EX-99.2 3 a992-q22026mda.htm EX-99.2
Exhibit 99.2
Baytex Energy Corp.
Management’s Discussion and Analysis
For the three and six months ended June 30, 2026 and 2025
Dated July 30, 2026
The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and six months ended June 30, 2026. This information is provided as of July 30, 2026. In this MD&A, references to “Baytex”, the “Company”, “we”, “us” and “our” and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three and six months ended June 30, 2026 ("Q2/2026" and "YTD 2026") have been compared with the results for the three and six months ended June 30, 2025 ("Q2/2025" and "YTD 2025"). This MD&A should be read in conjunction with the Company’s unaudited condensed consolidated interim financial statements (“consolidated financial statements”) for the three and six months ended June 30, 2026, its audited comparative consolidated financial statements for the years ended December 31, 2025 and 2024, together with the accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31, 2025. These documents and additional information about Baytex are accessible on the SEDAR+ website at www.sedarplus.ca and through the U.S. Securities and Exchange Commission at www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share amounts or as otherwise noted.
In this MD&A, barrel of oil equivalent (“boe”) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil, which represents an energy equivalency conversion method applicable at the burner tip and does not represent a value equivalency at the wellhead. While it is useful for comparative measures, it may not accurately reflect individual product values and may be misleading if used in isolation.
This MD&A contains forward-looking information and statements along with certain measures which do not have any standardized meaning in accordance with International Financial Reporting Standards ("IFRS") as prescribed by the International Accounting Standards Board ("IASB"). The terms "operating netback", "free cash flow", "average royalty rate", "heavy oil, net of blending and other expense" and "total sales, net of blending and other expense" are specified financial measures that do not have any standardized meaning as prescribed by IFRS and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. This MD&A also contains the terms "adjusted funds flow" and "net cash" which are capital management measures. Refer to our advisory on forward-looking information and statements and a summary of our specified financial measures at the end of the MD&A.
BAYTEX ENERGY CORP.
Baytex Energy Corp. is a Canadian oil and natural gas company based in Calgary, Alberta. Baytex has oil and natural gas assets in Western Canada primarily comprised of Viking and Duvernay light oil assets along with heavy oil assets in Peace River and Lloydminster.
1

PRESENTATION OF CONTINUING AND DISCONTINUED OPERATIONS
In Q4/2025, we completed the disposition of the operated and non-operated Eagle Ford assets which comprised the U.S. operating segment. This operating segment represented a geographical area of our operations and its results have been classified as discontinued operations. The financial results for the three and six months ended June 30, 2026 and June 30, 2025 are disaggregated between continuing and discontinued operations in the table below.
In this MD&A, references to "Canada", "Canadian operations" and similar terms refer to the continuing operations of Baytex Energy Corp. and references to "U.S. operations", "Eagle Ford" and similar terms refer to the discontinued operations.

| Three Months Ended June 30
| 2026 | 2025
| Continuing | Discontinued | Total | Continuing | Discontinued | Total
Revenue, net of royalties |  |  |  |  |  |
Petroleum and natural gas sales | $ | 639,943 |  | $ | — |  | $ | 639,943 |  | $ | 411,036 |  | $ | 475,543 |  | $ | 886,579 |
Royalties | (90,378) |  | — |  | (90,378) |  | (47,800) |  | (129,590) |  | (177,390) |
| 549,565 |  | — |  | 549,565 |  | 363,236 |  | 345,953 |  | 709,189 |
Expenses |  |  |  |  |  |
Operating | 89,843 |  | — |  | 89,843 |  | 88,035 |  | 72,985 |  | 161,020 |
Transportation | 25,932 |  | — |  | 25,932 |  | 20,544 |  | 12,363 |  | 32,907 |
Blending and other | 75,068 |  | — |  | 75,068 |  | 62,381 |  | — |  | 62,381 |
General and administrative | 16,480 |  | — |  | 16,480 |  | 16,595 |  | 5,625 |  | 22,220 |
Exploration and evaluation | 810 |  | — |  | 810 |  | 457 |  | — |  | 457 |
Depletion and depreciation | 128,945 |  | — |  | 128,945 |  | 118,004 |  | 204,155 |  | 322,159 |
Share-based compensation | 4,317 |  | — |  | 4,317 |  | 863 |  | 692 |  | 1,555 |
Net financing and interest expense | 4,516 |  | — |  | 4,516 |  | 46,869 |  | 4,844 |  | 51,713 |
Financial derivatives gain | (21,443) |  | — |  | (21,443) |  | (18,663) |  | — |  | (18,663) |
Foreign exchange gain | (316) |  | — |  | (316) |  | (100,586) |  | — |  | (100,586) |
Gain on dispositions | (261) |  | (6,281) |  | (6,542) |  | (666) |  | — |  | (666) |
Other expense (income) | 2,057 |  | — |  | 2,057 |  | 2,703 |  | (2,018) |  | 685 |
| 325,948 |  | (6,281) |  | 319,667 |  | 236,536 |  | 298,646 |  | 535,182 |
Net income before income taxes | 223,617 |  | 6,281 |  | 229,898 |  | 126,700 |  | 47,307 |  | 174,007 |
Income taxes |  |  |  |  |  |
Current income tax expense (recovery) | — |  | — |  | — |  | 6,038 |  | (1,491) |  | 4,547 |
Deferred income tax expense | 55,029 |  | — |  | 55,029 |  | 17,644 |  | 267 |  | 17,911 |
| 55,029 |  | — |  | 55,029 |  | 23,682 |  | (1,224) |  | 22,458 |
Net income | $ | 168,588 |  | $ | 6,281 |  | $ | 174,869 |  | $ | 103,018 |  | $ | 48,531 |  | $ | 151,549 |

2

| Six Months Ended June 30
| 2026 | 2025
| Continuing | Discontinued | Total | Continuing | Discontinued | Total
Revenue, net of royalties |  |  |  |  |  |
Petroleum and natural gas sales | $ | 1,092,897 |  | $ | — |  | $ | 1,092,897 |  | $ | 865,187 |  | $ | 1,020,522 |  | $ | 1,885,709 |
Royalties | (141,967) |  | — |  | (141,967) |  | (107,056) |  | (278,271) |  | (385,327) |
| 950,930 |  | — |  | 950,930 |  | 758,131 |  | 742,251 |  | 1,500,382 |
Expenses |  |  |  |  |  |
Operating | 171,087 |  | — |  | 171,087 |  | 163,615 |  | 145,108 |  | 308,723 |
Transportation | 49,066 |  | — |  | 49,066 |  | 39,323 |  | 24,096 |  | 63,419 |
Blending and other | 150,989 |  | — |  | 150,989 |  | 135,201 |  | — |  | 135,201 |
General and administrative | 38,779 |  | — |  | 38,779 |  | 35,161 |  | 12,665 |  | 47,826 |
Exploration and evaluation | 1,475 |  | — |  | 1,475 |  | 564 |  | — |  | 564 |
Depletion and depreciation | 252,635 |  | — |  | 252,635 |  | 234,747 |  | 407,335 |  | 642,082 |
Share-based compensation | 27,187 |  | — |  | 27,187 |  | 1,276 |  | 1,042 |  | 2,318 |
Net financing and interest expense | 7,613 |  | — |  | 7,613 |  | 97,436 |  | 9,523 |  | 106,959 |
Financial derivatives loss | 129,313 |  | — |  | 129,313 |  | 30,956 |  | — |  | 30,956 |
Foreign exchange loss (gain) | 1,618 |  | — |  | 1,618 |  | (104,464) |  | — |  | (104,464) |
(Gain) loss on dispositions | (2,278) |  | (19,720) |  | (21,998) |  | 563 |  | — |  | 563 |
Other expense (income) | 3,761 |  | — |  | 3,761 |  | 5,099 |  | (3,225) |  | 1,874 |
| 831,245 |  | (19,720) |  | 811,525 |  | 639,477 |  | 596,544 |  | 1,236,021 |
Net income before income taxes | 119,685 |  | 19,720 |  | 139,405 |  | 118,654 |  | 145,707 |  | 264,361 |
Income taxes |  |  |  |  |  |
Current income tax expense (recovery) | — |  | 1,086 |  | 1,086 |  | 6,985 |  | (286) |  | 6,699 |
Deferred income tax expense | 30,776 |  | — |  | 30,776 |  | 26,006 |  | 10,516 |  | 36,522 |
| 30,776 |  | 1,086 |  | 31,862 |  | 32,991 |  | 10,230 |  | 43,221 |
Net income | $ | 88,909 |  | $ | 18,634 |  | $ | 107,543 |  | $ | 85,663 |  | $ | 135,477 |  | $ | 221,140 |

SECOND QUARTER HIGHLIGHTS
Baytex delivered strong operating and financial results in Q2/2026, highlighted by production of 71,243 boe/d, which exceeded the high end of our annual guidance range of 69,000 - 71,000 boe/d. Strong performance in the Duvernay and across our heavy oil portfolio supported an increase to our 2026 production guidance to approximately 71,000 boe/d, with no change to our exploration and development expenditures guidance of approximately $625 million.
We invested $122.2 million in exploration and development activities during Q2/2026, consistent with our full-year capital plan and focused on our heavy oil and Duvernay development programs. During the quarter, we brought 26.0 net wells on production and continued to advance our 2026 development program.
Our financial results for Q2/2026 reflect strong operating performance and higher benchmark oil prices, partially offset by realized financial derivative losses. We generated adjusted funds flow(1) of $254.4 million and cash flows from operating activities of $230.9 million, compared to adjusted funds flow from continuing operations of $112.5 million and cash flows from operating activities from continuing operations of $85.7 million in Q2/2025.
We generated free cash flow(2) of $128.0 million in Q2/2026, reflecting the disciplined execution of our exploration and development programs while maintaining a strong balance sheet. During the quarter, we repurchased 21.7 million common shares for $138.6 million under our normal course issuer bid and declared a quarterly dividend of $0.0225 per share.
Net cash(1) was $566.3 million at June 30, 2026 compared to $765.8 million at December 31, 2025. The change reflects free cash flow generated during the period offset by shareholder returns, including share repurchases and dividends.
(1)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
3

GUIDANCE
Based on strong operating performance to-date and planned activity for the remainder of the year we have revised our 2026 production guidance to approximately 71,000 boe/d.
The following table compares our 2026 revised annual guidance to our previously announced guidance and YTD 2026 results.

| 2026 Annual Guidance | Revised Annual Guidance | YTD 2026 Results
Exploration and development expenditures (1) | ~ $625 million | No change | $267.3 million
Production (boe/d) (1) | 69,000 - 71,000 | ~ 71,000 | 70,366
Expenses: |  |  |
Average royalty rate (2)(3) | 15% | No change | 15.1 | %
Operating (2)(4) | $13.75 - $14.25/boe | No change | $13.43/boe
Transportation (2)(4) | $3.40 - $3.60/boe | No change | $3.85/boe
Leasing expenditures (2) | $7 million | No change | $4.0 million
Asset retirement obligations settled (2) | $20 million | No change | $4.6 million

