Ovintiv Inc.

Results of Operations

Selected Financial Information

(1)

Service revenues comprise third-party gathering and processing fees, and other revenues.

(2)

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, 2026, include non-cash ceiling test impairments of nil and $1,485 million, respectively (2025 ‑ nil and $730 million, respectively).

(3)

The three and six months ended June 30, 2026, include a loss on the divestiture of the Company’s Anadarko assets of $337 million, 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

Oil Revenues

Oil revenues were higher by $293 million compared to the second quarter of 2025 primarily due to:

•

An increase of $36.19 per bbl, or 56 percent, in the average realized oil prices which increased revenues by $405 million. The increase reflected higher Houston and WTI benchmark prices which were up 48 percent and 46 percent, respectively, and higher regional pricing relative to benchmark prices; and

•

Lower average oil production volumes of 19.0 Mbbls/d decreased revenues by $112 million. Lower production volumes were primarily due to the sale of the Anadarko assets in the second quarter of 2026 (21.2 Mbbls/d), partially offset by successful drilling in Permian (1.4 Mbbls/d).

Oil revenues were higher by $244 million compared to the first six months of 2025 primarily due to:

•

An increase of $17.50 per bbl, or 26 percent, in the average realized oil prices which increased revenues by $415 million. The increase reflected higher Houston and WTI benchmark prices which were up 23 percent and 22 percent, respectively, and higher regional pricing relative to benchmark prices; and

•

Lower average oil production volumes of 13.9 Mbbls/d decreased revenues by $171 million. Lower production volumes were primarily due to the sale of the Anadarko assets in the second quarter of 2026 (9.4 Mbbls/d) and the sale of the Uinta assets in the first quarter of 2025 (3.0 Mbbls/d).

NGL Revenues

NGL revenues were higher by $318 million compared to the second quarter of 2025 primarily due to:

•

An increase of $31.96 per bbl, or 53 percent, in the average realized plant condensate prices which increased revenues by $232 million. The increase primarily reflected the higher Edmonton Condensate benchmark price which was up 50 percent and higher regional pricing relative to benchmark prices; and

•

Higher average plant condensate production volumes of 13.6 Mbbls/d increased revenues by $82 million. Higher production volumes were primarily due to the NuVista Acquisition in the first quarter of 2026 (27.2 Mbbls/d), partially offset by the sale of the Anadarko assets in the second quarter of 2026 (4.8 Mbbls/d), higher effective royalty rates in Montney (3.2 Mbbls/d), natural declines in Montney (3.2 Mbbls/d) and lower production volumes in Montney due to increased third-party plant downtime and pipeline restrictions (2.8 Mbbls/d).

NGL revenues were higher by $490 million compared to the first six months of 2025 primarily due to:

•

An increase of $18.06 per bbl, or 29 percent, in the average realized plant condensate prices which increased revenues by $261 million. The increase primarily reflected the higher Edmonton Condensate benchmark price which was up 22 percent, higher regional pricing relative to benchmark prices and a lower U.S./Canadian dollar foreign exchange rate; and

•

Higher average plant condensate production volumes of 20.9 Mbbls/d increased revenues by $249 million. Higher production volumes were primarily due to the NuVista Acquisition in the first quarter of 2026 (22.3 Mbbls/d) and the Montney assets acquired in the first quarter of 2025 (3.7 Mbbls/d), partially offset by lower production volumes in Montney due to increased third-party plant downtime and pipeline restrictions (2.4 Mbbls/d) and the sale of the Anadarko assets in the second quarter of 2026 (2.2 Mbbls/d).

