# EDGAR Filing Document

**Accession Number:** 0001279495
**File Stem:** 0001279495-26-000007
**Filing Date:** 2026-3
**Character Count:** 644123
**Document Hash:** b31f42ef3fed38c1bccd4629e581640e
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001279495-26-000007.hdr.sgml**: 20260305

**ACCESSION NUMBER**: 0001279495-26-000007

**CONFORMED SUBMISSION TYPE**: 40-F

**PUBLIC DOCUMENT COUNT**: 123

**CONFORMED PERIOD OF REPORT**: 20251231

**FILED AS OF DATE**: 20260305

**DATE AS OF CHANGE**: 20260304

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** BAYTEX ENERGY CORP.
- **CENTRAL INDEX KEY:** 0001279495
- **STANDARD INDUSTRIAL CLASSIFICATION:** DRILLING OIL & GAS WELLS [1381]
- **ORGANIZATION NAME:** 01 Energy & Transportation
- **EIN:** 981035204

**FILING VALUES:**
- **FORM TYPE:** 40-F
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-32754
- **FILM NUMBER:** 26723362

**BUSINESS ADDRESS:**
- **ADDRESS IS A NON US LOCATION:** YES
- **STREET 1:** 2800, 520 3RD AVE SW
- **CITY:** CALGARY
- **PROVINCE COUNTRY:** A0
- **ZIP:** T2P 0R3
- **BUSINESS PHONE:** 587-952-3000

**MAIL ADDRESS:**
- **ADDRESS IS A NON US LOCATION:** YES
- **STREET 1:** 2800, 520 3RD AVE SW
- **CITY:** CALGARY
- **PROVINCE COUNTRY:** A0
- **ZIP:** T2P 0R3

**FORMER COMPANY:**
- **FORMER CONFORMED NAME:** BAYTEX ENERGY TRUST
- **DATE OF NAME CHANGE:** 20040210

?xml version='1.0' encoding='ASCII'? bte-20251231

&nbsp;&nbsp;&nbsp;&nbsp;

**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

&nbsp;&nbsp;&nbsp;&nbsp;

**FORM 40-F** 

☐ **Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934**

☒ **Annual Report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934**

For the fiscal year ended:&nbsp;&nbsp;&nbsp;&nbsp;December 31, 2025

Commission File Number:&nbsp;&nbsp;&nbsp;&nbsp;001-32754

&nbsp;&nbsp;&nbsp;&nbsp;

**BAYTEX ENERGY CORP.**

(Exact name of Registrant as specified in its charter)

---

| | | |
|:---|:---|:---|
| **Alberta** | **1381** | **Not Applicable** |
| (Province or other jurisdiction of incorporation or organization) | (Primary standard industrial classification code number, if applicable) | (I.R.S. employer identification number, if applicable) |

---

**2800, 520 - 3**<sup>rd</sup> **Avenue S.W.**

**Calgary, Alberta**

**T2P 0R3**

**(587) 952-3000**

(Address and telephone number of registrant's principle executive offices)

&nbsp;&nbsp;&nbsp;&nbsp;

**Baytex Energy USA, Inc.**

**16285 Park Ten Place, Ste 500**

**Houston, Texas 77084**

 **(713) 722-6500**

(Name, address (including zip code) and telephone number (including area code) of agent for service in the United States)

Securities registered pursuant to Section 12(b) of the Act:

---

| | | |
|:---|:---|:---|
| **Title of each class** | **Trading Symbol(s)** | **Name of each exchange on which registered** |
| Common Shares | BTE | New York Stock Exchange |

---

Securities registered pursuant to Section 12(g) of the Act:

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

None

For annual reports, indicate by check mark the information filed with this form:

&nbsp;&nbsp;&nbsp;&nbsp;☒&nbsp;&nbsp;&nbsp;&nbsp;Annual Information Form&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;☒&nbsp;&nbsp;&nbsp;&nbsp;Audited Annual Financial Statements

Indicate the number of outstanding shares of the issuer's classes of capital or common stock as of the close of the period covered by the annual report: 765,568,147

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes 🗷&nbsp;&nbsp;&nbsp;&nbsp; No ◻&nbsp;&nbsp;&nbsp;&nbsp;

------

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).

