Ovintiv Inc.

Results of Operations

Selected Financial Information

(1)

(2)

Service revenues comprise third-party gathering and processing fees.

(3)

Total Operating Expenses include non-cash items such as DD&A, impairments, accretion of asset retirement obligations and long-term incentive costs. The three and six months ended June 30, 2025, include non-cash ceiling test impairments of nil and $730 million, respectively (2024 - nil, respectively).

Revenues

Ovintiv’s revenues are substantially derived from sales of oil, NGLs and natural gas production. Increases or decreases in Ovintiv’s revenue, profitability and future production are highly dependent on the commodity prices the Company receives. Prices are market driven and fluctuate due to factors beyond the Company’s control, such as supply and demand, seasonality and geopolitical and economic factors. The Company’s realized prices generally reflect WTI, NYMEX, Edmonton Condensate and AECO benchmark prices, as well as other downstream benchmarks, including Houston and Dawn. The Company proactively mitigates price risk and optimizes margins by entering into firm transportation contracts to diversify market access to different sales points. Realized prices, excluding the impact of risk management activities, may differ from the benchmarks for many reasons, including quality, location, or production being sold at different market hubs.

Benchmark prices relevant to the Company are shown in the table below.

Benchmark Prices

Production Volumes and Realized Prices

(1)

Average daily.

(2)

Average per-unit prices, excluding the impact of risk management activities.

(3)

Includes production impacts of acquisitions and divestitures.

Upstream Product Revenues, Excluding Realized Gains (Losses) on Risk Management

(1)

Oil Revenues

Oil revenues were lower by $363 million compared to the second quarter of 2024 primarily due to:

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A decrease of $13.69 per bbl, or 18 percent, in the average realized oil prices which decreased revenues by $182 million. The decrease reflected lower WTI and Houston benchmark prices which were both down 21 percent, partially offset by higher regional pricing relative to the benchmark prices; and

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Lower average oil production volumes of 25.3 Mbbls/d decreased revenues by $181 million. Lower production volumes were primarily due to the sale of the Uinta assets during the first quarter of 2025 (27.9 Mbbls/d), partially offset by successful drilling in Anadarko and Permian (3.9 Mbbls/d).

Oil revenues were lower by $568 million compared to the first six months of 2024 primarily due to:

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Lower average oil production volumes of 22.5 Mbbls/d decreased revenues by $330 million. Lower production volumes were primarily due to the sale of the Uinta assets during the first quarter of 2025 (21.1 Mbbls/d); and

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A decrease of $8.93 per bbl, or 12 percent, in the average realized oil prices which decreased revenues by $238 million. The decrease reflected lower Houston and WTI benchmark prices which were down 15 percent and 14 percent, respectively, partially offset by higher regional pricing relative to the benchmark prices.

NGL Revenues

NGL revenues were higher by $97 million compared to the second quarter of 2024 primarily due to:

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Higher average plant condensate production volumes of 24.6 Mbbls/d increased revenues by $171 million. Higher production volumes were primarily due to the Montney Acquisition in the first quarter of 2025 (22.0 Mbbls/d) and successful drilling in Montney (5.7 Mbbls/d), partially offset by lower production volumes in Montney related to increased third-party plant downtime (4.4 Mbbls/d); and

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A decrease of $10.87 per bbl, or 15 percent, in the average realized plant condensate prices which decreased revenues by $80 million. The decrease primarily reflected the lower Edmonton Condensate benchmark price which was down 17 percent.

NGL revenues were higher by $188 million compared to the first six months of 2024 primarily due to:

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Higher average plant condensate production volumes of 19.7 Mbbls/d increased revenues by $262 million. Higher production volumes were primarily due to the Montney Acquisition in the first quarter of 2025 (18.4 Mbbls/d) and successful drilling in Montney (3.0 Mbbls/d), partially offset by lower production volumes in Montney related to increased third-party plant downtime (1.7 Mbbls/d); and

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A decrease of $6.78 per bbl, or 10 percent, in the average realized plant condensate prices which decreased revenues by $95 million. The decrease primarily reflected the lower Edmonton Condensate benchmark price which was down eight percent.

