EX-99.2 3 a992-q32025mda.htm EX-99.2
Exhibit 99.2
Baytex Energy Corp.
Management’s Discussion and Analysis
For the three and nine months ended September 30, 2025 and 2024
Dated October 30, 2025
The following is management’s discussion and analysis (“MD&A”) of the operating and financial results of Baytex Energy Corp. for the three and nine months ended September 30, 2025. This information is provided as of October 30, 2025. 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 nine months ended September 30, 2025 ("Q3/2025" and "YTD 2025") have been compared with the results for the three and nine months ended September 30, 2024 ("Q3/2024" and "YTD 2024"). 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 nine months ended September 30, 2025, its audited comparative consolidated financial statements for the years ended December 31, 2024 and 2023, together with the accompanying notes, and its Annual Information Form ("AIF") for the year ended December 31, 2024. 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. 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 debt" 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 North American focused oil and gas company based in Calgary, Alberta. The Company operates in Canada and the United States ("U.S."). The Canadian operating segment includes our light oil assets in the Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our Eagle Ford operated and non-operated assets in Texas.
THIRD QUARTER HIGHLIGHTS
Baytex delivered strong operating and financial results in Q3/2025. Production of 150,950 boe/d and exploration and development expenditures of $270.4 million for Q3/2025 were consistent with our full-year plan and reflect our successful development programs in the U.S. and Canada. In the U.S., we successfully continued strong execution in the Eagle Ford with 15.6 net wells to sales. In Canada, we achieved record production in our Duvernay light oil operations and delivered a 5% increase in production from our heavy oil properties.
We spent $270.4 million on exploration and development expenditures in Q3/2025, compared to $306.3 million in Q3/2024 and consistent with our full year plan to spend approximately $1.2 billion. In the U.S., we invested $146.8 million and production averaged 82,765 boe/d during Q3/2025 compared to exploration and development expenditures of $185.9 million and production of 89,800 boe/d for Q3/2024. In Canada, we invested $123.6 million and generated production of 68,185 boe/d in Q3/2025 compared to exploration and development expenditures of $120.5 million and production of 64,668 boe/d in Q3/2024.
Oil prices were volatile during Q3/2025 due to concerns over global economic conditions along with increasing supply. The WTI benchmark price for Q3/2025 was US$64.93/bbl which was lower than Q3/2024 when WTI averaged US$75.10/bbl. Adjusted funds flow(1) of $422.2 million and cash flows from operating activities of $472.7 million for Q3/2025 reflect lower realized pricing compared to Q3/2024 when we generated adjusted funds flow of $537.9 million and cash flows from operating activities of $550.0 million.
(1)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
1

Net debt(1) of $2.2 billion at September 30, 2025 was $172.8 million lower than at December 31, 2024. Free cash flow(2) of $198.4 million generated in YTD 2025 was allocated to debt repayment along with $38.7 million of shareholder returns including share buybacks and quarterly dividends. We expect net debt to decline over the remainder of 2025 as we continue to allocate free cash flow to the balance sheet after funding our dividend.
(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.
2025 GUIDANCE
We continue to execute our 2025 plan and anticipate full year production of approximately 148,000 boe/d and exploration and development expenditures of approximately $1.2 billion, consistent with our previous guidance. The following table compares our 2025 annual guidance to our YTD 2025 results.

| 2025 Annual Guidance |  | YTD 2025 Results
Exploration and development expenditures (1) | ~ $1.2 billion |  | $1.0 billion
Production (boe/d) (1) | ~ 148,000 |  | 147,771
Expenses: |  |  |
Average royalty rate (1)(2) | ~ 22% |  | 21.6 | %
Operating (4)(6) | $11.75 - $12.00/boe |  | $11.63/boe
Transportation (3)(4) | $2.40 - $2.55/boe |  | $2.45/boe
General and administrative (1)(4) | $95 million ($1.76/boe) |  | $68.6 million ($1.70/boe)
Cash interest (3)(4)(5) | $180 million ($3.33/boe) |  | $135.5 million ($3.36/boe)
Current income tax (6) | < 1% of EBITDA (7) |  | 0.1% of EBITDA (7)
Leasing expenditures | $15 million |  | $10 million
Asset retirement obligations | $20 million |  | $12.6 million

(1)As announced on July 31, 2025.
(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)As announced on December 3, 2024.
(4)Refer to Operating Expense, Transportation Expense, General and Administrative Expense and Financing and Interest Expense sections of this MD&A for a description of the composition of these measures.
(5)Cash interest per boe was updated to reflect the expected 2025 production of 148,000 boe/d.
(6)As announced on October 30, 2025.
(7)EBITDA is calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.
2

RESULTS OF OPERATIONS
The Canadian operating segment includes our light oil assets in Viking and Duvernay, our heavy oil assets in Peace River and Lloydminster and our conventional oil and natural gas assets in Western Canada. The U.S. operating segment includes our operated and non-operated Eagle Ford assets in Texas.
Production

| Three Months Ended September 30
| 2025 | 2024
| Canada | U.S. | Total | Canada | U.S. | Total
Daily Production |  |  |  |  |  |
Liquids (bbl/d) |  |  |  |  |  |
Light oil and condensate | 12,605 | 52,330 | 64,935 | 13,781 | 56,062 | 69,843
Heavy oil | 45,269 | — | 45,269 | 42,759 | — | 42,759
Natural Gas Liquids (NGL) | 3,485 | 15,582 | 19,067 | 2,533 | 17,303 | 19,836
Total liquids (bbl/d) | 61,359 | 67,912 | 129,271 | 59,073 | 73,365 | 132,438
Natural gas (mcf/d) | 40,961 | 89,115 | 130,076 | 33,566 | 98,609 | 132,175
Total production (boe/d) | 68,185 | 82,765 | 150,950 | 64,668 | 89,800 | 154,468
Production Mix |  |  |  |  |  |
Segment as a percent of total | 45 | % | 55 | % | 100 | % | 42 | % | 58 | % | 100 | %
Light oil and condensate | 19 | % | 63 | % | 43 | % | 21 | % | 63 | % | 45 | %
Heavy oil | 66 | % | — | % | 30 | % | 66 | % | — | % | 28 | %
NGL | 5 | % | 19 | % | 13 | % | 4 | % | 19 | % | 13 | %
Natural gas | 10 | % | 18 | % | 14 | % | 9 | % | 18 | % | 14 | %
| Nine Months Ended September 30
| 2025 | 2024
| Canada | U.S. | Total | Canada | U.S. | Total
Daily Production |  |  |  |  |  |
Liquids (bbl/d) |  |  |  |  |  |
Light oil and condensate | 11,852 | 51,284 | 63,136 | 12,123 | 55,522 | 67,645
Heavy oil | 42,825 | — | 42,825 | 42,342 | — | 42,342
Natural Gas Liquids (NGL) | 3,199 | 16,154 | 19,353 | 2,491 | 17,276 | 19,767
Total liquids (bbl/d) | 57,876 | 67,438 | 125,314 | 56,956 | 72,798 | 129,754
Natural gas (mcf/d) | 42,335 | 92,407 | 134,742 | 39,162 | 100,907 | 140,069
Total production (boe/d) | 64,932 | 82,839 | 147,771 | 63,483 | 89,616 | 153,099
Production Mix |  |  |  |  |  |
Segment as a percent of total | 44 | % | 56 | % | 100 | % | 41 | % | 59 | % | 100 | %
Light oil and condensate | 18 | % | 62 | % | 43 | % | 19 | % | 62 | % | 44 | %
Heavy oil | 66 | % | — | % | 29 | % | 67 | % | — | % | 28 | %
NGL | 5 | % | 20 | % | 13 | % | 4 | % | 19 | % | 13 | %
Natural gas | 11 | % | 18 | % | 15 | % | 10 | % | 19 | % | 15 | %