(1)As announced on May 7, 2026.
(2)As announced on December 22, 2025.
(3)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(4)Refer to the Operating Expense and Transportation Expense sections of this MD&A for description of the composition of these measures.
RESULTS OF OPERATIONS
Production

| Three Months Ended June 30 | Six Months Ended June 30
| 2026 | 2025 | Change | 2026 | 2025 | Change
Daily Production |  |  |  |  |  |
Liquids (bbl/d) |  |  |  |  |  |
Light oil and condensate | 12,236 | 11,167 | 10% | 12,036 | 11,469 | 5%
Heavy oil | 46,349 | 42,959 | 8% | 45,632 | 41,583 | 10%
Natural Gas Liquids (NGL) | 4,409 | 2,986 | 48% | 4,389 | 3,054 | 44%
Total liquids (bbl/d) | 62,994 | 57,112 | 10% | 62,057 | 56,106 | 11%
Natural gas (mcf/d) | 49,502 | 42,331 | 17% | 49,851 | 43,033 | 16%
Daily production (boe/d) - continuing operations | 71,243 | 64,167 | 11% | 70,366 | 63,279 | 11%
Daily production (boe/d) - discontinued operations | — | 83,928 | (100)% | — | 82,877 | (100)%
Total production (boe/d) | 71,243 | 148,095 | (52)% | 70,366 | 146,156 | (52)%
Production Mix - continuing operations |  |  |  |  |  |
Light oil and condensate | 17 | % | 17 | % | — | % | 17 | % | 18 | % | (1) | %
Heavy oil | 65 | % | 67 | % | (2) | % | 65 | % | 66 | % | (1) | %
NGL | 6 | % | 5 | % | 1 | % | 6 | % | 5 | % | 1 | %
Natural gas | 12 | % | 11 | % | 1 | % | 12 | % | 11 | % | 1 | %

Production from continuing operations of 71,243 boe/d for Q2/2026 and 70,366 boe/d for YTD 2026 increased 11% for both periods compared to 64,167 boe/d for Q2/2025 and 63,279 boe/d for YTD 2025 with strong performance from both our heavy oil and Duvernay development programs over the last year.
Total production of 70,366 boe/d for YTD 2026 is consistent with our revised annual guidance of approximately 71,000 boe/d for 2026.
4

COMMODITY PRICES
The prices received for our crude oil and natural gas production directly impact our earnings, free cash flow and our financial position.
Benchmark Prices

| Three Months Ended June 30 | Six Months Ended June 30
| 2026 |  | 2025 |  | Change | 2026 |  | 2025 |  | Change
WTI oil (US$/bbl) (1) | 92.79 |  | 63.74 |  | 29.05 |  | 82.36 |  | 67.58 |  | 14.78 |
Edmonton par oil ($/bbl) (2) | 132.26 |  | 84.15 |  | 48.11 |  | 112.88 |  | 89.71 |  | 23.17 |
Edmonton par oil differential to WTI (US$/bbl) | 2.80 |  | (2.94) |  | 5.74 |  | (0.42) |  | (3.93) |  | 3.51 |
WCS heavy oil ($/bbl) (3) | 108.16 |  | 74.10 |  | 34.06 |  | 93.66 |  | 79.15 |  | 14.51 |
WCS heavy oil differential to WTI (US$/bbl) | (14.62) |  | (10.20) |  | (4.42) |  | (14.37) |  | (11.43) |  | (2.94) |
AECO 7A natural gas price ($/mcf) (4) | 1.51 |  | 2.07 |  | (0.56) |  | 2.00 |  | 2.05 |  | (0.05) |
AECO 5A natural gas price ($/mcf) (5) | 1.63 |  | 1.69 |  | (0.06) |  | 1.82 |  | 1.94 |  | (0.12) |
CAD/USD average exchange rate | 1.3836 |  | 1.3840 |  | (0.0004) |  | 1.3776 |  | 1.4095 |  | (0.0319) |

(1)WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.
(2)Edmonton par refers to the average posting price for the benchmark MSW crude oil.
(3)WCS refers to the average posting price for the benchmark WCS heavy oil.
(4)AECO 7A refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").
(5)AECO 5A refers to the AECO arithmetic average daily index price published by the CGPR.
Crude Oil
In March 2026, oil prices increased sharply and have remained volatile due to the conflict in Iran and related supply disruptions. The WTI benchmark price averaged US$92.79/bbl for Q2/2026 and US$82.36/bbl for YTD 2026 compared to US$63.74/bbl for Q2/2025 and US$67.58/bbl for YTD 2025.
Prices for Canadian oil trade at a discount to WTI due to limited egress to diversified markets and the cost of transportation from Western Canada. Differentials for Canadian oil prices relative to WTI fluctuate from period to period based on production and inventory levels in Western Canada.
We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $132.26/bbl during Q2/2026 and $112.88/bbl for YTD 2026 compared to $84.15/bbl during Q2/2025 and $89.71/bl for YTD 2025. Edmonton par differentials strengthened in Q2/2026 as Canadian light oil benefited from tighter global light crude and refined product markets. Edmonton par traded at a premium to WTI of US$2.80/bbl for Q2/2026 and at a discount of US$0.42/bbl for YTD 2026, compared to discounts of US$2.94/bbl for Q2/2025 and US$3.93/bbl for YTD 2025.
We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark averaged $108.16/bbl for Q2/2026 and $93.66/bbl for YTD 2026 compared to $74.10/bbl for Q2/2025 and $79.15/bbl for YTD 2025. The WCS heavy oil differential to WTI was US$14.62/bbl in Q2/2026 and US$14.37/bbl for YTD 2026 which was wider compared to US$10.20/bbl for Q2/2025 and US$11.43/bbl for YTD 2025 reflecting higher Western Canadian supply and increased competition from other heavy and sour crude barrels delivered to the U.S. Gulf Coast.
Natural Gas
We compare our natural gas pricing to the AECO 7A benchmark which averaged $1.51/mcf during Q2/2026 and $2.00/mcf during YTD 2026 compared to $2.07/mcf for Q2/2025 and $2.05/mcf for YTD 2025. Natural gas prices in Canada remain low due to increasing production combined with egress constraints and slow ramp-up of LNG related demand.
5

Average Realized Sales Prices

| Three Months Ended June 30 | Six Months Ended June 30
| 2026 | 2025 | Change | 2026 | 2025 | Change
Light oil and condensate ($/bbl) (1) | $ | 131.91 |  | $ | 82.54 |  | $ | 49.37 |  | $ | 108.26 |  | $ | 88.32 |  | $ | 19.94 |
Heavy oil, net of blending and other expense ($/bbl) (2) | 94.92 |  | 64.43 |  | 30.49 |  | 81.26 |  | 68.79 |  | 12.47 |
NGL ($/bbl) (1) | 27.32 |  | 22.93 |  | 4.39 |  | 24.57 |  | 25.54 |  | (0.97) |
Natural gas ($/mcf) (1) | 1.48 |  | 1.73 |  | (0.25) |  | 1.70 |  | 1.89 |  | (0.19) |
Total sales, net of blending and other expense ($/boe) (2) - continuing operations | $ | 87.13 |  | $ | 59.71 |  | $ | 27.42 |  | $ | 73.96 |  | $ | 63.74 |  | $ | 10.22 |
Total sales ($/boe) - discontinued operations | — |  | 62.26 |  | (62.26) |  | — |  | 68.03 |  | (68.03) |
Total sales, net of blending and other expense ($/boe) (2) | $ | 87.13 |  | $ | 61.16 |  | $ | 25.97 |  | $ | 73.96 |  | $ | 66.17 |  | $ | 7.79 |

(1)Calculated as light oil and condensate or NGL sales divided by barrels of oil equivalent production volume for the applicable period, or natural gas sales divided by the production volume in Mcf for the applicable period for continuing operations.
(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
Our total sales, net of blending and other expense per boe for continuing operations was $87.13/boe for Q2/2026 and $73.96/boe for YTD 2026 compared to $59.71/boe for Q2/2025 and $63.74/boe for YTD 2025. The increase is primarily due to higher benchmark oil pricing relative to both periods of 2025.
Our realized light oil and condensate price for continuing operations represents a discount to the Edmonton par price of $0.35/bbl for Q2/2026 and $4.62/bbl for YTD 2026 compared to a discount of $1.61/bbl in Q2/2025 and $1.39/bbl in YTD 2025. The narrower discount in Q2/2026 is more reflective of normal operations and the wider discount in YTD 2026 reflects the timing of production along with the increase in benchmark oil prices during Q1 2026.
Our realized heavy oil price, net of blending and other expense for continuing operations was higher in Q2/2026 and YTD 2026 compared to the same periods of 2025 which reflects the increase in WCS benchmark pricing. Our realized pricing for Q2/2026 and YTD 2026 represents a discount to the WCS benchmark of $13.24/bbl and $12.40/bbl respectively compared to $9.67/bbl Q2/2025 and $10.36/bbl for YTD 2025 which reflects higher blending costs.
Our realized NGL price as a percentage of WTI varies based on the product mix of our NGL volumes and changes in the market prices for the underlying products. Expressed in Canadian dollars, our realized NGL price for continuing operations was 21% of WTI in Q2/2026 and 22% in YTD 2026 compared to 26% of WTI in Q2/2025 and 27% in YTD 2025, reflecting lower market prices for propane and butane during 2026 relative to 2025.
We compare our Canadian realized natural gas price to the AECO benchmark price. A portion of our natural gas sales is based on the daily index prices which fluctuate independently from the associated monthly index prices. Our realized natural gas price for continuing operations of $1.48/mcf for Q2/2026 and $1.70/mcf for YTD 2026 was lower than $1.73/mcf for Q2/2025 and $1.89/mf for YTD 2025.
6

PETROLEUM AND NATURAL GAS SALES

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands) | 2026 | 2025 | Change | 2026 | 2025 | Change
Oil sales |  |  |  |  |  |
Light oil and condensate | $ | 146,868 |  | $ | 83,876 |  | $ | 62,992 |  | $ | 235,861 |  | $ | 183,344 |  | $ | 52,517 |
Heavy oil | 475,431 |  | 314,254 |  | 161,177 |  | 822,168 |  | 652,965 |  | 169,203 |
NGL | 10,960 |  | 6,232 |  | 4,728 |  | 19,520 |  | 14,121 |  | 5,399 |
Total oil sales | 633,259 |  | 404,362 |  | 228,897 |  | 1,077,549 |  | 850,430 |  | 227,119 |
Natural gas sales | 6,684 |  | 6,674 |  | 10 |  | 15,348 |  | 14,757 |  | 591 |
Total petroleum and natural gas sales | 639,943 |  | 411,036 |  | 228,907 |  | 1,092,897 |  | 865,187 |  | 227,710 |
Blending and other expense | (75,068) |  | (62,381) |  | (12,687) |  | (150,989) |  | (135,201) |  | (15,788) |
Total sales, net of blending and other expense (1) - continuing operations | $ | 564,875 |  | $ | 348,655 |  | $ | 216,220 |  | $ | 941,908 |  | $ | 729,986 |  | $ | 211,922 |
Total sales - discontinued operations | — |  | 475,543 |  | (475,543) |  | — |  | 1,020,522 |  | (1,020,522) |
Total sales, net of blending and other expense (1) | $ | 564,875 |  | $ | 824,198 |  | $ | (259,323) |  | $ | 941,908 |  | $ | 1,750,508 |  | $ | (808,600) |

