Cenovus Energy : Supplemental Information (Q1 2025 Supplemental Information)

‌Cenovus Energy Inc.

Interim Supplemental Information (unaudited) For the Period Ended March 31, 2025 (Canadian Dollars)

‌Financial Statistics

($ millions, except per share amounts)

Three Months Ended

Twelve Months

Ended

Mar. 31, Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31,

Revenues 2025 2024 2024 2024 2024 2024

Upstream Oil Sands Conventional Offshore	6,996 924 426	6,217 6,286 6,739 5,931 761 698 669 855 348 346 448 331	25,173 2,983 1,473 29,629 5,310 28,308 33,618
Total Upstream Revenue Downstream Canadian Refining U.S. Refining (1)	8,346 1,282 6,423	7,326 7,330 7,856 7,117 1,263 1,580 1,135 1,332 6,574 7,218 7,615 6,901
Total Downstream Revenue (1)	7,705	7,837 8,798 8,750 8,233
Corporate and Eliminations	(2,752)	(2,350) (2,309) (2,024) (2,287) (8,970)
Total Revenues (1)	13,299	12,813 13,819 14,582 13,063	54,277

Operating Margin

Upstream Oil Sands Conventional Offshore	2,544 173 331	2,340 2,467 2,748 2,236 88 12 42 149 242 252 299 246	9,791 291 1,039 11,121 (80) (232) (312) 10,809
Total Upstream Operating Margin (2) Downstream Canadian Refining U.S. Refining	3,048 68 (305)	2,670 2,731 3,089 2,631 47 60 (255) 68 (443) (383) 102 492
Total Downstream Operating Margin (2)	(237)	(396) (323) (153) 560
Total Operating Margin (3)	2,811	2,274 2,408 2,936 3,191

Cash From (Used in) Operating Activities and Adjusted Funds Flow

Cash From (Used in) Operating Activities Deduct (Add Back): Settlement of Decommissioning Liabilities Net Change in Non-Cash Working Capital	1,315 (36) (861)	2,029 (64) 492	2,474 (74) 588	2,807 (48) 494	1,925 (48) (269)	9,235 (234) 1,305
Adjusted Funds Flow (3)	2,212	1,601	1,960	2,361	2,242	8,164
	1.21	0.88	1.06	1.27	1.20	4.41
Per Share - Basic (3)
Per Share - Diluted (3)	1.21	0.87	1.05	1.26	1.19	4.38

Net Earnings (Loss)

Net Earnings (Loss)	859	146	820	1,000	1,176	3,142
Per Share - Basic	0.47	0.08	0.44	0.53	0.62	1.68
Per Share - Diluted	0.47	0.07	0.42	0.53	0.62	1.67

Capital Investment

Upstream Oil Sands Conventional Offshore Atlantic Asia Pacific	763	773	681	613	647	2,714 421 1,077 68 1,145 4,280 208 488 696 39 5,015
	122	121	106	68	126
	227	312	341	266	158
	14	24	14	29	1
Total Offshore	241	336	355	295	159
Total Upstream Capital Investment	1,126	1,230	1,142	976	932
Downstream
Canadian Refining	22	63	44	70	31
U.S. Refining	77	168	153	100	67
Total Downstream Capital Investment	99	231	197	170	98
Corporate	4	17	7	9	6
Total Capital Investment	1,229	1,478	1,346	1,155	1,036

1. Comparative periods reflect certain revisions. See the Prior Period Revisions section located in our annual Management's Discussion and Analysis ("annual MD&A") for the year ended December 31, 2024, for further details.

2. Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental.

