Exhibit 3.10

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2025 AND 2024

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following management’s discussion and analysis (“MD&A”) of the financial condition and results of operations for Strathcona Resources Ltd. (the “Company” or “Strathcona”) is dated August 7, 2025 and should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (and related notes) as at and for the three and six months ended June 30, 2025 and 2024 (the “interim financial statements”) and the Company's audited consolidated financial statements as at and for the years ended December 31, 2024 and 2023 (the "annual financial statements"). The interim financial statements have been prepared in accordance with IFRS® Accounting Standards (the “Accounting Standards”) as issued by the International Accounting Standards Board, in Canadian dollars, except where indicated otherwise. The interim financial statements, annual financial statements, and MD&A of Strathcona have been prepared by management, reviewed by the Audit Committee of the Company's Board of Directors and were approved by the Company’s Board of Directors.

This MD&A contains forward looking information; see “Forward-Looking Information” in this MD&A for further information. The following MD&A also contains financial measures that do not have a standardized meaning under the Accounting Standards and may not be comparable to similar financial measures disclosed by other issuers; see “Specified Financial Measures” in this MD&A for further information. This MD&A contains certain oil and gas metrics and measures; see “Advisories Regarding Oil & Gas Information” at the end of this MD&A.

All dollar amounts are referenced in Canadian dollars and, in the case of amounts presented in tabular form, in millions of Canadian dollars, in each case except when noted otherwise. All per unit figures are based on commodity sales volumes, net of blending. Sales volumes differ from production volumes as a result of changes in oil inventory.

DESCRIPTION OF BUSINESS

Strathcona is a corporation that exists under, and is governed by, the provisions of the Business Corporations Act (Alberta) (the “ABCA”). Strathcona's common shares are listed on the TSX under the trading symbol "SCR".

At June 30, 2025, approximately 79.6% of the Company's common shares were owned by certain entities comprising Waterous Energy Fund and its affiliates (collectively "WEF").

RECENT DEVELOPMENTS

During the three months ended June 30, 2025 the Company entered into three separate asset purchase and sale agreements to dispose of its Montney segment. The Montney segment represents a separate major line of business and geographical area of operations, therefore, its results have been classified as discontinued operations in accordance with IFRS 5 Non-Current Assets Held for Sale and Discontinued Operations.

Groundbirch Asset Sale

On June 1, 2025 the Company completed the disposition of assets located primarily in the Groundbirch area in Northeast British Columbia (the “Groundbirch Asset Sale”) for aggregate proceeds of $291.6 million, inclusive of interim closing adjustments, paid in common shares of Tourmaline Oil Corp. An associated gain on sale of assets of $138.3 million was recognized on close of the transaction.

Kakwa and Grande Prairie Asset Sales

On May 14, 2025, the Company entered into asset purchase and sale agreements pursuant to which the Company agreed to sell assets primarily located in the Kakwa and Grande Prairie areas in Northwest Alberta (the "Kakwa and Grande Prairie Asset Sales"). On July 2, 2025, the Company completed the Kakwa and Grande Prairie Asset Sales for total cash consideration of $2,426.7 million, inclusive of interim closing adjustments. The carrying value of the associated assets and liabilities at June 30, 2025 was $1,802.4 million.

Based on preliminary accounting, the total combined estimated gain on sale of assets for the three disposition packages is expected to be approximately $760 million, before final closing adjustments.

The Company continues to assess the preferred use of proceeds from the sale of the Montney assets, including the potential payment of a distribution to Strathcona's shareholders. Any such distribution will be at the sole discretion of the board of directors of Strathcona. There are numerous factors that the board of directors may consider in determining whether or not to proceed with any such distribution, including, among others, factors such as Strathcona’s free cash flow, operating results, capital requirements, financial position, debt levels, market conditions, corporate strategy, requirements under the Company's debt arrangements, the success of the MEG Offer (as defined below) and applicable laws.

Offer to Acquire MEG Energy Corp.