Natural Gas Revenues

Natural gas revenues were higher by $173 million compared to the second quarter of 2024 primarily due to:

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An increase of $0.94 per Mcf, or 72 percent, in the average realized natural gas prices which increased revenues by $158 million. The increase reflected the higher NYMEX and AECO benchmark prices which were up 82 percent and 44 percent, respectively, and exposure to other downstream benchmark prices relating to the Company’s diversified markets in the Canadian Operations, partially offset by lower regional pricing relative to benchmark prices in the USA Operations; and

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Higher average natural gas production volumes of 111 MMcf/d increased revenues by $15 million. Higher production volumes were primarily due to the Montney Acquisition in the first quarter of 2025 (207 MMcf/d) and successful drilling in Montney and Permian (137 MMcf/d). The higher production volumes were partially offset by lower production volumes in Montney primarily related to pipeline restrictions and increased third-party plant downtime (102 MMcf/d), higher effective royalty rates in Montney (67 MMcf/d), the sale of the Uinta and Horn River assets in the first quarter of 2025 (31 MMcf/d), and natural declines in Anadarko (24 MMcf/d).

Natural gas revenues were higher by $313 million compared to the first six months of 2024 primarily due to:

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An increase of $0.86 per Mcf, or 49 percent, in the average realized natural gas prices which increased revenues by $277 million. The increase reflected the higher NYMEX and AECO benchmark prices which were up 71 percent and 18 percent, respectively, and exposure to other downstream benchmark prices relating to the Company’s diversified markets in the Canadian Operations, partially offset by lower regional pricing relative to benchmark prices in the USA Operations; and

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Higher average natural gas production volumes of 114 MMcf/d increased revenues by $36 million. Higher production volumes were primarily due to the Montney Acquisition in the first quarter of 2025 (173 MMcf/d), and successful drilling in Montney and Permian (93 MMcf/d). The higher production volumes were partially offset by lower production volumes in Montney primarily related to pipeline restrictions and increased third-party plant downtime (69 MMcf/d), the sale of the Uinta and Horn River assets in the first quarter of 2025 (42 MMcf/d), natural declines in Anadarko (22 MMcf/d), and higher effective royalty rates in Montney (18 MMcf/d).

Sales of Purchased Product

Revenues from the sale of purchased product relate to activities that provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification within the USA and Canadian Operations segments.

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Sales of purchased product revenues increased $106 million compared to the second quarter of 2024 primarily due to:

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Higher sales of third-party purchased liquids volumes in the USA Operations ($280 million) and higher realized third-party natural gas pricing ($16 million);

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Lower realized third-party liquids pricing ($189 million).

Sales of purchased product revenues increased $67 million compared to the first six months of 2024 primarily due to:

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Higher sales of third-party purchased liquids volumes in the USA Operations ($319 million) and higher realized third-party natural gas pricing ($10 million);

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Lower realized third-party liquids pricing ($258 million).

Gains (Losses) on Risk Management, Net

As a means of managing commodity price volatility, Ovintiv enters into commodity derivative financial instruments on a portion of its expected oil, NGLs and natural gas production volumes. Additional information on the Company’s commodity price positions as at June 30, 2025, can be found in Note 19 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

The following tables provide the effects of the Company’s risk management activities on revenues.

(1)

Other primarily includes realized gains from other derivative contracts with no associated production volumes.

Ovintiv recognizes fair value changes from its risk management activities each reporting period. The changes in fair value result from new positions and settlements that occur during each period, as well as the relationship between contract prices and the associated forward curves. Realized gains or losses on risk management activities related to commodity price mitigation are included in the USA and Canadian Operations’ revenues as the contracts are cash settled. Unrealized gains or losses on fair value changes of unsettled contracts are included in the Corporate and Other segment.

During the second quarter of 2025, the Company entered into physical forward contracts to further mitigate a portion of its exposure to AECO benchmark prices. The Company’s ongoing market diversification strategy shifts a portion of its commodity price exposure to alternative pricing hubs including Japan Korea Marker and Chicago city-gates, commencing in 2026 and 2027, respectively.

Additional information on fair value changes and risk management contracts can be found in Notes 18 and 19, respectively, to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Sublease Revenues

Sublease revenues primarily include amounts related to the sublease of office space in The Bow office building recorded in the Corporate and Other segment. Additional information on office sublease income can be found in Note 10 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Production, Mineral and Other Taxes

Production, mineral and other taxes include production and property taxes. Production taxes are generally assessed as a percentage of oil, NGLs and natural gas production revenues. Property taxes are generally assessed based on the value of the underlying assets.