Production was 150,950 boe/d for Q3/2025 and 147,771 boe/d for YTD 2025 compared to 154,468 boe/d for Q3/2024 and 153,099 boe/d for YTD 2024 which reflects lower development on our non-operated Eagle Ford assets and the disposition of non-core heavy oil assets in Q4/2024.
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In Canada, production was 68,185 boe/d for Q3/2025 and 64,932 boe/d for YTD 2025 compared to 64,668 boe/d for Q3/2024 and 63,483 boe/d for YTD 2024. Our successful light and heavy oil development programs resulted in production that was 3,517 boe/d higher for Q3/2025 and 1,449 boe/d higher for YTD 2025 relative to the same periods of 2024 despite the disposition of 2,000 boe/d of heavy oil production from the Kerrobert thermal assets in Q4/2024.
In the U.S., production was 82,765 boe/d for Q3/2025 and 82,839 for YTD 2025 compared to 89,800 boe/d for Q3/2024 and 89,616 boe/d for YTD 2024. Lower production for both periods of 2025 reflects reduced non-operated Eagle Ford activity in late 2024 and early 2025. We initiated production from 23 (15.6 net) wells during Q3/2025 and 69 (46.2 net) wells during YTD 2025 compared to 35 (21.0 net) wells during Q3/2024 and 102 (58.1 net) wells during YTD 2024.
Total production of 147,771 boe/d for YTD 2025 is consistent with guidance of approximately 148,000 boe/d for 2025.
COMMODITY PRICES
The prices received for our crude oil and natural gas production directly impact our earnings, free cash flow and our financial position.
Crude Oil
During Q3/2025 and YTD 2025, global benchmark prices for crude oil were lower compared to the same periods of 2024 as a result of increasing supply and concerns over slowing global economic activity. The WTI benchmark price averaged US$64.93/bbl for Q3/2025 and US$66.70/bbl for YTD 2025 compared to US$75.10/bbl for Q3/2024 and US$77.54/bbl for YTD 2024.
We compare the price received for our U.S. crude oil production to the Magellan East Houston ("MEH") stream at Houston, Texas. MEH is a representative benchmark for light oil pricing at the U.S. Gulf Coast which typically trades at a premium to WTI as a result of access to global markets. The MEH benchmark averaged US$67.03/bbl during Q3/2025 and US$68.65/bbl during YTD 2025 compared to US$77.50/bbl for Q3/2024 and US$79.85/bbl for YTD 2024. The MEH benchmark premium to WTI was US$2.10/bbl for Q3/2025 and US$1.95/bbl for YTD 2025 compared to premiums of US$2.40/bbl for Q3/2024 and US$2.31/bbl for YTD 2024.
Prices for Canadian oil trade at a discount to WTI due to a lack of 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. Canadian oil differentials were narrower in Q3/2025 and YTD 2025 relative to both periods of 2024 after exports commenced from the TMX pipeline expansion in May 2024.
We compare the price received for our light oil production in Canada to the Edmonton par benchmark oil price. The Edmonton par price averaged $86.20/bbl during Q3/2025 and $88.54/bbl during YTD 2025 compared to $97.91/bbl during Q3/2024 and $98.46/bbl during YTD 2024. Edmonton par traded at a discount to WTI of US$2.35/bbl for Q3/2025 and US$3.40/bbl for YTD 2025 compared to a discount of US$3.30/bbl for Q3/2024 and US$5.16/bbl for YTD 2024.
We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark for Q3/2025 averaged $75.14/bbl and $77.80/bbl for YTD 2025 compared to $83.98/bbl for Q3/2024 and $84.45/bbl for YTD 2024. The WCS heavy oil differential to WTI was US$10.38/bbl in Q3/2025 and US$11.08/bbl in YTD 2025 compared to US$13.51/bbl for Q3/2024 and US$15.46/bbl for YTD 2024.
Natural Gas
Natural gas prices in Canada and the U.S. were higher in both periods of 2025 compared to 2024 and reflect incremental demand and lower inventory levels.
Our U.S. natural gas production is priced in reference to the New York Mercantile Exchange ("NYMEX") natural gas index. The NYMEX natural gas benchmark averaged US$3.07/mmbtu for Q3/2025 and US$3.39/mmbtu for YTD 2025 compared to US$2.16/mmbtu for Q3/2024 and US$2.10/mmbtu for YTD 2024.
In Canada, we receive natural gas pricing based on the AECO benchmark which trades at a discount to NYMEX as a result of limited market access for Canadian natural gas production. The AECO benchmark averaged $1.00/mcf during Q3/2025 and $1.70/mcf for YTD 2025 which is higher than $0.81/mcf for Q3/2024 and $1.43/mcf for YTD 2024.
4

The following tables compare select benchmark prices and our average realized selling prices for the three and nine months ended September 30, 2025 and 2024.

| Three Months Ended September 30 | Nine Months Ended September 30
| 2025 |  | 2024 |  | Change | 2025 |  | 2024 |  | Change
Benchmark Averages |  |  |  |  |  |
WTI oil (US$/bbl) (1) | 64.93 |  | 75.10 |  | (10.17) |  | 66.70 |  | 77.54 |  | (10.84) |
MEH oil (US$/bbl) (2) | 67.03 |  | 77.50 |  | (10.47) |  | 68.65 |  | 79.85 |  | (11.20) |
MEH oil differential to WTI (US$/bbl) | 2.10 |  | 2.40 |  | (0.30) |  | 1.95 |  | 2.31 |  | (0.36) |
Edmonton par oil ($/bbl) (3) | 86.20 |  | 97.91 |  | (11.71) |  | 88.54 |  | 98.46 |  | (9.92) |
Edmonton par oil differential to WTI (US$/bbl) | (2.35) |  | (3.30) |  | 0.95 |  | (3.40) |  | (5.16) |  | 1.76 |
WCS heavy oil ($/bbl) (4) | 75.14 |  | 83.98 |  | (8.84) |  | 77.80 |  | 84.45 |  | (6.65) |
WCS heavy oil differential to WTI (US$/bbl) | (10.38) |  | (13.51) |  | 3.13 |  | (11.08) |  | (15.46) |  | 4.38 |
AECO natural gas ($/mcf) (5) | 1.00 |  | 0.81 |  | 0.19 |  | 1.70 |  | 1.43 |  | 0.27 |
NYMEX natural gas (US$/mmbtu) (6) | 3.07 |  | 2.16 |  | 0.91 |  | 3.39 |  | 2.10 |  | 1.29 |
CAD/USD average exchange rate | 1.3774 |  | 1.3636 |  | 0.0138 |  | 1.3988 |  | 1.3603 |  | 0.0385 |

(1)WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.
(2)MEH refers to arithmetic average of the Argus WTI Houston differential weighted index price for the applicable period.
(3)Edmonton par refers to the average posting price for the benchmark MSW crude oil.
(4)WCS refers to the average posting price for the benchmark WCS heavy oil.
(5)AECO refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").
(6)NYMEX refers to the NYMEX last day average index price as published by the CGPR.

| Three Months Ended September 30
| 2025 | 2024
| Canada | U.S. | Total | Canada | U.S. | Total
Average Realized Sales Prices |  |  |  |  |  |
Light oil and condensate ($/bbl) (1) | $ | 85.53 |  | $ | 88.63 |  | $ | 88.03 |  | $ | 96.58 |  | $ | 101.82 |  | $ | 100.78 |
Heavy oil, net of blending and other expense ($/bbl) (2) | 67.05 |  | — |  | 67.05 |  | 76.00 |  | — |  | 76.00 |
NGL ($/bbl) (1) | 22.62 |  | 23.83 |  | 23.60 |  | 26.04 |  | 27.66 |  | 27.45 |
Natural gas ($/mcf) (1) | 0.65 |  | 3.52 |  | 2.62 |  | 1.00 |  | 2.53 |  | 2.14 |
Total sales, net of blending and other expense ($/boe) (2) | $ | 61.88 |  | $ | 64.32 |  | $ | 63.22 |  | $ | 72.37 |  | $ | 71.68 |  | $ | 71.97 |
| Nine Months Ended September 30
| 2025 | 2024
| Canada | U.S. | Total | Canada | U.S. | Total
Average Realized Sales Prices |  |  |  |  |  |
Light oil and condensate ($/bbl) (1) | $ | 87.32 |  | $ | 91.94 |  | $ | 91.08 |  | $ | 96.85 |  | $ | 104.49 |  | $ | 103.12 |
Heavy oil, net of blending and other expense ($/bbl) (2) | 68.17 |  | — |  | 68.17 |  | 74.73 |  | — |  | 74.73 |
NGL ($/bbl) (1) | 24.47 |  | 27.29 |  | 26.82 |  | 25.76 |  | 27.03 |  | 26.87 |
Natural gas ($/mcf) (1) | 1.49 |  | 4.07 |  | 3.26 |  | 1.61 |  | 2.42 |  | 2.20 |
Total sales, net of blending and other expense ($/boe) (2) | $ | 63.08 |  | $ | 66.78 |  | $ | 65.15 |  | $ | 70.34 |  | $ | 72.68 |  | $ | 71.71 |

(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.
(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.
5

Average Realized Sales Prices
Our total sales, net of blending and other expense per boe(1) was $63.22/boe for Q3/2025 and $65.15/boe for YTD 2025 compared to $71.97/boe for Q3/2024 and $71.71/boe for YTD 2024. Our average realized sales price decreased due to lower WTI pricing partially offset by narrower Canadian oil differentials and higher natural gas prices.
We compare our light oil realized price in Canada to the Edmonton par benchmark price. Our realized light oil and condensate price(2) represents a discount to the Edmonton par price of $0.67/bbl for Q3/2025 and $1.22/bbl for YTD 2025 which is consistent with discounts of $1.33/bbl in Q3/2024 and $1.61/bbl in YTD 2024.
The price received for our U.S. light oil and condensate production is based on the MEH benchmark. Expressed in U.S. dollars, our realized light oil and condensate price(2) represents a discount to MEH of US$2.68/bbl for Q3/2025 and US$2.92/bbl for YTD 2025 consistent with a discount of US$2.83/bbl for Q3/2024 and US$3.04/bbl for YTD 2024.
Our realized heavy oil price, net of blending and other expense(1) was lower in Q3/2025 and YTD 2025 compared to the same periods of 2024 which reflects the decrease in WCS benchmark pricing. Our realized pricing for Q3/2025 and YTD 2025 represents a discount to the WCS benchmark of $8.09/bbl and $9.63/bbl compared to $7.98/bbl and $9.72/bbl for the same periods of 2024.
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(2) was 26% of WTI in Q3/2025 and 29% of WTI in YTD 2025 compared to 27% of WTI in Q3/2024 and 25% of WTI for YTD 2024.
We compare our realized natural gas price in the U.S. to the NYMEX benchmark and to the AECO benchmark price in Canada. The increase in AECO and NYMEX benchmark prices for Q3/2025 and YTD 2025 resulted in higher realized natural gas pricing in Canada and the U.S. relative to both periods of 2024.
(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)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.
6