3. Non-GAAP financial measure or contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.

‌Financial Metrics	Mar. 31, 2025	Dec. 31, 2024	Sep. 30, 2024	Jun. 30, 2024	Mar. 31, 2024	Dec. 31, 2024
Free Funds Flow (1)	983	123	614	1,206	1,206	3,149
Excess Free Funds Flow (1)	373	(416)	146	735	832	1,297
Long-Term Debt, Including Current Portion	7,524	7,534	7,199	7,275	7,227	7,534
Total Debt	7,847	7,707	7,300	7,412	7,227	7,707
Net Debt	5,079	4,614	4,196	4,258	4,827	4,614
Net Debt to Adjusted Funds Flow (2) (times)	0.6	0.6	0.5	0.4	0.5	0.6
Net Debt to Adjusted EBITDA (2) (times)	0.5	0.5	0.4	0.4	0.4	0.5
Income Tax and Exchange Rates

Effective Tax Rate on Net Earnings (Loss) (percent)	24.0					22.8
Foreign Exchange Rates
US$ per C$1 - Average	0.697	0.715	0.733	0.731	0.741	0.730
US$ per C$1 - Period End	0.696	0.695	0.741	0.731	0.738	0.695
RMB per C$1 - Average	5.069	5.142	5.255	5.293	5.330	5.255

Common Share Information

Commons Shares Outstanding (millions)
Period End	1,823	1,825	1,829	1,857	1,865	1,825
Weighted Average - Basic	1,821	1,826	1,848	1,859	1,868	1,850
Weighted Average - Diluted	1,831	1,839	1,863	1,874	1,878	1,863
Base Dividend ($ per share)	0.180	0.180	0.180	0.180	0.140	0.680
Variable Dividend ($ per share)	-	-	-	0.135	-	0.135
Closing Price
Toronto Stock Exchange (C$ per share)	20.00	21.79	22.62	26.88	27.08	21.79
New York Stock Exchange (US$ per share)	13.91	15.15	16.73	19.66	19.99	15.15
Total Share Volume Traded (millions)	1,357	1,061	1,120	1,210	1,322	4,713

Selected Average Benchmark Prices

(Average US$/bbl, unless otherwise indicated)
Crude Oil Prices
Dated Brent	75.66	74.69	80.18	84.94	83.24	80.76
West Texas Intermediate ("WTI")	71.42	70.27	75.09	80.57	76.96	75.72
Differential Dated Brent - WTI	4.24	4.42	5.09	4.37	6.28	5.04
Western Canadian Select ("WCS") at Hardisty	58.75	57.71	61.54	66.96	57.65	60.97
Differential WTI - WCS at Hardisty	12.67	12.56	13.55	13.61	19.31	14.75
WCS at Nederland	67.74	65.69	68.51	74.69	69.89	69.69
Differential WTI - WCS at Nederland	3.68	4.58	6.58	5.88	7.07	6.03
Condensate (C5 at Edmonton)	69.88	70.66	71.19	77.14	72.78	72.94
Differential Condensate - WTI Premium/(Discount)	(1.54)	0.39	(3.90)	(3.43)	(4.18)	(2.78)
Differential Condensate - WCS at Hardisty Premium/(Discount)	11.13	12.95	9.65	10.18	15.13	11.97
Synthetic at Edmonton	69.07	71.11	76.41	83.32	69.42	75.07
Differential Synthetic - WTI Premium/(Discount)	(2.35)	0.84	1.32	2.75	(7.54)	(0.65)
Refined Product Prices
Chicago Regular Unleaded Gasoline	83.08	78.95	92.29	99.09	89.48	89.95
Chicago Ultra-low Sulphur Diesel	89.12	89.28	96.55	99.80	104.27	97.47
Refining Benchmarks
Chicago 3-2-1 Crack Spread (3)	13.68	12.12	18.62	18.76	17.45	16.74
Group 3 3-2-1 Crack Spread (3)	16.48	12.66	18.95	18.13	17.50	16.81
Renewable Identification Numbers ("RINs")	4.76	4.02	3.89	3.39	3.68	3.74
Upgrading Differential (4) (C$/bbl)	14.69	18.64	20.26	22.28	15.65	19.21
Natural Gas Prices
AECO (5) (C$/Mcf)	2.17	1.48	0.69	1.18	2.50	1.46
NYMEX (6) (US$/Mcf)	3.65	2.79	2.16	1.89	2.24	2.27

1. Non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.

2. Calculated on a trailing twelve-month basis.

3. The average 3-2-1 crack spread is an indicator of the Refining Margin and is valued on a last-in, first-out accounting basis. The benchmark market crack spreads do not precisely mirror the configuration and product output of our refineries, or the location we sell product; however, they are used as a general market indicator.