On May 30, 2025, Strathcona formally commenced an offer (the "MEG Offer") to acquire all of the issued and outstanding common shares (the "MEG Shares") of MEG Energy Corp. ("MEG") not already owned by the Company or its affiliates, together with the associated rights issued and outstanding under the shareholder rights plan of MEG. Upon acceptance of the MEG Offer, each holder of MEG Shares whose MEG Shares are taken up by Strathcona will be entitled to receive, for each MEG Share, 0.62 of a Common Share and $4.10 in cash, subject to the terms and conditions of the MEG Offer, as set forth in the MEG Offer to Purchase and accompanying Take-Over Bid Circular dated May 30, 2025, available on Strathcona's website and under the Company’s profile on SEDAR+ at www.sedarplus.ca. The MEG Offer is open for acceptance until 5:00 p.m. (Mountain Time) on Monday, September 15, 2025, unless extended, accelerated or withdrawn by the Company in accordance with its terms.

In connection with the MEG Offer, on May 29, 2025, certain limited partnerships comprising Waterous Energy Fund III ("WEF III") committed to subscribe for and purchase 21.4 million subscription receipts of the Company ("Subscription Receipts") at a price of $30.92 per Strathcona Subscription Receipt (the "WEF III Equity Investment"). On June 27, 2025, the Company entered into a subscription receipt agreement with WEF III (the "Subscription Receipt Agreement") relating to the WEF III Equity Investment and issued 21.4 million Subscription Receipts to WEF III for aggregate gross proceeds of $661.7 million which were placed into escrow. See "Subscription Receipts" section in this MD&A.

If the MEG Offer is successful and the Company completes a second stage transaction to acquire all of the MEG Shares not already owned or acquired pursuant to the MEG Offer, the Company expects to issue approximately 145 million common shares (or 143 million common shares assuming all treasury settled incentive awards of MEG are settled in cash), for MEG Shares deposited or otherwise acquired thereunder. The Company anticipates that an aggregate of approximately 381 million common shares (or 379 million common shares, assuming all treasury-settled incentive awards of MEG are settled in cash) will be issued and outstanding following completion of the MEG Offer or second stage transaction, if applicable, and the WEF III Equity Investment. The Company expects to fund aggregate cash consideration of approximately $957.8 million (or approximately $947.1 million assuming all treasury settled incentive awards of MEG are settled in cash) payable under the MEG Offer or second stage transaction, if applicable, through a combination of a draw down on the Credit Facilities (as defined in the "Capital Resources" section of this MD&A) and using the proceeds from the WEF III Equity Investment.

If the MEG Offer is successful and a second stage transaction, if applicable, is completed, WEF, following completion of the WEF III Equity Investment, is expected to own, or control or direct, approximately 51% of the issued and outstanding common shares.

On June 6, 2025, the TSX approved the conditional listing of 147.9 million common shares issuable pursuant to the MEG Offer and 21.4 million common shares issuable upon the conversion of the Subscription Receipts issued pursuant to the WEF III Equity Investment.

On June 20, 2025, the Company received a No-Action Letter from the Commissioner of Competition (the "Commissioner") under the Competition Act (Canada) (the "Competition Act") indicating that the Commissioner does not, at that time, intend to challenge the MEG Offer by making an application to the Competition Tribunal under Section 92 of the Competition Act, while reserving the Commissioner's statutory right to challenge the transaction before the Competition Tribunal at any time within one year of the MEG Offer being completed.

On July 3, 2025, the waiting period under the United States Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the "HSR Act") expired in respect of the MEG Offer and Strathcona is therefore entitled under the HSR Act to complete the MEG Offer.

GUIDANCE

Strathcona's 2025 production guidance is unchanged at the mid-point but is now set within a revised range of 152 to 158 Mboe per day, compared to the prior range of 150 to 160 Mboe per day. The Company’s 2025 capital budget of $1.2 billion remains unchanged.

PRESENTATION OF CONTINUING AND DISCONTINUED OPERATIONS

The financial results for the three and six months ended June 30, 2025 and June 30, 2024, are presented below to reconcile continuing and discontinued operations to total results. Total results is a non-GAAP measure which does not have a standardized meaning under the Accounting Standards and may not be comparable to similar financial measures disclosed by other issuers. Total results is used by Management to assess the historical financial performance of the total business and is not intended to be indicative of future results of the Company.

PRODUCTION VOLUMES

Production volumes from continuing operations decreased 2% (or 1,999 boe per day) for the three months ended June 30, 2025 to an average of 108,926 boe per day compared to 110,925 boe per day for the same period of 2024. The decrease was primarily due to a planned turnaround at Tucker within the Cold Lake segment.