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
Total sales, net of blending and other expense for continuing operations was $564.9 million for Q2/2026 and $941.9 million for YTD 2026 compared to $348.7 million for Q2/2025 and $730.0 million for YTD 2025. The increase in total sales, net of blending and other expense reflects higher realized pricing and higher production in both Q2/2026 and YTD 2026. The increase in our realized pricing for Q2/2026 relative to Q2/2025 resulted in a $177.8 million increase in total sales, net of blending and other expense, and higher production contributed a $38.4 million increase in total sales, net of blending and other expense. Higher realized pricing resulted in a $130.1 million increase in total sales, net of blending and other expense, in YTD 2026 relative to YTD 2025 while higher production contributed an $81.8 million increase in total sales, net of blending and other expense, in YTD 2026 relative to YTD 2025.
ROYALTIES
Royalties are paid to various government entities and to land and mineral rights owners. Royalties are calculated based on gross revenues or on operating netbacks less capital investment for specific heavy oil projects and are generally expressed as a percentage of total sales, net of blending and other expense. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction.
The following table summarizes our royalties and royalty rates for the three and six months ended June 30, 2026 and 2025.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands except for % and per boe) | 2026 | 2025 | Change | 2026 | 2025 | Change
Royalties - continuing operations | $ | 90,378 | $ | 47,800 | $ | 42,578 | $ | 141,967 | $ | 107,056 | $ | 34,911
Royalties - discontinued operations | — | 129,590 | (129,590) | — | 278,271 | (278,271)
Total royalties | $ | 90,378 | $ | 177,390 | $ | (87,012) | $ | 141,967 | $ | 385,327 | $ | (243,360)
Average royalty rate (1) - continuing operations | 16.0 | % | 13.7 | % | 2.3 | % | 15.1 | % | 14.7 | % | 0.4 | %
Average royalty rate (1) - discontinued operations | — | % | 27.3 | % | (27.3) | % | — | % | 27.3 | % | (27.3) | %
Total average royalty rate (1) | 16.0 | % | 21.5 | % | (5.5) | % | 15.1 | % | 22.0 | % | (6.9) | %
Royalties per boe (2) - continuing operations | $ | 13.94 | $ | 8.19 | $ | 5.75 | $ | 11.15 | $ | 9.35 | $ | 1.80
Royalties per boe (2) - discontinued operations | $ | — | $ | 16.97 | $ | (16.97) | $ | — | $ | 18.55 | $ | (18.55)
Total royalties per boe (2) | $ | 13.94 | $ | 13.16 | $ | 0.78 | $ | 11.15 | $ | 14.57 | $ | (3.42)

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(2)Royalties per boe is calculated as royalties divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.
Royalties for continuing operations were $90.4 million or 16.0% of total sales, net of blending and other expense for Q2/2026 compared to $47.8 million or 13.7% for Q2/2025. Royalties for continuing operations were $142.0 million or 15.1% of total sales, net of blending and other expense for YTD 2026 compared to $107.1 million or 14.7% for YTD 2025. Our average royalty rate was higher for Q2/2026 and YTD 2026 as a result of higher benchmark prices.
Our average royalty rate of 15.1% for YTD 2026 is consistent with our annual guidance of approximately 15% for 2026.
OPERATING EXPENSE

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands except for per boe) | 2026 | 2025 | Change | 2026 | 2025 | Change
Operating expense - continuing operations | $ | 89,843 |  | $ | 88,035 |  | $ | 1,808 |  | $ | 171,087 |  | $ | 163,615 |  | $ | 7,472 |
Operating expense - discontinued operations | — |  | 72,985 |  | (72,985) |  | — |  | 145,108 |  | (145,108) |
Total operating expense | $ | 89,843 |  | $ | 161,020 |  | $ | (71,177) |  | $ | 171,087 |  | $ | 308,723 |  | $ | (137,636) |
Operating expense per boe (1) - continuing operations | $ | 13.86 |  | $ | 15.08 |  | $ | (1.22) |  | $ | 13.43 |  | $ | 14.29 |  | $ | (0.86) |
Operating expense per boe (1) - discontinued operations | $ | — |  | $ | 9.56 |  | $ | (9.56) |  | $ | — |  | $ | 9.67 |  | $ | (9.67) |
Total operating expense per boe (1) | $ | 13.86 |  | $ | 11.95 |  | $ | 1.91 |  | $ | 13.43 |  | $ | 11.67 |  | $ | 1.76 |

(1)Operating expense per boe is calculated as operating expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.
Operating expense for continuing operations was $89.8 million ($13.86/boe) for Q2/2026 and $171.1 million ($13.43/boe) for YTD 2026 compared to $88.0 million ($15.08/boe) for Q2/2025 and $163.6 million ($14.29/boe) for YTD 2025. Operating expense for continuing operations for Q2/2026 and YTD 2026 increased compared to Q2/2025 and YTD 2025 due to increased production over the same period while per unit operating expense decreased as higher production volumes enabled costs to be absorbed over a larger production base.
Operating expense of $13.43/boe for YTD 2026 is slightly below our annual guidance range of $13.75 - $14.25/boe for 2026.
TRANSPORTATION EXPENSE
Transportation expense includes the costs incurred to move production via truck or pipeline to the sales point. Transportation expense can vary from period to period as we seek to optimize sales prices and transportation rates. The following table compares our transportation expense for the three and six months ended June 30, 2026 and 2025.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands except for per boe) | 2026 | 2025 | Change | 2026 | 2025 | Change
Transportation expense - continuing operations | $ | 25,932 |  | $ | 20,544 |  | $ | 5,388 |  | $ | 49,066 |  | $ | 39,323 |  | $ | 9,743 |
Transportation expense - discontinued operations | — |  | 12,363 |  | (12,363) |  | — |  | 24,096 |  | (24,096) |
Total transportation expense | $ | 25,932 |  | $ | 32,907 |  | $ | (6,975) |  | $ | 49,066 |  | $ | 63,419 |  | $ | (14,353) |
Transportation expense per boe (1) - continuing operations | $ | 4.00 |  | $ | 3.52 |  | $ | 0.48 |  | $ | 3.85 |  | $ | 3.43 |  | $ | 0.42 |
Transportation expense per boe (1) - discontinued operations | $ | — |  | $ | 1.62 |  | $ | (1.62) |  | $ | — |  | $ | 1.61 |  | $ | (1.61) |
Total transportation expense per boe (1) | $ | 4.00 |  | $ | 2.44 |  | $ | 1.56 |  | $ | 3.85 |  | $ | 2.40 |  | $ | 1.45 |

(1)Transportation expense per boe is calculated as transportation expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.
Transportation expense for continuing operations was $25.9 million ($4.00/boe) for Q2/2026 and $49.1 million ($3.85/boe) for YTD 2026 compared to $20.5 million ($3.52/boe) for Q2/2025 and $39.3 million ($3.43/boe) for YTD 2025. The increase in transportation expense for both periods of 2026 reflects higher heavy oil production and an increase in trucking rates relative to 2025.
Transportation expense of $3.85/boe for YTD 2026 is consistent with expectations and slightly above our annual guidance range of $3.40 - $3.60/boe for 2026.
7

BLENDING AND OTHER EXPENSE
Blending and other expense primarily includes the cost of blending diluent purchased to reduce the viscosity of our heavy oil transported through pipelines in order to meet pipeline specifications. The purchased diluent is recorded as blending and other expense. The price received for the blended product is recorded as heavy oil sales revenue. We net blending and other expense against heavy oil sales to compare the realized price on our produced volumes to benchmark pricing.
Blending and other expense was $75.1 million for Q2/2026 and $151.0 million for YTD 2026 compared to $62.4 million for Q2/2025 and $135.2 million for YTD 2025. Higher blending and other expense for both periods in 2026 is a result of the increase in the cost of condensate purchased for blending in Q2/2026 and higher heavy oil production compared to both periods in 2025.
FINANCIAL DERIVATIVES
As part of our normal operations, our business is exposed to fluctuations in commodity prices. In an effort to manage this exposure, we may utilize various financial derivative contracts which are intended to reduce the volatility in our cash flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets fluctuate and as new contracts are entered into.
The following table summarizes the results of our financial derivative contracts for the three and six months ended June 30, 2026 and 2025.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands) | 2026 |  | 2025 |  | Change | 2026 |  | 2025 |  | Change
Realized financial derivatives gain (loss) |  |  |  |  |  |
Crude oil | $ | (84,824) |  | $ | (12,448) |  | $ | (72,376) |  | $ | (114,715) |  | $ | (13,281) |  | $ | (101,434) |
Natural gas | 678 |  | 574 |  | 104 |  | 1,280 |  | 1,213 |  | 67 |
Total | $ | (84,146) |  | $ | (11,874) |  | $ | (72,272) |  | $ | (113,435) |  | $ | (12,068) |  | $ | (101,367) |
Unrealized financial derivatives gain (loss) |  |  |  |  |  |
Crude oil | $ | 106,578 |  | $ | 18,426 |  | $ | 88,152 |  | $ | (15,492) |  | $ | (15,615) |  | $ | 123 |
Natural gas | (989) |  | 12,111 |  | (13,100) |  | (386) |  | (3,273) |  | 2,887 |
Total | $ | 105,589 |  | $ | 30,537 |  | $ | 75,052 |  | $ | (15,878) |  | $ | (18,888) |  | $ | 3,010 |
Total financial derivatives gain (loss) |  |  |  |  |  |
Crude oil | $ | 21,754 |  | $ | 5,978 |  | $ | 15,776 |  | $ | (130,207) |  | $ | (28,896) |  | $ | (101,311) |
Natural gas | (311) |  | 12,685 |  | (12,996) |  | 894 |  | (2,060) |  | 2,954 |
Total | $ | 21,443 |  | $ | 18,663 |  | $ | 2,780 |  | $ | (129,313) |  | $ | (30,956) |  | $ | (98,357) |

We recorded a total financial derivatives gain of $21.4 million for Q2/2026 and a loss of $129.3 million for YTD 2026 compared to a gain of $18.7 million for Q2/2025 and a loss of $31.0 million for YTD 2025. The realized financial derivatives loss of $113.4 million for YTD 2026 was primarily a result of the increase in benchmark oil prices in March 2026 resulting in market prices for crude oil settling at levels above those set in our derivative contracts which were entered into prior to the sale of our U.S. operations.The unrealized financial derivatives loss of $15.9 million for YTD 2026 reflects both the reclassification of unrealized losses to realized losses upon settlement of contracts during Q2/2026 and the increase in forecasted crude oil pricing used to revalue outstanding volumes on crude oil contracts in place at June 30, 2026, relative to December 31, 2025. The fair value of our financial derivative contracts resulted in a net asset of $10.6 million at June 30, 2026 compared to a net asset of $26.5 million at December 31, 2025.
Refer to Note 18 of the consolidated financial statements for a complete listing of our outstanding contracts at July 30, 2026.
8

OPERATING NETBACK
The following table summarizes our operating netback on a per boe basis for the three and six months ended June 30, 2026 and 2025.

| Three Months Ended June 30 | Six Months Ended June 30
($ per boe except for volume) | 2026 | 2025 | Change | 2026 | 2025 | Change
Daily production (boe/d) - continuing operations | 71,243 |  | 64,167 |  | 11 | % | 70,366 |  | 63,279 |  | 11 | %
Daily production (boe/d) - discontinued operations | — |  | 83,928 |  | (100) | % | — |  | 82,877 |  | (100) | %
Total production (boe/d) | 71,243 |  | 148,095 |  | (52) | % | 70,366 |  | 146,156 |  | (52) | %
Operating netback: |  |  |  |  |  |
Total sales, net of blending and other expense (1) | $ | 87.13 |  | $ | 59.71 |  | $ | 27.42 |  | $ | 73.96 |  | $ | 63.74 |  | $ | 10.22 |
Less: |  |  |  |  |  |
Royalties (2) | (13.94) |  | (8.19) |  | (5.75) |  | (11.15) |  | (9.35) |  | (1.80) |
Operating expense (2) | (13.86) |  | (15.08) |  | 1.22 |  | (13.43) |  | (14.29) |  | 0.86 |
Transportation expense (2) | (4.00) |  | (3.52) |  | (0.48) |  | (3.85) |  | (3.43) |  | (0.42) |
Operating netback (1) - continuing operations | $ | 55.33 |  | $ | 32.92 |  | $ | 22.41 |  | $ | 45.53 |  | $ | 36.67 |  | $ | 8.86 |
Operating netback (1) - discontinued operations | — |  | 34.11 |  | (34.11) |  | — |  | 38.20 |  | (38.20) |
Operating netback (1) | $ | 55.33 |  | $ | 33.61 |  | $ | 21.72 |  | $ | 45.53 |  | $ | 37.53 |  | $ | 8.00 |
Realized financial derivatives loss (3) | (12.98) |  | (0.88) |  | (12.10) |  | (8.91) |  | (0.46) |  | (8.45) |
Operating netback after financial derivatives (1) | $ | 42.35 |  | $ | 32.73 |  | $ | 9.62 |  | $ | 36.62 |  | $ | 37.07 |  | $ | (0.45) |