Production, mineral and other taxes decreased $16 million compared to the second quarter of 2024 primarily due to:

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The Uinta assets sold in the first quarter of 2025 ($11 million) and lower oil commodity prices ($10 million);

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Higher property taxes due to the Montney Acquisition in the first quarter of 2025 ($2 million).

Production, mineral and other taxes decreased $12 million compared to the first six months of 2024 primarily due to:

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Lower oil commodity prices ($14 million) and the Uinta assets sold in the first quarter of 2025 ($11 million);

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Higher effective production tax rates ($4 million), higher property taxes primarily due to the Montney Acquisition in the first quarter of 2025 ($4 million) and production tax recoveries in Anadarko in 2024 ($4 million).

Transportation and Processing

Transportation and processing expense includes transportation costs incurred to move product from production points to sales points including gathering, compression, pipeline tariffs, trucking and storage costs. Ovintiv also incurs costs related to processing provided by third parties or through ownership interests in processing facilities.

(1)

The second quarter and first six months of 2025 include pipeline transportation fees associated with previously divested assets in the USA Operations of $1 million, respectively (2024 ‑ $17 million and $50 million, respectively) and other third-party transportation and processing fees with no associated volumes in the Canadian Operations of approximately $8 million and $15 million, respectively (2024 ‑ $10 million and $18 million, respectively).

Transportation and processing expense increased $22 million compared to the second quarter of 2024 primarily due to:

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Higher production volumes due to the Montney Acquisition during the first quarter of 2025 ($71 million) and higher natural gas production volumes in Permian ($5 million);

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An expired pipeline transportation contract ($17 million), the Uinta and Horn River assets sold in the first quarter of 2025 ($15 million), a third-party plant turnaround in Montney in 2024 ($8 million), lower midstream transportation costs in Montney ($6 million) and lower natural gas production volumes in Anadarko ($4 million).

Transportation and processing expense increased $1 million compared to the first six months of 2024 primarily due to:

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Higher production volumes due to the Montney Acquisition during the first quarter of 2025 ($121 million) and higher natural gas production volumes in Permian ($10 million);

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An expired pipeline transportation contract ($50 million), the Uinta and Horn River assets sold in the first quarter of 2025 ($32 million), a higher U.S./Canadian dollar exchange rate ($18 million), lower midstream transportation costs in Montney ($15 million), a third-party plant turnaround in Montney in 2024 ($8 million), and lower production volumes in Anadarko ($8 million).

Operating

Operating expense includes costs paid by the Company, net of amounts capitalized, on oil and natural gas properties in which Ovintiv has a working interest. These costs primarily include labor, service contract fees, chemicals, fuel, water hauling, electricity and workovers.

Operating expense decreased $18 million compared to the second quarter of 2024 primarily due to:

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The sale of the Uinta assets in the first quarter of 2025 ($25 million), and decreased workover activity in Anadarko and Permian ($5 million);

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Higher activity due to the Montney Acquisition in the first quarter of 2025 ($11 million).

Operating expense decreased $56 million compared to the first six months of 2024 primarily due to:

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The sale of the Uinta assets in the first quarter of 2025 ($47 million), increased operational efficiencies in Permian ($12 million), decreased workover activity in Anadarko and Permian ($10 million), and lower salaries and benefits resulting from the corporate reorganization which commenced in 2024 ($8 million);

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Higher activity due to the Montney Acquisition in the first quarter of 2025 ($17 million).

Purchased Product

Purchased product expense includes purchases of oil, NGLs and natural gas from third parties that are used to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification within the USA and Canadian Operations segments.

Purchased product expense increased $107 million compared to the second quarter of 2024 primarily due to:

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Higher third-party purchased liquids volumes in the USA Operations ($280 million) and higher third-party natural gas purchase prices ($17 million);

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Lower third-party liquids purchase prices ($190 million).

Purchased product expense increased $69 million compared to the first six months of 2024 primarily due to:

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Higher third-party purchased liquids volumes in the USA Operations ($319 million) and higher third-party natural gas purchase prices ($13 million);

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Lower third-party liquids purchase prices ($260 million).

Depreciation, Depletion & Amortization

Proved properties within each country cost center are depleted using the unit-of-production method based on proved reserves as discussed in Note 1 to the Consolidated Financial Statements included in Item 8 of the 2024 Annual Report on Form 10-K. Depletion rates are impacted by impairments, acquisitions, divestitures and foreign exchange rates, as well as fluctuations in 12-month average trailing prices which affect proved reserves volumes. Corporate assets are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets.