Natural Gas Revenues

Natural gas revenues were lower by $73 million compared to the second quarter of 2025 primarily due to:

•

A decrease of $0.53 per Mcf, or 24 percent, in the average realized natural gas prices which decreased revenues by $94 million. The decrease reflected lower regional pricing relative to benchmark prices in the USA Operations and the lower AECO and NYMEX benchmark prices which were down 27 percent and 16 percent, respectively, partially offset by higher regional pricing relative to benchmark prices in the Canadian Operations; and

•

Higher average natural gas production volumes of 108 MMcf/d increased revenues by $21 million. Higher production volumes were primarily due to the NuVista Acquisition in the first quarter of 2026 (423 MMcf/d), partially offset by the sale of the Anadarko assets in the second quarter of 2026 (223 MMcf/d) and natural declines in Montney (88 MMcf/d).

Natural gas revenues were higher by $56 million compared to the first six months of 2025 primarily due to:

•

Higher average natural gas production volumes of 234 MMcf/d increased revenues by $106 million. Higher production volumes were primarily due to the NuVista Acquisition in the first quarter of 2026 (348 MMcf/d) and the Montney assets acquired in the first quarter of 2025 (34 MMcf/d), partially offset by the sale of the Anadarko assets in the second quarter of 2026 (117 MMcf/d); and

•

A decrease of $0.15 per Mcf, or six percent, in the average realized natural gas prices which decreased revenues by $50 million. The decrease reflected lower regional pricing relative to benchmark prices in the USA Operations, partially offset by the higher NYMEX benchmark price which was up 12 percent and higher regional pricing relative to benchmark prices in the Canadian Operations.

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.

Sales of purchased product revenues increased $125 million compared to the second quarter of 2025 primarily due to:

•

Higher realized third-party liquids pricing ($208 million) and higher sales of third-party purchased natural gas volumes ($29 million);

•

Lower sales of third-party purchased liquids volumes ($100 million) and lower realized third-party natural gas pricing ($13 million).

Sales of purchased product revenues increased $71 million compared to the first six months of 2025 primarily due to:

•

Higher realized third-party liquids and natural gas pricing ($214 million and $12 million, respectively), and higher sales of third-party purchased natural gas volumes ($32 million);

•

Lower sales of third-party purchased liquids volumes ($187 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, 2026, can be found in Note 20 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.

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.

Additional information on fair value changes 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.

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 11 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 increased $8 million compared to the second quarter of 2025 primarily due to:

•

Higher oil commodity prices ($18 million) and higher property taxes due to the NuVista Acquisition in the first quarter of 2026 ($4 million);

•

The sale of the Anadarko assets in the second quarter of 2026 ($14 million).

Production, mineral and other taxes were in line with the first six months of 2025 primarily due to:

•

Higher oil commodity prices ($19 million) and higher property taxes due to the NuVista Acquisition in the first quarter of 2026 ($7 million);

•

The sales of the Anadarko assets in the second quarter of 2026 and the Uinta assets in the first quarter of 2025 ($14 million and $5 million, respectively) and lower effective production tax rates ($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 2026 include pipeline transportation fees associated with previously divested assets in the USA Operations of nil, respectively (2025 - $1 million, respectively) and other third-party transportation and processing fees with no associated volumes in the Canadian Operations of approximately $11 million and $22 million, respectively (2025 ‑ $8 million and $15 million, respectively).

Transportation and processing expense increased $105 million compared to the second quarter of 2025 primarily due to:

•

Higher production volumes due to the NuVista Acquisition in the first quarter of 2026 ($91 million), higher midstream transportation costs in Montney ($31 million) and higher transportation costs in Permian due to increased gas production volumes ($7 million);

•

The sale of the Anadarko assets in the second quarter of 2026 ($36 million).

Transportation and processing expense increased $178 million compared to the first six months of 2025 primarily due to:

•

Higher production volumes due to the NuVista Acquisition in the first quarter of 2026 ($159 million), higher midstream transportation costs in Montney ($49 million), higher transportation costs in Permian due to increased gas production volumes ($13 million) and a lower U.S./Canadian dollar exchange rate ($13 million);

•

The sale of the Anadarko assets in the second quarter of 2026 ($36 million), a settlement related to a downstream transportation contract in the Canadian Operations ($19 million) and lower downstream transportation costs in Montney due to a third-party adjustment ($6 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 $36 million compared to the second quarter of 2025 primarily due to:

•

The sale of the Anadarko assets in the second quarter of 2026 ($35 million) and lower salaries and benefits resulting from the corporate reorganization during the quarter ($11 million);

•

Higher activity due to the NuVista Acquisition in the first quarter of 2026 ($9 million).