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(2)Refer to Royalties, Operating Expense and Transportation Expense sections in this MD&A for a description of the composition these measures.
(3)Calculated as realized financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period.
Our operating netback for continuing operations of $55.33/boe for Q2/2026 and $45.53/boe for YTD 2026 was higher than $32.92/boe for Q2/2025 and $36.67/boe for YTD 2025 due to the increase in our realized price which resulted in higher per unit sales net of royalties. Combined operating and transportation expense for Q2/2026 and YTD 2026 was consistent with the same periods of 2025. Our operating netback after financial derivatives of $42.35/boe for Q2/2026 was higher than $32.73/boe for Q2/2025 due to higher realized pricing while our operating netback after financial derivatives of $36.62/boe for YTD 2026 was lower than $37.07/boe for YTD 2025 due to higher realized financial derivatives losses in 2026 compared to 2025.
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative ("G&A") expense includes head office and corporate costs such as salaries and employee benefits, public company costs and administrative recoveries earned for operating exploration and development activities on behalf of our working interest partners. G&A expense fluctuates with head office staffing levels and the level of operated exploration and development activity during the period.
9

The following table summarizes our G&A expense for the three and six months ended June 30, 2026 and 2025.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands except for per boe) | 2026 |  | 2025 (1) | Change | 2026 |  | 2025 (1) | Change
Gross G&A expense - continuing operations | $ | 17,876 |  | $ | 18,179 |  | $ | (303) |  | $ | 42,107 |  | $ | 38,803 |  | $ | 3,304 |
Overhead recoveries - continuing operations | (1,396) |  | (1,584) |  | 188 |  | (3,328) |  | (3,642) |  | 314 |
G&A expense - continuing operations | $ | 16,480 |  | $ | 16,595 |  | $ | (115) |  | $ | 38,779 |  | $ | 35,161 |  | $ | 3,618 |
G&A expense - discontinued operations (2) | — |  | 5,625 |  | (5,625) |  | — |  | 12,665 |  | (12,665) |
Total G&A expense | $ | 16,480 |  | $ | 22,220 |  | $ | (5,740) |  | $ | 38,779 |  | $ | 47,826 |  | $ | (9,047) |
G&A expense per boe (3) - continuing operations | $ | 2.54 |  | $ | 2.84 |  | $ | (0.30) |  | $ | 3.04 |  | $ | 3.07 |  | $ | (0.03) |
G&A expense per boe (3) - discontinued operations | $ | — |  | $ | 0.74 |  | $ | (0.74) |  | $ | — |  | $ | 0.84 |  | $ | (0.84) |
Total G&A expense per boe (3) | $ | 2.54 |  | $ | 1.65 |  | $ | 0.89 |  | $ | 3.04 |  | $ | 1.81 |  | $ | 1.23 |

(1)Comparative period revised to reflect current period presentation. Refer to Note 6 of the consolidated financial statements for additional information.
(2)General and administrative expense for discontinued operations is net of recoveries.
(3)General and administrative expense per boe is calculated as general and administrative expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.
G&A expense for continuing operations was $16.5 million ($2.54/boe) for Q2/2026 and $38.8 million ($3.04/boe) for YTD 2026 compared to $16.6 million ($2.84/boe) for Q2/2025 and $35.2 million ($3.07/boe) for YTD 2025. G&A expense for continuing operations includes severance and other non-recurring costs related to staff reductions in Canada which resulted in higher G&A expense for YTD 2026 compared to YTD 2025.
NET FINANCING AND INTEREST EXPENSE
Net financing and interest includes interest expense on our credit facilities, long-term notes and lease obligations, interest income earned on our cash deposits, as well as non-cash financing costs which include the accretion on our debt issue costs and asset retirement obligations. Net financing and interest varies depending on debt levels outstanding during the period, the applicable borrowing rates, CAD/USD foreign exchange rates, cash deposits held during the period, along with the carrying amount of asset retirement obligations and the discount rates used to present value these obligations.
10

The following table summarizes our financing and interest expense for the three and six months ended June 30, 2026 and 2025.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands except for per boe) | 2026 |  | 2025 (1) | Change | 2026 |  | 2025 (1) | Change
Interest on credit facilities | $ | 842 |  | $ | 3,502 |  | $ | (2,660) |  | $ | 1,729 |  | $ | 6,839 |  | $ | (5,110) |
Interest on long-term notes | 1,636 |  | 37,683 |  | (36,047) |  | 3,355 |  | 77,962 |  | (74,607) |
Interest on lease obligations | 1,443 |  | 337 |  | 1,106 |  | 2,538 |  | 662 |  | 1,876 |
Interest income | (4,623) |  | (42) |  | (4,581) |  | (11,078) |  | (392) |  | (10,686) |
Net cash interest (income) expense | $ | (702) |  | $ | 41,480 |  | $ | (42,182) |  | $ | (3,456) |  | $ | 85,071 |  | $ | (88,527) |
Amortization of debt issue costs | 63 |  | 3,526 |  | (3,463) |  | 579 |  | 5,904 |  | (5,325) |
Accretion of asset retirement obligations | 5,155 |  | 4,618 |  | 537 |  | 10,193 |  | 9,216 |  | 977 |
Early redemption expense (gain) | — |  | (2,755) |  | 2,755 |  | 297 |  | (2,755) |  | 3,052 |
Net financing and interest expense - continuing operations | $ | 4,516 |  | $ | 46,869 |  | $ | (42,353) |  | $ | 7,613 |  | $ | 97,436 |  | $ | (89,823) |
Net financing and interest expense - discontinued operations | — |  | 4,844 |  | (4,844) |  | — |  | 9,523 |  | (9,523) |
Total net financing and interest expense | $ | 4,516 |  | $ | 51,713 |  | $ | (47,197) |  | $ | 7,613 |  | $ | 106,959 |  | $ | (99,346) |
Net financing and interest expense per boe (2) - continuing operations | $ | 0.70 |  | $ | 8.03 |  | $ | (7.33) |  | $ | 0.60 |  | $ | 8.51 |  | $ | (7.91) |
Net financing and interest expense per boe (2) - discontinued operations | $ | — |  | $ | 0.63 |  | $ | (0.63) |  | $ | — |  | $ | 0.63 |  | $ | (0.63) |
Total net financing and interest expense per boe (2) | $ | 0.70 |  | $ | 3.84 |  | $ | (3.14) |  | $ | 0.60 |  | $ | 4.04 |  | $ | (3.44) |

(1)Comparative period revised to reflect current period presentation. Refer to Note 6 of the consolidated financial statements for additional information.
(2)Calculated as net financing and interest expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.
Net financing and interest expense for continuing operations was $4.5 million ($0.70/boe) for Q2/2026 and $7.6 million ($0.60/boe) for YTD 2026 compared to $46.9 million ($8.03/boe) for Q2/2025 and $97.4 million ($8.51/boe) for YTD 2025. Lower net financing and interest expense for Q2/2026 and YTD 2026 reflects the repayment of nearly all of our outstanding debt following the Eagle Ford disposition in Q4/2025.
We recorded net cash interest income for continuing operations of $0.7 million for Q2/2026 and $3.5 million for YTD 2026 compared to interest expense of $41.5 million for Q2/2025 and $85.1 million for YTD 2025. In Q4/2025, we repaid the majority of our outstanding credit facilities, redeemed the 8.5% Senior Notes and partially redeemed the 7.375% Senior Notes which resulted in lower interest on our credit facilities and long-term notes in Q2/2026 and YTD 2026. Interest on our credit facilities for Q2/2026 and YTD 2026 reflects the standby fees rate of 0.5% compared to the weighted average interest rate of 6.5% for Q2/2025 and 6.6% for YTD 2025. Interest income for Q2/2026 and YTD 2026 reflects interest earned on cash deposits held in high-interest savings accounts during the period.
Accretion of asset retirement obligations for continuing operations of $5.2 million for Q2/2026 and $10.2 million for YTD 2026 was consistent with $4.6 million for Q2/2025 and $9.2 million for YTD 2025. Amortization of debt issue costs for continuing operations of $0.1 million for Q2/2026 and $0.6 million for YTD 2026 was lower than $3.5 million for Q2/2025 and $5.9 million for YTD 2025 due to the de-recognition of debt issue costs associated with the credit facilities and the long-term notes in Q4/2025.
EXPLORATION AND EVALUATION EXPENSE
Exploration and evaluation ("E&E") expense is related to the expiry of leases and the de-recognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the Company's exploration programs. Exploration and evaluation expense from continuing operations was $0.8 million for Q2/2026 and $1.5 million for YTD 2026 compared to $0.5 million for Q2/2025 and $0.6 million for YTD 2025.
11

DEPLETION AND DEPRECIATION
Depletion and depreciation expense varies with the carrying amount of the Company's oil and gas properties, the amount of proved and probable reserves volumes and the rate of production for the period. The following table summarizes depletion and depreciation expense for the three and six months ended June 30, 2026 and 2025.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands except for per boe) | 2026 | 2025 (1) | Change | 2026 | 2025 (1) | Change
Depletion and depreciation - continuing operations | $ | 128,945 |  | $ | 118,004 |  | $ | 10,941 |  | $ | 252,635 |  | $ | 234,747 |  | $ | 17,888 |
Depletion and depreciation - discontinued operations | — |  | 204,155 |  | (204,155) |  | — |  | 407,335 |  | (407,335) |
Total depletion and depreciation | $ | 128,945 |  | $ | 322,159 |  | $ | (193,214) |  | $ | 252,635 |  | $ | 642,082 |  | $ | (389,447) |
Depletion and depreciation per boe (2) - continuing operations | $ | 19.89 |  | $ | 20.21 |  | $ | (0.32) |  | $ | 19.84 |  | $ | 20.50 |  | $ | (0.66) |
Depletion and depreciation per boe (2) - discontinued operations | $ | — |  | $ | 26.73 |  | $ | (26.73) |  | $ | — |  | $ | 27.15 |  | $ | (27.15) |
Total depletion and depreciation per boe (2) | $ | 19.89 |  | $ | 23.90 |  | $ | (4.01) |  | $ | 19.84 |  | $ | 24.27 |  | $ | (4.43) |

