Exhibit 3.5

 

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE MONTHS ENDED MARCH 31, 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 May 15, 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 months ended March 31, 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; see “Non-GAAP financial Measures and Ratios” 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. Refer to the “Segment Results” section of this MD&A for additional information.

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 ("Common Shares") are listed on the TSX under the trading symbol "SCR".

At March 31, 2025, approximately 79.6% of the Company's Common Shares were owned by certain entities comprising Waterous Energy Fund (collectively "WEF").

RECENT DEVELOPMENTS

Montney Dispositions

Subsequent to March 31, 2025 the Company entered into three separate asset purchase and sale agreements to dispose of substantially all of the assets in its Montney segment (together, the "Montney Dispositions").

Groundbirch Asset Sale

On May 2, 2025, the Company entered into an asset purchase and sale agreement with Tourmaline Oil Corp. ("Tourmaline") pursuant to which the Company has agreed to sell certain assets primarily located in the Groundbirch area in Northeast British Columbia (the “Groundbirch Asset Sale”) for aggregate proceeds of $291.5 million, subject to closing adjustments. Closing of the transaction is expected to occur in the second quarter of 2025, subject to receipt of regulatory approvals and the satisfaction of other customary closing conditions. The purchase price will be paid on closing in common shares of Tourmaline. The Groundbirch Asset Sale Agreement does not contain any restrictions on the Company's ability to dispose of the consideration shares.

Kakwa Asset Sale

On May 14, 2025, the Company entered into an asset purchase and sale agreement with ARC Resources Ltd. pursuant to which the Company has agreed to sell certain assets primarily located in the Kakwa area in Northwest Alberta (the “Kakwa Asset Sale”) for $1,695.0 million in total value ($1,650.0 million in cash and approximately $45.0 million in assumed lease obligations), subject to closing adjustments. Closing of the transaction is expected to occur early in the third quarter of 2025, subject to receipt of regulatory approvals and the satisfaction of other customary closing conditions.

Grande Prairie Asset Sale

On May 14, 2025, the Company entered into an asset purchase and sale agreement to sell certain assets primarily located in the Grande Prairie area in Northwest Alberta (the “Grande Prairie Asset Sale”) for $850.0 million in total value ($750.0 million

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in cash proceeds and approximately $100.0 million in assumed lease obligations), subject to closing adjustments. Closing of the transaction is expected to occur early in the third quarter of 2025, subject to receipt of regulatory approvals and the satisfaction of other customary closing conditions.

Taken together, the disposed Montney segment generated $148.9 million of operating earnings in 2024 (12% of consolidated Strathcona 2024 operating earnings, excluding interest and other corporate items) and had a YE 2024 proved net present value before-tax, discounted at 10% ("Before-Tax PV-10"), of approximately $2.3 billion (15% of total Strathcona YE 2024 proved Before-Tax PV-10), while the combined sale price represents approximately 33% of Strathcona’s current enterprise value. The table below shows the historical Montney results as at December 31, 2024 less the results of the expected dispositions.

	As at and for the year ended December 31, 2024(1)
	Consolidated			Montney Dispositions			Consolidated excl. Montney Dispositions
Production (Mboe / d)		183			72			111
% Oil and Condensate		71	%		28	%		100	%
Operating Earnings ($ millions)
Field Operating Income(2)		2,203.5			482.9			1,720.6
General and administrative		(101.1	)		(25.0	)		(76.1	)
Depletion, depreciation and amortization		(856.7	)		(278.5	)		(578.2	)
Finance costs		(38.2	)		(30.5	)		(7.7	)
Operating Earnings, excluding Corporate		1,207.5			148.9			1,058.6
Interest Expense and Other Corporate Items		(237.0	)		-			(237.0	)
Operating Earnings		970.5			148.9			821.6
Reserves (MMboe)
Proved Developed Producing Reserves ("PDP")		367			131			236
Reserve Life Index (Years)(3)		5			5			6
Proved Reserves ("1P")		1,534			365			1,169
Reserve Life Index (Years)(4)		23			14			29
Proved Plus Probable Reserves ("2P")		2,655			635			2,020
Reserve Life Index (Years)(5)		40			24			50
Before-Tax PV-10 ($ millions)
PDP		6,113			1,159			4,954
1P		14,971			2,322			12,649
2P		21,997			4,092			17,905
Total Enterprise Value (“TEV”) ($ millions)
Market Capitalization as of May 14, 2025		5,811.2						5,811.2
Debt(6)		2,461.6			2,579.1			(117.5	)
Leases and other obligations(7)		347.0			257.4			89.6
TEV(2)		8,619.8			2,836.5			5,783.3
TEV / Operating Earnings, excluding Corporate		7.1x			19.0x			5.2x
TEV / 1P Before-Tax PV-10		0.58x			1.22x			0.46x

(1)	See “2024 Segment Information” section of this MD&A.
(2)	A non-GAAP financial measure which does not have a standardized meaning under the Accounting Standards; see “Non-GAAP financial Measures and Ratios” section of this MD&A.
(3)	Calculated by dividing gross PDP reserves by 2024 production.
(4)	Calculated by dividing gross 1P reserves by 2024 production.
(5)	Calculated by dividing gross 2P reserves by 2024 production.

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(6)	Assumes cash and share disposition proceeds of $2,691.5 million are used to repay $2,579.1 million of Debt and $112.4 million of Other Obligations pertaining to an asset-backed financing agreement on certain facility processing interests.
(7)	As at December 31, 2024 approximately $145.0 million of lease liabilities were outstanding relating to the Montney segment. These liabilities transfer to the purchasers on close of each of the transactions; Strathcona will also repay $112.4 million of Other Obligations pertaining to an asset-backed financing agreement on certain facility processing interests.

Acquisition

Hardisty Rail Terminal

In the first quarter, the Company signed a definitive agreement to acquire the Hardisty Rail Terminal ("HRT") for cash consideration of $50.0 million, $45.0 million net after estimated closing adjustments. The acquisition closed on April 4, 2025. HRT, located in Hardisty Alberta, is the largest crude-by-rail terminal in Western Canada.

GUIDANCE

The Table below provides updated full-year 2025 guidance reflecting the disposition of the Montney segment.

	2025 Guidance(1)	Revised 2025 Guidance(2)(3)
Production (Mboe/d)	185 – 195	150 – 160
Capital expenditures ($ millions)	1,350	1,200

(1)  As announced on March 4, 2025 and disclosed in the Company's MD&A for the years ended December 31, 2024 and 2023.

(2)  Assumes the transaction closing dates detailed in Recent Developments section above.

(3)  Does not reflect any future acquisitions or divestments that are not otherwise described in this MD&A.

PRODUCTION VOLUMES

	Three Months Ended
	March 31, 2025		March 31, 2024		December 31, 2024
Bitumen (bbl/d)		65,016		60,150		59,732
Heavy oil (bbl/d)		50,488		51,835		50,997
Condensate and light oil (bbl/d)		20,682		19,279		20,763
Total oil production (bbl/d)		136,186		131,264		131,492
Other NGLs (bbl/d)		11,837		11,738		12,980
Natural gas (mcf/d)		279,517		252,720		256,386
Total (boe/d)		194,609		185,122		187,203
% oil and condensate		70%		71%		70%
% liquids		76%		77%		77%

Production volumes increased 5% (or 9,487 boe per day) for the three months ended March 31, 2025 to an average of 194,609 boe per day compared to 185,122 boe per day for the same period of 2024. The increase was primarily due to new wells brought on stream in the Cold Lake segment, as well as better runtimes and new wells in the Montney segment.

Production volumes increased 4% (or 7,406 boe per day) during the three months ended March 31, 2025 to an average of 194,609 boe per day compared to 187,203 boe per day for the three months ended December 31, 2024. The increase was primarily due to new wells brought on stream in the Cold Lake and Montney segments.

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SALES VOLUMES

	Three Months Ended
	March 31, 2025		March 31, 2024		December 31, 2024
Bitumen (bbl/d)		64,794		60,422		59,796
Heavy oil (bbl/d)		50,985		49,303		47,850
Condensate and light oil (bbl/d)		20,682		19,279		20,763
Total oil production (bbl/d)		136,461		129,004		128,409
Other NGLs (bbl/d)		11,837		11,738		12,980
Natural gas (mcf/d)		279,517		252,720		256,386
Total (boe/d)		194,884		182,862		184,120

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, 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 beginning of the first quarter in 2025, however, the Company experienced continued weather related disruptions throughout the remainder of the quarter resulting in inventory levels at March 31, 2025 remaining high.

At March 31, 2024, heavy oil inventory volumes on rail were high due to a delay in the commissioning of an expansion to a unit train offloading facility on the US Gulf Coast. The facility was purpose-built for Strathcona to better supply a local US Gulf Coast refiner that entered into a new crude purchase agreement with the Company at a premium to WCS Houston. The facility was fully operational in the second quarter of 2024.

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BUSINESS ENVIRONMENT

	Three Months Ended
	March 31, 2025			March 31, 2024			December 31, 2024
Benchmark Pricing
US$/bbl unless otherwise indicated
WTI(1)		71.42			76.96			70.27
WCS Hardisty(2)		58.75			57.65			57.72
WCS USGC(3)		67.74			69.89			65.69
WTI-WCS Hardisty differential		(12.67	)		(19.31	)		(12.55	)
WTI-WCS USGC differential		(3.68	)		(7.07	)		(4.58	)
NYMEX-AECO differential (US$/MMbtu)(4)		(2.41	)		(0.88	)		(1.86	)
Condensate differential(5)		(1.53	)		(4.18	)		0.39
Average Exchange rate (C$/US$)		1.4348			1.3488			1.3992
CAD$/bbl unless otherwise indicated
WTI(1)		102.47			103.81			98.30
WCS Hardisty(2)		84.30			77.77			80.75
WCS USGC(3)		97.19			94.28			91.90
AECO 5A (C$/gj)(6)		2.05			2.36			1.40
Condensate par at Edmonton		100.28			98.18			98.85
AESO weighted average pool price (C$/MWh)(7)		41.21			100.96			53.10
CORRA (%)(8)		3.05			5.03			3.83

(1)	Calendar month average of West Texas Intermediate (“WTI”) oil.
(2)	Western Canadian Select (“WCS”).
(3)	United States Gulf Coast (“USGC”).
(4)	New York Mercantile Exchange (“NYMEX”) Futures Last Day differential / Relates to the Alberta Energy Company (“AECO”) 7A Index.
(5)	Condensate / WTI differential at Edmonton.
(6)	AECO hub pricing.
(7)	Alberta Electric System Operator (“AESO”) weighted average pool prices.
(8)	Canadian Overnight Repo Rate Average (“CORRA”).