Yes 🗷&nbsp;&nbsp;&nbsp;&nbsp; No ◻

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act. ☐ Emerging growth company

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐

† The term "new or revised financial accounting standard" refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ◻

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

**CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS**

Certain statements in this Annual Report on Form 40-F are forward-looking statements within the meaning of Section 21E of the Securities and Exchange Act of 1934, as amended (the "Exchange Act") and Section 27A of the Securities Act of 1933, as amended. Please see section titled "Special Note Regarding Forward-Looking Statements" in the Annual Information Form, which is Exhibit 99.1 of this Annual Report on Form 40-F.

**Principal Documents**

The following documents are filed as part of this Annual Report on Form 40-F and incorporated herein by reference:

***A.Annual Information Form***

For the Registrant's Annual Information Form for the year ended December 31, 2025, see Exhibit 99.1 of this Annual Report on Form 40-F.

***B.Audited Annual Financial Statements***

For the Registrant's Audited Consolidated Financial Statements for the year ended December 31, 2025, including the report of its Independent Registered Public Accounting Firm with respect thereto, see Exhibit 99.2 of this Annual Report on Form 40-F.

***C.Management's Discussion and Analysis***

For the Registrant's Management's Discussion and Analysis of the operating and financial results for the year ended December 31, 2025, see Exhibit 99.3 of this Annual Report on Form 40-F.

***D. Supplemental Oil and Gas Information***

For the Registrant's Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited), see Exhibit 99.4 of this Annual Report on Form 40-F.

&nbsp;&nbsp;&nbsp;&nbsp;

------

**Controls and Procedures**

***A.Certifications***

The required disclosure is included in Exhibits 99.5, 99.6, 99.7 and 99.8 of this Annual Report on Form 40-F.

***B. Disclosure Controls and Procedures***

As of the end of the Registrant's fiscal year ended December 31, 2025, an internal evaluation was conducted under the supervision of and with the participation of the Registrant's management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of the Registrant's "disclosure controls and procedures" (as defined in Rule 13a-15(e) under Exchange Act). Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of the Registrant's disclosure controls and procedures were effective to ensure that the information required to be disclosed in the reports that the Registrant files or submits to the Securities and Exchange Commission is (i) recorded, processed, summarized and reported, within the required time periods; and (ii) accumulated and communicated to the Registrant's management, including the Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding the required disclosure.

It should be noted that while the Chief Executive Officer and the Chief Financial Officer believe that the Registrant's disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect that the Registrant's disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

***C.Management's Annual Report on Internal Control Over Financial Reporting***

Management's Annual Report on Internal Control Over Financial Reporting is included in the Management's Report that accompanies the Registrant's Audited Consolidated Financial Statements for the year ended December 31, 2025, filed as Exhibit 99.2 to this Annual Report on Form 40-F, and is incorporated herein by reference.

***D.Attestation Report of Independent Registered Public Accounting Firm***

The Attestation Report of the Registrant's Auditor is included in the Report of Independent Registered Public Accounting Firm that accompanies the Registrant's Audited Consolidated Financial Statements for the year ended December 31, 2025, filed as Exhibit 99.2 of this Annual Report on Form 40-F, and is incorporated herein by reference.

***E.Changes in Internal Control Over Financial Reporting***

During the year ended December 31, 2025, there were no changes in the Registrant's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Registrant's internal control over financial reporting.

**Audit Committee Financial Expert**

The Registrant's Board of Directors has determined that Ms. Jennifer Maki is an "audit committee financial expert" (as that term is defined in paragraph 8(b) of General Instruction B to Form 40-F) and is "independent" (as defined by the New York Stock Exchange corporate governance rules).

The Securities and Exchange Commission has indicated that the designation or identification of a person as an "audit committee financial expert" does not (i) mean that such person is an "expert" for any purpose, including without limitation for purposes of Section 11 of the Securities Act of 1933, (ii) impose on such person any duties, obligations or liability that are greater than the duties, obligations and liability imposed on such person as a member of the audit committee and the board of directors in the absence of such designation or identification, or (iii) affect the duties, obligations or liability of any other member of the audit committee or the board of directors.

**Code of Ethics**

The Registrant has adopted a "code of ethics" (as that term is defined in paragraph 9(b) of General Instruction B to Form 40-F) ("Code of Ethics"), which is applicable to the directors, officers, employees and consultants of the Registrant and its affiliates

------

(including, its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions). The Code of Ethics is available on the Registrant's website at <u>www.baytexenergy.com</u>.