Additional information can be found under Upstream Assets and Reserve Estimates in the Critical Accounting Estimates section of the MD&A included in Item 7 of the 2024 Annual Report on Form 10-K.

DD&A decreased $24 million compared to the second quarter of 2024 primarily due to:

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Lower depletion rates and production volumes in the USA Operations primarily due to the sale of the Uinta assets in the first quarter of 2025 ($88 million and $40 million, respectively);

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Higher depletion rates and production volumes in the Canadian Operations primarily due to the Montney Acquisition in the first quarter of 2025 ($89 million and $15 million, respectively).

The upstream depletion rate in the USA Operations decreased $3.08 per BOE primarily due to a lower depletable base resulting from the sale of the Uinta assets in the first quarter of 2025. The upstream depletion rate in the Canadian Operations increased $3.22 per BOE primarily due to a higher depletable base resulting from the Montney Acquisition in the first quarter of 2025, partially offset by the ceiling test impairments recognized in the fourth quarter of 2024 and first quarter of 2025.

DD&A decreased $45 million compared to the first six months of 2024 primarily due to:

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Lower depletion rates and production volumes in the USA Operations primarily due to the sale of the Uinta assets in the first quarter of 2025 ($160 million and $82 million, respectively);

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Higher depletion rates and production volumes in the Canadian Operations primarily due to the Montney Acquisition in the first quarter of 2025 ($175 million and $26 million, respectively).

The upstream depletion rate in the USA Operations decreased $2.80 per BOE primarily due to a lower depletable base resulting from the sale of the Uinta assets in the first quarter of 2025. The upstream depletion rate in the Canadian Operations increased $3.26 per BOE primarily due to a higher depletable base resulting from the Montney Acquisition in the first quarter of 2025, partially offset by the ceiling test impairments recognized in the fourth quarter of 2024 and first quarter of 2025.

Ceiling Test Impairment

Under full cost accounting, the carrying amount of Ovintiv’s oil and natural gas properties within each country cost center is subject to a ceiling test performed quarterly. Ceiling test impairments are recognized when the capitalized costs, net of accumulated depletion and the related deferred income taxes, exceed the sum of the estimated after-tax future net cash flows from proved reserves as calculated under SEC requirements using the 12-month average trailing prices and discounted at 10 percent. The 12‑month average trailing price is calculated as the average of the price on the first day of each month within the trailing 12‑month period.

In the second quarter and first six months of 2025, the Company recognized before-tax non-cash ceiling test impairments of nil and $730 million, respectively, in the Canadian Operations. The non-cash impairment recognized in the first quarter of 2025 primarily resulted from the 12-month average trailing prices used in the ceiling test at March 31, 2025, which were lower than the market prices used for the Montney Acquisition on January 31, 2025.

The 12-month average trailing prices used in the ceiling test calculations were based on the benchmark prices below. The benchmark prices were adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality.

(1)

All prices were held constant in all future years when estimating net revenues and reserves.

Future declines in the 12‑month average trailing commodity prices could reduce proved reserves values and result in the recognition of future ceiling test impairments. Future ceiling test impairments can also result from changes to reserves estimates, future development costs, capitalized costs and unproved property costs. Proceeds received from oil and natural gas divestitures are typically deducted from the Company’s capitalized costs and can reduce the risk of ceiling test impairments.

The Company believes that the discounted after-tax future net cash flows from proved reserves required to be used in the ceiling test calculation are not indicative of the fair market value of Ovintiv’s oil and natural gas properties or the future net cash flows expected to be generated from such properties. The discounted after-tax future net cash flows do not consider the fair market value of unamortized unproved properties, or probable or possible liquids and natural gas reserves. In addition, there is no consideration given to the effect of future changes in commodity prices. Ovintiv manages its business using estimates of reserves and resources based on forecast prices and costs. Additional information on the ceiling test calculation can be found in Note 9 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10‑Q.

Administrative

Administrative expense represents costs associated with corporate functions provided by Ovintiv staff. These expenses primarily include salaries and benefits, operating leases, office, information technology, restructuring and long-term incentive costs.

(1)

The second quarter and first six months of 2025 include costs related to The Bow office lease of $26 million and $54 million, respectively (2024 - $29 million and $58 million, respectively), half of which is recovered from sublease revenues.