WTI crude oil prices increased 2% in the first quarter of 2025 compared to the fourth quarter of 2024 as global crude inventories remained below the five-year range. The increase in the WTI price was partially offset by U.S. President Donald Trump's threatened tariffs against global trade partners.

The WTI-WCS Hardisty differential widened by 1% in the first quarter of 2025 compared to the fourth quarter of 2024. The sustained strength in the differential was attributed to Western Canadian inventories remaining below the five-year range, bolstered by surplus egress capacity from the Trans Mountain Pipeline Expansion.

The WTI-WCS USGC differential narrowed by 20% in the first quarter of 2025 compared to the fourth quarter of 2024 due to low crude inventories in the USGC. Lower inventories were attributed to reduced imports of Mexican crude to the USGC due to production challenges. The Trump administration has also announced that Chevron’s Venezuelan production license will not be extended, which removes another source of heavy crude volumes to the USGC.

AECO 5A natural gas prices increased 46% in the first quarter of 2025 compared to the fourth quarter of 2024 due to extreme cold weather in February which drew AECO inventories below the top of the five-year range.

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REVENUE AND REALIZED PRICES

Oil and Natural Gas Sales – Net of Blending

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025			March 31, 2024			December 31, 2024
Bitumen blend		721.7			623.7			632.2
Heavy oil, blended and raw		454.1			416.5			409.9
Condensate and light oil		179.8			165.8			180.3
Other natural gas liquids		29.3			30.3			27.2
Natural gas		74.1			62.5			43.2
Oil and natural gas sales		1,459.0			1,298.8			1,292.8
Gain (loss) purchased product		(0.3	)		—			(0.5	)
Bitumen – blending cost		(281.0	)		(251.8	)		(232.6	)
Heavy oil – blending cost		(45.2	)		(42.8	)		(35.1	)
Oil and natural gas sales, net of blending(1)		1,132.5			1,004.2			1,024.6

(1) A non-GAAP financial measure which does not have a standardized meaning under the Accounting Standards; see “Non-GAAP financial Measures and Ratios” section of this MD&A.

Oil and natural gas sales, net of blending, increased 13% (or $128.3 million) for the three months ended March 31, 2025 to $1,132.5 million compared to $1,004.2 million in the same period of 2024. The increase was primarily due to higher average realized oil and natural gas prices and higher sales volumes.

Oil and natural gas sales, net of blending, increased 11% (or $107.9 million) for the three months ended March 31, 2025 to $1,132.5 million compared to $1,024.6 million in the three months ended December 31, 2024. This increase was primarily due to higher average realized prices and higher sales volumes.

Average Realized Prices

	Three Months Ended
	March 31, 2025		March 31, 2024		December 31, 2024
Bitumen blend ($/bbl)(1)(2)		75.55		67.66		72.62
Heavy oil, blended and raw ($/bbl)(1)(2)		89.11		83.29		85.05
Condensate and light oil ($/bbl)		96.60		94.50		94.39
Realized oil ($/bbl)		83.80		77.64		80.81
Other natural gas liquids ($/bbl)		27.52		28.37		22.78
Natural gas ($/mcf)		2.95		2.72		1.83
Combined ($/boe)		64.58		60.35		60.49

(1)	Realized prices are calculated using oil and natural gas sales and sales of purchased product, net of blending and purchased product.
(2)	A non-GAAP financial measure which does not have a standardized meaning under the Accounting Standards; see “Non-GAAP financial Measures and Ratios” section of this MD&A.

Combined realized price increased 7% (or $4.23 per boe) for the three months ended March 31, 2025 to $64.58 per boe compared to $60.35 per boe in the same period of 2024. The increase was primarily due to the strengthening of the WCS Hardisty and USGC benchmarks as a result of narrowed differentials and a weaker Canadian dollar.

Combined realized price increased 7% (or $4.09 per boe) for the three months ended March 31, 2025 to $64.58 per boe compared to $60.49 per boe for the three months ended December 31, 2024. The increase was primarily due to the strengthening of the WCS Hardisty and USGC benchmarks as a result of a weaker Canadian dollar and higher AECO 5A benchmark prices.

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ROYALTIES

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025			March 31, 2024			December 31, 2024
Crown royalties		108.4			99.6			188.2
Freehold royalties		6.8			8.2			6.8
Gross overriding royalties		16.4			14.4			10.5
Other royalties		6.6			4.0			3.0
Royalties		138.2			126.2			208.5
Effective royalty rate (%)(1)		12.2	%		12.6	%		20.3	%

(1) A non-GAAP financial measure which does not have a standardized meaning under the Accounting Standards; see “Non-GAAP financial Measures and Ratios” section of this MD&A.

For the three months ended March 31, 2025, the effective royalty rate was 12.2%, which is relatively unchanged compared to 12.6% for the same period in 2024.

For the three months ended March 31, 2025, the effective royalty rate was 12.2% compared to 20.3% in the three months ended December 31, 2024. This decrease was primarily attributable to a reduction in forecast pricing assumptions and timing of eligibility of capital deductions relating to projects at thermal properties.

PRODUCTION AND OPERATING EXPENSES

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025		March 31, 2024		December 31, 2024
Production and operating – Energy		75.7		78.8		58.7
Production and operating – Non-energy		155.5		135.4		138.5
Production and operating expenses		231.2		214.2		197.2
Production and operating – Energy ($/boe)		4.32		4.74		3.46
Production and operating – Non-energy ($/boe)		8.87		8.14		8.18
Production and operating expenses ($/boe)		13.19		12.88		11.64

Production and operating expenses increased 8% (or $17.0 million) for the three months ended March 31, 2025 to $231.2 million ($13.19 per boe) from $214.2 million ($12.88 per boe) in the same period of 2024. Energy costs decreased by $3.1 million ($0.42 per boe) primarily due to lower natural gas and power benchmark prices. These reductions are partially offset by an increase in carbon taxes impacting the Cold Lake segment. Non-energy costs increased by $20.1 million ($0.73 per boe) primarily due to increased surface maintenance and higher chemical costs as a result of sulphur recovery units installed in the first quarter of 2024, which were not fully operational until the second quarter of 2024.

Production and operating expenses increased 17% (or $34.0 million) for the three months ended March 31, 2025 to $231.2 million ($13.19 per boe) from $197.2 million ($11.64 per boe) in the three months ended December 31, 2024. Energy production and operating costs increased 29% (or $17.0 million) for the three months ended March 31, 2025 to $75.7 million ($4.32 per boe), compared to $58.7 million ($3.46 per boe) for the three months ended December 31, 2024. The increase was primarily due to higher natural gas prices and carbon taxes impacting the Cold Lake segment. During the three months ended December 31, 2024, the Company used carbon credits to reduce the cost of compliance. Non-energy production and operating costs increased 12% (or $17.0 million) to $155.5 million ($8.87 per boe) for the three months ended March 31, 2025 compared to $138.5 million ($8.18 per boe) for the three months ended December 31, 2024. The increase was primarily due to an increase in surface maintenance costs.

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TRANSPORTATION AND PROCESSING EXPENSES

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025		March 31, 2024		December 31, 2024
Transportation expenses		117.1		114.8		117.8
Processing expenses		25.3		28.6		26.4
Transportation and processing expenses		142.4		143.4		144.2
$ per boe		8.12		8.62		8.51

Transportation and processing expenses decreased 1% (or $1.0 million) for the three months ended March 31, 2025 to $142.4 million (8.12 per boe) compared to $143.4 million ($8.62 per boe) in the same period of 2024. The decrease was primarily due to reduced processing costs at the Montney segment reflecting a lower proportion of volumes processed at higher cost third party facilities.

Transportation and processing expenses decreased 1% (or $1.8 million) for the three months ended March 31, 2025 to $142.4 million ($8.12 per boe) from $144.2 million ($8.51 per boe) in the three months ended December 31, 2024. The decrease was primarily due to utilization of make-up rights at the Cold Lake segment.

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

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025		March 31, 2024		December 31, 2024
Depletion expense		202.3		208.9		181.9
Depreciation and amortization expense		13.4		12.9		14.4
DD&A		215.7		221.8		196.3
$ per boe		12.30		13.33		11.59

DD&A expense decreased 3% (or $6.1 million) for the three months ended March 31, 2025 to $215.7 million ($12.30 per boe) compared to $221.8 million ($13.33 per boe) for the same period of 2024. This decrease was primarily due to changes in management estimates which resulted in a lower depletion rate, partially offset by higher sales volumes.

DD&A expense increased 10% (or $19.4 million) during the three months ended March 31, 2025 to $215.7 million ($12.30 per boe) compared to $196.3 million ($11.59 per boe) for the three months ended December 31, 2024. This increase was primarily due to higher sales volumes and, during the fourth quarter of 2024, the Company's DD&A was impacted by updated depletion rate estimates in the Montney segment.

