Baytex Energy Corp.                                            
Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)
December 31, 2024


Exhibit 99.4

The following disclosures have been prepared by Baytex Energy Corp. (“Baytex” or the “Company”) in accordance with Accounting Standards Codification 932 “Extractive Activities - Oil & Gas” (“ASC 932”) issued by the Financial Accounting Standards Board. The standard requires the use of a 12 month average price to estimate proved reserves calculated as the unweighted arithmetic average of first-day-of-the-month prices within the 12 month period prior to the end of the reporting period.

Petroleum and Natural Gas Reserves Information

Users of this information should be aware that the process of estimating quantities of "proved developed" and "proved undeveloped" crude oil, natural gas liquids, bitumen and natural gas is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Future fluctuations in prices and costs, production rates, or changes in political or regulatory environments could cause the Company's reserves to be materially different from that presented.

Proved petroleum and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids (“NGL”) that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved developed petroleum and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, which may require future expenditures.

Proved undeveloped petroleum and natural gas reserves are reserves that are expected to be recovered from known accumulations where a future expenditure is required.

Proved reserves and production volumes are presented net of royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production. Figures reported as natural gas reserves and production volumes do not include flared gas, injected gas or gas consumed in operations. All natural gas reserves and production volumes presented are sales volumes. Undrilled locations underlying the estimates of our proved undeveloped reserves as of December 31, 2023 and 2024 are included in a development plan that was adopted by Baytex for the applicable year as a result of our annual long-range planning process and associated corporate financial model and all such locations were scheduled to be drilled within five years of the initial development plan adoption date.

The changes in Baytex's net proved crude oil, NGL, bitumen and natural gas reserves under constant prices and costs for the two-year period ended December 31, 2024 were as follows:
CanadaUnited States
Crude OilNGLBitumenNatural
Gas		Crude OilNGLBitumenNatural
Gas
(mbbl)(mbbl)(mbbl)(mmcf)(mbbl)(mbbl)(mbbl)(mmcf)
Net proved reserves
December 31, 202292,009 6,579 4,465 98,790 31,008 46,317 — 136,940 
Revisions of previous estimates(5,696)529 (400)(7,097)(7,169)(20,990)— (59,141)
Improved recovery— — — — — — — — 
Purchases of minerals in place6 — — — 83,302 20,189 — 116,270 
Extensions and discoveries12,276 2,240 — 9,300 14,226 4,690 — 25,681 
Production(14,940)(694)(585)(15,568)(9,961)(3,828)— (18,776)
Sales of minerals in place(10,740)(12)— (247)— — — — 
December 31, 202372,915 8,642 3,480 85,177 111,406 46,378 — 200,974 
Revisions of previous estimates3,307 (89)— (6,648)4,127 (5,771)— (25,394)
Improved recovery— — — — — — — — 
Purchases of minerals in place349 — — — — — — — 
Extensions and discoveries21,078 5,640 — 25,695 13,772 16,643 — 57,236 
Production(16,372)(930)(769)(13,908)(14,998)(5,253)— (28,134)
Sales of minerals in place(143)(5)(2,711)(24)(130)(47)— (267)
December 31, 202481,133 13,257 — 90,292 114,176 51,951 — 204,414 
Net proved developed reserves
End of year 202246,815 2,436 898 63,494 19,681 20,725 — 60,453 
End of year 202339,600 3,000 1,564 52,779 54,893 27,460 — 114,346 
End of year 202442,651 3,646 — 44,168 55,057 25,526 — 104,228 
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Baytex Energy Corp.                                            
Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)
December 31, 2024