PETROLEUM AND NATURAL GAS SALES

| Three Months Ended September 30
| 2025 | 2024
($ thousands) | Canada | U.S. | Total | Canada | U.S. | Total
Oil sales |  |  |  |  |  |
Light oil and condensate | $ | 99,188 |  | $ | 426,712 |  | $ | 525,900 |  | $ | 122,452 |  | $ | 525,135 |  | $ | 647,587 |
Heavy oil | 329,005 |  | — |  | 329,005 |  | 350,859 |  | — |  | 350,859 |
NGL | 7,250 |  | 34,154 |  | 41,404 |  | 6,067 |  | 44,034 |  | 50,101 |
Total oil sales | 435,443 |  | 460,866 |  | 896,309 |  | 479,378 |  | 569,169 |  | 1,048,547 |
Natural gas sales | 2,462 |  | 28,877 |  | 31,339 |  | 3,089 |  | 22,987 |  | 26,076 |
Total petroleum and natural gas sales | 437,905 |  | 489,743 |  | 927,648 |  | 482,467 |  | 592,156 |  | 1,074,623 |
Blending and other expense | (49,750) |  | — |  | (49,750) |  | (51,902) |  | — |  | (51,902) |
Total sales, net of blending and other expense (1) | $ | 388,155 |  | $ | 489,743 |  | $ | 877,898 |  | $ | 430,565 |  | $ | 592,156 |  | $ | 1,022,721 |
| Nine Months Ended September 30
| 2025 | 2024
($ thousands) | Canada | U.S. | Total | Canada | U.S. | Total
Oil sales |  |  |  |  |  |
Light oil and condensate | $ | 282,532 |  | $ | 1,287,251 |  | $ | 1,569,783 |  | $ | 321,704 |  | $ | 1,589,648 |  | $ | 1,911,352 |
Heavy oil | 981,970 |  | — |  | 981,970 |  | 1,050,743 |  | — |  | 1,050,743 |
NGL | 21,371 |  | 120,333 |  | 141,704 |  | 17,579 |  | 127,963 |  | 145,542 |
Total oil sales | 1,285,873 |  | 1,407,584 |  | 2,693,457 |  | 1,390,026 |  | 1,717,611 |  | 3,107,637 |
Natural gas sales | 17,219 |  | 102,681 |  | 119,900 |  | 17,314 |  | 66,987 |  | 84,301 |
Total petroleum and natural gas sales | 1,303,092 |  | 1,510,265 |  | 2,813,357 |  | 1,407,340 |  | 1,784,598 |  | 3,191,938 |
Blending and other expense | (184,951) |  | — |  | (184,951) |  | (183,795) |  | — |  | (183,795) |
Total sales, net of blending and other expense (1) | $ | 1,118,141 |  | $ | 1,510,265 |  | $ | 2,628,406 |  | $ | 1,223,545 |  | $ | 1,784,598 |  | $ | 3,008,143 |

(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, was $877.9 million for Q3/2025 and $2.6 billion for YTD 2025 compared to $1.0 billion for Q3/2024 and $3.0 billion for YTD 2024. The decrease in total sales, net of blending and other expense reflects lower realized pricing and lower production in both periods of 2025 compared to 2024.
In Canada, total sales, net of blending and other expense, of $388.2 million for Q3/2025 and $1.1 billion for YTD 2025 decreased from $430.6 million reported for Q3/2024 and $1.2 billion for YTD 2024. The decrease in benchmark prices in Q3/2025 and YTD 2025 relative to Q3/2024 and YTD 2024 resulted in lower total sales, net of blending and other expense as production was higher than the same periods.
In the U.S., total petroleum and natural gas sales of $489.7 million for Q3/2025 and $1.5 billion for YTD 2025 decreased from $592.2 million reported for Q3/2024 and $1.8 billion for YTD 2024. Lower realized pricing resulted in a $56.0 million decrease in total sales in Q3/2025 relative to Q3/2024 while lower production contributed to a $46.4 million decrease in total sales relative to Q3/2024. Lower realized pricing resulted in a $133.3 million decrease in total sales in YTD 2025 relative to YTD 2024 while lower production contributed to a $141.0 million decrease in total sales relative to YTD 2024.
7

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 nine months ended September 30, 2025 and 2024.

| Three Months Ended September 30
| 2025 | 2024
($ thousands except for % and per boe) | Canada | U.S. | Total | Canada | U.S. | Total
Royalties | $ | 53,645 | $ | 127,585 | $ | 181,230 | $ | 71,351 | $ | 152,449 | $ | 223,800
Average royalty rate (1)(2) | 13.8 | % | 26.1 | % | 20.6 | % | 16.6 | % | 25.7 | % | 21.9 | %
Royalties per boe (3) | $ | 8.55 | $ | 16.76 | $ | 13.05 | $ | 11.99 | $ | 18.45 | $ | 15.75
| Nine Months Ended September 30
| 2025 | 2024
($ thousands except for % and per boe) | Canada | U.S. | Total | Canada | U.S. | Total
Royalties | $ | 160,701 | $ | 405,856 | $ | 566,557 | $ | 200,809 | $ | 472,602 | $ | 673,411
Average royalty rate (1)(2) | 14.4 | % | 26.9 | % | 21.6 | % | 16.4 | % | 26.5 | % | 22.4 | %
Royalties per boe (3) | $ | 9.07 | $ | 17.95 | $ | 14.04 | $ | 11.54 | $ | 19.25 | $ | 16.05

(1)Average royalty rate is calculated as royalties divided by total sales, net of blending and other expense.
(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)Royalties per boe is calculated as royalties divided by barrels of oil equivalent production volume for the applicable period.
Royalties for Q3/2025 were $181.2 million or 20.6% of total sales, net of blending and other expense, compared to $223.8 million or 21.9% for Q3/2024. Total royalties for YTD 2025 were $566.6 million or 21.6% of total sales, net of blending and other expense, compared to $673.4 million or 22.4% for YTD 2024. Total royalty expense was lower for Q3/2025 and YTD 2025 due to lower total sales, net of blending and other expense, relative to the same periods of 2024.
Our average royalty rate in Canada of 13.8% for Q3/2025 and 14.4% for YTD 2025 was lower than 16.6% for Q3/2024 and 16.4% for YTD 2024 due to lower benchmark commodity prices. In the U.S., our average royalty rate was 26.1% for Q3/2025 and 26.9% for YTD 2025 which was relatively consistent with 25.7% for Q3/2024 and 26.5% for YTD 2024.
Our average royalty rate of 21.6% for YTD 2025 is consistent with our annual guidance of approximately 22% for 2025.
8

OPERATING EXPENSE

| Three Months Ended September 30
| 2025 | 2024
($ thousands except for per boe) | Canada | U.S. | Total | Canada | U.S. | Total
Operating expense | $ | 84,994 |  | $ | 75,290 |  | $ | 160,284 |  | $ | 87,373 |  | $ | 79,746 |  | $ | 167,119 |
Operating expense per boe (1) | $ | 13.55 |  | $ | 9.89 |  | $ | 11.54 |  | $ | 14.69 |  | $ | 9.65 |  | $ | 11.76 |
| Nine Months Ended September 30
| 2025 | 2024
($ thousands except for per boe) | Canada | U.S. | Total | Canada | U.S. | Total
Operating expense | $ | 248,609 |  | $ | 220,398 |  | $ | 469,007 |  | $ | 257,191 |  | $ | 251,068 |  | $ | 508,259 |
Operating expense per boe (1) | $ | 14.02 |  | $ | 9.75 |  | $ | 11.63 |  | $ | 14.79 |  | $ | 10.22 |  | $ | 12.12 |

(1)Operating expense per boe is calculated as operating expense divided by barrels of oil equivalent production volume for the applicable period.
Total operating expense was $160.3 million ($11.54/boe) for Q3/2025 and $469.0 million ($11.63/boe) for YTD 2025 compared to $167.1 million ($11.76/boe) for Q3/2024 and $508.3 million ($12.12/boe) for YTD 2024. Total operating expense for both periods of 2025 decreased relative to 2024 due to lower production and per unit operating costs were slightly lower compared to the same periods as well.
In Canada, total operating expense was $85.0 million ($13.55/boe) for Q3/2025 and $248.6 million ($14.02/boe) for YTD 2025 compared to $87.4 million ($14.69/boe) for Q3/2024 and $257.2 million ($14.79/boe) for YTD 2024. Total operating expense in Canada for Q3/2025 decreased due to the disposition of higher cost non-core assets in Q4/2024 which also contributed to lower per unit operating expense of $13.55/boe for Q3/2025 and $14.02/boe for YTD 2025 compared to $14.69/boe for Q3/2024 and $14.79/boe for YTD 2024.
In the U.S., operating expense was $75.3 million ($9.89/boe) for Q3/2025 and $220.4 million ($9.75/boe) for YTD 2025 which was lower than $79.7 million ($9.65/boe) for Q3/2024 and $251.1 million ($10.22/boe) for YTD 2024. Per boe operating expense in the U.S., expressed in U.S. dollars, was US$7.18/boe for Q3/2025 and US$6.97/boe for YTD 2025 which was consistent with US$7.08/boe for Q3/2024 and US$7.51/boe for YTD 2024. The decrease in total operating expense reflects lower production in both periods of 2025 compared to 2024.
Operating expense of $11.63/boe for YTD 2025 is slightly below our revised annual guidance range of $11.75 - $12.00/boe for 2025.
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 nine months ended September 30, 2025 and 2024.

| Three Months Ended September 30
| 2025 | 2024
($ thousands except for per boe) | Canada | U.S. | Total | Canada | U.S. | Total
Transportation expense | $ | 23,060 |  | $ | 12,235 |  | $ | 35,295 |  | $ | 24,837 |  | $ | 12,046 |  | $ | 36,883 |
Transportation expense per boe (1) | $ | 3.68 |  | $ | 1.61 |  | $ | 2.54 |  | $ | 4.17 |  | $ | 1.46 |  | $ | 2.60 |
| Nine Months Ended September 30
| 2025 | 2024
($ thousands except for per boe) | Canada | U.S. | Total | Canada | U.S. | Total
Transportation expense | $ | 62,383 |  | $ | 36,331 |  | $ | 98,714 |  | $ | 62,616 |  | $ | 37,416 |  | $ | 100,032 |
Transportation expense per boe (1) | $ | 3.52 |  | $ | 1.61 |  | $ | 2.45 |  | $ | 3.60 |  | $ | 1.52 |  | $ | 2.38 |

(1)Transportation expense per boe is calculated as transportation expense divided by barrels of oil equivalent production volume for the applicable period.
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Transportation expense was $35.3 million ($2.54/boe) for Q3/2025 and $98.7 million ($2.45/boe) for YTD 2025 consistent with $36.9 million ($2.60/boe) for Q3/2024 and $100.0 million ($2.38/boe) for YTD 2024.
Transportation expense of $2.45/boe for YTD 2025 is consistent with expectations and our annual guidance range of $2.40 - $2.55/boe for 2025.
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 $49.8 million for Q3/2025 and $185.0 million for YTD 2025 compared to $51.9 million for Q3/2024 and $183.8 million for YTD 2024. Blending and other expense for Q3/2025 and YTD 2025 was comparable to Q3/2024 and YTD 2024 as heavy oil production was relatively consistent over the same periods.
FINANCIAL DERIVATIVES
Our business is exposed to fluctuations in commodity prices, foreign exchange rates and interest rates. We utilize various financial derivative contracts which are intended to partially reduce the volatility in our free cash flow caused by these exposures. 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 executed. The following table summarizes the results of our financial derivative contracts for the three and nine months ended September 30, 2025 and 2024.