GENERAL AND ADMINISTRATION EXPENSES (“G&A”)

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025		March 31, 2024		December 31, 2024
General and administrative		24.7		22.0		28.4
$ per boe		1.41		1.32		1.68

For the three months ended March 31, 2025, G&A expenses increased 12% (or $2.7 million) to $24.7 million ($1.41 per boe) compared to $22.0 million ($1.32 per boe) for the same period in 2024. This increase was primarily due to higher personnel costs resulting from the growth of the business and the internal corporate reorganization completed in the fourth quarter of 2024.

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G&A expenses decreased 13% (or $3.7 million) during the three months ended March 31, 2025 to $24.7 million ($1.41 per boe) compared to $28.4 million ($1.68 per boe) for the three months ended December 31, 2024. The decrease was primarily due to non-recurring costs associated with the internal corporate reorganization completed in the fourth quarter of 2024.

INTEREST

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025			March 31, 2024			December 31, 2024
Interest		38.4			45.4			39.0
Weighted average interest rate (%)		5.7	%		6.4	%		5.8	%

For the three months ended March 31, 2025, interest expense decreased 15% (or $7.0 million) to $38.4 million compared to $45.4 million in the same period of 2024. Interest expense decreased 2% (or $0.6 million) for the three months ended March 31, 2025 to $38.4 million compared to $39.0 million for the three months ended December 31, 2024. These decreases were primarily due to lower debt levels and interest rates.

During the three months ended March 31, 2025, the Company recorded $12.3 million in interest expense on the Senior Notes (as defined in the “Capital Resources” section of this MD&A) (March 31, 2024 – $11.6 million), and $26.6 million in interest expense on the Credit Facilities (as defined in the "Capital Resources" section of this MD&A) (March 31, 2024 - $41.0 million), and a realized gain of $0.5 million on interest rate swaps (March 31, 2024 - $7.2 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

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025		March 31, 2024		December 31, 2024
Accretion of lease obligations		5.5		6.2		5.9
Accretion of decommissioning provision		7.3		7.1		7.1
Amortization of debt issuance costs		5.2		4.1		5.1
Accretion of other obligations		2.7		4.9		2.9
Finance costs		20.7		22.3		21.0

Finance costs for the three months ended March 31, 2025 decreased 7% (or $1.6 million) to $20.7 million compared to $22.3 million for the same period of 2024. The decrease was primarily due to a reduction in accretion of other obligations due to the termination of an asset-backed financing arrangement on July 15, 2024 and entrance into a new asset-backed financing arrangement on August 9, 2024 with a lower principal balance and different terms.

Finance costs remained consistent for the three months ended March 31, 2025 at $20.7 million compared to $21.0 million for the three months ended December 31, 2024.

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TAX POOLS

As at March 31, 2025, the Company had approximately $5,460.4 million (December 31, 2024 - $5,595.4 million) of tax pools available for deduction in future periods as shown in the table below.

($ millions, unless otherwise indicated)	Annual Pool Deduction Rate			March 31, 2025		December 31, 2024
Canadian oil and gas property expenditures(1)		10	%		818.0		838.5
Canadian development expenditures(1)		30	%		1,361.8		1,279.7
Canadian exploration expenditures(1)		100	%		25.0		18.3
Undepreciated capital costs(2)		4% - 55	%		1,568.8		1,502.6
Non-capital losses		100	%		1,447.7		1,707.6
Other(1)(3)					239.1		248.7
Total tax pools					5,460.4		5,595.4

(1)	Amount is net of tax pools where deductibility is uncertain.
(2)	As at March 31, 2025, approximately 92% (December 31, 2024 – 92%) of costs in this pool have an annual deduction rate of 25%.
(3)	"Other" tax pools are comprised of federal and provincial scientific research and experimental development expenditure pools and credits and financing costs.

10 | STRATHCONA RESOURCES LTD.

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 the date of this MD&A.

Term	Contract(1)	Index	Currency	Volume		Units	Price
Jul 1, 2025 - Sep 30, 2025	Swap	WCS	USD		50,000	bbl/d	$	(12.93	)
Oct 1, 2025 - Dec 31, 2026	Swap	WCS	USD		50,000	bbl/d	$	(14.40	)
Apr 1, 2025 - Jun 30, 2025	Swap	ARV	USD		18,500	bbl/d	$	(3.59	)
Jul 1, 2025 - Sep 30, 2025	Swap	ARV	USD		23,500	bbl/d	$	(3.46	)

(1) For swap contracts, Strathcona receives the fixed price and pays the index.

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.

11 | STRATHCONA RESOURCES LTD.

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

Term	Contract	Bought Put - USD per Month	Bought Put Price- CAD/USD		Sold Call - USD per Month	Sold Call - CAD/USD
Feb 1, 2025 - Jun 30, 2026	Collar	100.0 million		1.2500	130.0 million		1.4500

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

Expiry	Contract	USD	CAD/USD Strike
Jul 31, 2026	Sold Put Option	500.0 million		1.3775

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.

Notional (C$)	Term	Contract	Index	Contract Price
1,500.0 million	Oct 1, 2024 - Apr 30, 2030	Swap(1)	CORRA		2.9453	%

(1) The swap contracts have a term to April 30, 2030. The counterparties have an option to terminate the swap effective May 1, 2028, which is exercisable on April 28, 2028.

For a listing of the Company’s commodity contracts, foreign exchange and interest rate contracts outstanding as at March 31, 2025 refer to Note 13 to 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.

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025		March 31, 2024			December 31, 2024
Loss (gain) on risk management contracts - realized		0.9		(4.5	)		5.4
Loss (gain) on risk management contracts - unrealized		77.1		44.2			(15.6	)
Total loss (gain) on risk management contracts		78.0		39.7			(10.2	)
Realized loss (gain) on risk management contracts per boe		0.05		(0.27	)		0.32

Strathcona realized a loss on risk management contracts of $0.9 million for the three months ended March 31, 2025, compared to a gain of $4.5 million for the same period in 2024. The realized loss in the three months ended March 31, 2025 was primarily due to cash settlement of the loss position on foreign exchange contracts resulting from the weakened Canadian dollar.

As at March 31, 2025, the mark-to-market value of risk management contracts was a net liability of $117.9 (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 13 to the interim financial statements.

12 | STRATHCONA RESOURCES LTD.

MARKETABLE SECURITIES

The following table summarizes the Company's marketable securities as at the dates indicated.

($ million, unless otherwise indicated)	March 31, 2025		December 31, 2024
Balance, beginning of period		—		—
Additions		459.1		—
Gain on marketable securities		22.7		—
Balance, end of period		481.8		—

During the three months ended March 31, 2025, the Company invested in certain marketable securities with an aggregate value of $459.1 million. During the first quarter, the Company realized a gain on marketable securities of $22.7 million due to increase in the market price of these securities. For sensitivities related to the Company's investment in marketable securities relating to the market price fluctuations, see Note 13 to the interim financial statements.

CAPITAL EXPENDITURES

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

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025		March 31, 2024		December 31, 2024
Cold Lake		89.2		58.9		138.3
Lloydminster		151.8		95.7		138.3
Montney		109.0		129.9		112.9
Corporate		—		1.6		3.0
Capital expenditures		350.0		286.1		392.5

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

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025		March 31, 2024		December 31, 2024
Drilling, completion and equipping		199.2		165.4		170.6
Facilities and pipelines		120.2		74.3		172.5
Recompletion, workovers and polymer powder		18.4		29.0		34.3
Capitalized G&A and other expenditures		12.2		17.4		15.1
Capital expenditures		350.0		286.1		392.5

For the three months ended March 31, 2025, drilling, completion and equipping activities accounted for 57% of capital expenditures as the Company drilled 71 new wells during the first quarter of 2025; 13 in Cold Lake, 49 in Lloydminster and 9 in Montney. For the quarter ended March 31, 2025, facilities and pipeline expenditures accounted for 34% of capital expenditures and relate primarily to Lindbergh debottlenecking and the construction of the Meota Central processing facility.

For the three months ended March 31, 2025, capital expenditures increased 22% (or $63.9 million) to $350.0 million compared to $286.1 million for the same period of 2024. Capital expenditures decreased 11% (or $42.5 million) for the three months ended March 31, 2025 to $350.0 million compared to $392.5 million for the three months ended December 31, 2024. Timing of the expenditures in the 2025 capital program will vary from quarter to quarter, refer to the guidance section of this MD&A for further information on the Company's full year capital plan.

Assets Held for Sale

At March 31, 2025, Strathcona determined that certain assets within its Montney segment met the classification for assets held for sale. Immediately prior to classifying the assets as held for sale, Strathcona assessed the assets for indicators of

13 | STRATHCONA RESOURCES LTD.

impairment. The recoverable amount exceeded the assets carrying value and as such no impairment loss was recognized. The assets held for sale had associated decommissioning liabilities of $0.8 million.

FOREIGN EXCHANGE

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025			March 31, 2024			December 31, 2024
Realized (gain) loss		(0.2	)		2.0			(3.6	)
Unrealized loss (gain) - Senior Notes		0.2			14.9			42.9
Unrealized (gain) loss - Credit Facilities		(28.2	)		50.1			39.3
Unrealized loss (gain) - cross-currency swaps		28.2			(49.5	)		(38.7	)
Unrealized (gain) loss - other		(1.0	)		2.9			7.8
Foreign exchange (gain) loss		(1.0	)		20.4			47.7

Foreign exchange for the three months ended March 31, 2025 resulted in a gain of $1.0 million compared to a loss of $20.4 million and a loss of $47.7 million for the three months ended March 31, 2024 and December 31, 2024, respectively. 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 three operating segments based on the similarity of services and goods provided and economic characteristics exhibited by the operating segments. The three operating segments are:

· Cold Lake, which includes the development and production of bitumen in the Cold Lake region of Northern Alberta;

· Lloydminster, which includes the development and production of heavy oil through enhanced oil recovery and thermal steam-assisted gravity drainage ("SAGD") methods in Southeast Alberta and Southwest Saskatchewan; and

· Montney, which includes the development and production of liquids rich natural gas produced from the Montney region in Northwest Alberta and Northeast British Columbia.