CanadaUnited States
Crude OilNGLBitumenNatural
Gas		Crude OilNGLBitumenNatural
Gas
(mbbl)(mbbl)(mbbl)(mmcf)(mbbl)(mbbl)(mbbl)(mmcf)
Net proved undeveloped reserves
End of year 202245,194 4,143 3,567 35,295 11,327 25,592 — 76,487 
End of year 202333,314 5,641 1,916 32,398 56,513 18,918 — 86,628 
End of year 202438,482 9,611 — 46,124 59,119 26,425 — 100,186 
Total
Crude OilNGLBitumenNatural
Gas		Total
(mbbl)(mbbl)(mbbl)(mmcf)(mboe)
Net proved reserves
December 31, 2022123,017 52,895 4,465 235,729 219,666 
Revisions of previous estimates(12,865)(20,461)(400)(66,238)(44,766)
Improved recovery— — — — — 
Purchases of minerals in place83,308 20,189 — 116,270 122,875 
Extensions and discoveries26,502 6,930 — 34,981 39,262 
Production(24,901)(4,522)(585)(34,344)(35,732)
Sales of minerals in place(10,740)(12)— (247)(10,793)
December 31, 2023184,321 55,019 3,480 286,151 290,512 
Revisions of previous estimates7,434 (5,860)— (32,043)(3,767)
Improved recovery— — — — — 
Purchases of minerals in place349 — — — 349 
Extensions and discoveries34,850 22,283 — 82,931 70,955 
Production(31,370)(6,184)(769)(42,042)(45,330)
Sales of minerals in place(273)(52)(2,711)(291)(3,084)
December 31, 2024195,309 65,208 — 294,707 309,635 
Net proved developed reserves
End of year 202266,496 23,160 898 123,947 111,213 
End of year 202394,493 30,461 1,564 167,125 154,372 
End of year 202497,708 29,172 — 148,397 151,612 
Net proved undeveloped reserves
End of year 202256,521 29,735 3,567 111,782 108,453 
End of year 202389,827 24,559 1,916 119,026 136,140 
End of year 202497,601 36,036 — 146,310 158,022 

Revisions of Previous Estimates

In 2023, the Company realized total net proved revisions of negative 44,766 mboe. These revisions consisted of: (i) negative revisions of 2,809 mboe in Canada and 1,245 mboe in the U.S. due to a decrease in YE 2023 constant pricing as compared to YE 2022 (WTI decreased to US$78.21/bbl from US$94.14/bbl), (ii) positive revisions of 807 mboe in our Canadian assets as a result of improved performance as compared to previous forecasts, well design changes and changes to operating costs, (iii) negative revisions of 5,877 mboe in our non-operated Eagle Ford assets due to lower performance as compared to previous forecasts and changes in plans for undeveloped locations, and (iv) negative revisions of 30,866 mboe in our non-operated Eagle Ford assets and 4,776 mboe in our Viking assets associated with proved undeveloped locations that were not developed within five years of being booked and so are required to be removed by SEC rules.

In 2024, the Company realized total proved revisions of negative 3,767 mboe. These revisions consisted of: (i) negative revisions of 3,726 mboe in Canada and negative 782 mboe in the U.S. due to a decrease in YE 2024 constant pricing as compared to YE 2023 (WTI decreased to US$76.32/bbl from US$78.21/bbl, Henry Hub decreased to US$2.07/MMBtu from US$2.59/MMBtu), (ii) positive revisions of 6,797 mboe in our Canadian assets as a result of improved performance as compared to previous forecasts, well design changes and changes to operating costs, (iii) positive revisions of 460 mboe in our Eagle Ford assets due to improved performance as compared to previous forecasts, and (iv) negative revisions of 5,554 mboe in our non-operated Eagle Ford assets and 963 mboe in our Viking assets associated with proved undeveloped locations that were not developed within five years of being booked and so are required to be removed by SEC rules.

Purchases of minerals in place

In 2023, the Company acquired 122,875 mboe of reserves primarily in the U.S. in connection with the Company’s acquisition of Ranger Oil. In 2024, the Company acquired 349 mboe of oil reserves in the Peace River region in Canada.

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Baytex Energy Corp.                                            
Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)
December 31, 2024


Extensions and Discoveries

In 2023, the Company added 39,262 mboe of net proved reserves. These additions consisted of 16,066 mboe in Canada and 23,196 mboe in the U.S. due to drilling activity undertaken in 2023.

In 2024, the Company added 70,955 mboe of net proved reserves. These additions consisted of 31,001 mboe in Canada and 39,954 mboe in the U.S. due to extension drilling and future offset additions being added to our development plan.

Sales of Minerals in Place

In 2023, the Company divested 10,793 mboe net proved reserves as a result of a property disposition in our Viking asset in Canada.