Production volumes from continuing operations increased 1% (or 789 boe per day) for the six months ended June 30, 2025 to an average of 112,373 boe per day compared to 111,584 boe per day for the same period of 2024. The increase is primarily due to the performance of new Tucker wells drilled as part of the Company’s capital program, partially offset by decreased volumes from a planned turnaround at Tucker within the Cold Lake segment.

Production volumes from continuing operations decreased 6% (or 6,933 boe per day) during the three months ended June 30, 2025 to an average of 108,926 boe per day compared to 115,859 boe per day for the three months ended March 31, 2025. The decrease was primarily due to a planned turnaround at Tucker within the Cold Lake segment.

SALES VOLUMES

Sales volumes typically trend with production volumes, except in cases of an inventory build or draw. Strathcona carries inventory on rail cars in transit to the US Gulf Coast, on pipelines and in storage tanks.

In the fourth quarter of 2024 and the first quarter of 2025, the Company had a build up of heavy oil inventory related to volumes transported by rail due to weather conditions which resulted in congestion at major rail hubs. This inventory was sold in the second quarter with inventory volumes associated with continuing operations at June 30, 2025 having been reduced.

BUSINESS ENVIRONMENT

WTI crude oil prices declined during the second quarter of 2025, with average prices decreasing by 11% compared to the first quarter of 2025. Early in the quarter, oil benchmarks experienced downward pressure due to subdued demand and increased supply, as global crude inventories exceeded typical seasonal levels and OPEC+ indicated intentions to raise production beginning in July. Additionally, decelerating economic growth in China and renewed concerns regarding the U.S.–China trade relationship further dampened market sentiment.

The WTI–WCS Hardisty differential continued to narrow during the second quarter of 2025, remaining at historically tight levels. This sustained strength in Canadian heavy oil pricing was supported by the full-period operation of the Trans Mountain Pipeline Expansion, which alleviated transportation constraints that previously led to significant price discounts at Hardisty. Maintenance activities and scheduled oil sands turnarounds in the first half of 2025 reduced bitumen production volumes, temporarily tightening supply and contributing to the narrower differential. Western Canadian crude inventories remained below the five-year range, driven by robust refinery demand and improved transportation capacity, thereby supporting WCS prices. Globally, OPEC+ production cuts and stricter sanctions on other heavy crude producers elevated the value of heavy sour crude relative to lighter grades.

At the U.S. Gulf Coast, the WTI–WCS differential also narrowed in the second quarter of 2025. The reduction in Venezuelan and Mexican heavy crude supplies, coupled with low Gulf Coast inventories and strong refining demand, resulted in WCS achieving a stronger price position relative to WTI.

AECO 5A natural gas prices decreased in the second quarter of 2025, primarily due to a mild winter and ample storage levels.

REVENUE AND REALIZED PRICES

Oil and Natural Gas Sales – Net of Blending

Oil and natural gas sales, net of blending from continuing operations, decreased 23% (or $212.4 million) for the three months ended June 30, 2025 to $731.2 million compared to $943.7 million in the same period of 2024. This decrease was primarily due to weaker oil benchmark pricing and lower sales volumes, partially offset by decreased blending costs due to lower condensate benchmark pricing.

Oil and natural gas, net of blending from continuing operations, decreased 6% (or $108.9 million) for the six months ended June 30, 2025 to $1,581.0 million compared to $1,689.9 million for the same period in 2024. This decrease was primarily due to weaker oil benchmark pricing, partially offset by decreased blending costs due to lower condensate benchmark pricing.

Oil and natural gas sales, net of blending from continuing operations, decreased 14% (or $118.6 million) for the three months ended June 30, 2025 to $731.2 million compared to $849.8 million in the three months ended March 31, 2025. This decrease was primarily due to lower sales volumes and weaker oil benchmark pricing, partially offset by decreased blending costs due to lower condensate benchmark pricing.

Average Realized Prices

For three and six months ended June 30, 2025, combined realized price from continuing operations decreased 20% (or $17.98 per boe) and 7% (or $5.72 per boe) compared to the same periods of 2024. Combined realized price from continuing operations decreased 11% (or $9.14 per boe) for the three months ended June 30, 2025 compared to the three months ended March 31, 2025. These decreases were primarily due to lower average WTI benchmark prices, partially offset by narrower WCS Hardisty and USGC differentials and reduced condensate prices, which lowered per barrel blend costs.