The Company reports activities not directly attributable to an operating segment under Corporate.

The following tables present the financial performance by reportable segment and include a measure of segment profit or loss regularly reviewed by management for the noted periods ended March 31, 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.

See "Recent Developments" for further information regarding proposed disposition of certain of the Company's assets pursuant to the Groundbirch Asset Disposition.

14 | STRATHCONA RESOURCES LTD.

	Cold Lake Segment						Lloydminster Segment						Montney Segment			Corporate						Consolidated
For the Three Months Ended ($ millions, unless otherwise indicated)	Mar 31, 2025		Mar 31, 2024		Dec 31, 2024		Mar 31, 2025		Mar 31, 2024		Dec 31, 2024		Mar 31, 2025	Mar 31, 2024	Dec 31, 2024	Mar 31, 2025		Mar 31, 2024		Dec 31, 2024		Mar 31, 2025		Mar 31, 2024		Dec 31, 2024
Production volumes
Bitumen (bbl/d)	65,016		60,150		59,732		—		—		—		—	—	—	—		—		—		65,016		60,150		59,732
Heavy oil (bbl/d)	—		—		—		50,488		51,835		50,997		—	—	—	—		—		—		50,488		51,835		50,997
Condensate and light oil (bbl/d)	—		—		—		19		46		64		20,663	19,233	20,699	—		—		—		20,682		19,279		20,763
Other NGLs (bbl/d)	—		—		—		3		2		4		11,834	11,736	12,976	—		—		—		11,837		11,738		12,980
Natural gas (mcf/d)	—		—		—		2,000		1,254		1,295		277,517	251,466	255,091	—		—		—		279,517		252,720		256,386
Production volumes (boe/d)	65,016		60,150		59,732		50,843		52,092		51,281		78,750	72,880	76,190	—		—		—		194,609		185,122		187,203
Sales volumes (boe/d)	64,794		60,422		59,796		51,340		49,560		48,134		78,750	72,880	76,190	—		—		—		194,884		182,862		184,120
Segment revenues
Oil and natural gas sales	721.7		623.8		632.1		454.6		417.0		409.9		282.7	258.0	250.4	—		—		0.4		1,459.0		1,298.8		1,292.8
Sales of purchased products	2.4		1.0		—		4.9		—		5.6		—	—	—	—		1.0		10.0		7.3		2.0		15.6
Blending costs	(281.0	)	(251.8	)	(232.6	)	(45.2	)	(42.8	)	(35.1	)	—	—	—	—		—		—		(326.2	)	(294.6	)	(267.7	)
Purchased product	(2.7	)	(1.0	)	—		(4.9	)	—		(5.7	)	—	—	—	—		(1.0	)	(10.4	)	(7.6	)	(2.0	)	(16.1	)
Oil and natural gas sales, net of blending(1)	440.4		372.0		399.5		409.4		374.2		374.7		282.7	258.0	250.4	—		—		—		1,132.5		1,004.2		1,024.6
Segment expenses
Royalties	69.4		57.1		132.9		43.0		42.8		52.1		25.8	26.3	23.5	—		—		—		138.2		126.2		208.5
Production and operating – Energy	40.4		43.8		29.9		33.5		33.8		26.7		1.8	1.2	2.1	—				—		75.7		78.8		58.7
Production and operating – Non-energy	53.5		48.0		49.5		55.0		45.5		44.9		47.0	41.9	44.1	—		—		—		155.5		135.4		138.5
Transportation and processing	21.2		21.6		22.3		66.8		65.2		66.3		54.4	56.6	55.6	—		—		—		142.4		143.4		144.2
Field Operating Income(1)	255.9		201.5		164.9		211.1		186.9		184.7		153.7	132.0	125.1	—		—		—		620.7		520.4		474.7
Depletion, depreciation and amortization	43.2		42.9		39.7		100.6		99.1		97.3		68.1	76.0	54.6	3.8		3.8		4.7		215.7		221.8		196.3
General and administrative	7.1		6.0		7.9		12.1		10.8		13.2		5.5	5.2	7.3	—		—		—		24.7		22.0		28.4
Finance costs	0.8		0.8		1.0		0.9		1.1		1.0		6.3	8.9	6.6	12.7		11.5		12.4		20.7		22.3		21.0
Other (income) loss	—		—		—		—		—		—		—	—	—	(1.2	)	(0.1	)	—		(1.2	)	(0.1	)	—
Interest	—		—		—		—		—		—		—	—	—	38.4		45.4		39.0		38.4		45.4		39.0
Operating Earnings	204.8		151.8		116.3		97.5		75.9		73.2		73.8	41.9	56.6	(53.7	)	(60.6	)	(56.1	)	322.4		209.0		190.0
Loss (gain) on risk management contracts - realized	—		—		—		—		—		—		—	—	—	0.9		(4.5	)	5.4		0.9		(4.5	)	5.4
Loss (gain) on risk management contracts - unrealized	—		—		—		—		—		—		—	—	—	77.1		44.2		(15.6	)	77.1		44.2		(15.6	)
Realized (gain) loss - foreign exchange	—		—		—		—		—		—		—	—	—	(0.2	)	2.0		(3.6	)	(0.2	)	2.0		(3.6	)
Unrealized (gain) loss - foreign exchange	—		—		—		—		—		—		—	—	—	(0.8	)	18.4		51.3		(0.8	)	18.4		51.3
Transaction related costs	—		—		—		—		—		—		—	—	—	0.6		0.1		0.3		0.6		0.1		0.3
Unrealized loss on Sable remediation fund	—		—		—		—		—		—		—	—	—	—		0.1		—		—		0.1		—
Gain on marketable securities	—		—		—		—		—		—		—	—	—	(22.7	)	—		—		(22.7	)	—		—
Deferred tax expense																						62.2		48.1		64.3
Income and comprehensive income																						205.3		100.6		87.9

(1) A non-GAAP financial measure which does not have a standardized meaning under the Accounting Standards; see “Non-GAAP financial Measures and Ratios” section of this MD&A.

15 | STRATHCONA RESOURCES LTD.

	Cold Lake Segment						Lloydminster Segment						Montney Segment			Corporate						Consolidated
For the Three Months Ended ($/boe)	Mar 31, 2025		Mar 31, 2024		Dec 31, 2024		Mar 31, 2025		Mar 31, 2024		Dec 31, 2024		Mar 31, 2025	Mar 31, 2024	Dec 31, 2024	Mar 31, 2025		Mar 31, 2024		Dec 31, 2024		Mar 31, 2025		Mar 31, 2024		Dec 31, 2024
Segment revenues
Oil and natural gas sales	84.17		77.80		80.88		90.79		85.78		87.17		39.89	38.90	35.72	—		—		0.02		70.59		66.57		66.21
Sales of purchased products	0.42		0.18		—		1.06		—		1.26		—	—	—	—		0.06		0.59		0.42		0.12		0.92
Blending costs	(8.58	)	(10.14	)	(8.26	)	(2.19	)	(2.81	)	(2.53	)	—	—	—	—		—		—		(6.00	)	(6.22	)	(5.69	)
Purchased product	(0.46	)	(0.18	)	—		(1.06	)	—		(1.29	)	—	—	—	—		(0.06	)	(0.61	)	(0.43	)	(0.12	)	(0.95	)
Oil and natural gas sales, net of blending(1)	75.55		67.66		72.62		88.60		82.97		84.61		39.89	38.90	35.72	—		—		—		64.58		60.35		60.49
Segment expenses
Royalties	11.90		10.38		24.16		9.32		9.49		11.77		3.63	3.97	3.35	—		—		—		7.88		7.58		12.31
Production and operating – Energy	6.94		7.97		5.44		7.25		7.49		6.03		0.25	0.18	0.30	—		—		—		4.32		4.74		3.46
Production and operating – Non-energy	9.18		8.73		9.00		11.90		10.09		10.14		6.62	6.32	6.29	—		—		—		8.87		8.14		8.18
Transportation and processing	3.64		3.93		4.05		14.46		14.46		14.97		7.68	8.53	7.93	—		—		—		8.12		8.62		8.51
Field Operating Netback(1)	43.89		36.65		29.97		45.67		41.44		41.70		21.71	19.90	17.85	—		—		—		35.39		31.27		28.03
Depletion, depreciation and amortization	7.41		7.80		7.22		21.77		21.97		21.97		9.61	11.46	7.79	0.22		0.23		0.28		12.30		13.33		11.59
General and administrative	1.23		1.10		1.44		2.60		2.41		2.98		0.78	0.78	1.04	—		—		—		1.41		1.32		1.68
Finance costs	0.13		0.15		0.18		0.20		0.26		0.22		0.89	1.34	0.94	0.72		0.69		0.73		1.18		1.34		1.24
Other (income) expense	—		—		—		—		—		—		—	—	—	(0.07	)	(0.01	)	—		(0.07	)	(0.01	)	—
Interest	—		—		—		—		—		—		—	—	—	2.19		2.73		2.30		2.19		2.73		2.30
Operating Earnings	35.12		27.60		21.13		21.10		16.80		16.53		10.43	6.32	8.08	(3.06	)	(3.64	)	(3.31	)	18.38		12.56		11.22
Effective royalty rate (%)(1)	15.8		15.3		33.3		10.5		11.4		13.9		9.1	10.2	9.4							12.2		12.6		20.3

(1) A non-GAAP financial measure which does not have a standardized meaning under the Accounting Standards; see “Non-GAAP financial Measures and Ratios” section of this MD&A.

16 | STRATHCONA RESOURCES LTD.

Cold Lake Segment

Production at the Cold Lake segment for the three months ended March 31, 2025 increased to 65,016 boe per day compared to 60,150 boe per day in the same period of 2024. This increase was primarily due to new wells brought on stream at the Company’s Tucker property.