In 2024, the Company divested 3,084 mboe net proved reserves as a result of 2,862 mboe of property dispositions in Canada, primarily from our Kerrobert Thermal asset, and 221 mboe of property dispositions in our Eagle Ford asset in the U.S.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Petroleum and Natural Gas Reserves

The following information has been developed utilizing procedures prescribed by ASC 932 and based on crude oil, NGL and natural gas reserves and production volumes estimated by Baytex's independent reserves evaluator, McDaniel & Associates Consultants Ltd. The methodology used in calculating our price assumptions for the standardized measure of discounted future net cash flows for reserves estimation is based upon the average first-day-of-the-month prices during the year.

Future production and development costs are based on constant price assumptions and assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after providing for the tax cost of the petroleum and natural gas properties based upon existing laws and regulations. A 10% discount factor was applied to the future net cash flows.

The information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the fair market value of Baytex's petroleum and natural gas properties. Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The prescribed discount rate of 10% may not appropriately reflect interest rates.

The computation of the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves was based on an unweighted arithmetic average of the first-day-of-the-month price for each month in 2024 and 2023.
Commodity Pricing
20242023
WTI crude (US$/bbl)$76.32 $78.21 
Edmonton Light crude (Cdn$/bbl)$98.01 $100.49 
Western Canadian Select crude (WCS) (1) (Cdn$/bbl)
$83.79 $79.89 
AECO spot (Cdn$/mmbtu)$1.46 $2.84 
Henry Hub (US$/mmbtu)$2.07 $2.59 
Exchange rate (US$/Cdn$)0.7330 0.7410 
(1)     Price used in the preparation of heavy oil and bitumen reserves in Canada.

The standardized measure of discounted future net cash flows relating to net proved petroleum and natural gas reserves are as follows:
CanadaUnited States
Total (2)
(thousands of Canadian dollars)202420232024202320242023
Future cash inflows$7,147,647 $6,306,909 $13,674,283 $13,067,619 $20,821,930 $19,374,528 
Future production costs(2,923,863)(2,488,443)(4,916,987)(3,690,844)(7,840,850)(6,179,287)
Future development costs (1)
(1,812,936)(1,535,153)(3,647,866)(3,976,050)(5,460,802)(5,511,203)
Future income taxes(248,023)(171,413)(270,193)(206,428)(518,216)(377,841)
Future net cash flows (2)
2,162,825 2,111,900 4,839,237 5,194,297 7,002,062 7,306,197 
Deduct:
10% annual discount factor		(637,681)(583,252)(1,841,656)(2,069,662)(2,479,337)(2,652,914)
Standardized measure (2)
$1,525,144 $1,528,648 $2,997,581 $3,124,635 $4,522,725 $4,653,283 
(1)Our estimated future costs to settle asset retirement obligations includes both: (i) estimated costs associated with future undrilled proved locations, and (ii) estimated costs associated with producing reserves. These costs are included in the “Future development costs” line.
(2)The data in the table may not add due to rounding.

3
Baytex Energy Corp.                                            
Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)
December 31, 2024


Reconciliation of Changes in Standardized Measure of Future Net Cash Flows Discounted at 10% per Year Relating to Net Proved Petroleum and Natural Gas Reserves
As at December 31, 2024
(thousands of Canadian dollars)		CanadaUnited States
Total (1)
Balance, beginning of year$1,528,648 $3,124,635 $4,653,283 
Sales, net of production costs(1,012,829)(1,398,148)(2,410,977)
Net change in prices and production costs related to future production22,156 (223,919)(201,763)
Changes in previously estimated future development costs incurred during the period(371,601)131,114 (240,487)
Development costs incurred during the period489,486 767,147 1,256,633 
Extensions, discoveries and improved recovery, net of related costs740,619 523,606 1,264,225 
Revisions of previous quantity estimates32,389 (180,663)(148,274)
Sales of reserves in place(15,376)(4,170)(19,546)
Purchases of reserves in place6,230 — 6,230 
Accretion of discount164,123 320,224 484,347 
Net change in income taxes(58,702)(62,246)(120,947)
Balance, end of year (1)
$1,525,144 $2,997,581 $4,522,725 