4. The upgrading differential is the difference between synthetic crude oil at Edmonton and Lloydminster Blend crude oil at Hardisty. The upgrading differential does not precisely mirror the configuration and the product output of our Canadian Refining assets; however, it is used as a general market indicator.

5. Alberta Energy Company ("AECO") 5A natural gas daily index.

6. New York Mercantile Exchange ("NYMEX") natural gas monthly index.

Mar. 31,	Dec. 31,	Sep. 30,	Jun. 30,	Mar. 31,	Dec. 31,
2025	2024	2024	2024	2024	2024

‌Upstream Production Volumes (1)

Crude Oil and Natural Gas Liquids (Mbbls/d) Oil Sands Bitumen Foster Creek Christina Lake Sunrise Lloydminster Thermal Lloydminster Conventional Heavy Oil	202.7	195.2	198.0	195.0	196.0	196.0 234.2 49.6 111.5 17.6 608.9 4.9 21.0 25.9 9.3 1.7 8.0 19.0 653.8 11.1 563.8 199.5 85.8 860.2 797.2
	237.8	251.4	211.8	237.1	236.5
	52.1	53.1	50.4	46.1	48.8
	109.9	108.9	109.4	113.5	114.1
	21.8	18.0	16.3	18.1	17.9
Total Oil Sands Production	624.3	626.6	585.9	609.8	613.3
Conventional (2)
Light Crude Oil	5.2	4.8	4.6	5.1	5.3
Natural Gas Liquids (3)	20.5	19.7	21.1	21.4	22.0
Total Conventional Production	25.7	24.5	25.7	26.5	27.3
Offshore Natural Gas Liquids
Asia Pacific - China	8.8	9.1	8.8	9.8	9.5
Asia Pacific - Indonesia (4)	0.5	2.9	1.1	1.8	0.9
Offshore Light Crude Oil
Atlantic	11.6	7.5	9.0	8.4	7.2
Total Offshore Production	20.9	19.5	18.9	20.0	17.6
Total Liquids Production	670.9	670.6	630.5	656.3	658.2
Conventional Natural Gas (MMcf/d) Oil Sands Conventional (2) Offshore Asia Pacific - China Asia Pacific - Indonesia (4)	11.4	11.8	10.4	10.5	11.9
	589.3	560.5	554.8	579.4	560.5
	199.0	200.8	190.2	202.5	204.7
	88.2	100.2	89.2	74.8	78.7
Total Conventional Natural Gas Production	887.9	873.3	844.6	867.2	855.8
Total Upstream Production (MBOE/d) (5)	818.9	816.0	771.3	800.8	800.9

Effective Royalty Rates (6) (percent)

Oil Sands
Foster Creek	24.4	24.2	25.9	21.1	24.9	24.0
Christina Lake	26.8	30.2	27.7	25.9	25.0	27.3
Sunrise	6.6	5.8	7.0	7.3	3.8	6.1
Lloydminster (7)	11.4	14.3	14.3	11.2	6.8	11.7
Conventional (2)	9.0	8.4	10.7	12.4	9.9	10.3
Offshore
Asia Pacific - China	7.6	7.8	7.8	7.7	7.6	7.7
Asia Pacific - Indonesia (4)	30.1	24.1	11.7	16.8	7.7	16.1
Atlantic	1.0	1.0	1.0	(0.6)	4.5	0.7

1. Before royalties.

2. For the three months ended March 31, 2025, reported production volumes and royalty rates reflect Cenovus's 30 percent equity interest in Duvernay Energy Corporation ("Duvernay"). The Duvernay joint venture is accounted for using the equity method in the interim Consolidated Financial Statements.

3. Natural gas liquids include condensate volumes.

4. Reported production volumes and royalty rates reflect Cenovus's 40 percent equity interest in Husky-CNOOC Madura Ltd. ("HCML"). The HCML joint venture is accounted for using the equity method in the interim Consolidated Financial Statements.

5. Natural gas volumes have been converted to barrels of oil equivalent ("BOE") on the basis of six thousand cubic feet ("Mcf") to one barrel ("bbl"). BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.

6. Effective royalty rates are equal to royalty expense divided by product revenue, net of transportation expenses, excluding realized (gain) loss on risk management.