| Three Months Ended September 30 | Nine Months Ended September 30
($ thousands) | 2025 |  | 2024 |  | Change | 2025 |  | 2024 |  | Change
Realized financial derivatives gain (loss) |  |  |  |  |  |
Crude oil | $ | (9,203) |  | $ | (2,190) |  | $ | (7,013) |  | $ | (22,484) |  | $ | (6,091) |  | $ | (16,393) |
Natural gas | 623 |  | 2,521 |  | (1,898) |  | 1,836 |  | 9,653 |  | (7,817) |
Total | $ | (8,580) |  | $ | 331 |  | $ | (8,911) |  | $ | (20,648) |  | $ | 3,562 |  | $ | (24,210) |
Unrealized financial derivatives gain (loss) |  |  |  |  |  |
Crude oil | $ | (4,401) |  | $ | 21,239 |  | $ | (25,640) |  | $ | (20,016) |  | $ | 3,251 |  | $ | (23,267) |
Natural gas | 7,942 |  | 1,357 |  | 6,585 |  | 4,669 |  | (2,215) |  | 6,884 |
Total | $ | 3,541 |  | $ | 22,596 |  | $ | (19,055) |  | $ | (15,347) |  | $ | 1,036 |  | $ | (16,383) |
Total financial derivatives gain (loss) |  |  |  |  |  |
Crude oil | $ | (13,604) |  | $ | 19,049 |  | $ | (32,653) |  | $ | (42,500) |  | $ | (2,840) |  | $ | (39,660) |
Natural gas | 8,565 |  | 3,878 |  | 4,687 |  | 6,505 |  | 7,438 |  | (933) |
Total | $ | (5,039) |  | $ | 22,927 |  | $ | (27,966) |  | $ | (35,995) |  | $ | 4,598 |  | $ | (40,593) |

We recorded total financial derivatives losses of $5.0 million for Q3/2025 and $36.0 million for YTD 2025 compared to gains of $22.9 million for Q3/2024 and $4.6 million for YTD 2024. The realized financial derivatives loss of $20.6 million for YTD 2025 resulted from losses of $22.5 million on crude oil contracts and gains of $1.8 million on natural gas contracts. The unrealized financial derivatives loss of $15.3 million for YTD 2025 resulted from a $20.0 million loss on crude oil contracts and a $4.7 million gain on natural gas contracts. The fair value of our financial derivative contracts resulted in a net asset of $8.6 million at September 30, 2025 compared to a net asset of $23.9 million at December 31, 2024.
Refer to Note 17 of the consolidated financial statements for a complete listing of our outstanding contracts at October 30, 2025.
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OPERATING NETBACK
The following table summarizes our operating netback on a per boe basis for our Canadian and U.S. operations for the three and nine months ended September 30, 2025 and 2024.

| Three Months Ended September 30
| 2025 | 2024
($ per boe except for volume) | Canada | U.S. | Total | Canada | U.S. | Total
Total production (boe/d) | 68,185 |  | 82,765 |  | 150,950 |  | 64,668 |  | 89,800 |  | 154,468 |
Operating netback: |  |  |  |  |  |
Total sales, net of blending and other expense (1) | $ | 61.88 |  | $ | 64.32 |  | $ | 63.22 |  | $ | 72.37 |  | $ | 71.68 |  | $ | 71.97 |
Less: |  |  |  |  |  |
Royalties (2) | (8.55) |  | (16.76) |  | (13.05) |  | (11.99) |  | (18.45) |  | (15.75) |
Operating expense (2) | (13.55) |  | (9.89) |  | (11.54) |  | (14.69) |  | (9.65) |  | (11.76) |
Transportation expense (2) | (3.68) |  | (1.61) |  | (2.54) |  | (4.17) |  | (1.46) |  | (2.60) |
Operating netback (1) | $ | 36.10 |  | $ | 36.06 |  | $ | 36.09 |  | $ | 41.52 |  | $ | 42.12 |  | $ | 41.86 |
Realized financial derivatives (loss) gain (3) | — |  | — |  | (0.62) |  | — |  | — |  | 0.02 |
Operating netback after financial derivatives (1) | $ | 36.10 |  | $ | 36.06 |  | $ | 35.47 |  | $ | 41.52 |  | $ | 42.12 |  | $ | 41.88 |
| Nine Months Ended September 30
| 2025 | 2024
($ per boe except for volume) | Canada | U.S. | Total | Canada | U.S. | Total
Total production (boe/d) | 64,932 |  | 82,839 |  | 147,771 |  | 63,483 |  | 89,616 |  | 153,099 |
Operating netback: |  |  |  |  |  |
Total sales, net of blending and other expense (1) | $ | 63.08 |  | $ | 66.78 |  | $ | 65.15 |  | $ | 70.34 |  | $ | 72.68 |  | $ | 71.71 |
Less: |  |  |  |  |  |
Royalties (2) | (9.07) |  | (17.95) |  | (14.04) |  | (11.54) |  | (19.25) |  | (16.05) |
Operating expense (2) | (14.02) |  | (9.75) |  | (11.63) |  | (14.79) |  | (10.22) |  | (12.12) |
Transportation expense (2) | (3.52) |  | (1.61) |  | (2.45) |  | (3.60) |  | (1.52) |  | (2.38) |
Operating netback (1) | $ | 36.47 |  | $ | 37.47 |  | $ | 37.03 |  | $ | 40.41 |  | $ | 41.69 |  | $ | 41.16 |
Realized financial derivatives (loss) gain (3) | — |  | — |  | (0.51) |  | — |  | — |  | 0.08 |
Operating netback after financial derivatives (1) | $ | 36.47 |  | $ | 37.47 |  | $ | 36.52 |  | $ | 40.41 |  | $ | 41.69 |  | $ | 41.24 |

(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 of $36.09/boe for Q3/2025 and $37.03/boe for YTD 2025 was lower than $41.86/boe for Q3/2024 and $41.16/boe for YTD 2024 due to the decrease in our realized price which resulted in lower per unit sales net of royalties. Total operating and transportation expense for Q3/2025 and YTD 2025 was consistent with the same periods of 2024. Our operating netback net of realized gains and losses on financial derivatives of $35.47/boe for Q3/2025 and $36.52/boe for YTD 2025 was lower than $41.88/boe for Q3/2024 and $41.24/boe for YTD 2024 due to the decrease in realized prices.
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. G&A expense fluctuates with head office staffing levels and the level of operated exploration and development activity during the period.
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The following table summarizes our G&A expense for the three and nine months ended September 30, 2025 and 2024.

| Three Months Ended September 30 | Nine Months Ended September 30
($ thousands except for per boe) | 2025 |  | 2024 |  | Change | 2025 |  | 2024 |  | Change
Gross general and administrative expense | $ | 27,445 |  | $ | 24,255 |  | $ | 3,190 |  | $ | 88,967 |  | $ | 80,082 |  | $ | 8,885 |
Overhead recoveries | (6,709) |  | (6,360) |  | (349) |  | (20,405) |  | (18,769) |  | (1,636) |
General and administrative expense | $ | 20,736 |  | $ | 17,895 |  | $ | 2,841 |  | $ | 68,562 |  | $ | 61,313 |  | $ | 7,249 |
General and administrative expense per boe (1) | $ | 1.49 |  | $ | 1.26 |  | $ | 0.23 |  | $ | 1.70 |  | $ | 1.46 |  | $ | 0.24 |

(1)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.
G&A expense was $20.7 million ($1.49/boe) for Q3/2025 and $68.6 million ($1.70/boe) for YTD 2025 compared to $17.9 million ($1.26/boe) for Q3/2024 and $61.3 million ($1.46/boe) for YTD 2024. G&A expense of $68.6 million ($1.70/boe) for YTD 2025 is consistent with expectations and our 2025 annual guidance of approximately $95.0 million ($1.76/boe) which reflects the timing of certain costs and our expectations for production over the remainder of 2025.
FINANCING AND INTEREST EXPENSE
Financing and interest expense includes interest on our credit facilities, long-term notes and lease obligations as well as non-cash financing costs which include the accretion on our debt issue costs and asset retirement obligations. Financing and interest expense varies depending on debt levels outstanding during the period, the applicable borrowing rates, CAD/USD foreign exchange rates, along with the carrying amount of asset retirement obligations and the discount rates used to present value these obligations.
The following table summarizes our financing and interest expense for the three and nine months ended September 30, 2025 and 2024.

| Three Months Ended September 30 | Nine Months Ended September 30
($ thousands except for per boe) | 2025 |  | 2024 |  | Change | 2025 |  | 2024 |  | Change
Interest on credit facilities | $ | 6,832 |  | $ | 12,343 |  | $ | (5,511) |  | $ | 19,870 |  | $ | 46,271 |  | $ | (26,401) |
Interest on long-term notes | 36,718 |  | 37,426 |  | (708) |  | 114,680 |  | 109,760 |  | 4,920 |
Interest on lease obligations | 323 |  | 340 |  | (17) |  | 985 |  | 1,304 |  | (319) |
Cash interest | $ | 43,873 |  | $ | 50,109 |  | $ | (6,236) |  | $ | 135,535 |  | $ | 157,335 |  | $ | (21,800) |
Accretion of debt issue costs | 2,564 |  | 3,067 |  | (503) |  | 9,300 |  | 13,989 |  | (4,689) |
Accretion of asset retirement obligations | 5,999 |  | 5,524 |  | 475 |  | 17,315 |  | 15,910 |  | 1,405 |
Gain on repurchase and cancellation of long-term notes | — |  | — |  | — |  | (2,755) |  | — |  | (2,755) |
Early redemption expense | — |  | — |  | — |  | — |  | 24,350 |  | (24,350) |
Financing and interest expense | $ | 52,436 |  | $ | 58,700 |  | $ | (6,264) |  | $ | 159,395 |  | $ | 211,584 |  | $ | (52,189) |
Cash interest per boe (1) | $ | 3.16 |  | $ | 3.53 |  | $ | (0.37) |  | $ | 3.36 |  | $ | 3.75 |  | $ | (0.39) |
Financing and interest expense per boe (1) | $ | 3.78 |  | $ | 4.13 |  | $ | (0.35) |  | $ | 3.95 |  | $ | 5.04 |  | $ | (1.09) |