Oil and natural gas sales, net of blending, increased to $440.4 million ($75.55 per boe) during the three months ended March 31, 2025 compared to $372.0 million ($67.66 per boe) for the same period of 2024. This increase was primarily due to higher sales volumes and higher average WCS Hardisty benchmark pricing.

The effective royalty rate for the three months ended March 31, 2025 remained relatively unchanged at 15.8% compared to 15.3% in the same period of 2024.

Energy related production and operating expenses for the three months ended March 31, 2025 decreased to $40.4 million ($6.94 per boe) compared to $43.8 million ($7.97 per boe) in the same period of 2024. This decrease was primarily due to the lower price of natural gas and electricity, partially offset by an increase in carbon tax.

Non-energy related production and operating expenses for the three months ended March 31, 2025 increased to $53.5 million ($9.18 per boe) compared to $48.0 million ($8.73 per boe) for the same periods of 2024. This increase was primarily due to surface maintenance and increased chemical costs as a result of sulphur recovery units installed in the first quarter of 2024, which weren't fully operational until the second quarter of 2024.

Transportation and processing expenses for the three months ended March 31, 2025 of $21.2 million ($3.64 per boe) were consistent with $21.6 million ($3.93 per boe) in the same period of 2024.

For the three months ended March 31, 2025, general and administrative costs increased to $7.1 million ($1.23 per boe) compared to $6.0 million ($1.10 per boe) in the same period of 2024. This increase was primarily due to higher personnel costs resulting from the growth of the business and the internal corporate reorganization that was completed in the fourth quarter of 2024.

Lloydminster Segment

Production at the Lloydminster segment for the three months ended March 31, 2025, decreased to 50,843 boe per day compared to 52,092 boe per day in the same period of 2024. This decrease was primarily due to lower production volumes from thermal properties, partially offset by higher production volumes from conventional heavy oil properties.

Sales volumes for the three months ended March 31, 2025, increased to 51,340 boe per day compared to 49,560 boe per day in the same period of 2024. Sales volumes in the three months ended March 31, 2024 were impacted by a delay in the commissioning of an expansion to a unit train offloading facility on the US Gulf Coast.

Oil and natural gas sales, net of blending increased to $409.4 million ($88.60 per boe) during the three months ended March 31, 2025 compared to $374.2 million ($82.97 per boe) for the same period of 2024. This increase was primarily due to higher sales volumes and higher average WCS Hardisty and WCS USGC benchmark pricing.

The effective royalty rate for the three months ended March 31, 2025 decreased to 10.5% compared to 11.4% in the same period of 2024. The decrease was primarily due to a reduction in forecast pricing assumptions.

Energy related production and operating expenses decreased to $33.5 million ($7.25 per boe) during the three months ended March 31, 2025 compared to $33.8 million ($7.49 per boe) for the same period in 2024. The modest decrease was primarily due to a decrease in carbon taxes, partially offset by an increase in electricity costs due to increasing well count and additional steam capacity at Meota West 2.

Non-energy related production and operating expenses for the three months ended March 31, 2025 increased to $55.0 million ($11.90 per boe) compared to $45.5 million ($10.09 per boe) in the same period of 2024. This increase was primarily due to higher chemical costs associated with acid stimulation treatments at thermal properties and higher personnel costs in the Lloydminster segment.

For the three months ended March 31, 2025, transportation and processing expenses increased to $66.8 million ($14.46 per boe) compared to $65.2 million ($14.46 per boe) in the same period of 2024. This increase is primarily due to higher sales volumes.

For the three months ended March 31, 2025, general and administrative costs increased to $12.1 million ($2.60 per boe) compared to $10.8 million ($2.41 per boe) in the same period of 2024. This increase was primarily due to higher personnel

17 | STRATHCONA RESOURCES LTD.

costs resulting from the growth of the business and the internal corporate reorganization that was completed in the fourth quarter of 2024.

Montney Segment

Production at the Company’s Montney segment for the three months ended March 31, 2025 increased to 78,750 boe per day compared to 72,880 boe per day in the same period of 2024. The increase was primarily due to new wells brought on stream and better runtimes in the first quarter of 2025.

Oil and natural gas sales for the three months ended March 31, 2025 increased to $282.7 million ($39.89 per boe) compared to $258.0 million ($38.90 per boe). This increase was primarily due to higher sales volumes and higher realized prices for condensate and light oil and natural gas.

For the three months ended March 31, 2025, effective royalty rate decreased to 9.1% compared to 10.2% in the same period of 2024. The decrease was primarily due to increased weighting to production from new wells that qualify for incentive rates.

Non-energy related production and operating expenses for the three months ended March 31, 2025 increased to $47.0 million ($6.62 per boe) compared to $41.9 million ($6.32 per boe) for the same period of 2024. The increase was primarily due to increased downhole maintenance and trucking costs at Kakwa due to delayed completion of a water disposal well.

Transportation and processing expenses for the three months ended March 31, 2025 decreased to $54.4 million ($7.68 per boe) compared to $56.6 million ($8.53 per boe) in the same period of 2024. The decrease was primarily due to reduced processing costs reflecting lower rates for acid gas treatment and a lower proportion of volumes requiring processing from higher cost third party facilities.

For the three months ended March 31, 2025, general and administrative costs increased to $5.5 million ($0.78 per boe) compared to $5.2 million ($0.78 per boe) in the same period of 2024. This increase was primarily due to higher personnel costs resulting from the growth of the business and the internal corporate reorganization that was completed in the fourth quarter of 2024.

18 | STRATHCONA RESOURCES LTD.

CAPITAL RESOURCES

Bank Credit Facilities

Covenant-Based Revolving Credit Facility and Term Credit Facility

As at March 31, 2025, the Company had a covenant-based revolving credit facility of $2.5 billion (December 31, 2024 - $2.5 billion) with a syndicate of Canadian, U.S. and international financial institutions (the “Revolving Credit Facility”) and a US$175.0 million covenant-based term facility (December 31, 2024 - $nil) (the "Term Credit Facility" and together with the Revolving Credit Facility, the "Credit Facilities"). On April 25, 2025, the availability under the Revolving Credit Facility was increased to $3.0 billion. The agreement governing the Credit Facilities (the “Credit Agreement”) includes an accordion feature which permits the Company to increase the available Credit Facilities by up to an additional $250.0 million, subject to the satisfaction of certain conditions.

The Credit Facilities have a maturity date of March 28, 2028, provided that the maturity date will be May 1, 2026 if the Senior Notes (as defined below) remain outstanding and have not been refinanced or legally defeased at such date. There are no mandatory payments on either the Revolving Credit Facility or the Term Credit Facility. Borrowings under the Revolving Credit Facility may be drawn and repaid from time to time by the Company in Canadian or U.S. dollars. Borrowings under the Term Credit Facility were made in a single upfront draw in U.S. dollars and amounts repaid by the Company may not be re-borrowed. The Credit Facilities are not subject to annual or semi-annual reviews.

The Credit Facilities bear interest at the applicable prime lending rate, base rate, Canadian Overnight Repo Rate Average ("CORRA") or Secured Overnight Financing Rate (“SOFR”) plus applicable margins. The applicable margin charged by the lenders is dependent on the Company’s Senior Debt to Adjusted EBITDA ratio (as defined below) for the most recently completed quarter. The Credit Facilities are guaranteed by the Company's subsidiaries, and are secured by a security interest in substantially all of the existing and future assets of the Company and its subsidiaries, including by way of a floating charge debenture granted by the Company and each of its subsidiaries.

As at March 31, 2025, the Company had letters of credit outstanding under the Revolving Credit Facility of $4.0 million (December 31, 2024 - $1.6 million).

Foreign Exchange Risk Management on U.S. Denominated Bank Debt

Strathcona periodically borrows in U.S. dollars and concurrently enters into cross-currency interest rate swap contracts to take advantage of an interest rate arbitrage that results from the relationship between Canadian and U.S. dollar interest rates and forward foreign exchange curves.

Foreign currency risk associated with these borrowings is offset at the time of borrowing as cross-currency interest rate swap contracts fix the principal and interest payments due at maturity. Debt on the balance sheet includes the Canadian dollar equivalent of U.S. borrowings translated at the period end exchange rate, which does not include the offsetting impact of cross-currency interest rate swaps. As at March 31, 2025 the cross-currency swap asset was $0.4 million (December 31, 2024 – an asset of $28.6 million) and total debt includes an unrealized loss of $0.4 million (December 31, 2024 – unrealized loss of $28.6 million) related to U.S. borrowings on the Credit Facilities. Unrealized gains or losses on U.S. borrowings and offsetting unrealized gains or losses on cross-currency interest swap contracts are included in foreign exchange gains or losses in the interim financial statements.

As at March 31, 2025, the Company had the following cross-currency interest rate swap contracts outstanding totaling.

Notional (US$)	Maturity Date	Contract Price
1,208.6 million	April 17, 2025	CAD/USD 1.4395
175.0 million	April 28, 2025	CAD/USD 1.4309

Financial Covenants

The Credit Agreement has three financial covenants which are calculated quarterly (as set out below).

(i) Total Debt to Adjusted EBITDA Ratio – All debt excluding the Financing Agreement (see Note 7 of the interim financial statements), capital leases and letters of credit constituting debt (“Total Debt”), each as defined in the Credit Agreement shall not exceed 4.0 times trailing 12-month net income before non-cash items, income taxes, interest expense and extraordinary and non-recurring losses, adjusted for material acquisitions or dispositions as if they occurred on the first

19 | STRATHCONA RESOURCES LTD.

	day of the calculation period (“Adjusted EBITDA”). For the purposes of Adjusted EBITDA, lease payments are deducted from the calculation if a lease would have been considered an operating lease before the adoption of IFRS 16.
(ii)	Senior Debt to Adjusted EBITDA Ratio – Total Debt excluding permitted junior debt (e.g. Senior Notes), as defined in the Credit Agreement, shall not exceed 3.5 times trailing 12-month Adjusted EBITDA.
(iii)	Interest Coverage Ratio – Trailing 12-month Adjusted EBITDA, shall not be less than 3.5 times cash interest expense ("Interest Charges"), as defined in the Credit Agreement.