7. Composed of the Lloydminster thermal and Lloydminster conventional heavy oil assets.

Mar. 31,	Dec. 31,	Sep. 30,	Jun. 30,	Mar. 31,	Dec. 31,
2025	2024	2024	2024	2024	2024

‌Oil Sands - Netbacks (1)

Foster Creek Bitumen ($/bbl) Realized Sales Price Royalties Transportation and Blending Operating	87.26 17.40 15.85 9.82	85.87 16.73 16.61 9.60	84.72 18.63 12.90 9.01	90.89 16.08 14.69 10.06	76.80 16.61 10.25 10.81	84.49 17.03 13.57 9.87 44.02 75.74 18.86 6.53 8.63 41.72 86.07 4.26 16.07 14.36 51.38 79.65 8.84 3.95 17.52 49.34 80.20 14.92 9.00 11.40 44.88
Netback	44.19	42.93	44.18	50.06	39.13
Christina Lake Bitumen ($/bbl) Realized Sales Price Royalties Transportation and Blending Operating	75.07 18.48 6.12 8.76	72.86 20.14 6.08 8.25	79.54 19.91 7.63 9.33	84.93 20.17 7.16 8.49	66.90 15.40 5.40 8.51
Netback	41.71	38.39	42.67	49.11	37.59
Sunrise Bitumen ($/bbl) Realized Sales Price Royalties Transportation and Blending Operating	87.30 4.56 18.07 17.55	79.30 3.86 12.32 14.84	83.02 4.72 15.36 12.97	94.47 5.53 18.71 13.17	88.36 2.62 18.51 17.02
Netback	47.12	48.28	49.97	57.06	50.21
Lloydminster (2) Bitumen and Heavy Crude Oil ($/bbl) Realized Sales Price Royalties Transportation and Blending Operating	78.93 8.61 3.42 18.46	75.16 10.15 3.71 17.32	80.67 11.23 3.63 16.91	89.90 9.42 4.55 17.81	72.71 4.58 3.89 18.05
Netback	48.44	43.98	48.90	58.12	46.19
Total Oil Sands ($/bbl) Realized Sales Price Royalties Transportation and Blending Operating	80.99 15.03 9.85 11.77	77.83 15.64 9.31 11.10	81.77 16.26 9.18 11.17	88.76 15.21 9.98 11.47	72.79 12.60 7.54 11.86
Netback	44.34	41.78	45.16	52.10	40.79

Conventional - Netbacks (1)

Total Conventional ($/BOE) (3)
Realized Sales Price	34.01	25.18	20.42	22.20	32.92	25.18
Royalties	1.83	1.34	1.38	2.02	2.16	1.73
Transportation and Blending	5.49	4.83	5.15	5.25	4.67	4.98
Operating	10.92	10.91	12.77	11.25	13.05	11.99
Netback	15.77	8.10	1.12	3.68	13.04	6.48

1. Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.

2. Composed of the Lloydminster thermal and Lloydminster conventional heavy oil assets.

3. See footnote 5 on page 3 of this Supplemental for BOE definition. For the three months ended March 31, 2025, reported per-unit values reflect Cenovus's 30 percent equity interest in the Duvernay joint venture. The Duvernay joint venture is accounted for using the equity method in the interim Consolidated Financial Statements.

‌Mar. 31, Dec. 31, Sep. 30, Jun. 30, Mar. 31, Dec. 31, China

Natural Gas Liquids ($/bbl)

Indonesia

Natural Gas Liquids ($/bbl)

Total Asia Pacific (3)

Natural Gas Liquids ($/bbl)

Offshore - Netbacks (1) 2025 2024 2024 2024 2024 2024

Realized Sales Price	97.29	90.91	96.60	99.65	95.20	95.64
Royalties	13.96	14.28	14.50	13.78	13.30	13.95
Operating	6.00	8.77	8.14	7.24	6.27	7.58
Conventional Natural Gas ($/Mcf)
Realized Sales Price	12.79	12.92	12.68	12.59	12.46	12.66
Royalties	0.68	0.68	0.67	0.67	0.66	0.67
Operating	1.00	1.46	1.37	1.21	1.05	1.27
Asia Pacific - China Total ($/BOE) (2)
Realized Sales Price	81.01	80.39	80.52	80.95	79.21	80.26
Royalties	6.13	6.28	6.31	6.20	6.00	6.19
Operating	6.00	8.77	8.20	7.24	6.28	7.61
Netback	68.88	65.34	66.01	67.51	66.93	66.46