ROYALTIES

For three and six months ended June 30, 2025, the effective royalty rate from continuing operations decreased to 13.1% from 17.8% and to 13.2% from 15.9%, respectively, compared to the same periods in 2024. These decreases reflect lower average commodity prices.

The effective royalty rate from continuing operations remained consistent at 13.1% for the three months ended June 30, 2025 compared to 13.2% for the three months ended March 31, 2025.

PRODUCTION AND OPERATING EXPENSES

Production and operating expenses from continuing operations increased 5% (or $7.8 million) for the three months ended June 30, 2025 to $180.7 million ($17.83 per boe) from $172.9 million ($16.51 per boe) in the same period of 2024. Energy costs decreased by $4.4 million ($0.23 per boe) primarily due to the purchase of carbon credits, which lowered the Company's initial estimate of the carbon tax burden compared to legislated rates, partially offset by increased fuel costs due to higher natural gas benchmark prices. Non-energy costs increased by $12.2 million ($1.55 per boe) due primarily to higher downhole and surface maintenance expenses and the addition of midstream throughput fees at the newly acquired Hardisty Rail Terminal, partially offset by a reduction in chemical expenditures.

Production and operating expenses from continuing operations increased 6% (or $19.1 million) for the six months ended June 30, 2025 to $363.1 million ($17.65 per boe) from $344.0 million ($16.80 per boe) in the same period of 2024. Energy costs decreased by $8.1 million ($0.43 per boe) primarily due to the purchase of carbon credits, which lowered the Company's initial estimate of the carbon tax burden compared to legislated rates, partially offset by increased fuel costs due to higher natural gas benchmark prices. Non-energy costs increased by $27.2 million ($1.28 per boe) primarily due to higher downhole, surface maintenance and chemical expenses and the addition of midstream throughput fees at the newly acquired Hardisty Rail Terminal.

Production and operating expenses from continuing operations decreased 1% (or $1.7 million) for the three months ended June 30, 2025 to $180.7 million ($17.83 per boe) from $182.4 million ($17.46 per boe) for the three months ended March 31, 2025. Energy production and operating costs decreased 22% (or $15.9 million) due to the purchase of carbon credits, which lowered the Company's initial estimate of the carbon tax burden compared to legislated rates and decreased fuel costs due to lower natural gas benchmark prices. Non-energy production and operating costs increased 13% (or $14.2 million) primarily due to increases in surface maintenance and the addition of midstream throughput fees at the newly acquired Hardisty Rail Terminal.

TRANSPORTATION EXPENSES

Transportation expenses from continuing operations decreased 4% (or $4.1 million) for the three months ended June 30, 2025 to $94.2 million ($9.30 per boe) compared to $98.3 million ($9.39 per boe) in the same period of 2024. Transportation expenses from continuing operations decreased 2% (or $2.9 million) for the six months ended June 30, 2025 to $182.2 million ($8.85 per boe) compared to $185.1 million ($9.04 per boe) in the same period of 2024. These decreases are primarily attributable to lower volumes sold on rail and utilization of make-up rights at the Cold Lake segment.

Transportation expenses from continuing operations increased 7% (or $6.2 million) for the three months ended June 30, 2025 to $94.2 million ($9.30 per boe) from $88.0 million ($8.42 per boe) in the three months ended March 31, 2025. This increase is due to increased volumes sold on rail and the absence of make-up rights at the Cold Lake segment for a portion of the second quarter of 2025.

DEPLETION, DEPRECIATION AND AMORTIZATION (“DD&A”)

DD&A expense from continuing operations decreased 1% (or $1.5 million) for the three months ended June 30, 2025 to $155.7 million ($15.36 per boe) compared to $157.2 million ($15.03 per boe) for the same period of 2024. This decrease was primarily due to lower sales volumes.

DD&A expense from continuing operations remained consistent for the six months ended June 30, 2025 at $303.3 million ($14.73 per boe), compared to $303.0 million ($14.80 per boe) for the same period of 2024.

DD&A expense from continuing operations increased 5% (or $8.1 million) during the three months ended June 30, 2025 to $155.7 million ($15.36 per boe) compared to $147.6 million ($14.12 per boe) for the three months ended March 31, 2025. The increase reflects a higher proportion of sales volumes from areas with a higher per barrel rate of depletion.