As at March 31, 2025, the Company was in compliance with such financial covenants.

Senior Notes

As at March 31, 2025, Strathcona had $719.4 million (December 31, 2024 - $719.2 million) of senior unsecured notes outstanding, with an aggregate principal amount of US$500.0 million, due August 1, 2026 (the “Senior Notes”). The Senior Notes bear interest at 6.875% per annum, payable semi-annually in arrears on February 1 and August 1 of each year. The Senior Notes are redeemable at Strathcona’s option, in whole or in part, at the following redemption prices.

Date	Price
August 1, 2024		101.719	%
August 1, 2025 and thereafter		100.000	%

The Senior Notes have no financial maintenance covenants.

Demand Letter of Credit Facility

As at March 31, 2025, the Company had a $100.0 million (December 31, 2024 - $100.0 million) demand letter of credit facility with a financial institution (the “LC Facility”). The LC Facility is supported by an account performance security guarantee issued by Export Development Canada in favour of the financial institution. The Company and its subsidiaries have indemnified Export Development Canada for the amount of any payment made by Export Development Canada to the financial institution pursuant to such account performance security guarantee; however, the obligations under such indemnity are unsecured. The letters of credit outstanding under the LC Facility do not impact the Company’s borrowing capacity under the Revolving Credit Facility. As at March 31, 2025, the Company had letters of credit in the amount of $68.8 million (December 31, 2024 - $70.3 million) outstanding under the LC Facility.

20 | STRATHCONA RESOURCES LTD.

CAPITAL MANAGEMENT AND LIQUIDITY

The Company’s policy is to maintain a strong capital base for the objectives of maintaining financial flexibility, creditor and market confidence and to sustain the future development of the business. The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying petroleum and natural gas assets. The Company considers its capital structure to include equity, long-term debt and working capital.

The Company generally relies on Funds from Operations and its Credit Facilities to fund its capital requirements. Future liquidity depends primarily on Funds from Operations, availability on the Credit Facilities and the ability to access debt and equity markets. All repayments of principal on the Credit Facilities are due at its maturity date.

The availability under the Credit Facilities is summarized in the following table.

As at	March 31, 2025			December 31, 2024
Revolving Credit Facility capacity(1)		2,500.0			2,500.0
Term Credit Facility capacity(2)		251.8			—
Credit Facilities debt at period end exchange rate		(2,200.4	)		(1,766.9	)
Unrealized loss (gain) on U.S. borrowings		0.4			28.6
Letters of credit outstanding		(4.0	)		(1.6	)
Availability		547.8			760.1

(1)	On April 25 2025, the credit capacity under the Revolving Credit Facility increased to $3.0 billion.
(2)	CAD equivalent converted at the period end exchange rate.

The Company has a working capital surplus as part of its current capital structure. As at March 31, 2025, the working capital surplus was $19.0 million (December 31, 2024 - $545.6 million working capital deficiency). Management believes that its current capital resources and its ability to manage cash flow and working capital levels will allow the Company to meet its current and future obligations, to make scheduled interest payments, to fund planned capital expenditures and to fund the other needs of the business for at least the next 12 months. However, no assurance can be given that this will be the case or that future or additional sources of capital will not be necessary. The Company’s cash flow and the development of projects are subject to certain risk factors discussed in the “Risk Factors” section of the Annual Information Form for the year ended December 31, 2024.

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The oil and natural gas industry is cyclical and commodity prices can be volatile, both of which are expected to impact the Company’s future revenue and profitability. A sustained decline in commodity prices and increased inflation and interest rates could adversely affect our business, financial condition and results of operations, liquidity and ability to meet financial commitments when due or delay planned capital expenditures. The imposition of tariffs or other tariff barriers may negatively impact the Company's realized prices, the timing of cash flows where production is directly exported by the Company and may increase certain of the Company's input costs.

The Company regularly prepares and updates budgets and forecasts in order to monitor its liquidity and ability to meet its financial obligations and commitments, including the ability to comply with the financial covenants under the Credit Facilities.

DECOMMISSIONING LIABILITY

At March 31, 2025, Strathcona’s discounted decommissioning provision balance was $274.5 million (December 31, 2024 - $290.7 million) for future abandonment and reclamation of the Company’s oil and natural gas properties. During the three months ended March 31, 2025, the Company incurred $23.5 million of decommissioning costs to settle existing liabilities. This amount was offset by additions made as a result of new wells and facilities, accretion and changes in estimates.

21 | STRATHCONA RESOURCES LTD.

CONTRACTUAL OBLIGATIONS AND OFF-BALANCE SHEET ARRANGEMENTS

Strathcona has contractual obligations in the normal course of business which may include purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, lease rental obligations, employee agreements and debt. These obligations are of a recurring, consistent nature and impact Strathcona’s cash flows in an ongoing manner.

The following tables detail the undiscounted cash flows and contractual maturities of the Company’s financial liabilities as at March 31, 2025.

	Total		<1 year		1-3 years		4-5 years		> 5 years
Credit Facilities(1)		2,200.0		—		2,200.0		—		—
Senior Notes(2)		793.6		49.5		744.1		—		—
Accounts payable and accrued liabilities		856.6		856.6		—		—		—
Risk management contract liability		117.9		58.1		59.8		—		—
Lease and other obligations(3)		450.9		90.1		143.4		136.8		80.6
Total		4,419.0		1,054.3		3,147.3		136.8		80.6

(1)	Contractual amount reflects contracted settlement price on cross-currency interest rate swap ("CCS") contracts and excludes future interest payments on borrowings.
(2)	Amounts represent repayment of the Senior Notes ($719.4 million) and associated interest payments ($74.2 million) based on the foreign exchange rate in effect on March 31, 2025.
(3)	Amounts relate to undiscounted payments for lease and other obligations. The estimation of future cash payments related to other obligations reflects minimum required payments and may change based on the principal and interest payment options taken. See Note 7 of the interim financial statements.

As at March 31, 2025, the Company was committed to the following non-cancellable payments.

	Total		< 1 year		1-3 years		4-5 years		> 5 years
Transportation and processing commitments		2,063.6		298.3		529.4		434.5		801.4
Capital commitments		103.2		101.9		1.3		—		—
Other		25.1		13.2		9.9		2.0		—
Total		2,191.9		413.4		540.6		436.5		801.4

In the normal course of business, the Company is obligated to make future payments, including contractual obligations and non-cancellable commitments. The Company generally expects to meet these commitments through funds from operations and draws on its Credit Facilities. Strathcona does not maintain off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on the Company’s financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources and which are not disclosed in the interim financial statements or notes thereto.

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SHARE CAPITAL

The authorized capital of the Company consists of an unlimited number of Common Shares and an unlimited number of preferred shares. No preferred shares have been issued by the Company as at March 31, 2025 (December 31, 2024 – nil).

On January 31, 2025, two of the limited partnerships comprising WEF (the "Limited Partnerships"), completed a share pass-through transaction resulting in the disposition of 24,010,576 Common Shares by the Limited Partnerships to their limited partners (the "Pass-through Transaction"). Following completion of the Pass-Through Transaction, the ownership of the issued and outstanding Common Shares by entities comprising WEF collectively decreased from approximately 90.8% to approximately 79.6%, resulting in public float of over 20%.

The Pass-through Transaction was comprised of a series for reorganizational steps, including the issuance by Strathcona of 19,534,409 Common Shares to limited partners of the Limited Partnerships upon the dissolution of the Limited Partnerships. Notwithstanding such issuance, the number of issued and outstanding Common Shares remained the same following the completion of the Pass-Through Transaction.

The following table summarizes the number of shares outstanding as at May 15, 2025:

Share Class	Shares Outstanding at May 15, 2025
Common Shares		214,235,608

The Company had no outstanding securities which are convertible into Common Shares or preferred shares as at May 15, 2025.

During the three months ended March 31, 2025, Strathcona declared and paid total dividends of $55.7 million, or $0.26 per Common Share ($nil - in the three months ended March 31, 2024).

On May 15, 2025, the Board declared a quarterly dividend of $0.30 per Common Share to be paid on June 23, 2025 to all shareholders of record on June 13, 2025.

23 | STRATHCONA RESOURCES LTD.

SUMMARY OF QUARTERLY RESULTS

	2025	2024				2023
($ millions, unless otherwise indicated)	Q1	Q4	Q3	Q2	Q1	Q4	Q3		Q2
Operating results (boe/d)
Average production volumes	194,609	187,203	178,235	181,766	185,122	186,064	147,461		143,778
Average sales volumes	194,884	184,120	178,391	185,841	182,862	184,360	148,874		143,239
Financial Results
Oil and natural gas sales	1,459.0	1,292.8	1,272.5	1,472.3	1,298.8	1,287.6	1,300.2		1,112.8
Net Income (loss)	205.3	87.9	188.0	227.2	100.6	263.7	(41.1	)	274.1
Net income (loss) per share	0.96	0.41	0.88	1.06	0.47	1.23	(0.02	)	0.13
Cash flow from operating activities	516.9	542.4	521.9	519.7	408.8	570.0	430.5		343.1
Operating Earnings	322.4	190.0	265.4	306.1	209.0	202.1	289.9		201.4
Funds from Operations(1)	558.1	405.5	528.7	547.6	455.6	470.8	425.3		389.2
Free Cash Flow(1)	184.0	0.3	200.6	247.3	157.9	150.8	158.0		152.6
Field Operating Income(1)	620.7	474.7	581.1	627.3	520.4	527.4	549.6		460.8
Field Operating Netback ($/boe)(1)	35.39	28.03	35.42	37.09	31.27	31.09	40.13		35.35
Capital expenditures	350.0	392.5	319.6	298.0	286.1	307.8	260.2		231.7
Decommissioning costs	23.5	12.7	8.5	2.9	11.6	13.8	7.1		4.9
Total assets	11,538.5	10,977.5	10,663.3	10,670.9	10,597.8	10,496.9	9,588.9		9,451.2
Debt	2,898.6	2,461.6	2,449.9	2,435.6	2,642.5	2,665.0	2,787.6		2,898.2
Total equity	5,973.0	5,823.7	5,789.3	5,654.9	5,427.7	5,327.1	4,526.4		4,567.5
Common shares outstanding, end of period	214.2	214.2	214.2	214.2	214.2	214.2	2,186.7		2,186.7
Dividends per share	0.26	0.25	0.25	—	—	—	—		—

(1) A non-GAAP financial measure which does not have a standardized meaning under the Accounting Standards; see “Non-GAAP financial Measures and Ratios” section of this MD&A.