(1)Calculated as cash interest or financing and interest expense divided by barrels of oil equivalent production volume for the applicable period.
Financing and interest expense was $52.4 million ($3.78/boe) for Q3/2025 and $159.4 million ($3.95/boe) for YTD 2025 compared to $58.7 million ($4.13/boe) for Q3/2024 and $211.6 million ($5.04/boe) for YTD 2024. The decrease for both periods of 2025 is due to lower outstanding debt balances for YTD 2025 and early redemption expense recognized in Q2/2024 related to the redemption of the 8.75% senior notes.
Cash interest of $43.9 million ($3.16/boe) for Q3/2025 and $135.5 million ($3.36/boe) for YTD 2025 was lower than $50.1 million ($3.53/boe) for Q3/2024 and $157.3 million ($3.75/boe) for YTD 2024. Lower interest on our credit facilities reflects lower debt balances outstanding in both periods of 2025 and lower rates, while higher interest on long-term notes is a result of additional principal amounts outstanding after the issuance of the 7.375% Senior Notes in Q2/2024. The weighted average interest rate applicable on our credit facilities was 6.7% for Q3/2025 and 6.7% for YTD 2025 compared to 7.5% for Q3/2024 and 7.8% for YTD 2024.
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Accretion of asset retirement obligations of $6.0 million for Q3/2025 and $17.3 million for YTD 2025 was consistent with $5.5 million for Q3/2024 and $15.9 million for YTD 2024. Accretion of debt issue costs of $2.6 million for Q3/2025 and $9.3 million for YTD 2025 was lower than $3.1 million for Q3/2024 and $14.0 million for YTD 2024. In Q2/2024, we recorded $24.4 million of early redemption expense related to the redemption of the 8.75% senior notes.
Cash interest expense of $135.5 million ($3.36/boe) for YTD 2025 is consistent with our expectations and our 2025 annual guidance of $180 million ($3.33/boe).
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 was $0.1 million for Q3/2025 and $0.7 million for YTD 2025 compared to $0.1 million for Q3/2024 and $0.7 million for YTD 2024.
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 nine months ended September 30, 2025 and 2024.

| Three Months Ended September 30 | Nine Months Ended September 30
($ thousands except for per boe) | 2025 | 2024 | Change | 2025 | 2024 | Change
Depletion | $ | 326,707 |  | $ | 352,745 |  | $ | (26,038) |  | $ | 960,737 |  | $ | 1,043,898 |  | $ | (83,161) |
Depreciation | 2,386 |  | 3,639 |  | (1,253) |  | 10,438 |  | 9,724 |  | 714 |
Depletion and depreciation | $ | 329,093 |  | $ | 356,384 |  | $ | (27,291) |  | $ | 971,175 |  | $ | 1,053,622 |  | $ | (82,447) |
Depletion and depreciation per boe (1) | $ | 23.70 |  | $ | 25.08 |  | $ | (1.38) |  | $ | 24.07 |  | $ | 25.12 |  | $ | (1.05) |

(1)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.
Depletion and depreciation expense was $329.1 million ($23.70/boe) for Q3/2025 and $971.2 million ($24.07/boe) for YTD 2025 compared to $356.4 million ($25.08/boe) for Q3/2024 and $1.1 billion ($25.12/boe) for YTD 2024. Total depletion and depreciation expense and depletion and depreciation per boe were lower in Q3/2025 and YTD 2025 relative to Q3/2024 and YTD 2024. This was due to lower production and a decrease in future development costs for proved plus probable reserves which resulted in a lower depletable base for our oil and gas properties during 2025.
IMPAIRMENT
We assessed our oil and gas properties and exploration and evaluation assets for indicators of impairment or impairment reversal and concluded that the estimation of recoverable amount was not required for any of our cash generating units at September 30, 2025 and December 31, 2024.
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 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 $10.7 million for Q3/2025 and $13.1 million for YTD 2025 compared to $2.3 million for Q3/2024 and $17.4 million for YTD 2024. SBC expense for Q3/2025 reflects an increase in the Company's share price which resulted in higher SBC expense relative to Q3/2024, while the decrease in SBC expense for YTD 2025 reflects a decrease in the Company's share price compared to YTD 2024.
FOREIGN EXCHANGE
Unrealized foreign exchange gains and losses are primarily a result of changes in the reported amount of our U.S. dollar denominated long-term notes and credit facilities in our Canadian functional currency entities. The long-term notes and credit facilities are translated to Canadian dollars on the balance sheet date using the closing CAD/USD exchange rate resulting in unrealized gains and losses. Realized foreign exchange gains and losses are due to day-to-day U.S. dollar denominated transactions occurring in our Canadian functional currency entities.
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| Three Months Ended September 30 | Nine Months Ended September 30
($ thousands except for exchange rates) | 2025 |  | 2024 |  | Change | 2025 |  | 2024 |  | Change
Unrealized foreign exchange loss (gain) | $ | 36,840 |  | $ | (24,401) |  | $ | 61,241 |  | $ | (67,427) |  | $ | 33,506 |  | $ | (100,933) |
Realized foreign exchange loss (gain) | 81 |  | (151) |  | 232 |  | (116) |  | 1,934 |  | (2,050) |
Foreign exchange loss (gain) | $ | 36,921 |  | $ | (24,552) |  | $ | 61,473 |  | $ | (67,543) |  | $ | 35,440 |  | $ | (102,983) |
CAD/USD exchange rates: |  |  |  |  |  |
At beginning of period | 1.3622 |  | 1.3687 |  |  | 1.4405 |  | 1.3205 |  |
At end of period | 1.3906 |  | 1.3505 |  |  | 1.3906 |  | 1.3505 |  |

We recorded a foreign exchange loss of $36.9 million for Q3/2025 and a gain of $67.5 million for YTD 2025 compared to a gain of $24.6 million for Q3/2024 and a loss of $35.4 million for YTD 2024.
The unrealized foreign exchange loss of $36.8 million for Q3/2025 and gain of $67.4 million for YTD 2025 is related to changes in the reported amount of our U.S. dollar denominated long-term notes and credit facilities due to changes in the value of the Canadian dollar relative to the U.S. dollar at September 30, 2025 compared to June 30, 2025 and December 31, 2024. The unrealized foreign exchange gain of $24.4 million for Q3/2024 and loss of $33.5 million for YTD 2024 is related to changes in the reported amount of our long-term notes and credit facilities due to changes in the value of the Canadian dollar relative to the U.S. dollar at September 30, 2024 compared to June 30, 2024 and December 31, 2023.
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 functional currency entities. We recorded a realized foreign exchange loss of $0.1 million for Q3/2025 and a gain of $0.1 million for YTD 2025 compared to a gain of $0.2 million for Q3/2024 and a loss of $1.9 million for YTD 2024.
INCOME TAXES

| Three Months Ended September 30 | Nine Months Ended September 30
($ thousands) | 2025 |  | 2024 |  | Change | 2025 |  | 2024 |  | Change
Current income tax (recovery) expense | $ | (5,733) |  | $ | (3,748) |  | $ | (1,985) |  | $ | 966 |  | $ | 4,407 |  | $ | (3,441) |
Deferred income tax expense | 20,773 |  | 33,577 |  | (12,804) |  | 57,295 |  | 72,188 |  | (14,893) |
Total income tax expense | $ | 15,040 |  | $ | 29,829 |  | $ | (14,789) |  | $ | 58,261 |  | $ | 76,595 |  | $ | (18,334) |

We recorded a current income tax recovery of $5.7 million for Q3/2025 and expense of $1.0 million for YTD 2025 compared to a recovery of $3.7 million for Q3/2024 and expense of $4.4 million for YTD 2024. The current income tax expense for YTD 2025 and 2024 primarily relates to repatriation and related taxes and the recoveries recorded in Q3/2025 and Q3/2024 represent recoveries of taxes previously accrued for the 2024 and 2023 tax years, respectively.
We recorded deferred income tax expense of $20.8 million for Q3/2025 and $57.3 million for YTD 2025 compared to $33.6 million for Q3/2024 and $72.2 million for YTD 2024. The deferred tax expense for Q3/2025 and YTD 2025 decreased compared to Q3/2024 and YTD 2024 as a result of lower earnings, partially offset by the removal of the valuation allowance against tax pools associated with our Canadian operations in 2024, with no such movement in 2025.
On July 4, 2025, the U.S. enacted a budget reconciliation package known as the One Big Beautiful Bill Act of 2025 ("OBBBA") which included both tax and non-tax provisions. The changes resulting from the tax provisions in OBBBA did not have a material impact on the Company’s financial results.
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 to three 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 Q4/2023, we purchased $272.5 million of insurance coverage to manage the litigation risk associated with this matter. The most recent reassessments issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $232.9 million as at the date of reassessments and a late filing penalty in respect of the 2011 tax year of $4.1 million.
14

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 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 for the three and nine months ended September 30, 2025 and 2024 are set forth in the following table.