Realized Sales Price	117.54	101.42	111.68	117.32	107.19	108.19
Royalties	40.97	52.25	53.07	56.89	47.48	52.99
Operating	9.07	10.69	10.83	8.49	9.21	9.93
Conventional Natural Gas ($/Mcf)
Realized Sales Price	10.45	8.97	8.60	8.67	8.21	8.63
Royalties	3.11	1.35	0.49	0.54	0.17	0.68
Operating	1.79	1.87	1.83	1.64	2.01	1.84
Asia Pacific - Indonesia Total ($/BOE) (2)
Realized Sales Price	64.65	60.88	55.93	60.43	53.05	57.82
Royalties	19.44	14.66	6.54	10.17	4.10	9.32
Operating	10.67	11.16	10.95	9.68	11.86	10.93
Netback	34.54	35.06	38.44	40.58	37.09	37.57

Realized Sales Price	98.46	93.47	98.35	102.45	96.25	97.59
Royalties	15.52	23.51	18.97	20.62	16.32	20.02
Operating	6.17	9.24	8.45	7.44	6.53	7.95
Conventional Natural Gas ($/Mcf)
Realized Sales Price	12.07	11.60	11.37	11.53	11.28	11.45
Royalties	1.42	0.91	0.61	0.63	0.53	0.67
Operating	1.24	1.60	1.52	1.32	1.31	1.44
Asia Pacific - Total ($/BOE) (2)
Realized Sales Price	76.65	74.23	73.55	75.87	72.84	74.13
Royalties	9.68	8.93	6.37	7.18	5.54	7.05
Operating	7.24	9.53	8.98	7.84	7.64	8.52
Netback	59.73	55.77	58.20	60.85	59.66	58.56
Atlantic
Light Crude Oil ($/bbl) Realized Sales Price	102.63	102.78	106.56	112.74	114.07	109.58
Royalties	1.04	1.00	1.03	(0.72)	5.09	0.72
Transportation and Blending	4.25	4.27	3.00	5.60	(2.14)	3.81
Operating	45.47	114.23	88.40	79.03	158.70	97.70
Netback	51.87	(16.72)	14.13	28.83	(47.58)	7.35

1. Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.

2. See footnote 5 on page 3 of this Supplemental for BOE definition.

3. Reported per-unit values reflect Cenovus's 40 percent equity interest in the HCML joint venture. The HCML joint venture is accounted for using the equity method in the interim Consolidated Financial Statements.

Mar. 31,	Dec. 31,	Sep. 30,	Jun. 30,	Mar. 31,	Dec. 31,
2025	2024	2024	2024	2024	2024

‌Canadian Refining

Operable Capacity (Mbbls/d)	108.0	108.0	108.0	108.0	108.0	108.0 96.6 90.5 84 41.0 15.7 10.8 30.8 98.3 4.8 103.1 20.72 798 544 254 22.56 15.38 7.18
Total Processed Inputs (Mbbls/d)	119.5	112.1	106.4	58.9	108.8
Crude Oil Unit Throughput (Mbbls/d)	111.9	104.4	99.4	53.8	104.1
Crude Unit Utilization (percent)	104	97	92	50	96
Total Refined Product Production (Mbbls/d)
Synthetic Crude Oil	52.4	48.8	47.3	20.7	47.1
Asphalt
	16.6	16.8	16.5	14.0	15.6
Diesel
	15.5	13.4	11.8	5.2	12.9
Other	37.7
		35.6	32.5	19.7	35.2
Total Refined Product Production (Mbbls/d)	122.2	114.6	108.1	59.6	110.8
Ethanol (Mbbls/d)	4.3	3.8	5.5	4.4	5.4
Total Production (Mbbls/d)	126.5	118.4	113.6	64.0	116.2
Adjusted Refining Margin (1) ($/bbl)	17.33	16.96	22.17	26.23	20.23
Operating Expenses - Upgrading and Refining (2)	116	131	143	377	147
Operating Expenses - Excluding Turnaround Costs	116	127	119	166	132
Operating Expenses - Turnaround Costs	-	4	24	211	15
Per-Unit Operating Expenses (2) (3) ($/bbl)	10.81	12.65	14.63	70.44	14.83
Per-Unit Operating Expenses - Excluding Turnaround Costs	10.81	12.26	12.22	30.92	13.36
Per-Unit Operating Expenses - Turnaround Costs	-	0.39	2.41	39.52	1.47