In the past fiscal year, the Registrant has not amended any provision of its Code of Ethics that relates to any element of the code of ethics definition enumerated in paragraph (9)(b) of General Instruction B to Form 40-F, or granted any waiver, including an implicit waiver, from any provision of its Code of Ethics.

If any amendment to the Code of Ethics is made, or if any waiver from the provisions thereof is granted, the Registrant may elect to disclose the information about such amendment or waiver required by Form 40-F to be disclosed, by posting such disclosure on the Registrant's website, which may be accessed at <u>www.baytexenergy.com</u>.

**Principal Accountant Fees and Services**

The required disclosure is included under the heading "Audit Committee Information" and subheading "External Auditor Service Fees" in the Registrant's Annual Information Form for the year ended December 31, 2025, filed as Exhibit 99.1 to this Annual Report on Form 40-F, and is incorporated herein by reference. Our independent registered public accounting firm is KPMG LLP, Calgary, Alberta, Canada, Auditor Firm ID: 85.

**Off-Balance Sheet Arrangements** 

The Registrant does not have any "off-balance sheet arrangements" (as that term is described in paragraph 11 of General Instruction B to Form 40-F) that have or are reasonably likely to have a current or future effect on its financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

**Cash Obligations**

The required disclosure is included under the heading "Capital Resources and Liquidity" and subheading "Contractual Obligations and Contingencies" in the Registrant's Management's Discussion and Analysis for the year ended December 31, 2025, filed as Exhibit 99.3 to this Annual Report on Form 40-F, and is incorporated herein by reference.

**Identification of the Audit Committee**

The Registrant has a separately designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. The Registrant's Audit Committee members consist of Ms. Jennifer Maki, Mr. Steve Reynish and Mr. Don Hrap.

**Mine Safety Disclosure**

Not applicable.

**Disclosure Regarding Foreign Jurisdictions that Prevent Inspections**

Not applicable.

**Recovery of Erroneously Awarded Compensation**

Not applicable.

**Compliance with NYSE Corporate Governance Rules** 

As a Canadian corporation listed on the NYSE, we are not required to comply with most of the NYSE's corporate governance standards, and instead may comply with Canadian corporate governance practices. However, we are required to disclose the significant differences between our corporate governance practices and the requirements applicable to U.S. domestic companies listed on the NYSE. These significant differences are disclosed on our website at <u>https://www.baytexenergy.com</u>. Except as disclosed on our website, we are in compliance with the NYSE corporate governance standards in all significant respects.

------

**UNDERTAKING**

The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

**CONSENT TO SERVICE OF PROCESS** 

(1)The Registrant has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

(2)Any change to the name or address of the Registrant's agent for service shall be communicated promptly to the Commission by amendment to Form F-X referencing the file number of the Registrant.

------

**SIGNATURES**

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this report to be signed on its behalf by the undersigned, thereto duly authorized on March 4, 2026.

---

| | |
|:---|:---|
| **BAYTEX ENERGY CORP.** | **BAYTEX ENERGY CORP.** |
| By: | *<u>/s/ Chad L. Kalmakoff</u>* |
| Name: | Chad L. Kalmakoff |
| Title: | Chief Financial Officer |

---

------

**EXHIBIT INDEX**

---

| | |
|:---|:---|
| **Exhibit No.** | **Document** |
| <u>[97.1](https://www.sec.gov/ix?doc=/Archives/edgar/data/0001279495/000127949524000041/bte-20231231.htm)</u> | Executive Incentive Compensation Clawback Policy, dated as of November 24, 2023 (incorporated by reference to Exhibit 97.1 of the Registrant's Annual Report on Form 40-F for the year ended December 31, 2023 (File No. 001-32754) |
| <u>[99.1](a991-2025aif.htm)</u> | Annual Information Form of the Registrant for the fiscal year ended December 31, 2025. |
| <u>[99.2](bte-20251231_d2.htm)</u> | Audited Consolidated Financial Statements of the Registrant for the year ended December 31, 2025 together with the Auditors' Report thereon. |
| <u>[99.3](a993-2025mda.htm)</u> | Management's Discussion and Analysis of the operating and financial results of the Registrant for the year ended December 31, 2025. |
| <u>[99.4](a994-2025asc932.htm)</u> | Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited). |
| <u>[99.5](a995-2025ceocertsec302.htm)</u> | Certification of Chief Executive Officer under Section 302 of the *Sarbanes-Oxley Act of 2002.* |
| <u>[99.6](a996-2025cfocertsec302.htm)</u> | Certification of Chief Financial Officer under Section 302 of the *Sarbanes-Oxley Act of 2002.* |
| <u>[99.7](a997-2025ceocertsec906.htm)</u> | Certification of Chief Executive Officer under Section 906 of the *Sarbanes-Oxley Act of 2002.* |
| <u>[99.8](a998-2025cfocertsec906.htm)</u> | Certification of Chief Financial Officer under Section 906 of the *Sarbanes-Oxley Act of 2002.* |
| <u>[99.9](a999-2025auditorconsent40xf.htm)</u> | Consent of KPMG LLP, Independent Registered Public Accounting Firm. |
| <u>[99.10](a9910-2025consentofmcdaniel.htm)</u> | Consent of McDaniel & Associates Consultants Ltd., independent engineers. |
| 101 | Interactive Data Files. |