GENERAL AND ADMINISTRATION EXPENSES (“G&A”)

For the three and six months ended June 30, 2025 G&A expenses from continuing operations increased 11% (or $2.1 million) and 13% (or $4.5 million) compared to the same periods of 2024. G&A expenses from continuing operations increased 10% (or $1.9 million) during the three months ended June 30, 2025 compared to the three months ended March 31, 2025. The increases were primarily due to higher personnel costs resulting from the growth of the business and the internal corporate re-organization completed in the fourth quarter of 2024 as well as increased information technology costs.

INTEREST

For the three months ended June 30, 2025, interest expense increased 5% (or $2.1 million) to $45.8 million compared to $43.7 million in the same period of 2024. Interest expense increased 19% (or $7.4 million) for the three months ended June 30, 2025 to $45.8 million compared to $38.4 million for the three months ended March 31, 2025. The increases were primarily due to higher debt levels.

For the six months ended June 30, 2025, interest expense decreased 5% (or $4.9 million) to $84.2 million compared to $89.1 million in the same period of 2024. The decrease was primarily due to lower interest rates in 2025 compared to 2024.

During the six months ended June 30, 2025, the Company recorded $24.2 million in interest expense on the Senior Notes (as defined in the “Capital Resources” section of this MD&A) (June 30, 2024 – $23.4 million), and $59.8 million in interest expense on the Credit Facilities (June 30, 2024 - $79.9 million), and a realized loss of $0.2 million on interest rate swaps (June 30, 2024 - realized gain of $14.2 million).

The impact of changes in interest rates is partially mitigated through interest rate swaps, see the “Risk Management - Market Risk - Interest Rate Risk” section of this MD&A.

FINANCE COSTS

Finance costs from continuing operations for the three months ended June 30, 2025 increased 18% (or $2.3 million) to $14.8 million compared to $12.5 million for the same period of 2024. Finance costs from continuing operations increased 13% (or $3.2 million) to $27.1 million for the period ended June 30, 2025 compared to $23.9 million in the same period of 2024. The increases were primarily due to an increase in the credit adjusted rate used to accrete the decommissioning provision from 8% to 10%.

TAX POOLS

As at June 30, 2025, the Company had approximately $5,242.6 million (December 31, 2024 - $5,595.4 million) of tax pools available for deduction in future periods as shown in the table below.

RISK MANAGEMENT

The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production and financing activities. These risks include credit risk, liquidity risk and market risk.

Credit Risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations. This will arise principally from outstanding receivables related to oil and natural gas customers, counterparties with which financial derivative contracts are held, and joint interest partners.

On entering into any business contract, the extent to which the arrangement exposes the Company to credit risk is considered. The Company’s policy to mitigate credit risk associated with these balances is to establish relationships with reputable counterparties, review the financial capacity of its counterparties, request prepayment as deemed advisable and, in certain circumstances, the Company may seek enhanced credit protection from a counterparty or purchase accounts receivable insurance.

Market Risk

Market risk is the risk that the future fair value or cash flows of a financial instrument will fluctuate due to changes in market prices. Market risk is comprised of commodity price risk, foreign exchange risk and interest rate risk. The Company uses financial risk management contracts to reduce volatility in financial results and to ensure a certain level of cash flow to fund planned capital projects.

Commodity Price Risk

The Company’s operational results and financial condition are largely dependent on the commodity price received for oil and natural gas production. Commodity prices have fluctuated widely in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, weather, economic and geopolitical factors. The Company uses financial derivative instruments and other commodity derivative mechanisms to help limit the adverse effects of commodity price volatility. However, the Company does not have commodity contracts in place for all its production and expects there will always be a portion that remains unhedged. Furthermore, the Company may use financial derivative instruments that offer only limited protection within selected price ranges. To the extent price exposure is hedged, the Company may forego the benefits that would otherwise be experienced if commodity prices increase.

The following table summarizes the Company’s commodity contracts outstanding as at August 6, 2025.

Foreign Exchange Risk

The Company is exposed to fluctuations of the CAD to USD exchange rate given commodity pricing is directly influenced by USD denominated benchmark pricing. In addition, the Company periodically borrows from its Credit Facilities in USD and the Senior Notes are denominated in USD. The Company actively manages foreign exchange risk using foreign exchange derivatives.

The following table summarizes the Company’s foreign exchange contract on revenues as at the date of this MD&A.

The following table summarizes the Company’s foreign exchange contract on the Senior Notes as at the date of this MD&A.