U.S. Refining (4)

Operable Capacity (Mbbls/d)	612.3	612.3	612.3	612.3	612.3	612.3
Total Processed Inputs (Mbbls/d)	581.0	588.4	568.0	594.0	575.0	581.4
Crude Oil Unit Throughput (Mbbls/d)	553.5	562.3	543.5	568.9	551.1	556.4
Heavy Crude Oil	226.3	218.7	215.7	219.4	224.7	219.6
Light/Medium Crude Oil	327.2	343.6	327.8	349.5	326.4	336.8
Crude Unit Utilization (percent)	90	92	89	93	90	91
Total Refined Product Production (Mbbls/d)
Gasoline	284.7	301.8	259.7	278.3	281.9	280.5
Distillates (5)	208.8	216.2	205.3	216.3	200.1	209.1
Asphalt	25.7	29.1	29.6	26.2	26.1	28.3
Other	76.7	57.1	77.0	74.7	77.8	72.1
Total Refined Product Production (Mbbls/d)	595.9	604.2	571.6	595.5	585.9	590.0
Adjusted Refining Margin (1) ($/bbl)	8.41	5.98	10.97	13.15	17.37	11.83
Weighted Average Crack Spread, Net of RINs (US$/bbl)	9.46	8.20	14.79	15.25	13.78	13.01
Weighted Average Crack Spread, Net of RINs (C$/bbl)	13.58	11.47	20.18	20.86	18.59	17.82
Adjusted Market Capture (1) (percent)	62	52	54	63	93	67
Operating Expenses	716	718	751	684	610	2,763
Operating Expenses - Excluding Turnaround Costs	635	590	666	626	576	2,457
Operating Expenses - Turnaround Costs	81	128	85	58	34	306
Per-Unit Operating Expenses (3) ($/bbl)	13.69	13.26	14.37	12.66	11.65	12.99
Per-Unit Operating Expenses - Excluding Turnaround Costs	12.15	10.89	12.74	11.58	11.01	11.55
Per-Unit Operating Expenses - Turnaround Costs	1.54	2.37	1.63	1.08	0.64	1.44

1. Contains a non-GAAP financial measure. See the Specified Financial Measures Advisory of this Supplemental.

2. In the Canadian Refining segment, operating expenses represent expenses associated with the Lloydminster Upgrader, the Lloydminster Refinery and the commercial fuels business.

3. Specified financial measure. See the Specified Financial Measures Advisory of this Supplemental.

4. Reflects Cenovus's 50 percent interest in Wood River and Borger refinery operations.

5. Includes diesel and jet fuel.

‌Specified Financial Measures

Certain financial measures, including non-GAAP financial measures, in this document do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS"), as issued by the International Accounting Standards Board (the "IFRS Accounting Standards"), and are considered specified financial measures. These specified financial measures may not be comparable to similar measures presented by other issuers. See the Specified Financial Measures Advisory located in our Management's Discussion and Analysis ("MD&A") for the periods ended March 31, 2025, September 30, 2024, and June 30, 2024, and our annual MD&A for the year ended December 31, 2024 (available on SEDAR+ at sedarplus.ca) for information incorporated by reference about these specified financial measures.

We have replaced our definitions of Refining Margin and Market Capture with Adjusted Refining Margin and Adjusted Market Capture, respectively, which excludes the impact of inventory holding gains or losses. These gains or losses reflect the difference between the cost of volumes produced at current-period costs and the cost of volumes produced under the first-in, first-out or weighted average cost basis, as required by IFRS Accounting Standards. For definitions and reconciliations, please refer to the Specified Financial Measures Advisory located in our MD&A for the period ended March 31, 2025.