---

## Exhibit 99.1

 **Exhibit 99.1**

![baytexenergy-coloura.jpg](baytexenergy-coloura.jpg)

**ANNUAL INFORMATION FORM**

**2025**

**March 4, 2026**

------

**TABLE OF CONTENTS**

---

| | |
|:---|:---|
| | Page |
| SELECTED TERMS | <u>[1](#idfb9299081314ea4a70a56049f770b00_10)</u> |
| ABBREVIATIONS | <u>[4](#idfb9299081314ea4a70a56049f770b00_13)</u> |
| CONVERSIONS AND CONVENTIONS | <u>[5](#idfb9299081314ea4a70a56049f770b00_16)</u> |
| SPECIAL NOTES TO READER | <u>[5](#idfb9299081314ea4a70a56049f770b00_19)</u> |
| CORPORATE STRUCTURE | <u>[8](#idfb9299081314ea4a70a56049f770b00_22)</u> |
| DEVELOPMENT OF OUR BUSINESS | <u>[9](#idfb9299081314ea4a70a56049f770b00_25)</u> |
| DESCRIPTION OF OUR BUSINESS | <u>[12](#idfb9299081314ea4a70a56049f770b00_28)</u> |
| PRINCIPAL PROPERTIES | <u>[13](#idfb9299081314ea4a70a56049f770b00_31)</u> |
| STATEMENT OF RESERVES DATA | <u>[20](#idfb9299081314ea4a70a56049f770b00_34)</u> |
| RISK FACTORS | <u>[31](#idfb9299081314ea4a70a56049f770b00_37)</u> |
| INDUSTRY CONDITIONS | <u>[45](#idfb9299081314ea4a70a56049f770b00_40)</u> |
| DIVIDENDS | <u>[51](#idfb9299081314ea4a70a56049f770b00_43)</u> |
| DESCRIPTION OF CAPITAL STRUCTURE | <u>[52](#idfb9299081314ea4a70a56049f770b00_46)</u> |
| MARKET FOR SECURITIES | <u>[54](#idfb9299081314ea4a70a56049f770b00_52)</u> |
| DIRECTORS AND OFFICERS | <u>[54](#idfb9299081314ea4a70a56049f770b00_55)</u> |
| AUDIT COMMITTEE INFORMATION | <u>[57](#idfb9299081314ea4a70a56049f770b00_58)</u> |
| LEGAL PROCEEDINGS AND REGULATORY ACTIONS | <u>[59](#idfb9299081314ea4a70a56049f770b00_61)</u> |
| INTEREST OF INSIDERS AND OTHER MATERIAL TRANSACTIONS | <u>[60](#idfb9299081314ea4a70a56049f770b00_64)</u> |
| TRANSFER AGENT AND REGISTRAR | <u>[60](#idfb9299081314ea4a70a56049f770b00_70)</u> |
| MATERIAL CONTRACTS | <u>[60](#idfb9299081314ea4a70a56049f770b00_67)</u> |
| INTERESTS OF EXPERTS | <u>[60](#idfb9299081314ea4a70a56049f770b00_73)</u> |
| ADDITIONAL INFORMATION | <u>[61](#idfb9299081314ea4a70a56049f770b00_76)</u> |

---

**APPENDICES:**

APPENDIX A&nbsp;&nbsp;&nbsp;&nbsp;REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

APPENDIX B&nbsp;&nbsp;&nbsp;&nbsp;REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR

APPENDIX C&nbsp;&nbsp;&nbsp;&nbsp;AUDIT COMMITTEE MANDATE AND TERMS OF REFERENCE

------

**SELECTED TERMS**

Capitalized terms in this document have the meanings set forth below:

***<u>Entities</u>***

**Baytex** or the **Corporation** means Baytex Energy Corp., a corporation incorporated under the ABCA.

**Baytex Energy** means Baytex Energy Ltd., a corporation amalgamated under the ABCA.

**Board** or **Board of Directors** means the board of directors of Baytex.

**CRA** means the Canada Revenue Agency.

**NYSE** means New York Stock Exchange.

**OPEC** means the Organization of the Petroleum Exporting Countries.

**OPEC+** means OPEC plus a number of other oil exporting countries, including Russia.

**Ranger** means Ranger Oil Corporation.

**SEC** means the United States Securities and Exchange Commission.

**Shareholders** mean the holders from time to time of Common Shares.

**subsidiary** has the meaning ascribed thereto in the *Securities Act* (Ontario) and, for greater certainty, includes all corporations, partnerships and trusts owned, controlled or directed, directly or indirectly, by us.

**the Merger** means the acquisition of all of the issued and outstanding Class A common stock of Ranger by Baytex by way of merger of Ranger and a newly formed indirect wholly owned subsidiary of Baytex.

**TSX** means the Toronto Stock Exchange.

**we**, **us** and **our** means Baytex and all its subsidiaries on a consolidated basis unless the context requires otherwise.

***<u>Securities and Other Terms</u>***

**2027 Notes** means the 8.750% senior unsecured notes due April 1, 2027 issued pursuant to an indenture dated February 5, 2020, which notes were redeemed as of April 1, 2024 and which indenture was terminated and discharged as of April 16, 2024.

**2030 Notes** means the 8.500% senior unsecured notes due April 30, 2030 issued pursuant to an indenture dated April 27, 2023, which notes were redeemed and which indenture was terminated and discharged as of December 22, 2025.

**2032 Notes** means the 7.375% senior unsecured notes due March 15, 2032 issued pursuant to an indenture dated April 1, 2024.

**ABCA** means the *Business Corporations Act* (Alberta), R.S.A. 2000, c. B-9, as amended, including the regulations promulgated thereunder.

**AIF** means this annual information form of the Corporation dated March 4, 2026 for the year ended December 31, 2025.

![btefooter1a.jpg](btefooter1a.jpg)<sub>1</sub>

------

**Baytex Annual 2025 MD&A** means Baytex's annual MD&A dated March 4, 2026 for the year ended December 31, 2025.

**Canadian GAAP** means generally accepted accounting principles in Canada, which are consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board.

**Common Shares** means the common shares of Baytex.

**Credit Facilities** means our secured covenant-based revolving credit facilities with a syndicate of financial institutions.

**CSS** means cyclic steam stimulation.

**GHG** means greenhouse gas.

**MD&A** means management's discussion and analysis of operating and financial results*.*

**NCIB** means normal course issuer bid.

**Preferred Shares** means preferred shares of Baytex.

**SAGD** means steam-assisted gravity drainage.

**Tax Act** means the *Income Tax Act* (Canada), R.S.C. 1985, c. 1 (5<sup>th</sup> Supp.), as amended, including the regulations promulgated thereunder, as amended from time to time.

**Tender Offer** has the meaning ascribed thereto under "*Development of Our Business – 2025*".

***<u>Independent Engineering</u>***

**Baytex Reserves Report** means the report of McDaniel dated February 2, 2026 entitled ''Baytex Energy Corp., Evaluation of Petroleum Reserves, Based on Forecast Prices and Costs, As of December 31, 2025''.

**COGE Handbook** means the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time.

**McDaniel** means McDaniel & Associates Consultants Ltd., independent petroleum consultants.

**NI 51-101** means National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities" of the Canadian Securities Administrators.

***<u>Reserves Definitions</u>***

**Gross** means:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)in relation to our interest in production and reserves, our interest (operating and non-operating) share before deduction of royalties and without including any of our royalty interests;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)in relation to wells, the total number of wells in which we have an interest; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c)in relation to properties, the total area of properties in which we have an interest.

**Net** means:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)in relation to our interest in production and reserves, our interest (operating and non-operating) share after deduction of royalty obligations, plus our royalty interest in production or reserves;

![btefooter1a.jpg](btefooter1a.jpg)<sub>2</sub>

------

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c)in relation to our interest in a property, the total area in which we have an interest multiplied by our working interest.