Interest Rate Risk

The Company is exposed to movements in floating interest rates on the Credit Facilities. The Company is not exposed to interest rate risk on the Senior Notes or other liabilities as they bear a fixed interest rate.

The following table summarizes the Company’s risk management contracts in place to fix interest rates as at the date of this MD&A.

For a listing of the Company’s commodity contracts, foreign exchange and interest rate contracts outstanding as at June 30, 2025 refer to Note 15 in the interim financial statements.

Refer to the “Capital Resources” section of this MD&A for information on the Company’s cross-currency interest rate swaps related to debt.

The following table summarizes the Company’s gains and losses on risk management contracts.

Strathcona realized a loss on risk management contracts of $4.6 million for the three months ended June 30, 2025, compared to a loss of $11.4 million for the same period in 2024. The Company realized a loss on risk management contracts of $5.5 million for the six months ended June 30, 2025, compared to a loss of $6.9 million for the same period in 2024. The realized losses are due to realized commodity benchmark prices in comparison to contracted hedge pricing.

As at June 30, 2025, the mark-to-market value of risk management contracts was a net liability of $93.9 million (December 31, 2024 - net liability of $40.7 million). Unrealized gains and losses represent the change in the mark-to-market values of these contracts due to the fluctuation of forward commodity prices, exchange rates and interest rates. The significant assumptions made in determining the fair value of financial instruments are disclosed in Note 15 to the interim financial statements.

MARKETABLE SECURITIES

The following table summarizes the Company's marketable securities as at June 30, 2025:

Marketable securities represent equity interests in publicly-traded companies that the Company has acquired either through open market transactions or as consideration in the Groundbirch Asset Sale.

During the three and six months ended June 30, 2025, the Company recognized a gain on marketable securities of $24.6 million and $47.3 million, respectively (for the three and six months ended June 30, 2024 - nil). The Company recognized dividend income for the three and six months ended June 30, 2025 of $4.7 million and $5.8 million, respectively (for the three and six months ended June 30, 2024 - nil).

CAPITAL EXPENDITURES

The following table summarizes the Company’s capital expenditures by category.

For the three months ended June 30, 2025, drilling, completion and equipping activities accounted for 57% of capital expenditures as the Company drilled 54 new wells during the second quarter of 2025; 17 in Cold Lake, 33 in Lloydminster and 4 in Montney. For the six months ended June 30, 2025, drilling, completion and equipping activities accounted for 57% of capital expenditures as the Company drilled 125 new wells during the year; 30 at Cold Lake, 82 in Lloydminster and 13 in Montney. For three and six months ended June 30, 2025, facilities and pipeline expenditures accounted for 36% and 35% of capital expenditures, respectively, and relate primarily to the construction of the Meota Central processing facility, the turnaround at Tucker, and one-time steam generation expansion and debottlenecking at Lindbergh.

FOREIGN EXCHANGE

Foreign exchange for the three months ended June 30, 2025 resulted in a gain of $39.5 million compared to a loss of $6.9 million and a gain of $1.0 million for the three months ended June 30, 2024 and March 31, 2025, respectively. For the six months ended June 30, 2025, foreign exchange resulted in a gain of $40.5 million compared to a loss of $27.3 million in the same period of 2024. The foreign exchange gains and losses are driven by the CAD/USD exchange rate applied to U.S. dollar denominated debt balances net of cross-currency swaps.

SEGMENT RESULTS

The Chief Operating Decision Makers ("CODMs") of the Company are comprised of the Chief Financial Officer, Chief Operating Officer and Chief Commercial Officer. The CODMs review and evaluate the Company's performance, and have identified two operating segments based on the similarity of services and goods provided and economic characteristics exhibited by the operating segments. The two operating segments are:

The Company reports activities not directly attributable to an operating segment under Corporate and Midstream, which includes the Hardisty Rail Terminal.

The following tables present the financial performance by reportable segment and include a measure of segment profit or loss regularly reviewed by CODMs for the noted periods ended June 30, 2025 and 2024. Certain comparative information related to finance costs and general and administrative costs have been allocated by segment to conform with current period presentation. For the year ended December 31, 2024, Field Operating Earnings was used by the CODMs to evaluate segment profit or loss. Operating Earnings was used by the CODMs commencing for the period ended March 31, 2025.

See the "Recent Developments" and "Discontinued Operations" sections in this MD&A for information regarding the sale of the Company's Montney segment.