| Three Months Ended September 30 | Nine Months Ended September 30
($ thousands) | 2025 |  | 2024 | Change | 2025 |  | 2024 | Change
Petroleum and natural gas sales | $ | 927,648 |  | $ | 1,074,623 |  | $ | (146,975) |  | $ | 2,813,357 |  | $ | 3,191,938 |  | $ | (378,581) |
Royalties | (181,230) |  | (223,800) |  | 42,570 |  | (566,557) |  | (673,411) |  | 106,854 |
Revenue, net of royalties | 746,418 |  | 850,823 |  | (104,405) |  | 2,246,800 |  | 2,518,527 |  | (271,727) |
Expenses |  |  |  |  |  |
Operating | (160,284) |  | (167,119) |  | 6,835 |  | (469,007) |  | (508,259) |  | 39,252 |
Transportation | (35,295) |  | (36,883) |  | 1,588 |  | (98,714) |  | (100,032) |  | 1,318 |
Blending and other | (49,750) |  | (51,902) |  | 2,152 |  | (184,951) |  | (183,795) |  | (1,156) |
Operating netback (1) | $ | 501,089 |  | $ | 594,919 |  | $ | (93,830) |  | $ | 1,494,128 |  | $ | 1,726,441 |  | $ | (232,313) |
General and administrative | (20,736) |  | (17,895) |  | (2,841) |  | (68,562) |  | (61,313) |  | (7,249) |
Cash interest | (43,873) |  | (50,109) |  | 6,236 |  | (135,535) |  | (157,335) |  | 21,800 |
Realized financial derivatives (loss) gain | (8,580) |  | 331 |  | (8,911) |  | (20,648) |  | 3,562 |  | (24,210) |
Realized foreign exchange (loss) gain | (81) |  | 151 |  | (232) |  | 116 |  | (1,934) |  | 2,050 |
Cash other (expense) income | (583) |  | 9,107 |  | (9,690) |  | (2,457) |  | 7,011 |  | (9,468) |
Current income tax recovery (expense) | 5,733 |  | 3,748 |  | 1,985 |  | (966) |  | (4,407) |  | 3,441 |
Cash share-based compensation | (10,737) |  | (2,305) |  | (8,432) |  | (13,055) |  | (17,393) |  | 4,338 |
Adjusted funds flow (2) | $ | 422,232 |  | $ | 537,947 |  | $ | (115,715) |  | $ | 1,253,021 |  | $ | 1,494,632 |  | $ | (241,611) |
Transaction costs | — |  | — |  | — |  | — |  | (1,539) |  | 1,539 |
Exploration and evaluation | (127) |  | (82) |  | (45) |  | (691) |  | (749) |  | 58 |
Depletion and depreciation | (329,093) |  | (356,384) |  | 27,291 |  | (971,175) |  | (1,053,622) |  | 82,447 |
Non-cash financing and interest | (8,563) |  | (8,591) |  | 28 |  | (23,860) |  | (54,249) |  | 30,389 |
Unrealized financial derivatives gain (loss) | 3,541 |  | 22,596 |  | (19,055) |  | (15,347) |  | 1,036 |  | (16,383) |
Unrealized foreign exchange (loss) gain | (36,840) |  | 24,401 |  | (61,241) |  | 67,427 |  | (33,506) |  | 100,933 |
Gain (loss) on dispositions | 1,591 |  | (1,091) |  | 2,682 |  | 1,028 |  | (4,741) |  | 5,769 |
Deferred income tax expense | (20,773) |  | (33,577) |  | 12,804 |  | (57,295) |  | (72,188) |  | 14,893 |
Net income | $ | 31,968 |  | $ | 185,219 |  | $ | (153,251) |  | $ | 253,108 |  | $ | 275,074 |  | $ | (21,966) |

(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)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
We generated adjusted funds flow of $422.2 million for Q3/2025 and $1.3 billion for YTD 2025 compared to $537.9 million for Q3/2024 and $1.5 billion for YTD 2024. The decrease in adjusted funds flow was primarily due to the decrease in realized pricing and production that resulted in lower revenues net of royalties partially offset by lower operating and transportation expense.
15

We reported net income of $32.0 million for Q3/2025 and $253.1 million for YTD 2025 compared to net income of $185.2 million for Q3/2024 and $275.1 million for YTD 2024. The decrease in net income for Q3/2025 and YTD 2025 is the result of an unrealized foreign exchange loss and lower unrealized financial derivatives gains, partially offset by lower depletion expense and lower deferred income tax expense.
OTHER COMPREHENSIVE INCOME (LOSS)
Other comprehensive income or loss is comprised of the foreign currency translation adjustment on U.S. net assets which is not recognized in net income or loss. The foreign currency translation gain of $90.5 million for Q3/2025 and loss of $165.3 million for YTD 2025 relates to the change in value of our U.S. net assets and is due to changes in the Canadian dollar relative to the U.S. dollar at September 30, 2025 compared to June 30, 2025 and December 31, 2024. The CAD/USD exchange rate was 1.3906 CAD/USD as at September 30, 2025 compared to 1.3622 CAD/USD at June 30, 2025 and 1.4405 CAD/USD at December 31, 2024.
CAPITAL EXPENDITURES
Capital expenditures for the three and nine months ended September 30, 2025 and 2024 are summarized as follows.

| Three Months Ended September 30
| 2025 | 2024
($ thousands) | Canada | U.S. | Total | Canada | U.S. | Total
Drilling, completion and equipping | $ | 109,383 |  | $ | 141,772 |  | $ | 251,155 |  | $ | 104,787 |  | $ | 175,544 |  | $ | 280,331 |
Facilities and other | 14,196 |  | 5,013 |  | 19,209 |  | 15,686 |  | 10,315 |  | 26,001 |
Exploration and development expenditures | $ | 123,579 |  | $ | 146,785 |  | $ | 270,364 |  | $ | 120,473 |  | $ | 185,859 |  | $ | 306,332 |
Property acquisitions | $ | 23,560 |  | $ | 464 |  | $ | 24,024 |  | $ | 507 |  | $ | 535 |  | $ | 1,042 |
Proceeds from dispositions | $ | (8,254) |  | $ | — |  | $ | (8,254) |  | $ | 236 |  | $ | (1,672) |  | $ | (1,436) |
| Nine Months Ended September 30
| 2025 | 2024
($ thousands) | Canada | U.S. | Total | Canada | U.S. | Total
Drilling, completion and equipping | $ | 398,810 |  | $ | 535,571 |  | $ | 934,381 |  | $ | 311,143 |  | $ | 604,144 |  | $ | 915,287 |
Facilities and other | 56,822 |  | 40,790 |  | 97,612 |  | 69,372 |  | 73,797 |  | 143,169 |
Exploration and development expenditures | $ | 455,632 |  | $ | 576,361 |  | $ | 1,031,993 |  | $ | 380,515 |  | $ | 677,941 |  | $ | 1,058,456 |
Property acquisitions | $ | 24,934 |  | $ | 1,540 |  | $ | 26,474 |  | $ | 36,584 |  | $ | 3,210 |  | $ | 39,794 |
Proceeds from dispositions | $ | (11,794) |  | $ | 549 |  | $ | (11,245) |  | $ | 368 |  | $ | (4,524) |  | $ | (4,156) |

Exploration and development expenditures were $270.4 million for Q3/2025 and $1.0 billion for YTD 2025 compared to $306.3 million for Q3/2024 and $1.1 billion for YTD 2024. Exploration and development expenditures in Q3/2025 and YTD 2025 reflect our active heavy and light oil development program in Canada along with lower non-operated Eagle Ford development in the U.S.
In Canada, exploration and development expenditures were $123.6 million in Q3/2025 and $455.6 million for YTD 2025 compared to $120.5 million in Q3/2024 and $380.5 million for YTD 2024. Drilling and completion spending of $109.4 million in Q3/2025 and $398.8 million for YTD 2025 was higher than the comparative periods of 2024 which reflects increased development activity on our light and heavy oil properties.
Total U.S. exploration and development expenditures were $146.8 million for Q3/2025 and $576.4 million for YTD 2025 compared to $185.9 million in Q3/2024 and $677.9 million for YTD 2024. The decrease in exploration and development expenditures for both periods of 2025 compared to the same periods of 2024 reflects lower development activity primarily on our non-operated Eagle Ford properties in addition to lower drilling and completion costs on our operated properties.
Exploration and development expenditures of $1.0 billion for YTD 2025 were consistent with expectations. We expect exploration and development expenditures for 2025 to be approximately $1.2 billion.
16

CAPITAL RESOURCES AND LIQUIDITY
Our capital management objective is to maintain a strong balance sheet that provides financial flexibility to execute our development programs, provide returns to shareholders and optimize our portfolio through strategic acquisitions and dispositions. We strive to actively manage our capital structure in response to changes in economic conditions. At September 30, 2025, our capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, trade payables, dividends payable, share-based compensation liability, other long-term liabilities, cash and the credit facilities.
In order to manage our capital structure and liquidity, we 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 debt levels. There is no certainty that any of these additional sources of capital would be available if required.
Management of debt levels is a priority for Baytex in order to sustain operations and support our business strategy. Net debt(1) of $2.2 billion at September 30, 2025 was $172.8 million lower than $2.4 billion at December 31, 2024 which reflects our allocation of free cash flow to debt repayment. At current commodity prices we plan to allocate free cash flow to debt repayment after funding our quarterly dividend.
(1)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.
Credit Facilities
At September 30, 2025, we had $182.3 million of principal amount outstanding under our revolving credit facilities which total US$1.1 billion ($1.5 billion) (the "Credit Facilities"). The Credit Facilities are secured and are comprised of a US$50 million operating loan and a US$750 million syndicated revolving loan for Baytex and a US$45 million operating loan and a US$255 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc.
On June 27, 2025, we extended the maturity of the Credit Facilities from May 9, 2028 to June 27, 2029. There were no changes to the loan balances or financial covenants as a result of the amendment.
There are no mandatory principal payments required prior to maturity which could be extended upon our request. 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 ("SOFR"), plus applicable margins. Advances under the Baytex Energy USA, Inc. Credit Facilities can be drawn in U.S. funds and bear interest at the bank's prime lending rate or SOFR, plus applicable margins.
The weighted average interest rate on the Credit Facilities was 6.7% for Q3/2025 and 6.7% for YTD 2025 compared to 7.5% for Q3/2024 and 7.8% for YTD 2024. The interest rate on our Credit Facilities has decreased with lower government benchmark rates.
At September 30, 2025, we had $4.7 million of outstanding letters of credit (December 31, 2024 - $5.8 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 September 30, 2025.