(1)Comparative period revised to reflect current period presentation. Refer to Note 6 of the consolidated financial statements for additional information.
(2)Depletion and depreciation expense per boe is calculated as depletion and depreciation expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.
Depletion and depreciation expense for continuing operations was $128.9 million ($19.89/boe) for Q2/2026 and $252.6 million ($19.84/boe) for YTD 2026 compared to $118.0 million ($20.21/boe) for Q2/2025 and $234.7 million ($20.50/boe) for YTD 2025. Depletion and depreciation expense for continuing operations was higher in Q2/2026 and YTD 2026 relative to Q2/2025 and YTD 2025 due to higher production as the depletion rate has decreased.
IMPAIRMENT
We concluded there were no indicators of impairment or impairment reversal on all of our oil and gas properties and exploration and evaluation assets at June 30, 2026.
SHARE-BASED COMPENSATION EXPENSE
Share-based compensation ("SBC") expense includes expense associated with our Share Award Incentive Plan, Incentive Award Plan, and Deferred Share Unit Plan. SBC expense associated with equity-classified awards is recognized in net income or loss over the vesting period of the awards with a corresponding increase in contributed surplus. SBC expense associated with cash-settled awards is recognized in net income or loss over the vesting period of the awards with a corresponding share-based compensation liability. SBC expense varies with the quantity of share awards outstanding and changes in the market price of our common shares.
We recorded SBC expense of $4.3 million for Q2/2026 and $27.2 million for YTD 2026 for our continuing operations compared to $0.9 million for Q2/2025 and $1.3 million for YTD 2025. The increase for Q2/2026 and YTD 2026 primarily reflects changes in the Company's share price, which increased the value of the awards resulting in higher SBC expense relative to the same periods in 2025. The total expense for YTD 2026 for continuing operations is comprised of $22.3 million of cash expense and $4.9 million of non-cash expense for awards designated as equity-settled.
FOREIGN EXCHANGE
Unrealized foreign exchange gains and losses are primarily a result of changes in the reported amount of our U.S. dollar denominated long-term notes and credit facilities in our Canadian functional currency entities. The long-term notes and credit facilities are translated to Canadian dollars on the balance sheet date using the closing CAD/USD exchange rate resulting in unrealized gains and losses. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in our Canadian functional currency entities.
12

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands except for exchange rates) | 2026 |  | 2025 | Change | 2026 |  | 2025 | Change
Unrealized foreign exchange loss (gain) | $ | 1,693 |  | $ | (100,792) |  | $ | 102,485 |  | $ | 3,323 |  | $ | (104,267) |  | $ | 107,590 |
Realized foreign exchange (gain) loss | (2,009) |  | 206 |  | (2,215) |  | (1,705) |  | (197) |  | (1,508) |
Foreign exchange (gain) loss - continuing operations | $ | (316) |  | $ | (100,586) |  | $ | 100,270 |  | $ | 1,618 |  | $ | (104,464) |  | $ | 106,082 |
CAD/USD exchange rates: |  |  |  |  |  |
At beginning of period | 1.3956 |  | 1.4379 |  |  | 1.3715 |  | 1.4405 |  |
At end of period | 1.4206 |  | 1.3622 |  |  | 1.4206 |  | 1.3622 |  |

We recorded a foreign exchange gain for continuing operations of $0.3 million for Q2/2026 and loss of $1.6 million for YTD 2026 compared to gains of $100.6 million for Q2/2025 and $104.5 million for YTD 2025.
The unrealized foreign exchange loss for continuing operations of $1.7 million for Q2/2026 and $3.3 million for YTD 2026 is related to changes in the reported amount of our U.S. dollar denominated long-term notes due to the weakening of the Canadian dollar relative to the U.S. dollar at June 30, 2026 compared to March 31, 2026 and December 31, 2025. The unrealized foreign exchange gain of $100.8 million for Q2/2025 and $104.3 million for YTD 2025 is related to changes in the reported amount of our long-term notes and credit facilities due to the strengthening of the Canadian dollar relative to the U.S. dollar at June 30, 2025 compared to March 31, 2025 and December 31, 2024.
Realized foreign exchange gains and losses will fluctuate depending on the amount and timing of day-to-day U.S. dollar denominated transactions for our Canadian operations. We recorded a realized foreign exchange gain for continuing operations of $2.0 million for Q2/2026 and $1.7 million for YTD 2026 compared to a loss of $0.2 million for Q2/2025 and a gain of $0.2 million for YTD 2025.
INCOME TAXES

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands) | 2026 |  | 2025 (1) | Change | 2026 |  | 2025 (1) | Change
Current income tax expense | $ | — |  | $ | 6,038 |  | $ | (6,038) |  | $ | — |  | $ | 6,985 |  | $ | (6,985) |
Deferred income tax expense | 55,029 |  | 17,644 |  | 37,385 |  | 30,776 |  | 26,006 |  | 4,770 |
Income tax expense - continuing operations | $ | 55,029 |  | $ | 23,682 |  | $ | 31,347 |  | $ | 30,776 |  | $ | 32,991 |  | $ | (2,215) |
Income tax (recovery) expense - discontinued operations | $ | — |  | $ | (1,224) |  | $ | 1,224 |  | $ | — |  | $ | 10,230 |  | $ | (10,230) |

(1)Comparative period revised to reflect current period presentation. Refer to Note 6 of the consolidated financial statements for additional information.
We did not record current income tax for continuing operations in Q2/2026 and YTD 2026 and recorded an expense of $6.0 million for Q2/2025 and $7.0 million for YTD 2025.
We recorded a deferred income tax expense for continuing operations of $55.0 million for Q2/2026 and $30.8 million for YTD 2026 compared to expense of $17.6 million for Q2/2025 and $26.0 million for YTD 2025. The deferred tax expense for Q2/2026 and YTD 2026 reflects an effective tax rate of 24.6% and 25.7% which is similar to our statutory rate of 24.2%.
In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency ("CRA") that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. Following objections and submissions, in November 2023 the CRA issued notices of confirmation regarding their prior reassessments. In February 2024, Baytex filed notices of appeal with the Tax Court of Canada (“TCC”) and we estimate it could take another two years to receive a judgment. The reassessments do not require us to pay any amounts in order to participate in the appeals process. Should we be unsuccessful at the TCC, additional appeals are available; a process that we estimate could take another two years and potentially longer.
We remain confident that the tax filings of the affected entities are correct and will defend our tax filing positions. During 2023, we purchased $272.5 million of insurance coverage for a premium of $50.3 million which will help manage the litigation risk associated with this matter. The most recent statement of account issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $244.2 million and a late filing penalty in respect of the 2011 tax year of $4.1 million.
By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. First, the reassessments allege that the trusts were resettled and the resulting successor trusts were not able to access the losses of the predecessor
13

trusts. Second, the reassessments allege that the general anti-avoidance rule of the Income Tax Act (Canada) operates to deny the deduction of the Losses. In September 2025, the Department of Justice, legal counsel for the Crown, abandoned the position that the trusts were resettled. The issue of whether the general anti-avoidance rule applies remains in dispute. If, after exhausting available appeals, the deduction of the Losses continues to be disallowed, either the trusts or their corporate beneficiary will owe cash taxes, late payment interest and potential penalties. The amount of cash taxes owing, late payment interest and potential penalties are dependent upon the taxpayer(s) ultimately liable (the trusts or their corporate beneficiary) and the amount of unused tax shelter available to the taxpayer(s) to offset the reassessed income, including tax shelter from subsequent years that may be carried back and applied to prior years.
NET INCOME AND ADJUSTED FUNDS FLOW
The components of adjusted funds flow and net income or loss for the three and six months ended June 30, 2026 and 2025 are set forth in the following table.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands) | 2026 |  | 2025 (1) | Change | 2026 |  | 2025 (1) | Change
Petroleum and natural gas sales | $ | 639,943 |  | $ | 411,036 |  | $ | 228,907 |  | $ | 1,092,897 |  | $ | 865,187 |  | $ | 227,710 |
Royalties | (90,378) |  | (47,800) |  | (42,578) |  | (141,967) |  | (107,056) |  | (34,911) |
Revenue, net of royalties | 549,565 |  | 363,236 |  | 186,329 |  | 950,930 |  | 758,131 |  | 192,799 |
Expenses |  |  |  |  |  |
Operating | (89,843) |  | (88,035) |  | (1,808) |  | (171,087) |  | (163,615) |  | (7,472) |
Transportation | (25,932) |  | (20,544) |  | (5,388) |  | (49,066) |  | (39,323) |  | (9,743) |
Blending and other | (75,068) |  | (62,381) |  | (12,687) |  | (150,989) |  | (135,201) |  | (15,788) |
Operating netback (2) from continuing operations | $ | 358,722 |  | $ | 192,276 |  | $ | 166,446 |  | $ | 579,788 |  | $ | 419,992 |  | $ | 159,796 |
General and administrative | (16,480) |  | (16,595) |  | 115 |  | (38,779) |  | (35,161) |  | (3,618) |
Net cash interest income (expense) | 702 |  | (41,480) |  | 42,182 |  | 3,456 |  | (85,071) |  | 88,527 |
Realized financial derivatives loss | (84,146) |  | (11,874) |  | (72,272) |  | (113,435) |  | (12,068) |  | (101,367) |
Realized foreign exchange gain (loss) | 2,009 |  | (206) |  | 2,215 |  | 1,705 |  | 197 |  | 1,508 |
Cash other expense | (2,057) |  | (2,703) |  | 646 |  | (3,761) |  | (5,099) |  | 1,338 |
Current income tax expense | — |  | (6,038) |  | 6,038 |  | — |  | (6,985) |  | 6,985 |
Cash share-based compensation | (4,317) |  | (863) |  | (3,454) |  | (22,330) |  | (1,276) |  | (21,054) |
Adjusted funds flow (3) from continuing operations | $ | 254,433 |  | $ | 112,517 |  | $ | 141,916 |  | $ | 406,644 |  | $ | 274,529 |  | $ | 132,115 |
Exploration and evaluation | (810) |  | (457) |  | (353) |  | (1,475) |  | (564) |  | (911) |
Depletion and depreciation | (128,945) |  | (118,004) |  | (10,941) |  | (252,635) |  | (234,747) |  | (17,888) |
Non-cash share-based compensation | — |  | — |  | — |  | (4,857) |  | — |  | (4,857) |
Non-cash financing and interest | (5,218) |  | (5,389) |  | 171 |  | (11,069) |  | (12,365) |  | 1,296 |
Unrealized financial derivatives gain (loss) | 105,589 |  | 30,537 |  | 75,052 |  | (15,878) |  | (18,888) |  | 3,010 |
Unrealized foreign exchange (loss) gain | (1,693) |  | 100,792 |  | (102,485) |  | (3,323) |  | 104,267 |  | (107,590) |
Gain (loss) on dispositions | 261 |  | 666 |  | (405) |  | 2,278 |  | (563) |  | 2,841 |
Deferred income tax expense | (55,029) |  | (17,644) |  | (37,385) |  | (30,776) |  | (26,006) |  | (4,770) |
Net income from continuing operations | $ | 168,588 |  | $ | 103,018 |  | $ | 65,570 |  | $ | 88,909 |  | $ | 85,663 |  | $ | 3,246 |
Net income from discontinued operations | 6,281 |  | 48,531 |  | (42,250) |  | 18,634 |  | 135,477 |  | (116,843) |
Net income | $ | 174,869 |  | $ | 151,549 |  | $ | 23,320 |  | $ | 107,543 |  | $ | 221,140 |  | $ | (113,597) |

(1)Comparative period revised to reflect current period presentation. Refer to Note 6 of the consolidated financial statements for additional information.
(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(3)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
14