Operating expense decreased $14 million compared to the first six months of 2025 primarily due to:

•

The sales of the Anadarko assets in the second quarter of 2026 ($35 million) and lower salaries and benefits resulting from the corporate reorganization during the quarter ($11 million);

•

Higher activity due to the NuVista Acquisition in the first quarter of 2026 ($17 million), and increased workover activity in Montney and Permian ($9 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 $123 million compared to the second quarter of 2025 primarily due to:

•

Higher third-party liquids purchase prices ($205 million) and higher third-party purchased natural gas volumes ($22 million);

•

Lower third-party purchased liquids volumes ($99 million) and lower third-party natural gas purchase prices ($7 million).

Purchased product expense increased $65 million compared to the first six months of 2025 primarily due to:

•

Higher third-party liquids and natural gas purchase prices ($211 million and $14 million, respectively), and higher third-party purchased natural gas volumes ($26 million);

•

Lower third-party purchased liquids volumes ($186 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 2025 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 2025 Annual Report on Form 10-K.

DD&A decreased $37 million compared to the second quarter of 2025 primarily due to:

•

Lower production volumes in the USA Operations primarily due to the sale of the Anadarko assets in the second quarter of 2026 ($88 million);

•

Higher production volumes in the Canadian Operations primarily due to the NuVista Acquisition in the first quarter of 2026 ($43 million) and a higher depletion rate in the Canadian Operations ($9 million).

The upstream depletion rate in the USA Operations increased $0.02 per BOE primarily due to lower reserve volumes from the sale of the Anadarko assets in the second quarter of 2026, partially offset by a decrease in the depletable base resulting from the ceiling test impairment recognized in the first quarter of 2026. The upstream depletion rate in the Canadian Operations increased $0.26 per BOE primarily due to a higher depletable base resulting from the NuVista Acquisition in the first quarter of 2026, partially offset by the ceiling test impairments recognized in the first quarter of 2026 and the third quarter of 2025.

DD&A decreased $21 million compared to the first six months of 2025 primarily due to:

•

Lower production volumes in the USA Operations primarily due to the sale of the Anadarko assets in the second quarter of 2026 ($91 million), and a lower depletion rate in the USA Operations ($35 million);

•

Higher production volumes in the Canadian Operations primarily due to the NuVista Acquisition in the first quarter of 2026 ($102 million) and a lower U.S./Canadian dollar foreign exchange rate ($8 million).

The upstream depletion rate in the USA Operations decreased $0.70 per BOE primarily due to a lower depletable base resulting from the ceiling test impairment recognized in the first quarter of 2026, partially offset by the lower reserve volumes resulting from the sale of the Anadarko assets in the second quarter of 2026. The upstream depletion rate in the Canadian Operations increased $0.12 per BOE primarily due to a higher depletable base resulting from the NuVista Acquisition in the first quarter of 2026, partially offset by the ceiling test impairments recognized in the first quarter of 2026 and the third 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 of 2026, the Company did not recognize ceiling test impairments in the USA and Canadian Operations. In the first six months of 2026, the Company recognized before-tax non-cash ceiling test impairments of $1,485 million, comprising $1,111 million in the USA Operations and $374 million in the Canadian Operations. The non-cash ceiling test impairments recognized in the first quarter of 2026 primarily resulted from declines in the 12-month average trailing prices which reduced proved reserves in the USA Operations, and the 12-month average trailing prices used in the ceiling test at March 31, 2026, which were lower than the market prices used for the NuVista Acquisition on February 3, 2026, in the Canadian Operations.

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.

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 10 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, transaction, restructuring and long-term incentive costs.