Over the past eight quarters, the Company’s oil and natural gas sales have fluctuated due to the volatility in the crude oil, condensate and natural gas benchmark prices, oil price differentials and changes in production. The Company’s production has fluctuated due to asset acquisitions and dispositions, changes in its development capital spending levels and natural declines.

Net income (loss) has fluctuated over the past eight quarters primarily due to the changes in Funds from Operations, unrealized gains and losses from risk management contracts, which fluctuate with changes in forward market prices and foreign exchange rates, unrealized gain on marketable securities, which fluctuate with changes in listed share prices, foreign exchange gains and losses associated with the Company’s Senior Notes, fluctuations in natural gas and power pricing and the associated impact on energy-related production and operating costs, inflationary pressure and fluctuations in deferred tax expense or recovery.

Capital expenditures and total assets have fluctuated throughout the past eight quarters due to changes in the Company’s development capital spending levels which vary based on a number of factors, including the prevailing commodity price environment.

24 | STRATHCONA RESOURCES LTD.

NON-GAAP FINANCIAL MEASURES AND RATIOS

Non-GAAP financial measures and ratios are used internally by management to assess the performance of the Company. They also provide investors with meaningful metrics to assess the Company’s performance compared to other companies in the same industry. However, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. Investors are cautioned that these measures should not be construed as an alternative to financial measures determined in accordance with GAAP and these measures should not be considered to be more meaningful than GAAP measures in evaluating the Company’s performance.

The term “Oil and natural gas sales, net of blending” is calculated by deducting purchased product and blending costs from oil and natural gas sales and sales of purchased product. Management uses this metric to isolate the revenue associated with the Company’s production after accounting for the unavoidable cost of blending. A quantitative reconciliation of Oil and natural gas sales, net of blending to the most directly comparable GAAP financial measure, Oil and natural gas sales, is contained under the heading “Revenue and Realized Prices - Oil and Natural Gas Sales Net of Blending” and “Segment Results” of this MD&A.

Oil and natural gas sales, net of blending, is also reflected on a per boe basis calculated using sales volumes. Management also calculates “Bitumen blend per bbl” and “Heavy oil, blended and raw per bbl” by deducting the associated purchased product and blending cost from oil and natural gas sales and sales of purchased product and dividing by the respective sales volume. This ratio is useful to management when analyzing realized pricing against benchmark commodity prices.

The term “Effective royalty rate” is calculated by dividing royalties by oil and natural gas sales and sales of purchased product, net of blending costs and purchased product. This metric allows management to analyze the movement of royalty expenses in relation to realized and benchmark commodity prices.

“Field Operating Income” and “Field Operating Netback” are common metrics used in the oil and natural gas industry to assess the profitability and efficiency of the Company’s field operations. Management derives Field Operating Netback by dividing Field Operating Income by the respective sales volumes.

The following table reconciles “Field Operating Income” and “Field Operating Netback” to the nearest GAAP measure.

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025			March 31, 2024			December 31, 2024
Oil and natural gas sales		1,459.0			1,298.8			1,292.8
Sales of purchased products		7.3			2.0			15.6
Purchased product		(7.6	)		(2.0	)		(16.1	)
Blending costs		(326.2	)		(294.6	)		(267.7	)
Oil and natural gas sales, net of blending		1,132.5			1,004.2			1,024.6
Royalties		138.2			126.2			208.5
Production and operating		231.2			214.2			197.2
Transportation and processing		142.4			143.4			144.2
Field Operating Income		620.7			520.4			474.7
Field Operating Netback ($/boe)		35.39			31.27			28.03

“Funds from Operations” is used by management to analyze operating performance and provides an indication of the funds generated by Strathcona's principal business to either fund operating activities, re-invest to either maintain or grow the business or make debt repayments. Funds from Operations is derived from Operating Earnings and adjusted for DD&A, finance costs, (loss) gain on risk management contracts - realized and realized gain (loss) - foreign exchange.

“Free Cash Flow” indicates funds available for deleveraging, funding future growth, or shareholder returns. Free Cash Flow is derived from Operating Earnings and adjusted for DD&A, finance costs, gain (loss) on risk management contracts - realized and foreign exchange gain (loss) - realized, capital expenditures and decommissioning costs.

25 | STRATHCONA RESOURCES LTD.

A quantitative reconciliation of Funds from Operations and Free Cash Flow to the most directly comparable GAAP financial measure, Operating Earnings, is set forth below.

	Three Months Ended
($ millions, unless otherwise indicated)	March 31, 2025			March 31, 2024			December 31, 2024
Operating Earnings		322.4			209.0			190.0
Depletion, depreciation and amortization		215.7			221.8			196.3
Finance costs		20.7			22.3			21.0
(Loss) gain on risk management contracts - realized		(0.9	)		4.5			(5.4	)
Realized gain (loss) - foreign exchange		0.2			(2.0	)		3.6
Funds from Operations		558.1			455.6			405.5
Capital expenditures		(350.6	)		(286.1	)		(392.5	)
Decommissioning costs		(23.5	)		(11.6	)		(12.7	)
Free Cash Flow		184.0			157.9			0.3

Supplementary Financial Measures

“TEV” is an aggregation of the Company’s market capitalization, debt and lease and other obligations. Market capitalization is determined by multiplying outstanding common shares by the common share price. Debt and other obligations are as derived under IFRS Accounting Standards.

26 | STRATHCONA RESOURCES LTD.

2024 SEGMENT INFORMATION

The following table presents the financial performance by reportable segment for the year ended December 31, 2024. Certain information related to general and administrative and finance costs have been allocated by segment to conform with the presentation as at March 31, 2025. Operating earnings is the metric used by the Company’s Chief Operating Decision Makers to evaluate segment profit or loss.

	Cold Lake Segment			Lloydminster Segment			Montney Segment		Corporate			Consolidated
For the Year Ended ($ millions, unless otherwise indicated)	December 31, 2024			December 31, 2024			December 31, 2024		December 31, 2024			December 31, 2024
Production volumes
Bitumen (bbl/d)		59,516			—			—		—			59,516
Heavy oil (bbl/d)		—			51,107			—		—			51,107
Condensate and light oil (bbl/d)		—			42			19,880		—			19,922
Other NGLs (bbl/d)		—			2			11,956		—			11,958
Natural gas (mcf/d)		—			1,232			242,224		—			243,456
Production volumes (boe/d)		59,516			51,357			72,207		—			183,080
Sales volumes (boe/d)		59,491			51,097			72,206		—			182,794
Segment revenues
Oil and natural gas sales		2,576.0			1,797.1			963.0		0.3			5,336.4
Sales of purchased product		18.3			26.0			—		30.7			75.0
Blending costs		(929.9	)		(151.6	)		—		—			(1,081.5	)
Purchased product		(18.2	)		(25.8	)		—		(31.0	)		(75.0	)
Oil and natural gas sales, net of blending(1)		1,646.2			1,645.7			963.0		—			4,254.9
Segment expenses
Royalties		385.3			181.7			95.7		—			662.7
Production and operating – Energy		127.9			112.8			7.4		—			248.1
Production and operating – Non-energy		196.0			203.7			163.9		—			563.6
Transportation and processing		87.7			276.2			213.1		—			577.0
Field Operating Income(1)		849.3			871.3			482.9		—			2,203.5
Depletion, depreciation and amortization		167.1			411.1			278.5		16.8			873.5
General and administrative		27.8			48.3			25.0		—			101.1
Finance costs		3.4			4.3			30.5		50.1			88.3
Other income		—			—			—		(0.1	)		(0.1	)
Interest expense		—			—			—		170.2			170.2
Current income tax (recovery)		—			—			—		—			—
Operating Earnings		651.0			407.6			148.9		(237.0	)		970.5
Loss (gain) on risk management contracts - realized		—			—			—		107.0			107.0
(Gain) loss on risk management contracts - unrealized		—			—			—		(63.0	)		(63.0	)
Foreign exchange loss (gain) - realized		—			—			—		0.5			0.5
Foreign exchange loss (gain) - unrealized		—			—			—		67.7			67.7
Transaction related costs		—			—			—		1.0			1.0
Unrealized (gain) loss on Sable remediation fund		—			—			—		(0.1	)		(0.1	)
Loss on settlement of other obligations		—			—			—		4.4			4.4
Deferred tax expense		—			—			—		249.3			249.3
Income and comprehensive income													603.7

(1) A non-GAAP financial measure which does not have a standardized meaning under the Accounting Standards; see “Non-GAAP financial Measures and Ratios” section of this MD&A.

27 | STRATHCONA RESOURCES LTD.