As at December 31, 2023
(thousands of Canadian dollars)		CanadaUnited States
Total (1)
Balance, beginning of year$2,897,463 $2,324,112 $5,221,575 
Sales, net of production costs(922,466)(994,723)(1,917,189)
Net change in prices and production costs related to future production(1,294,788)(854,833)(2,149,621)
Changes in previously estimated future development costs incurred during the period(273,910)(73,764)(347,674)
Development costs incurred during the period463,198 549,589 1,012,787 
Extensions, discoveries and improved recovery, net of related costs488,266 381,810 870,076 
Revisions of previous quantity estimates(229,669)(1,199,229)(1,428,898)
Sales of reserves in place(369,943)— (369,943)
Purchases of reserves in place70 2,398,015 2,398,085 
Accretion of discount343,679 273,609 617,288 
Net change in income taxes426,748 320,049 746,797 
Balance, end of year (1)
$1,528,648 $3,124,635 $4,653,283 
(1)The data in the table may not add due to rounding.

Capitalized Costs Relating to Petroleum and Natural Gas Producing Activities
As at December 31, 2024
(thousands of Canadian dollars)		CanadaUnited StatesTotal
Proved properties$6,885,991 $10,557,353 $17,443,344 
Unproved properties124,355 — 124,355 
Total capital costs7,010,346 10,557,353 17,567,699 
Accumulated depletion and impairment(4,865,976)(5,656,200)(10,522,176)
Net capitalized costs$2,144,370 $4,901,153 $7,045,523 

As at December 31, 2023
(thousands of Canadian dollars)		CanadaUnited StatesTotal
Proved properties$6,522,443 $9,003,574 $15,526,017 
Unproved properties90,919 — 90,919 
Total capital costs6,613,362 9,003,574 15,616,936 
Accumulated depletion and impairment(4,526,811)(4,380,173)(8,906,984)
Net capitalized costs$2,086,551 $4,623,401 $6,709,952 

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Baytex Energy Corp.                                            
Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)
December 31, 2024


Costs Incurred in Petroleum and Natural Gas Property Acquisition, Exploration and Development Activities
As at December 31, 2024
(thousands of Canadian dollars)		CanadaUnited StatesTotal
Property acquisition costs
Proved properties$9,534 $3,526 $13,060 
Unproved properties39,355 — 39,355 
Development costs (1)
489,486 767,147 1,256,633 
Exploration costs (2)
— — — 
Total$538,375 $770,673 $1,309,048 

As at December 31, 2023
(thousands of Canadian dollars)		CanadaUnited StatesTotal
Property acquisition costs
Proved properties$1,556 $18,891 $20,447 
Unproved properties18,467 — 18,467 
Development costs (1)
463,198 549,589 1,012,787 
Exploration costs (2)
— — — 
Total$483,221 $568,480 $1,051,701 
(1)     Development and facilities capital expenditures.
(2)     Cost of geological and geophysical capital expenditures and drilling costs for exploratory wells.

Results of Operations for Producing Activities
For year ended December 31, 2024
(thousands of Canadian dollars except per boe amounts)		CanadaUnited StatesTotal
Petroleum and natural gas revenues, net of royalties$1,612,841 $1,716,028 $3,328,869 
Less:
Operating costs, production and mineral taxes336,069 317,880 653,949 
Transportation and blending expense348,154 48,931 397,085 
Exploration and evaluation779 — 779 
Depletion473,792 898,271 1,372,063 
Operating income454,047 450,946 904,993 
Income tax expense110,697 97,359 208,056 
Results of operations (1)
$343,350 $353,587 $696,937 

For year ended December 31, 2023
(thousands of Canadian dollars except per boe amounts)		CanadaUnited StatesTotal
Petroleum and natural gas revenues, net of royalties$1,515,873 $1,196,956 $2,712,829 
Less:
Operating costs, production and mineral taxes368,605 202,234 570,839 
Transportation and blending expense289,127 24,981 314,108 
Exploration and evaluation8,896 — 8,896 
Depletion and impairment loss668,232 1,205,210 1,873,442 
Operating income (loss)181,013 (235,469)(54,456)
Income tax expense (recovery)44,602 (50,838)(6,236)
Results of operations (1)
$136,411 $(184,631)$(48,220)
(1)     Excludes corporate overhead and interest costs.

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