Covenant Description | Position as at September 30, 2025 | Covenant
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) | 0.1:1.0 | 3.5:1.0
Interest Coverage (3) (Minimum Ratio) | 10.5:1.0 | 3.5:1.0
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio) | 1.1:1.0 | 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 September 30, 2025, the Company's Senior Secured Debt totaled $187.1 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 expenses, income tax, 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 acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended September 30, 2025 was $1.9 billion.
(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 acquisitions as if they had occurred at the beginning of the twelve-month period. Financing and interest expense for the twelve months ended September 30, 2025 was $183.0 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, leases, deferred income tax liabilities, other long-term liabilities and financial derivative liabilities. As at September 30, 2025, the Company's Total Debt totaled $2.0 billion of principal amounts outstanding.
Long-Term Notes
At September 30, 2025 we have two issuances of long-term notes outstanding with a total principal amount of $1.9 billion. The long-term notes do not contain any financial maintenance covenants.
On April 27, 2023, we issued US$800 million aggregate principal amount of senior unsecured notes due April 30, 2030 bearing interest at a rate of 8.50% per annum semi-annually (the "8.50% Senior Notes"). The 8.50% Senior Notes are redeemable at our option, in whole or in part, at specified redemption prices after April 30, 2026 and will be redeemable at par from April 30, 2028 to maturity.
On April 1, 2024, we issued US$575 million aggregate principal amount of senior unsecured notes due March 15, 2032 bearing interest at a rate of 7.375% per annum payable semi-annually ("7.375% Senior Notes"). The 7.375% Senior Notes 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.
During YTD 2025, Baytex repurchased and cancelled US$40.6 million principal of the 8.50% Senior Notes for US$38.8 million ($53.7 million) and recorded a gain of $2.8 million.
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 nine months ended September 30, 2025, we issued 0.1 million common shares pursuant to our share-based compensation program. As at September 30, 2025, we had 768.3 million common shares issued and outstanding and no preferred shares issued and outstanding. As at October 30, 2025, there were 768.3 million common shares issued and outstanding and no preferred shares issued and outstanding.
Our shareholder returns framework includes common share repurchases and a quarterly dividend. During the nine months ended September 30, 2025, we repurchased 5.4 million common shares under our normal course issuer bid ("NCIB") at an average price of $3.12 per share for total consideration of $16.8 million. In June 2025, we renewed our NCIB under which we are permitted to purchase for cancellation up to 66.2 million common shares over the 12-month period commencing July 2, 2025, which represents 10% of Baytex's public float, as defined by the Toronto Stock Exchange, as at June 18, 2025. We have obtained an exemption order from the Canadian securities regulators which permits us to purchase its common shares through the New York Stock Exchange and other U.S.-based trading systems.
During the nine months ended September 30, 2025, we recorded a $0.4 million liability related to the 2% federal tax on equity repurchases (December 31, 2024 - $4.3 million), which is charged to shareholders’ equity.
On January 2, April 1, July 2, and October 1, 2025 we paid a quarterly cash dividend of $0.0225 per share to shareholders of record. On October 30, 2025, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on January 2, 2026 to shareholders of record as at December 15, 2025. 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 September 30, 2025 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
Credit facilities - principal | $ | 182,345 |  | $ | — |  | $ | — |  | $ | 182,345 |  | $ | — |
Long-term notes - principal | 1,855,605 |  | — |  | — |  | 1,056,039 |  | 799,566 |
Interest on long-term notes (1) | 792,385 |  | 148,731 |  | 297,463 |  | 260,082 |  | 86,109 |
Lease obligations - principal | 35,531 |  | 12,901 |  | 13,797 |  | 8,833 |  | — |
Processing agreements | 5,206 |  | 948 |  | 732 |  | 536 |  | 2,990 |
Transportation agreements | 181,765 |  | 56,919 |  | 69,560 |  | 23,899 |  | 31,387 |
Total | $ | 3,052,837 |  | $ | 219,499 |  | $ | 381,552 |  | $ | 1,531,734 |  | $ | 920,052 |

(1)Excludes interest on our credit facilities as interest payments fluctuate based on a floating rate of interest and changes in the outstanding balances.
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.
17

QUARTERLY FINANCIAL INFORMATION

| 2025 | 2024 | 2023
($ thousands, except per common share amounts) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4
Petroleum and natural gas sales | 927,648 |  | 886,579 |  | 999,130 |  | 1,017,017 |  | 1,074,623 |  | 1,133,123 |  | 984,192 |  | 1,065,515 |
Net income (loss) | 31,968 |  | 151,549 |  | 69,591 |  | (38,477) |  | 185,219 |  | 103,898 |  | (14,043) |  | (625,830) |
Per common share - basic | 0.04 |  | 0.20 |  | 0.09 |  | (0.05) |  | 0.23 |  | 0.13 |  | (0.02) |  | (0.75) |
Per common share - diluted | 0.04 |  | 0.20 |  | 0.09 |  | (0.05) |  | 0.23 |  | 0.13 |  | (0.02) |  | (0.75) |
Adjusted funds flow (1) | 422,232 |  | 366,919 |  | 463,870 |  | 461,886 |  | 537,947 |  | 532,839 |  | 423,846 |  | 502,148 |
Per common share - basic | 0.55 |  | 0.48 |  | 0.60 |  | 0.59 |  | 0.68 |  | 0.65 |  | 0.52 |  | 0.60 |
Per common share - diluted | 0.55 |  | 0.48 |  | 0.60 |  | 0.59 |  | 0.67 |  | 0.65 |  | 0.52 |  | 0.60 |
Free cash flow (2) | 142,688 |  | 3,188 |  | 52,529 |  | 254,838 |  | 220,159 |  | 180,673 |  | (88) |  | 290,785 |
Per common share - basic | 0.19 |  | — |  | 0.07 |  | 0.33 |  | 0.28 |  | 0.22 |  | — |  | 0.35 |
Per common share - diluted | 0.18 |  | — |  | 0.07 |  | 0.33 |  | 0.28 |  | 0.22 |  | — |  | 0.35 |
Cash flows from operating activities | 472,676 |  | 354,312 |  | 431,317 |  | 468,865 |  | 550,042 |  | 505,584 |  | 383,773 |  | 474,452 |
Per common share - basic | 0.62 |  | 0.46 |  | 0.56 |  | 0.60 |  | 0.69 |  | 0.62 |  | 0.47 |  | 0.57 |
Per common share - diluted | 0.61 |  | 0.46 |  | 0.56 |  | 0.60 |  | 0.69 |  | 0.62 |  | 0.47 |  | 0.57 |
Dividends declared | 17,326 |  | 17,304 |  | 17,334 |  | 17,598 |  | 17,732 |  | 18,161 |  | 18,494 |  | 18,381 |
Per common share | 0.0225 |  | 0.0225 |  | 0.0225 |  | 0.0225 |  | 0.0225 |  | 0.0225 |  | 0.0225 |  | 0.0225 |
Exploration and development | 270,364 |  | 356,532 |  | 405,097 |  | 198,177 |  | 306,332 |  | 339,573 |  | 412,551 |  | 199,214 |
Canada | 123,579 |  | 147,734 |  | 184,319 |  | 108,971 |  | 120,473 |  | 101,916 |  | 158,126 |  | 75,137 |
U.S. | 146,785 |  | 208,798 |  | 220,778 |  | 89,206 |  | 185,859 |  | 237,657 |  | 254,425 |  | 124,077 |
Property acquisitions | 24,024 |  | 1,193 |  | 1,257 |  | 12,621 |  | 1,042 |  | 3,349 |  | 35,403 |  | 33,923 |
Proceeds from dispositions | (8,254) |  | (725) |  | (2,266) |  | (42,339) |  | (1,436) |  | (2,695) |  | (25) |  | (159,745) |
Net debt (1) | 2,244,358 |  | 2,293,940 |  | 2,390,250 |  | 2,417,172 |  | 2,493,269 |  | 2,639,014 |  | 2,639,841 |  | 2,534,287 |
Total assets | 7,601,389 |  | 7,552,013 |  | 7,824,576 |  | 7,759,745 |  | 7,614,157 |  | 7,770,926 |  | 7,717,495 |  | 7,460,931 |
Common shares outstanding | 768,317 |  | 768,317 |  | 770,039 |  | 773,590 |  | 787,328 |  | 804,977 |  | 821,322 |  | 821,681 |
Daily production |  |  |  |  |  |  |  |
Total production (boe/d) | 150,950 |  | 148,095 |  | 144,194 |  | 152,894 |  | 154,468 |  | 154,194 |  | 150,620 |  | 160,373 |
Canada (boe/d) | 68,185 |  | 64,167 |  | 62,380 |  | 65,332 |  | 64,668 |  | 63,688 |  | 62,081 |  | 64,744 |
U.S. (boe/d) | 82,765 |  | 83,928 |  | 81,814 |  | 87,562 |  | 89,800 |  | 90,506 |  | 88,540 |  | 95,629 |
Benchmark prices |  |  |  |  |  |  |  |
WTI oil (US$/bbl) | 64.93 |  | 63.74 |  | 71.42 |  | 70.27 |  | 75.10 |  | 80.57 |  | 76.96 |  | 78.32 |
WCS heavy oil ($/bbl) | 75.14 |  | 74.10 |  | 84.33 |  | 80.77 |  | 83.98 |  | 91.72 |  | 77.73 |  | 76.86 |
Edmonton par oil ($/bbl) | 86.20 |  | 84.15 |  | 95.27 |  | 94.98 |  | 97.91 |  | 105.30 |  | 92.16 |  | 99.72 |
CAD/USD avg exchange rate | 1.3774 |  | 1.3840 |  | 1.4350 |  | 1.3992 |  | 1.3636 |  | 1.3684 |  | 1.3488 |  | 1.3619 |
AECO natural gas ($/mcf) | 1.00 |  | 2.07 |  | 2.02 |  | 1.46 |  | 0.81 |  | 1.44 |  | 2.05 |  | 2.66 |
NYMEX natural gas (US$/mmbtu) | 3.07 |  | 3.44 |  | 3.65 |  | 2.79 |  | 2.16 |  | 1.89 |  | 2.24 |  | 2.88 |
Total sales, net of blending and other expense ($/boe) (2) | 63.22 |  | 61.16 |  | 71.38 |  | 66.60 |  | 71.97 |  | 75.93 |  | 67.12 |  | 68.00 |
Royalties ($/boe) (3) | (13.05) |  | (13.16) |  | (16.02) |  | (14.69) |  | (15.75) |  | (17.14) |  | (15.26) |  | (15.49) |
Operating expense ($/boe) (3) | (11.54) |  | (11.95) |  | (11.38) |  | (10.36) |  | (11.76) |  | (11.95) |  | (12.65) |  | (11.17) |
Transportation expense ($/boe) (3) | (2.54) |  | (2.44) |  | (2.35) |  | (2.35) |  | (2.60) |  | (2.37) |  | (2.18) |  | (2.02) |
Operating netback ($/boe) (2) | 36.09 |  | 33.61 |  | 41.63 |  | 39.20 |  | 41.86 |  | 44.47 |  | 37.03 |  | 39.32 |
Financial derivatives (loss) gain ($/boe) (3) | (0.62) |  | (0.88) |  | (0.01) |  | (0.15) |  | 0.02 |  | (0.16) |  | 0.40 |  | 0.84 |
Operating netback after financial derivatives ($/boe) (2) | 35.47 |  | 32.73 |  | 41.62 |  | 39.05 |  | 41.88 |  | 44.31 |  | 37.43 |  | 40.16 |