We generated adjusted funds flow from continuing operations of $254.4 million for Q2/2026 and $406.6 million for YTD 2026 compared to $112.5 million for Q2/2025 and $274.5 million for YTD 2025. The increase in adjusted funds flow for both periods of 2026 is a result of an increase in operating netback which is primarily due to higher benchmark pricing, an increase in production and lower cash interest expense due to the repayment of nearly all outstanding debt in Q4/2025. The increase in operating netback was partially offset by higher realized losses on financial derivatives.
We reported net income from continuing operations of $168.6 million for Q2/2026 and $88.9 million for YTD 2026 compared to $103.0 million for Q2/2025 and $85.7 million for YTD 2025. The increase in net income for both periods of 2026 relative to 2025 is due to an increase in adjusted funds flow as well as higher unrealized financial derivative gains, partially offset by lower unrealized foreign exchange gains.
CAPITAL EXPENDITURES
Capital expenditures for the three and six months ended June 30, 2026 and 2025 are summarized as follows.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands) | 2026 | 2025 | Change | 2026 | 2025 | Change
Drilling, completion and equipping | $ | 98,546 |  | $ | 121,950 |  | $ | (23,404) |  | $ | 220,126 |  | $ | 289,428 |  | $ | (69,302) |
Facilities and other | 23,696 |  | 25,784 |  | (2,088) |  | 47,128 |  | 42,625 |  | 4,503 |
Exploration and development expenditures - continuing operations | $ | 122,242 |  | $ | 147,734 |  | $ | (25,492) |  | $ | 267,254 |  | $ | 332,053 |  | $ | (64,799) |
Exploration and development expenditures - discontinued operations | — |  | 208,798 |  | (208,798) |  | — |  | 429,576 |  | (429,576) |
Total exploration and development expenditures | $ | 122,242 |  | $ | 356,532 |  | $ | (234,290) |  | $ | 267,254 |  | $ | 761,629 |  | $ | (494,375) |
Property acquisitions - continuing operations | $ | 226 |  | $ | 905 |  | $ | (679) |  | $ | 8,353 |  | $ | 1,374 |  | $ | 6,979 |
Proceeds from dispositions - continuing operations | $ | 162 |  | $ | (863) |  | $ | 1,025 |  | $ | 202 |  | $ | (3,540) |  | $ | 3,742 |
Property acquisitions - discontinued operations | $ | — |  | $ | 288 |  | $ | (288) |  | $ | — |  | $ | 1,076 |  | $ | (1,076) |
Proceeds from dispositions - discontinued operations | $ | (6,281) |  | $ | 138 |  | $ | (6,419) |  | $ | (19,434) |  | $ | 549 |  | $ | (19,983) |

Exploration and development expenditures for continuing operations were $122.2 million in Q2/2026 and $267.3 million for YTD 2026 compared to $147.7 million in Q2/2025 and $332.1 million in YTD 2025. Exploration and development expenditures for continuing operations for YTD 2026 included costs associated with drilling 96 (78.5 net) wells along with 90 (78.8 net) wells that were brought on production compared to drilling 124 (118.6 net) wells along with 132 (126.6 net) wells brought on production during YTD 2025. We also invested $47.1 million on facilities and other expenditures during YTD 2026.
Exploration and development expenditures of $267.3 million for YTD 2026 were consistent with expectations and our annual guidance for 2026 of approximately $625 million.
CAPITAL RESOURCES AND LIQUIDITY
Our capital management objective is to maintain a strong financial position that provides flexibility to execute our development programs, provide returns to shareholders and optimize our portfolio. Baytex assesses its capital structure in response to operational requirements and changes in economic conditions. At June 30, 2026, the Company's capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, inventory, trade payables, share-based compensation liability, dividends payable, cash and the credit facilities.
In order to manage its capital structure and liquidity, Baytex may from time-to-time issue or repurchase equity or debt securities, enter into business transactions including the sale of assets or adjust capital spending to manage current and projected liquidity levels. There is no certainty that any of these additional sources of capital would be available if required.
At June 30, 2026 we had net cash(1) of $566.3 million compared to $765.8 million at December 31, 2025. The decrease in net cash from December 31, 2025 primarily reflects shareholder returns of $342.9 million during YTD 2026, which includes share buybacks and quarterly dividends, partially offset by $129.8 million of free cash flow(2) earned during YTD 2026.
(1)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
Credit Facilities
At June 30, 2026, Baytex had $750 million of revolving credit facilities (the "Credit Facilities") that mature on June 27, 2030. The Credit Facilities are secured and are comprised of a $50 million operating loan and a $700 million syndicated revolving loan. The Credit Facilities were undrawn at June 30, 2026.
The Credit Facilities contain standard commercial covenants in addition to the financial covenants detailed below. Advances under the Baytex Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, Canadian Overnight Repo Rate Average rates or Secured Overnight Financing Rates, plus applicable margins.
At June 30, 2026, Baytex had $4.4 million of outstanding letters of credit (December 31, 2025 - $4.4 million outstanding) under the Credit Facilities.
The agreements and associated amending agreements relating to the Credit Facilities are accessible on the SEDAR+ website at www.sedarplus.ca and through the U.S. Securities and Exchange Commission at www.sec.gov.
Financial Covenants
The following table summarizes the financial covenants applicable to the Credit Facilities and our compliance therewith at June 30, 2026.

Covenant Description | Position as at June 30, 2026 | Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) | 0:0:1.0 | 3.5:1.0
Interest Coverage (3) (Minimum Ratio) | 9.3:1.0 | 3.5:1.0
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio) | 0.1:1.0 | 4.0:1.0

(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreement and is defined as the principal amount of the Credit Facilities and other secured obligations identified in the credit facility agreement. As at June 30, 2026, the Company's Senior Secured Debt totaled $4.4 million.
(2)"Bank EBITDA" is calculated based on terms and definitions set out in the credit facility agreement which adjusts net income or loss for financing and interest expense, income taxes, non-recurring losses, certain specific unrealized and non-cash transactions and is calculated based on a trailing twelve-month basis including the impact of material dispositions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended June 30, 2026 was $758.9 million.
(3)"Interest coverage" is calculated in accordance with the credit facility agreement and is computed as the ratio of Bank EBITDA to financing and interest expense, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis including the impact of material dispositions as if they had occurred at the beginning of the twelve month period. Financing and interest expense for the twelve months ended June 30, 2026 was $81.5 million.
(4)"Total Debt" is calculated in accordance with the credit facility agreement and is defined as all obligations, liabilities, and indebtedness of Baytex excluding trade payables, share-based compensation liability, dividends payable, asset retirement obligations, lease obligations, deferred income tax liability, and financial derivative liabilities. As at June 30, 2026, the Company's Total Debt totaled $95.5 million of principal amounts outstanding.
Long-Term Notes
During YTD 2026, Baytex repurchased and cancelled US$5.8 million principal amount of the 7.375% Senior Notes at 103.613% of par value and recorded an early redemption expense of $0.3 million. The 7.375% Senior Notes were issued on April 1, 2024 and US$64.1 million remains outstanding as at June 30, 2026. The 7.375% Senior Notes mature on March 15, 2032 and are redeemable at our option, in whole or in part, at specified redemption prices on or after March 15, 2027 and will be redeemable at par from March 15, 2029 to maturity.
Shareholders’ Capital
We are authorized to issue an unlimited number of common shares and 10.0 million preferred shares. The rights and terms of preferred shares are determined upon issuance. During the six months ended June 30, 2026, we issued 0.1 million common shares pursuant to our share-based compensation program. As at June 30, 2026, we had 708.9 million common shares issued and outstanding and no preferred shares issued and outstanding. As at July 30, 2026, there were 699.2 million common shares issued and outstanding and no preferred shares issued and outstanding.
During the six months ended June 30, 2026, we repurchased 56.8 million common shares under our normal course issuer bid ("NCIB") at an average price of $5.46 per share for total consideration of $310.1 million. In June 2026, the Toronto Stock Exchange ("TSX") accepted the renewal of our NCIB under which we are permitted to purchase for cancellation up to 70.9 million common shares over the 12-month period commencing July 2, 2026, which represents 10% of the Company's public float, as defined by the TSX, as at June 19, 2026. We have obtained an exemption order from the Canadian securities regulators which permits us to purchase common shares through the New York Stock Exchange and other U.S. based trading systems.
During the six months ended June 30, 2026, we recorded a $6.2 million charge to shareholders’ capital related to the federal tax on equity repurchases (December 31, 2025 - $0.5 million).
On January 2, April 1, 2026 and July 2, 2026, we paid quarterly cash dividends of $0.0225 per share to shareholders of record. On July 30, 2026, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on October 1, 2026 to shareholders of record on September 15, 2026. These dividends are designated as “eligible dividends” for Canadian income tax purposes. These dividends are considered “qualified dividends” for U.S income tax purposes.
Contractual Obligations
We have a number of financial obligations that are incurred in the ordinary course of business. A significant portion of these obligations will be funded by adjusted funds flow. These obligations as of June 30, 2026 and the expected timing for funding these obligations are noted in the table below.

($ thousands) | Total | Less than 1 year | 1-3 years | 3-5 years | Beyond 5 years
Long-term notes - principal | $ | 91,107 |  | $ | — |  | $ | — |  | $ | — |  | $ | 91,107 |
Interest on long-term notes | 38,381 |  | 6,719 |  | 13,438 |  | 13,438 |  | 4,786 |
Lease obligations - principal | 96,756 |  | 15,837 |  | 23,396 |  | 18,049 |  | 39,474 |
Processing agreements | 4,496 |  | 630 |  | 543 |  | 525 |  | 2,798 |
Transportation agreements | 66,410 |  | 36,092 |  | 24,381 |  | 3,320 |  | 2,617 |
Total | $ | 297,150 |  | $ | 59,278 |  | $ | 61,758 |  | $ | 35,332 |  | $ | 140,782 |

We also have ongoing obligations related to the abandonment and reclamation of well sites and facilities when they reach the end of their economic lives. The present value of the future estimated abandonment and reclamation costs are included in the asset retirement obligations presented in the statement of financial position. Programs to abandon and reclaim well sites and facilities are undertaken regularly in accordance with applicable legislative requirements.
The Company is, from time-to-time, subject to various claims, demands, audits and other proceedings covering matters that arise in the ordinary course of business activities. Such claims and other proceedings often relate to labour, tax, personal injury, environmental, title or commercial matters. Baytex retains liability for matters related to our prior ownership of assets located in the U.S. Resolution of these matters may have an unfavorable financial or operating impact on the Company. Certain conditions may exist as at June 30, 2026 which may result in a loss to the Company. However, the Company believes that none of these matters are expected to have a material effect on the results of operations or financial position of the Company.
The Company establishes legal provisions for known and potential claims for which payment is probable and can be reliably estimated. The Company also has comprehensive liability insurance coverage; however such insurance does not cover all risks to which we might be exposed and in other cases, may only partially cover losses incurred by the Company.
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QUARTERLY FINANCIAL INFORMATION