(1)

The second quarter and first six months of 2026 includes costs related to The Bow office lease of $28 million and $57 million, respectively (2025 - $26 million and $54 million, respectively), half of which is recovered from sublease revenues.

Administrative expense increased $50 million compared to the second quarter of 2025 primarily due to:

•

Higher restructuring costs ($44 million).

Administrative expense increased $69 million compared to the first six months of 2025 primarily due to:

•

Higher restructuring costs ($34 million) and transaction costs incurred related to the NuVista Acquisition ($23 million).

In 2024, Ovintiv undertook a plan, which extended into 2025, to reduce its workforce by approximately 10 percent as part of a corporate reorganization. In 2026, the Company completed further workforce reductions as part of a company-wide reorganization to better align staffing levels and organizational structure with the Company’s transformed portfolio following the sale of the Anadarko assets. Additional information on the NuVista Acquisition, restructuring charges and long-term incentive costs can be found in Notes 9, 17 and 18, respectively, 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 12, respectively, to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Interest expense increased $5 million compared to the second quarter of 2025 primarily due to:

•

A one-time make-whole interest payment resulting from the early redemption of the Company’s $700 million senior notes during the quarter ($20 million);

•

Interest savings related to the repayment of the Company’s $700 million senior notes during the quarter, its $459 million senior notes in the first quarter of 2026 and its $600 million senior notes in the second quarter of 2025 ($18 million).

Interest expense increased $12 million compared to the first six months of 2025 primarily due to:

•

A one-time make-whole interest payment resulting from the early redemption of the Company’s $700 million senior notes during the quarter ($20 million), higher interest expense on short-term borrowings and the Term Credit Agreement ($11 million) and higher interest expense on finance leases ($4 million);

•

Interest savings related to the repayment of the Company’s $700 million senior notes during the quarter, its $459 million senior notes in the first quarter of 2026 and its $600 million senior notes in the second quarter of 2025 ($33 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 increased $1 million compared to the second quarter of 2025 primarily due to:

•

Unrealized foreign exchange losses on the translation of intercompany notes in 2026 ($30 million);

•

Gains on other monetary revaluations compared to losses in 2025 ($27 million).

Net foreign exchange loss decreased $11 million compared to the first six months of 2025 primarily due to:

•

Realized foreign exchange losses on the settlement of U.S. dollar risk management contracts issued from Canada in 2025 ($98 million), gains on other monetary revaluations compared to losses in 2025 ($26 million) and lower unrealized foreign exchange losses on the translation of intercompany notes ($12 million);

•

Lower unrealized foreign exchange gains on the translation of U.S. dollar risk management contracts issued from Canada ($83 million) and realized foreign exchange losses on the settlement of intercompany notes compared to gains in 2025 ($42 million).

(Gain) Loss on Divestitures, Net

During the second quarter and first six months of 2026, the Company recognized a before-tax loss on the sale of the Company’s Anadarko assets of $337 million, respectively, as discussed in the Significant Developments section of this MD&A.

Amounts received from the Company’s divestiture transactions are deducted from the respective U.S. and Canadian full cost pools, except for divestitures that result in a significant alteration between capitalized costs and proved reserves in a country cost center, in which case a gain or loss is recognized. Additional information on the loss on divestiture can be found in Note 8 to the Consolidated Financial Statements included in Part I, Item 1 of this Quarterly Report on Form 10-Q.

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 and adjustments related to other assets.

In the first quarter of 2026, the Company recognized a gain of approximately $25 million resulting from the fair value remeasurement of the previously acquired 18.5 million NuVista common shares in conjunction with the closing of the NuVista Acquisition.

Income Tax

During the first six months of 2026, the current income tax expense of $35 million was lower than 2025 primarily due to recently enacted Canadian legislation that accelerates capital cost recovery and favorable changes in the calculation of Corporate Alternative Minimum Tax in the U.S.

During the first six months of 2026, the deferred income tax recovery of $149 million was higher than 2025, primarily due to the impact of the non-cash ceiling test impairment recognized in the U.S. in the first quarter of 2026.

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.

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.