(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)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.
Benchmark prices for crude oil have declined over the previous eight quarters due to increasing supply from OPEC+ and North American production growth along with concerns over slowing global economic activity. Our realized sales price of $75.93/boe for Q2/2024 was our strongest realized pricing in the most recent eight quarters and we reported a realized price of $63.22/boe for Q3/2025.
Increased activity on our Eagle Ford properties following the Ranger merger resulted in production of 160,373 boe/d in Q4/2023 and has moderated since then as oil prices have declined. We have completed several non-core dispositions in Canada and the pace of non-operated activity in the U.S. has moderated which has resulted in production of 150,950 boe/d in Q3/2025. 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 $422.2 million and cash flows from operating activities of $472.7 million for Q3/2025 reflect strong production results from our development plans in the U.S. and Canada.
Net debt can fluctuate on a quarterly basis depending on changes in our free cash flow, shareholder returns and the closing CAD/USD exchange rate which is used to translate our U.S. dollar denominated debt. Net debt(1) decreased to $2.2 billion at Q3/2025 from $2.5 billion at Q4/2023 which reflects free cash flow(2) of $854.0 million generated in the period since Q4/2023, and $358.6 million allocated to shareholder returns in addition to a weaker Canadian dollar at Q3/2025, which increases the reported amount of our U.S. dollar denominated debt.
(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, 2024 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 September 30, 2025, 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 nine months ended September 30, 2025. 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, 2024.
SPECIFIED FINANCIAL MEASURES
In this MD&A, we refer to certain specified financial measures (such as free cash flow, operating netback, total sales, net of blending and other expense, heavy oil sales, net of blending and other expense, 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 debt" 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.
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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 in the following table.

| Three Months Ended September 30 | Nine Months Ended September 30
($ thousands) | 2025 | 2024 | 2025 | 2024
Petroleum and natural gas sales | $ | 927,648 |  | $ | 1,074,623 |  | $ | 2,813,357 |  | $ | 3,191,938 |
Light oil and condensate (1) | (525,900) |  | (647,587) |  | (1,569,783) |  | (1,911,352) |
NGL (1) | (41,404) |  | (50,101) |  | (141,704) |  | (145,542) |
Natural gas (1) | (31,339) |  | (26,076) |  | (119,900) |  | (84,301) |
Heavy oil | $ | 329,005 |  | $ | 350,859 |  | $ | 981,970 |  | $ | 1,050,743 |
Blending and other expense (2) | (49,750) |  | (51,902) |  | (184,951) |  | (183,795) |
Heavy oil, net of blending and other expense | $ | 279,255 |  | $ | 298,957 |  | $ | 797,019 |  | $ | 866,948 |

(1)Component of petroleum and natural gas sales. See Note 13 - Petroleum and Natural Gas Sales in the consolidated financial statements for the three and nine months ended September 30, 2025 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 provide price certainty on a portion of our production.
The following table reconciles operating netback and operating netback after realized financial derivatives to petroleum and natural gas sales.

| Three Months Ended September 30 | Nine Months Ended September 30
($ thousands) | 2025 | 2024 | 2025 | 2024
Petroleum and natural gas sales | $ | 927,648 |  | $ | 1,074,623 |  | $ | 2,813,357 |  | $ | 3,191,938 |
Blending and other expense | (49,750) |  | (51,902) |  | (184,951) |  | (183,795) |
Total sales, net of blending and other expense | 877,898 |  | 1,022,721 |  | 2,628,406 |  | 3,008,143 |
Royalties | (181,230) |  | (223,800) |  | (566,557) |  | (673,411) |
Operating expense | (160,284) |  | (167,119) |  | (469,007) |  | (508,259) |
Transportation expense | (35,295) |  | (36,883) |  | (98,714) |  | (100,032) |
Operating netback | $ | 501,089 |  | $ | 594,919 |  | $ | 1,494,128 |  | $ | 1,726,441 |
Realized financial derivatives (loss) gain (1) | (8,580) |  | 331 |  | (20,648) |  | 3,562 |
Operating netback after realized financial derivatives | $ | 492,509 |  | $ | 595,250 |  | $ | 1,473,480 |  | $ | 1,730,003 |

(1)Realized financial derivatives gain or loss is a component of financial derivatives gain or loss. See Note 17 - Financial Instruments and Risk Management in the consolidated financial statements for the three and nine months ended September 30, 2025 for further information.
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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 September 30 | Nine Months Ended September 30
($ thousands) | 2025 | 2024 | 2025 | 2024
Cash flows from operating activities | $ | 472,676 |  | $ | 550,042 |  | $ | 1,258,305 |  | $ | 1,439,399 |
Change in non-cash working capital | (55,961) |  | (20,813) |  | (17,885) |  | 31,350 |
Additions to exploration and evaluation assets | — |  | — |  | (930) |  | — |
Additions to oil and gas properties | (270,364) |  | (306,332) |  | (1,031,063) |  | (1,058,456) |
Payments on lease obligations | (3,663) |  | (2,738) |  | (10,022) |  | (13,088) |
Transaction costs | — |  | — |  | — |  | 1,539 |
Free cash flow | $ | 142,688 |  | $ | 220,159 |  | $ | 198,405 |  | $ | 400,744 |

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 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.
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.
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). 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.
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 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 provide price certainty on a portion of our production.
Capital Management Measures
Net debt
We use net debt to monitor our current financial position and to evaluate existing sources of liquidity. We also use net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. Net debt 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, other long-term liabilities, cash, trade receivables, and prepaids and other assets.
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The following table summarizes our calculation of net debt.

| As at
($ thousands) | September 30, 2025 | December 31, 2024
Credit facilities | $ | 166,841 |  | $ | 324,346 |
Unamortized debt issuance costs - Credit facilities (1) | 15,504 |  | 16,861 |
Long-term notes | 1,815,230 |  | 1,932,890 |
Unamortized debt issuance costs - Long-term notes (1) | 40,375 |  | 47,729 |
Trade payables | 554,057 |  | 512,473 |
Share-based compensation liability | 24,666 |  | 24,732 |
Dividends payable | 17,326 |  | 17,598 |
Other long-term liabilities | 20,163 |  | 20,887 |
Cash | (10,417) |  | (16,610) |
Trade receivables | (324,287) |  | (387,266) |
Prepaids and other assets | (75,100) |  | (76,468) |
Net debt | $ | 2,244,358 |  | $ | 2,417,172 |

(1)Unamortized debt issuance costs were obtained from Note 7 - Credit Facilities and Note 8 - Long-term Notes from the consolidated financial statements for the three and nine months ended September 30, 2025. 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, asset retirements obligations settled during the applicable period, and transaction costs.
Adjusted funds flow is reconciled to amounts disclosed in the primary financial statements in the following table.

| Three Months Ended September 30 | Nine Months Ended September 30
($ thousands) | 2025 | 2024 | 2025 | 2024
Cash flow from operating activities | $ | 472,676 |  | $ | 550,042 |  | $ | 1,258,305 |  | $ | 1,439,399 |
Change in non-cash working capital | (55,961) |  | (20,813) |  | (17,885) |  | 31,350 |
Asset retirement obligations settled | 5,517 |  | 8,718 |  | 12,601 |  | 22,344 |
Transaction costs | — |  | — |  | — |  | 1,539 |
Adjusted funds flow | $ | 422,232 |  | $ | 537,947 |  | $ | 1,253,021 |  | $ | 1,494,632 |

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 such material weaknesses were identified in, or that changes were made to, internal controls over financial reporting during the three months ended September 30, 2025.
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: we expect net debt to decline over the remainder of 2025; our 2025 guidance for: exploration and development expenditures, average daily production, royalty rate and operating expense, transportation expense, general and administrative expense, cash interest expense, current income taxes, lease expenditures and asset retirement obligations settled; the existence, operation and strategy of our risk management program; 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; our intent to fund certain financial obligations with adjusted funds flow and the expected timing of
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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; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; our ability to borrow under our credit agreements; 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; that we will have sufficient financial resources in the future to 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; risks associated with a third-party operating our Eagle Ford properties; 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, 2024, 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.
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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