| 2026 | 2025 | 2024
($ thousands, except per common share amounts) | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3
Petroleum and natural gas sales | 639,943 |  | 452,954 |  | 759,815 |  | 927,648 |  | 886,579 |  | 999,130 |  | 1,017,017 |  | 1,074,623 |
Net income (loss) - continuing operations (1) | 168,588 |  | (79,679) |  | (334,057) |  | (28,451) |  | 103,018 |  | (17,355) |  | (124,903) |  | 96,204 |
Per common share - basic | 0.23 |  | (0.11) |  | (0.43) |  | (0.04) |  | 0.13 |  | (0.02) |  | (0.16) |  | 0.12 |
Per common share - diluted | 0.23 |  | (0.11) |  | (0.43) |  | (0.04) |  | 0.13 |  | (0.02) |  | (0.16) |  | 0.12 |
Net income (loss) | 174,869 |  | (67,326) |  | (856,887) |  | 31,968 |  | 151,549 |  | 69,591 |  | (38,477) |  | 185,219 |
Per common share - basic | 0.24 |  | (0.09) |  | (1.12) |  | 0.04 |  | 0.20 |  | 0.09 |  | (0.05) |  | 0.23 |
Per common share - diluted | 0.24 |  | (0.09) |  | (1.12) |  | 0.04 |  | 0.20 |  | 0.09 |  | (0.05) |  | 0.23 |
Adjusted funds flow (2) | 254,433 |  | 151,125 |  | 261,531 |  | 422,232 |  | 366,919 |  | 463,870 |  | 461,886 |  | 537,947 |
Per common share - basic | 0.35 |  | 0.20 |  | 0.34 |  | 0.55 |  | 0.48 |  | 0.60 |  | 0.59 |  | 0.68 |
Per common share - diluted | 0.35 |  | 0.20 |  | 0.34 |  | 0.55 |  | 0.48 |  | 0.60 |  | 0.59 |  | 0.67 |
Free cash flow (3) | 128,045 |  | 1,705 |  | 76,486 |  | 142,688 |  | 3,188 |  | 52,529 |  | 254,838 |  | 220,159 |
Per common share - basic | 0.18 |  | — |  | 0.10 |  | 0.19 |  | — |  | 0.07 |  | 0.33 |  | 0.28 |
Per common share - diluted | 0.18 |  | — |  | 0.10 |  | 0.18 |  | — |  | 0.07 |  | 0.33 |  | 0.28 |
Cash flows from operating activities | 230,852 |  | 122,203 |  | 227,657 |  | 472,676 |  | 354,312 |  | 431,317 |  | 468,865 |  | 550,042 |
Per common share - basic | 0.32 |  | 0.16 |  | 0.30 |  | 0.62 |  | 0.46 |  | 0.56 |  | 0.60 |  | 0.69 |
Per common share - diluted | 0.32 |  | 0.16 |  | 0.30 |  | 0.61 |  | 0.46 |  | 0.56 |  | 0.60 |  | 0.69 |
Dividends declared | 16,144 |  | 16,606 |  | 17,268 |  | 17,326 |  | 17,304 |  | 17,289 |  | 17,598 |  | 17,732 |
Per common share | 0.0225 |  | 0.0225 |  | 0.0225 |  | 0.0225 |  | 0.0225 |  | 0.0225 |  | 0.0225 |  | 0.0225 |
Exploration and development | 122,242 |  | 145,012 |  | 174,078 |  | 270,364 |  | 356,532 |  | 405,097 |  | 198,177 |  | 306,332 |
Canada | 122,242 |  | 145,012 |  | 92,720 |  | 123,579 |  | 147,734 |  | 184,319 |  | 108,971 |  | 120,473 |
U.S. (4) | — |  | — |  | 81,358 |  | 146,785 |  | 208,798 |  | 220,778 |  | 89,206 |  | 185,859 |
Property acquisitions | 226 |  | 8,127 |  | 5,544 |  | 24,024 |  | 1,193 |  | 1,257 |  | 12,621 |  | 1,042 |
Proceeds from dispositions | (6,119) |  | (13,113) |  | (3,012,058) |  | (8,254) |  | (725) |  | (2,266) |  | (42,339) |  | (1,436) |
Net (cash) debt (2) | (566,286) |  | (591,151) |  | (765,785) |  | 2,244,358 |  | 2,293,940 |  | 2,390,250 |  | 2,417,172 |  | 2,493,269 |
Total assets | 3,169,943 |  | 3,252,692 |  | 3,345,414 |  | 7,601,389 |  | 7,552,013 |  | 7,824,576 |  | 7,759,745 |  | 7,614,157 |
Common shares outstanding | 708,888 |  | 730,561 |  | 765,568 |  | 768,317 |  | 768,317 |  | 770,039 |  | 773,590 |  | 787,328 |
Daily production |  |  |  |  |  |  |  |
Total production (boe/d) | 71,243 |  | 69,478 |  | 137,087 |  | 150,950 |  | 148,095 |  | 144,194 |  | 152,894 |  | 154,468 |
Canada (boe/d) | 71,243 |  | 69,478 |  | 67,295 |  | 68,185 |  | 64,167 |  | 62,380 |  | 65,332 |  | 64,668 |
U.S. (boe/d) (4) | — |  | — |  | 69,792 |  | 82,765 |  | 83,928 |  | 81,814 |  | 87,562 |  | 89,800 |
Benchmark prices |  |  |  |  |  |  |  |
WTI oil (US$/bbl) | 92.79 |  | 71.93 |  | 59.14 |  | 64.93 |  | 63.74 |  | 71.42 |  | 70.27 |  | 75.10 |
WCS heavy oil ($/bbl) | 108.16 |  | 49.28 |  | 66.88 |  | 75.14 |  | 74.10 |  | 84.33 |  | 80.77 |  | 83.98 |
Edmonton par oil ($/bbl) | 132.26 |  | 93.50 |  | 76.49 |  | 86.20 |  | 84.15 |  | 95.27 |  | 94.98 |  | 97.91 |
AECO 7A natural gas ($/mcf) | 1.51 |  | 2.49 |  | 2.34 |  | 1.00 |  | 2.07 |  | 2.02 |  | 1.46 |  | 0.81 |
CAD/USD avg exchange rate | 1.3836 |  | 1.3716 |  | 1.3949 |  | 1.3774 |  | 1.3840 |  | 1.4350 |  | 1.3992 |  | 1.3636 |
Total sales, net of blending and other expense ($/boe) (3) | 87.13 |  | 60.30 |  | 56.28 |  | 63.22 |  | 61.16 |  | 71.38 |  | 66.60 |  | 71.97 |
Royalties ($/boe) (5) | (13.94) |  | (8.25) |  | (11.54) |  | (13.05) |  | (13.16) |  | (16.02) |  | (14.69) |  | (15.75) |
Operating expense ($/boe) (5) | (13.86) |  | (12.99) |  | (12.51) |  | (11.54) |  | (11.95) |  | (11.38) |  | (10.36) |  | (11.76) |
Transportation expense ($/boe) (5) | (4.00) |  | (3.70) |  | (2.43) |  | (2.54) |  | (2.44) |  | (2.35) |  | (2.35) |  | (2.60) |
Operating netback ($/boe) (3) | 55.33 |  | 35.36 |  | 29.80 |  | 36.09 |  | 33.61 |  | 41.63 |  | 39.20 |  | 41.86 |
Financial derivatives (loss) gain ($/boe) (5) | (12.98) |  | (4.68) |  | 0.08 |  | (0.62) |  | (0.88) |  | (0.01) |  | (0.15) |  | 0.02 |
Operating netback after financial derivatives ($/boe) (3) | 42.35 |  | 30.68 |  | 29.88 |  | 35.47 |  | 32.73 |  | 41.62 |  | 39.05 |  | 41.88 |

(1)Previously disclosed amounts have been revised to conform with current period presentation.
(2)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
(3)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
(4)The Company's U.S. operations were disposed in December 2025.
(5)Calculated as royalties, operating expense, transportation expense or financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period.
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Our results for the previous eight quarters reflect the disciplined execution of our capital programs while oil and natural gas prices have fluctuated, along with acquisition and disposition activity. Production of 71,243 boe/d in Q2/2026 and 69,478 boe/d in Q1/2026 reflects our Canadian operations following the Eagle Ford disposition in Q4/2025. Our successful light and heavy oil development programs in Canada for YTD 2026 resulted in production growth to 71,243 boe/d from 64,668 boe/d in Q3/2024 despite the disposition of certain thermal assets in Q4/2024.
Benchmark prices for crude oil declined from Q3/2024 through Q4/2025 due to increasing supply from OPEC+ and North American production growth along with concerns over slowing global economic activity. Prices sharply increased in March 2026 and remained volatile through Q2/2026 due to supply disruptions related to the conflict in Iran and resulted in realized pricing of $87.13/boe for Q2/2026 and operating netback after financial derivatives of $42.35/boe. Adjusted funds flow is directly impacted by our average daily production and changes in benchmark commodity prices which are the basis for our realized sales price. Adjusted funds flow(1) of $254.4 million and cash flows from operating activities of $230.9 million for Q2/2026 reflect strong operating performance from our light and heavy oil assets.
In Q4/2025, we completed the disposition of the Eagle Ford assets which resulted in net cash(1) of $566.3 million at Q2/2026 compared to a net debt position of $2.5 billion at Q3/2024. The change in net (cash) debt also reflects free cash flow(2) of $659.5 million generated in the period since Q3/2024, along with $511.2 million of shareholder returns including share buybacks and quarterly dividends.
(1)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.
ENVIRONMENTAL REGULATIONS
As a result of our involvement in the exploration for and production of oil and natural gas we are subject to various emissions, carbon and other environmental regulations. Refer to the AIF for the year ended December 31, 2025 for a full description of the risks associated with these regulations and how they may impact our business in the future.
Reporting Regulations
Environmental reporting for public enterprises continues to evolve and the Company may be subject to additional future disclosure requirements. The International Sustainability Standards Board ("ISSB") has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. The Canadian Sustainability Standards Board has released voluntary standards for reporting periods starting on or after January 1, 2025 that are aligned with the ISSB release and include suggestions for Canadian-specific modifications. The Canadian Securities Administrators ("CSA") have also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth additional reporting requirements for Canadian Public Companies. In April 2025, the CSA announced it is pausing development of new sustainability reporting requirements to allow issuers to adapt to recent developments in the U.S. and globally. Baytex continues to monitor developments on these reporting requirements and has not yet quantified the cost to comply with these regulations.
OFF BALANCE SHEET TRANSACTIONS
We do not have any material financial arrangements that are excluded from the consolidated financial statements as at June 30, 2026, nor are any such arrangements outstanding as of the date of this MD&A.
CRITICAL ACCOUNTING ESTIMATES
There have been no changes in our critical accounting estimates in the six months ended June 30, 2026. Further information on our critical accounting policies and estimates can be found in the notes to the audited annual consolidated financial statements and MD&A for the year ended December 31, 2025.
CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2026, Baytex adopted amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures which were issued by the IASB in May 2024. The amendments further clarify the date of recognition and derecognition of financial assets and liabilities. These amendments have not had a material impact on our consolidated financial statements. The amendments have been applied retrospectively with no restatement of comparative information, in accordance with transition requirements on initial application of IFRS 9. The adjustment to the cash balance is reflected as a $1.8 million increase to the opening balance of cash in the consolidated statements of cash flows.
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SPECIFIED FINANCIAL MEASURES
In this MD&A, we refer to certain specified financial measures (such as total sales, net of blending and other expense, heavy oil sales, net of blending and other expense, operating netback, free cash flow, and average royalty rate) which do not have any standardized meaning prescribed by IFRS. While these measures are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. This MD&A also contains the terms "adjusted funds flow" and "net cash" which are capital management measures. We believe that inclusion of these specified financial measures provides useful information to financial statement users when evaluating the financial results of Baytex.
Non-GAAP Financial Measures
Total sales, net of blending and other expense and heavy oil, net of blending and other expense
Total sales, net of blending and other expense and heavy oil, net of blending and other expense represent the total revenues and heavy oil revenues realized from produced volumes during a period, respectively. Total sales, net of blending and other expense is comprised of total petroleum and natural gas sales adjusted for blending and other expense. Heavy oil, net of blending and other expense is calculated as heavy oil sales less blending and other expense. We believe including the blending and other expense associated with purchased volumes is useful when analyzing our realized pricing for produced volumes against benchmark commodity prices.
The following table reconciles heavy oil, net of blending and other expense to amounts disclosed in the primary financial statements from continuing operations.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands) | 2026 | 2025 | 2026 | 2025
Petroleum and natural gas sales | $ | 639,943 |  | $ | 411,036 |  | $ | 1,092,897 |  | $ | 865,187 |
Light oil and condensate (1) | (146,868) |  | (83,876) |  | (235,861) |  | (183,344) |
NGL (1) | (10,960) |  | (6,232) |  | (19,520) |  | (14,121) |
Natural gas (1) | (6,684) |  | (6,674) |  | (15,348) |  | (14,757) |
Heavy oil | $ | 475,431 |  | $ | 314,254 |  | $ | 822,168 |  | $ | 652,965 |
Blending and other expense (2) | (75,068) |  | (62,381) |  | (150,989) |  | (135,201) |
Heavy oil, net of blending and other expense | $ | 400,363 |  | $ | 251,873 |  | $ | 671,179 |  | $ | 517,764 |