APPLICATION OF CRITICAL ACCOUNTING ESTIMATES

Certain material accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates. The Company’s use of estimates and judgements in preparing the interim financial statements are discussed in Note 2 of the annual financial statements.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

Strathcona is required to comply with National Instrument 52-109 - Certification of Disclosure in Issuers' Annual and Interim Filings ("NI 52-109"). The certification of interim filings for the interim period ended March 31, 2025 requires that Strathcona disclose in the interim MD&A any changes in Strathcona's internal controls over financial reporting ("ICFR") that occurred during the period that have materially affected, or are reasonably likely to materially affect, Strathcona's ICFR. Strathcona confirms that no such changes were made to its ICFR during the three months ended March 31, 2025.

ADVISORIES REGARDING OIL & GAS INFORMATION

This MD&A contains various references to the abbreviation “boe” which means barrels of oil equivalent. All boe conversions in this MD&A are derived by converting gas to oil at the ratio of six thousand cubic feet (“mcf”) of natural gas to one barrel (“bbl”) of crude oil. Boe may be misleading, particularly if used in isolation. A boe conversion rate of 1 bbl : 6 mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 bbl : 6 mcf, utilizing a conversion ratio of 1 bbl : 6 mcf may be misleading as an indication of value. References to “liquids” in this MD&A refer to, collectively, bitumen, heavy oil, condensate and light oil and other natural gas liquids (“NGL”) (comprised of ethane, propane and butane only).

National Instruments 51-101 - Standards of Disclosure for Oil and Gas Activities includes condensate within the natural gas liquids product type. The Company has disclosed condensate as combined with light oil and separately from other natural gas liquids in this MD&A since the price of condensate as compared to other natural gas liquids is currently significantly higher and the Company believes that this presentation provides a more accurate description of its operations and results therefrom. References to “oil and condensate" in this MD&A refer to, collectively, light and medium crude oil, heavy crude oil, bitumen and natural gas liquids. References to "natural gas" in this MD&A refer to conventional natural gas.

The Company’s annual and quarterly average daily production volumes for 2025 and 2024, and the references to “natural gas”, “crude oil” and “condensate”, reported in this MD&A consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 6 mcf : 1 bbl where applicable:

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	Three Months Ended
	March 31, 2025		March 31, 2024		December 31, 2024
Cold Lake segment
Heavy crude oil (bbl/d)		—		—		—
Light and medium crude oil (bbl/d)		—		—		—
Total crude oil (bbl/d)		—		—		—
Bitumen (bbl/d)		65,016		60,150		59,732
NGLs (bbl/d)		—		—		—
Total liquids (bbl/d)		65,016		60,150		59,732
Conventional natural gas (mcf/d)		—		—		—
Total (boe/d)		65,016		60,150		59,732
Lloydminster segment
Heavy crude oil (bbl/d)		50,488		51,835		50,997
Light and medium crude oil (bbl/d)		17		46		64
Total crude oil (bbl/d)		50,505		51,881		51,061
Bitumen (bbl/d)		—		—		—
NGLs (bbl/d)		5		2		4
Total liquids (bbl/d)		50,510		51,883		51,065
Conventional natural gas (mcf/d)		2,000		1,254		1,295
Total (boe/d)		50,843		52,092		51,281
Montney segment
Heavy crude oil (bbl/d)		—		—		—
Light and medium crude oil (bbl/d)		487		505		553
Total crude oil (bbl/d)		487		505		553
Bitumen (bbl/d)		—		—		—
NGLs (bbl/d)		32,010		30,464		33,122
Total liquids (bbl/d)		32,497		30,969		33,675
Conventional natural gas (mcf/d)		277,517		251,466		255,091
Total (boe/d)		78,750		72,880		76,190
Consolidated
Heavy crude oil (bbl/d)		50,488		51,835		50,997
Light and medium crude oil (bbl/d)		504		551		617
Total crude oil (bbl/d)		50,992		52,386		51,614
Bitumen (bbl/d)		65,016		60,150		59,732
NGLs (bbl/d)		32,015		30,466		33,126
Total liquids (bbl/d)		148,023		143,002		144,472
Conventional natural gas (mcf/d)		279,517		252,720		256,386
Total (boe/d)		194,609		185,122		187,203

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FORWARD-LOOKING INFORMATION

Certain statements contained in this MD&A constitute forward-looking information within the meaning of applicable securities laws. The forward-looking information in this MD&A is based on Strathcona’s current internal expectations, estimates, projections, assumptions and beliefs. Such forward-looking information is not a guarantee of future performance and involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. The Company believes the material factors, expectations and assumptions reflected in the forward-looking information are reasonable as of the time of such information, but no assurance can be given that these factors, expectations and assumptions will prove to be correct, and such forward-looking information included in this MD&A should not be unduly relied upon.

The use of any of the words “expect”, “anticipate”, “estimate”, “objective”, “ongoing”, “may”, “will”, “project”, “believe”, “depends”, “could” and similar expressions are intended to identify forward-looking information. In particular, but without limiting the generality of the foregoing, this MD&A contains forward-looking information pertaining to the following: the Company’s business strategy and future plans; the Groundbirch Asset Sale, including the expected timing of completion; the Company’s 2025 production and capital spending guidance; the declaration and payment of dividends, including the amount and timing thereof; expected impacts of tariffs on Strathcona's operations; the Company’s use of hedging arrangements; the Company’s ability to meet current and future obligations, including making scheduled principal and interest payments, to fund planned capital expenditures and to fund the other needs of the business; future liquidity and financial capacity; anticipated proceeds from financial instruments, including commodity contracts; and sources of funding for the Company’s capital program and the terms of Strathcona’s future contractual obligations, including its obligations under the Credit Agreement and Senior Notes and oil and natural gas prices and differentials.

All forward-looking information reflects Strathcona’s beliefs and assumptions based on information available at the time the applicable forward-looking information is disclosed and in light of the Company’s current expectations with respect to such things as: the success of Strathcona’s operations and growth and expansion projects; expectations regarding production growth, future well production rates and reserve volumes; expectations regarding Strathcona's capital program; the completion of the Groundbirch Asset Sale; Strathcona's ability to declare and pay dividends; expectations regarding the impact of tariffs on Strathcona's operations and its ability to effectively mitigate the impact thereof; the outlook for general economic trends, industry trends, prevailing and future commodity prices, foreign exchange rates and interest rates; prevailing and future royalty regimes and tax laws; future well production rates and reserve volumes; fluctuations in energy prices based on worldwide demand and geopolitical events; the impact of inflation; the integrity and reliability of Strathcona’s assets; decommissioning obligations; Strathcona’s ability to comply with its financial covenants; and the governmental, regulatory and legal environment, including expectations regarding the current and future carbon tax regime and regulations. In addition, certain forward-looking information with respect to the Company’s 2025 guidance assumes commodity prices and exchange rates of: US$70 / bbl WTI, US$13 / bbl WCS-WTI differential, 1.38 USD-CAD and C$3 / GJ AECO. Management believes that its assumptions and expectations reflected in the forward-looking information contained herein are reasonable based on the information available on the date such information is provided and the process used to prepare the information. However, it cannot assure readers that these expectations will prove to be correct.

The forward-looking information included in this MD&A is not a guarantee of future performance and involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information, including, without limitation: changes in commodity prices; changes in the demand for or supply of Strathcona’s products; the continued impact, or further deterioration, in global economic and market conditions, including from inflation and/or certain geopolitical conflicts, such as the ongoing Russia/Ukraine conflict, the conflict in the Middle East, and other heightened geopolitical risks, including the imposition of tariffs or other trade barriers, and the ability of the Company to carry on operations as contemplated in light of the foregoing; determinations by the Organization of the Petroleum Exporting Countries and other countries as to production levels; unanticipated operating results or production declines; changes in tax or environmental laws, climate change, royalty rates or other regulatory matters; changes in Strathcona’s development plans or by third party operators of Strathcona’s properties; failure to achieve anticipated results of its operations; competition from other producers; inability to retain drilling rigs and other services; failure to complete or realize the anticipated benefits of the Company’s acquisitions, dispositions or corporate reorganizations, including the Groundbirch Asset Sale; incorrect assessment of the value of acquisitions; delays resulting from or inability to obtain required regulatory approvals; increased debt levels or debt service requirements; inflation; changes in foreign exchange rates; inaccurate estimation of Strathcona’s oil and gas reserve and contingent resource volumes; limited, unfavourable or a lack of access to capital markets or other sources of capital; increased costs; a lack of adequate insurance coverage; the impact of competitors; and the other factors discussed under the “Risk Factors” section in the Company's Management's Discussion and Analysis and Annual Information Form for the year ended December 31, 2024, a copy of each of which is available under the Company’s profile on SEDAR+ at www.sedarplus.ca.

30 | STRATHCONA RESOURCES LTD.

Declaration of dividends is at the sole discretion of the board of directors of Strathcona and will continue to be evaluated on an ongoing basis. There are numerous factors that may result in Strathcona changing, suspending or discontinuing its quarterly dividends, including changes to its free cash flow, operating results, capital requirements, financial position, debt levels, market conditions or corporate strategy and the need to comply with requirements under the Credit Agreement and applicable laws respecting the declaration and payment of dividends. There are no assurances as to the continuing declaration and payment of future dividends or the amount or timing of any such dividends.

The purpose of the capital expenditure guidance is to assist readers in understanding Strathcona's expected and targeted financial position and performance, and this information may not be appropriate for other purposes.

The foregoing risks should not be construed as exhaustive. The forward-looking information contained in this MD&A speaks only as of the date of this MD&A and Strathcona does not assume any obligation to publicly update or revise such forward-looking information to reflect new events or circumstances, except as may be required pursuant to applicable laws. Any forward-looking information contained herein is expressly qualified by this cautionary statement.

ADDITIONAL INFORMATION

Additional information about Strathcona, including Strathcona's Annual Information Form for the year ended December 31, 2024 and the interim financial statements, can be found at: www.sedarplus.ca and www.strathconaresources.com.

31 | STRATHCONA RESOURCES LTD.