Ovintiv Inc

Results of Operations

Selected Financial Information

(1)

In conjunction with the Segment Reclassification as discussed in the Highlights section of this MD&A, prior period results have been reclassified for comparative purposes.

(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.

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. See Notes 8 and 9 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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

(1)

Revenues for 2023 exclude certain other revenue and royalty adjustments with no associated production volumes of $1 million.

(2)

In conjunction with the Segment Reclassification as discussed in the Highlights section of this MD&A, prior period results have been reclassified for comparative purposes.

Oil Revenues

Oil revenues were higher by $112 million compared to 2023 primarily due to:

•

Higher average oil production volumes of 9.4 Mbbls/d increased revenues by $279 million. Higher volumes were primarily due to the Permian assets acquired in the second quarter of 2023 (21.1 Mbbls/d) and successful drilling in Uinta (7.5 Mbbls/d), partially offset by the sale of the Bakken assets in the second quarter of 2023 (9.3 Mbbls/d) and natural declines in Anadarko (8.7 Mbbls/d); and

•

A decrease of $2.56 per bbl, or three percent, in the average realized oil prices which decreased revenues by $167 million. The decrease reflected lower WTI and Houston benchmark prices which were both down two percent and the lower regional pricing relative to benchmark prices.

NGL Revenues

NGL revenues were higher by $24 million compared to 2023 primarily due to:

•

An increase of $1.48 per bbl, or eight percent, in the average realized other NGL prices which increased revenues by $51 million. The increase reflected higher other NGL benchmark prices and higher regional pricing; and

•

A decrease of $2.18 per bbl, or three percent, in the average realized plant condensate prices which decreased revenues by $31 million. The decrease reflected the lower Edmonton Condensate benchmark price which was down three percent.

Natural Gas Revenues

Natural gas revenues were lower by $590 million compared to 2023 primarily due to:

•

A decrease of $1.04 per Mcf, or 38 percent, in the average realized natural gas prices which decreased revenues by $650 million. The decrease reflected lower AECO, NYMEX and Dawn benchmark prices which were down 51 percent, 17 percent and 11 percent, respectively, and lower regional pricing relative to benchmark prices in the USA Operations; and

•

Higher average natural gas production volumes of 56 MMcf/d increased revenues by $60 million. Higher volumes were primarily due to successful drilling in Permian and Montney (73 MMcf/d), lower effective royalty rates resulting from lower commodity prices in Montney (46 MMcf/d), and the Permian assets acquired in the second quarter of 2023 (12 MMcf/d). The higher production volumes were partially offset by the sale of the Bakken assets in the second quarter of 2023 (23 MMcf/d), the shut-in of production in Other Canadian Operations in 2024 due to low commodity prices (20 MMcf/d), natural declines in Anadarko (17 MMcf/d), and third-party plant outages in Montney and Permian (15 MMcf/d).

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 December 31, 2024 can be found in Note 25 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

The following table provides the effects of the Company’s risk management activities on revenues.

(1)

Other primarily includes realized gains or losses 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. Additional information on fair value changes can be found in Note 24 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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.

(1)

In conjunction with the Segment Reclassification as discussed in the Highlights section in this MD&A, prior period results have been reclassified for comparative purposes.

Sales of purchased product decreased $1,264 million compared to 2023 primarily due to:

•

Lower sales of third-party purchased volumes in the USA Operations ($1,170 million) and lower natural gas benchmark prices ($114 million);

•

Higher realized third-party prices on sales of purchased oil volumes ($20 million).

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 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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 $9 million compared to 2023 primarily due to:

•

The sale of the Bakken assets in the second quarter of 2023 ($26 million), lower production volumes in Anadarko ($18 million), lower production tax rates ($9 million) and lower natural gas commodity prices ($6 million);

•

Higher volumes in Permian and Uinta ($42 million) and higher property taxes in Permian primarily due to the assets acquired in the second quarter of 2023 ($11 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)

Other includes pipeline transportation fees associated with previously divested assets in the USA Operations of approximately $50 million (2023 - $136 million) and other third-party transportation and processing fees in the Canadian Operations of approximately $36 million (2023 - $27 million).

Transportation and processing expense decreased $127 million compared to 2023 primarily due to:

•

An expired pipeline transportation contract ($86 million), the impact of new downstream contracts in Uinta ($53 million), the sale of the Bakken assets in the second quarter of 2023 ($46 million), lower flow-through rates in Montney ($20 million), lower production volumes in Anadarko ($18 million), a higher U.S./Canadian dollar exchange rate ($17 million), the shut-in of production in Other Canadian Operations in 2024 due to low commodity prices ($11 million) and lower variable contract rates in Permian ($4 million);

•

Higher volumes in Permian, Uinta and Montney ($87 million), increased minimum volume commitments associated with certain gathering and processing assets in Montney ($20 million) and higher downstream transportation costs in Montney ($12 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.

(1)

Other includes indirect internal costs of $11 million and $12 million in the USA and Canadian Operations, respectively (2023 - $14 million and $14 million, respectively).