(1)Component of petroleum and natural gas sales. See Note 14 - Petroleum and Natural Gas Sales in the consolidated financial statements for the three and six months ended June 30, 2026 for further information.
(2)The portion of blending and other expense that relates to heavy oil sales for the applicable period.
Operating netback
Operating netback and operating netback after financial derivatives are used to assess our operating performance and our ability to generate cash margin on a unit of production basis. Operating netback is comprised of petroleum and natural gas sales, less blending expense, royalties, operating expense and transportation expense. Realized financial derivatives gains and losses are added to operating netback to provide a more complete picture of our financial performance as our financial derivatives are used to reduce price uncertainty on a portion of our production.
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The following table reconciles operating netback and operating netback after realized financial derivatives to petroleum and natural gas sales from continuing operations.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands) | 2026 | 2025 | 2026 | 2025
Petroleum and natural gas sales | $ | 639,943 |  | $ | 411,036 |  | $ | 1,092,897 |  | $ | 865,187 |
Blending and other expense | (75,068) |  | (62,381) |  | (150,989) |  | (135,201) |
Total sales, net of blending and other expense | 564,875 |  | 348,655 |  | 941,908 |  | 729,986 |
Royalties | (90,378) |  | (47,800) |  | (141,967) |  | (107,056) |
Operating expense | (89,843) |  | (88,035) |  | (171,087) |  | (163,615) |
Transportation expense | (25,932) |  | (20,544) |  | (49,066) |  | (39,323) |
Operating netback - continuing operations | $ | 358,722 |  | $ | 192,276 |  | $ | 579,788 |  | $ | 419,992 |
Realized financial derivatives loss (1) | (84,146) |  | (11,874) |  | (113,435) |  | (12,068) |
Operating netback after realized financial derivatives - continuing operations | $ | 274,576 |  | $ | 180,402 |  | $ | 466,353 |  | $ | 407,924 |

(1)Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See Note 18 - Financial Instruments and Risk Management in the consolidated financial statements for the three and six months ended June 30, 2026 for further information.
Free cash flow
We use free cash flow to evaluate our financial performance and to assess the cash available for debt repayment, common share repurchases, dividends and acquisition opportunities. Free cash flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, additions to exploration and evaluation assets, additions to oil and gas properties, payments on lease obligations, and transaction costs.
Free cash flow is reconciled to cash flows from operating activities in the following table.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands) | 2026 | 2025 | 2026 | 2025
Cash flows from operating activities | $ | 230,852 |  | $ | 354,312 |  | $ | 353,055 |  | $ | 785,629 |
Change in non-cash working capital | 21,648 |  | 9,042 |  | 47,951 |  | 38,076 |
Additions to exploration and evaluation assets | — |  | (930) |  | (1,737) |  | (930) |
Additions to oil and gas properties | (122,242) |  | (355,602) |  | (265,517) |  | (760,699) |
Payments on lease obligations | (2,213) |  | (3,634) |  | (4,002) |  | (6,359) |
Free cash flow | $ | 128,045 |  | $ | 3,188 |  | $ | 129,750 |  | $ | 55,717 |

Non-GAAP Financial Ratios
Heavy oil, net of blending and other expense per bbl
Heavy oil, net of blending and other expense per bbl represents the realized price for produced heavy oil volumes during a period. Heavy oil, net of blending and other expense is a non-GAAP measure that is divided by barrels of heavy oil production volume for the applicable period for continuing operations to calculate the ratio. We use heavy oil, net of blending and other expense per bbl to analyze our realized heavy oil price for produced volumes against the WCS benchmark price in Canada.
Total sales, net of blending and other expense per boe
Total sales, net of blending and other per boe is used to compare our realized pricing to applicable benchmark prices and is calculated as total sales, net of blending and other expense (a non-GAAP financial measure) divided by barrels of oil equivalent production volume for the applicable period for continuing or total operations.
Average royalty rate
Average royalty rate is used to evaluate the performance of our operations from period to period and is comprised of royalties divided by total sales, net of blending and other expense (a non-GAAP financial measure) for continuing or total operations. Average royalty rate for discontinued operations is calculated as royalties divided by total petroleum and natural gas sales. The actual royalty rates can vary for a number of reasons, including the commodity produced, royalty contract terms, commodity price level, royalty incentives and the area or jurisdiction.
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Operating netback per boe
Operating netback per boe is operating netback (a non-GAAP financial measure) divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued, or total operations and is used to assess our operating performance on a unit of production basis. Realized financial derivative gains and losses per boe are added to operating netback per boe to arrive at operating netback after financial derivatives per boe. Realized financial derivatives gains and losses are added to operating netback to provide a more complete picture of our financial performance as our financial derivatives are used to reduce price uncertainty on a portion of our production.
Capital Management Measures
Net cash
We use net cash to monitor our current financial position and to evaluate existing sources of liquidity. We also use net cash projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. Net cash is comprised of our Credit Facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade payables, share-based compensation liability, dividends payable, cash, trade receivables, prepaids and other assets, and inventory.
The following table summarizes our calculation of net cash.

| As at
($ thousands) | June 30, 2026 | December 31, 2025
Credit facilities | $ | — |  | $ | 1,138 |
Unamortized debt issuance costs - Credit facilities (1) | — |  | 262 |
Long-term notes | 89,229 |  | 93,834 |
Unamortized debt issuance costs - Long-term notes (1) | 1,878 |  | 2,113 |
Trade payables | 275,032 |  | 236,373 |
Share-based compensation liability | 29,498 |  | 34,802 |
Dividends payable | 16,144 |  | 17,268 |
Cash | (720,337) |  | (953,113) |
Trade receivables | (188,260) |  | (135,230) |
Prepaids and other assets | (60,714) |  | (63,232) |
Inventory | (8,756) |  | — |
Net cash | $ | (566,286) |  | $ | (765,785) |

(1)Unamortized debt issuance costs were obtained from Note 8 - Credit Facilities and Note 9 - Long-term Notes from the consolidated financial statements for the three and six months ended June 30, 2026. These amounts represent the remaining balance of costs that were paid by Baytex at the inception of the contract.
Adjusted funds flow
Adjusted funds flow is used to monitor operating performance and the Company's ability to generate funds for exploration and development expenditures and settlement of abandonment obligations. Adjusted funds flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital and asset retirements obligations settled during the applicable period.
Adjusted funds flow is reconciled to amounts disclosed in the primary financial statements in the following table.

| Three Months Ended June 30 | Six Months Ended June 30
($ thousands) | 2026 | 2025 | 2026 | 2025
Cash flow from operating activities | $ | 230,852 |  | $ | 354,312 |  | $ | 353,055 |  | $ | 785,629 |
Change in non-cash working capital | 21,648 |  | 9,042 |  | 47,951 |  | 38,076 |
Asset retirement obligations settled | 1,933 |  | 3,565 |  | 4,552 |  | 7,084 |
Adjusted funds flow | $ | 254,433 |  | $ | 366,919 |  | $ | 405,558 |  | $ | 830,789 |

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INTERNAL CONTROL OVER FINANCIAL REPORTING
We are required to comply with Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings". This instrument requires us to disclose in our interim MD&A any material weaknesses in or changes to our internal control over financial reporting during the period that may have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We confirm that no material weaknesses or such changes were identified in our internal controls over financial reporting during the three and six months ended June 30, 2026.
FORWARD-LOOKING STATEMENTS
In the interest of providing our shareholders and potential investors with information regarding Baytex, including management's assessment of the Company’s future plans and operations, certain statements in this document are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "plan", "project", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this document speak only as of the date of this document and are expressly qualified by this cautionary statement.
Specifically, this document contains forward-looking statements relating to but not limited to: our 2026 guidance for: exploration and development expenditures, average daily production, royalty rate and operating expense, transportation expense, lease expenditures and asset retirement obligations settled; the we may seek to reduce cash flow volatility by using financial derivates; the expected time to resolve the reassessment of our tax filings by the Canada Revenue Agency; our objective to maintain a strong balance sheet to execute development programs, deliver shareholder returns and optimize our portfolio through strategic acquisitions and dispositions; that we may issue or repurchase debt or equity securities from time to time and sell adjust or adjust capital spending; our intent to fund a significant portion of our financial obligations with adjusted funds flow and the expected timing of those financial obligations. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future.
These forward-looking statements are based on certain key assumptions regarding, among other things: oil and natural gas prices and differentials between light, medium and heavy crude oil prices; well production rates and reserve volumes; success obtained drilling new wells; the duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; operating costs; the receipt, in a timely manner, of regulatory and other required approvals for our operating activities; the availability and cost of labour and other industry services; interest and foreign exchange rates; the continuance of existing and, in certain circumstances, proposed tax and royalty regimes; our ability to develop our crude oil and natural gas properties in the manner currently contemplated; our ability to successfully market oil and natural gas; that we will have sufficient financial resources in the future to pursue our development plans and provide shareholder returns; and current industry conditions, laws and regulations continuing in effect (or, where changes are proposed, such changes being adopted as anticipated). Readers are cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect.
Actual results achieved will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: the risk of an extended period of low oil and natural gas prices (including as a result of tariffs); risks associated with our ability to develop our properties and add reserves; that we may not achieve the expected benefits of acquisitions and we may sell assets below their carrying value; the availability and cost of capital or borrowing; restrictions or costs imposed by climate change initiatives and the physical risks of climate change; the impact of an energy transition on demand for petroleum productions; availability and cost of gathering, processing and pipeline systems; retaining or replacing our leadership and key personnel; changes in income tax or other laws or government incentive programs; risks associated with large projects; risks associated with higher a higher concentration of activity and tighter drilling spacing; costs to develop and operate our properties; current or future controls, legislation or regulations; restrictions on or access to water or other fluids; public perception and its influence on the regulatory regime; new regulations on hydraulic fracturing; regulations regarding the disposal of fluids; risks associated with our hedging activities; variations in interest rates and foreign exchange rates; uncertainties associated with estimating oil and natural gas reserves; our inability to fully insure against all risks; additional risks associated with our thermal heavy crude oil projects; our ability to compete with other organizations in the oil and gas industry; risks associated with our use of information technology systems; adverse results of litigation; that our Credit Facilities may not provide sufficient liquidity or may not be renewed; failure to comply with the covenants in our debt agreements; risks associated with expansion into new activities; the impact of Indigenous claims; risks of counterparty default; impact of geopolitical risk and conflicts; loss of foreign private issuer status; conflicts of interest between the Company and its directors and officers; variability of share buybacks and dividends; risks associated with the ownership of our securities, including changes in market-based factors; risks for United States and other non-resident shareholders, including the ability to enforce civil remedies, differing practices for reporting reserves and production, additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. These and additional risk factors are discussed in our Annual Information Form, Annual Report on Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2025, filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission and in our other public filings.
The above summary of assumptions and risks related to forward-looking statements has been provided in order to provide shareholders and potential investors with a more complete perspective on Baytex’s current and future operations and such information may not be appropriate for other purposes.
There is no representation by Baytex that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.
Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements.

The future acquisition of our common shares pursuant to a share buyback (including through its NCIB), if any, and the level thereof is uncertain. Any decision to acquire Common Shares pursuant to a share buyback will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, the Company's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions (including covenants contained in the agreements governing any indebtedness that the Company has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Company under applicable corporate law. There can be no assurance of the number of Common Shares that the Company will acquire pursuant to a share buyback, if any, in the future.
Baytex’s future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. Any decision to pay dividends on the common shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith and any special dividends) will be subject to the discretion of the Board of Directors of Baytex and may depend on a variety of factors, including, without limitation, Baytex’s business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on Baytex under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend is subject to the discretion of the Board of Directors of Baytex.
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