Administrative expense decreased $9 million compared to the first six months of 2024 primarily due to:

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Lower legal costs ($10 million) and lower long-term incentive costs ($5 million);

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Restructuring costs incurred primarily related to the corporate reorganization which commenced in 2024 ($11 million).

In 2024, Ovintiv undertook a plan to reduce its workforce by approximately 10 percent as part of a corporate reorganization. Additional information on restructuring charges and long-term incentive costs can be found in Notes 16 and 17 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Other (Income) Expenses

Interest

Interest expense primarily includes interest on Ovintiv’s short-term and long-term debt. Additional information on changes in interest and long-term debt can be found in Notes 5 and 11, respectively, to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Interest expense decreased $10 million compared to the second quarter of 2024 primarily due to:

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Lower interest expense on short-term borrowings ($4 million) and lower interest expense resulting from the repayment of the Company’s $600 million senior note in the second quarter of 2025 ($4 million).

Interest expense decreased $11 million compared to the first six months of 2024 primarily due to:

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Lower interest expense on short-term borrowings ($8 million) and lower interest expense resulting from the repayment of the Company’s $600 million senior note in the second quarter of 2025 ($4 million);

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Financing fees incurred related to the termination of two term facilities following the closing of the Uinta divestiture and Montney Acquisition in the first quarter of 2025 ($5 million).

Foreign Exchange (Gain) Loss, Net

Foreign exchange gains and losses primarily result from the impact of fluctuations in the Canadian to U.S. dollar exchange rate. Additional information on changes in foreign exchange gains or losses can be found in Note 6 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q. Additional information on foreign exchange rates and the effects of foreign exchange rate changes can be found in Part I, Item 3 of this Quarterly Report on Form 10-Q.

Net foreign exchange loss of $22 million compared to a gain of $10 million during the second quarter of 2024 primarily due to:

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Losses on other monetary revaluations compared to gains in 2024 ($20 million), realized foreign exchange losses on the settlement of intercompany notes compared to gains in 2024 ($7 million) and unrealized foreign exchange gains on the translation of intercompany notes in 2024 ($6 million).

Net foreign exchange loss of $32 million compared to a gain of $38 million during the first six months of 2024 primarily due to:

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Higher realized foreign exchange losses on the settlement of U.S. dollar risk management contracts issued from Canada ($97 million), unrealized foreign exchange losses on the translation of intercompany notes compared to gains in 2024 ($77 million) and losses on other monetary revaluations compared to gains in 2024 ($22 million);

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Unrealized foreign exchange gains on the translation of U.S. dollar risk management contracts issued from Canada compared to losses in 2024 ($92 million) and higher realized foreign exchange gains on the settlement of intercompany notes ($33 million).

Other (Gains) Losses, Net

Other (gains) losses, net, primarily includes other non-recurring revenues or expenses and may also include items such as interest income, reclamation charges related to decommissioned assets, and adjustments related to other assets.

Other gains in the second quarter and first six months of 2025 includes interest income of $3 million and $8 million, respectively, primarily generated from short-term investments (2024 - $1 million and $3 million, respectively).

Income Tax

During the first six months of 2025, current income tax expense of $69 million was higher than the comparative period in 2024 primarily due to the resolution of prior period items in Canada in 2025.

During the second quarter of 2025, the deferred income tax expense of $66 million was lower than the comparative period in 2024 primarily due to lower earnings in 2025. During the first six months of 2025, the deferred income tax recovery was $11 million compared to an expense of $161 million in 2024 primarily due to the impact of the non-cash ceiling test impairment recognized in Canada in the first quarter of 2025.

The determination of income and other tax liabilities of the Company and its subsidiaries requires interpretation of complex domestic and foreign tax laws and regulations, that are subject to change. The Company’s interpretation of tax laws may differ from the interpretation of the tax authorities. As a result, there are tax matters under review for which the timing of resolution is uncertain. The Company believes that the provision for income taxes is adequate.

On July 4, 2025, the One Big Beautiful Bill Act (H.R.1) was signed into law, introducing reforms to U.S. tax policy, energy infrastructure, and environmental regulation. Ovintiv continues to assess the impact of this legislative change. The Company does not anticipate a significant impact in 2025, however it does anticipate additional tax benefits for 2026 and beyond.

Additional information on income taxes can be found in Note 7 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.