Operating expense increased $72 million compared to 2023 primarily due to:

•

Higher activity in Permian primarily related to the assets acquired in the second quarter of 2023 ($98 million), updates to operating contract terms, including a recovery of prior years’ costs in 2023 ($31 million), increased activity in Uinta primarily due to workovers ($10 million) and lower capitalization of directly attributable internal costs in Montney ($8 million);

•

The sale of the Bakken assets in the second quarter of 2023 ($41 million) and decreased activity in Anadarko ($24 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 decreased $1,269 million compared to 2023 primarily due to:

•

Lower third-party purchased volumes in the USA Operations ($1,169 million) and lower natural gas benchmark prices ($119 million);

•

Higher purchase prices on third-party oil volumes ($19 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 this 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 this MD&A.

DD&A increased $465 million compared to 2023 primarily due to:

•

Higher depletion rates and production volumes in the USA Operations ($384 million and $68 million, respectively).

The depletion rate in the USA Operations increased $3.04 per BOE compared to 2023 primarily due to a higher depletable base.

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 2024, the Company recognized a before-tax non-cash ceiling test impairment of $450 million in the Canadian Operations. The non-cash ceiling test impairment primarily resulted from the decline in the 12-month average trailing prices, which reduced proved reserves.

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.

Further declines in the 12‑month average trailing commodity prices could further 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. Moreover, acquisitions of oil and natural gas assets are transacted at market prices, which may be higher than the SEC average trailing prices at the reporting date and could result in the recognition of a ceiling test impairment. 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.

On January 31, 2025, the Company closed its previously announced Montney Acquisition, as discussed in the Significant Developments and Subsequent Events section of this MD&A. The acquisition was recognized at its purchased value using market prices. On March 31, 2025, when Ovintiv performs its required ceiling test for the Canadian cost center, the Company expects the 12-month average trailing prices used in the ceiling test calculation to be lower than the market prices used in the valuation of the Montney Acquisition. Accordingly, the Company expects to recognize an after-tax impairment in the Canadian cost center between approximately $400 million to $600 million for the three months ended March 31, 2025. No impairment is expected in the U.S. cost center.

The additional estimated after-tax ceiling test impairment is not expected to impact proved undeveloped reserves for the Canadian Operations. Due to uncertainties in estimating proved reserves, the additional after-tax ceiling test impairment described above and resulting implications may not be indicative of Ovintiv’s future development plans, operating or financial results.

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 Item 8 of this Annual Report on Form 10-K.

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)

Includes costs related to The Bow office lease of $116 million (2023 - $114 million), half of which is recovered from sublease revenues.

Administrative expense decreased $28 million compared to 2023 primarily due to:

•

Transaction costs incurred mainly related to the Permian assets acquired in the second quarter of 2023 ($83 million);

•

Restructuring costs incurred in 2024 ($27 million), higher long-term incentive costs resulting from changes in the Company’s share price in 2023 ($18 million), and increases in travel and legal costs ($9 million).

In October 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 21 and 22 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Other (Income) Expenses

Interest

Interest expense primarily includes interest on Ovintiv’s short-term and long-term debt. Additional information on changes in interest can be found in Note 4 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Interest expense increased $57 million compared to 2023 primarily due to:

•

Interest expense related to the senior unsecured notes issued in May 2023 ($57 million) and bridge loan financing fees related to the Montney Acquisition as discussed in the Highlights section in this MD&A ($12 million);

•

Decreased amounts drawn from the Company’s short-term borrowings ($9 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 Notes 5 and 25 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Additional information on foreign exchange rates and the effects of foreign exchange rate changes can be found in Item 7A of this Annual Report on Form 10-K.

Net foreign exchange gain of $19 million compared to a loss of $19 million in 2023 primarily due to:

•

Unrealized foreign exchange gains on the translation of intercompany notes compared to losses in 2023 ($71 million), realized foreign exchange gains on the settlement of intercompany notes compared to losses in 2023 ($49 million) and gains on other monetary revaluations compared to losses in 2023 ($26 million);

•

Unrealized foreign exchange losses on the translation of U.S. dollar risk management contracts issued from Canada compared to gains in 2023 ($112 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, proceeds related to previously divested assets and adjustments related to other assets.

During 2024, the Company received settlement proceeds of approximately $156 million related to the previous dispositions of certain legacy assets. Accordingly, the Company recognized total net proceeds of $156 million as a gain within Other (gains) losses, net. Additional information on the net settlement proceeds can be found in Note 8 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Other gains in 2024 also includes interest income of $7 million primarily generated from short-term investments (2023 ‑ $11 million).

Income Tax

In 2024, current income tax expense in the U.S. of $8 million is lower than 2023 primarily due to the impact of the corporate alternative minimum tax and lower state income tax expense. In Canada, the current income tax expense in 2024 of $74 million is lower than 2023 primarily due to the recognition of prior year deferred income in 2023.

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 June 20, 2024, Canada enacted its Global Minimum Tax Act (“GMTA”), which implements the Organization for Economic Cooperation and Development Pillar II framework, providing a global minimum tax rate of 15 percent. The GMTA did not have a material impact to the Company’s Consolidated Financial Statements in 2024.

Additional information on income taxes can be found in Note 6 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.