Q2/26 | Q1/26 | Q4/25 | Q3/25 | Q2/25 | Q1/25 | Q4/24 | Q3/24 | Q2/24 | Q1/24 | Q4/23 | |
Consolidated | ||||||||||||
Crude oil and condensate sales ($/bbl) | 130.00 | 133.97 | 100.61 | 83.21 | 91.93 | 85.07 | 99.36 | 100.06 | 103.55 | 108.93 | 104.26 | 107.92 |
NGL sales ($/bbl) | 30.99 | 27.70 | 23.00 | 21.17 | 22.99 | 24.68 | 31.56 | 29.38 | 27.49 | 31.61 | 34.16 | 33.38 |
Natural gas sales ($/mcf) | 5.60 | 5.08 | 5.41 | 5.13 | 4.36 | 4.88 | 7.80 | 8.47 | 6.57 | 5.69 | 6.10 | 8.48 |
Sales ($/boe) | 53.37 | 49.23 | 44.96 | 40.99 | 42.18 | 43.71 | 61.71 | 66.54 | 61.97 | 62.46 | 63.45 | 68.64 |
Royalties ($/boe) | (3.91) | (3.92) | (2.74) | (2.91) | (2.86) | (3.77) | (5.35) | (5.28) | (5.40) | (6.08) | (6.06) | (5.93) |
Transportation ($/boe) | (3.91) | (3.40) | (2.92) | (3.23) | (3.23) | (3.00) | (3.38) | (3.16) | (3.38) | (3.30) | (2.87) | (2.95) |
Operating ($/boe) | (14.46) | (10.80) | (12.42) | (11.86) | (12.96) | (12.18) | (15.38) | (18.41) | (17.55) | (18.29) | (18.65) | (15.35) |
General and administration ($/boe) | (1.82) | (2.07) | (1.76) | (2.34) | (2.13) | (2.80) | (3.76) | (3.62) | (2.76) | (3.46) | (2.96) | (2.60) |
Corporate income taxes ($/boe) | (1.54) | (1.03) | (1.02) | 0.79 | (0.42) | (0.91) | (2.07) | (2.11) | (1.61) | (1.58) | (3.20) | (2.58) |
PRRT ($/boe) | 0.25 | 0.22 | - | 0.75 | (0.15) | (0.06) | (0.33) | 0.43 | (0.06) | (0.47) | (1.35) | 2.74 |
Interest ($/boe) | (2.39) | (2.32) | (2.34) | (2.47) | (3.10) | (3.08) | (3.58) | (3.16) | (2.68) | (2.75) | (2.30) | (3.01) |
Equity based compensation ($/boe) | (0.05) | (0.95) | - | (0.06) | - | (0.47) | - | - | - | (1.87) | - | - |
Realized derivatives ($/boe) | (4.21) | (5.10) | (1.39) | 1.88 | 5.56 | 3.90 | 1.21 | 3.80 | 6.31 | 6.00 | 27.55 | 10.33 |
Realized foreign exchange ($/boe) | (0.05) | (0.38) | (0.05) | 0.01 | (0.08) | (0.04) | 0.27 | 0.32 | 0.15 | 0.30 | 0.23 | (0.73) |
Realized other ($/boe) | 0.01 | 1.07 | 0.01 | (0.08) | 0.01 | (0.05) | (1.57) | (0.68) | (0.21) | (0.09) | 0.02 | 0.26 |
Fund flows from operations ($/boe) 21.29 20.55 20.33 21.47 22.82 21.25 27.77 34.67 34.78 30.87 53.86 48.82
Fund flows from operations | 236,919 | 231,222 | 232,277 | 240,734 | 253,810 | 259,678 | 256,029 | 262,698 | 275,024 | 236,703 | 431,358 | 372,117 |
Drilling and development | (142,643) | (109,514) | (134,146) | (193,757) | (144,791) | (111,238) | (167,464) | (176,505) | (118,809) | (109,350) | (182,298) | (132,308) |
Exploration and evaluation | (3,823) | (62) | (434) | 2,005 | (771) | (4,251) | (14,655) | (24,154) | (2,460) | (1,260) | (8,144) | (10,579) |
Free cash flow | 90,453 | 121,646 | 97,697 | 48,982 | 108,248 | 144,189 | 73,910 | 62,039 | 153,755 | 126,093 | 240,916 | 229,230 |
(1) General and administration expenses previously presented within the Corporate segment have been reclassified to our Canadian segment. The prior period results have been presented to conform with current period presentation.