**Forecast Prices and Costs** are prices and costs that are:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)generally acceptable as being a reasonable outlook of the future; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)if, and only to the extent that, there are fixed or presently determinable future prices or costs to which Baytex is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

***<u>Reserves and Reserve Categories</u>***

**Reserves** are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)analysis of drilling, geological, geophysical and engineering data;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)the use of established technology; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c)specified economic conditions, which are generally accepted as being reasonable (being the Forecast Prices and Costs used in the estimate).

**Proved reserves** are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

**Probable reserves** are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

***<u>Development and Production Status</u>***

Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)**Developed reserves** are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure

![btefooter1a.jpg](btefooter1a.jpg)<sub>3</sub>

------

(for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into the following categories:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;i.**Developed producing reserves** are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;ii.**Developed non-producing reserves** are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)**Undeveloped reserves** are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved or probable) to which they are assigned.

**ABBREVIATIONS**

---

| | | | |
|:---|:---|:---|:---|
| **<u>Oil and Natural Gas Liquids</u>** | **<u>Oil and Natural Gas Liquids</u>** | **<u>Natural Gas</u>** | **<u>Natural Gas</u>** |
| bbl | barrel | Mcf | thousand cubic feet |
| Mbbl | thousand barrels | MMcf | million cubic feet |
| MMbbl | million barrels | Bcf | billion cubic feet |
| NGL | natural gas liquids | Mcf/d | thousand cubic feet per day |
| bbl/d | barrels per day | MMcf/d | million cubic feet per day |
|  |  | m<sup>3</sup> | cubic metres |
|  |  | MMbtu | million British Thermal Units |
| **<u>Other</u>** |  |  |  |
| API | the measure of the density or gravity of liquid petroleum products as compared to water | the measure of the density or gravity of liquid petroleum products as compared to water | the measure of the density or gravity of liquid petroleum products as compared to water |
| BOE or boe | barrel of oil equivalent, using the conversion factor of six Mcf of natural gas being equivalent to one bbl of oil. **BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.** | barrel of oil equivalent, using the conversion factor of six Mcf of natural gas being equivalent to one bbl of oil. **BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.** | barrel of oil equivalent, using the conversion factor of six Mcf of natural gas being equivalent to one bbl of oil. **BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.** |
| boe/d | barrels of oil equivalent per day | MSW | Mixed Sweet Blend |
| Mboe | thousand barrels of oil equivalent | WTI | West Texas Intermediate |
| MMboe | million barrels of oil equivalent | WCS | Western Canadian Select |
| NYMEX | the New York Mercantile Exchange | $ Million | millions of dollars |
| AECO | the natural gas storage facility located at Suffield, Alberta | $000s | thousands of dollars |
| AECO | the natural gas storage facility located at Suffield, Alberta |  |  |

---

![btefooter1a.jpg](btefooter1a.jpg)<sub>4</sub>

------

**CONVERSIONS AND CONVENTIONS**

The following table sets forth certain conversions between Standard Imperial Units and the International System of Units (or metric units).

---

| | | |
|:---|:---|:---|
| **<u>To Convert From</u>** | **<u>To</u>** | **<u>Multiply By</u>** |
| Mcf | Cubic metres | 28.174 |
| Cubic metres | Cubic feet | 35.494 |
| Bbl | Cubic metres | 0.159 |
| Cubic metres | Bbl | 6.293 |
| Feet | Metres | 0.305 |
| Metres | Feet | 3.281 |
| Miles | Kilometres | 1.609 |
| Kilometres | Miles | 0.621 |
| Acres | Hectares | 0.400 |
| Hectares | Acres | 2.500 |

---

Certain terms used herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings in this AIF as in NI 51-101. Unless otherwise indicated, references in this AIF to "$" or "dollars" are to Canadian dollars and references to "US$" are to United States dollars. All financial information contained in this AIF has been presented in Canadian dollars in accordance with Canadian GAAP. All operational information contained in this AIF relates to our consolidated operations unless the context otherwise requires.

**SPECIAL NOTES TO READER**

**Forward-Looking Statements**

In the interest of providing our Shareholders and potential investors with information about us, including management's assessment of our future plans and operations, certain statements in this AIF 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", "project", "plan", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this AIF speak only as of the date hereof and are expressly qualified by this cautionary statement.

Specifically, this AIF contains forward-looking statements relating to, but not limited to: our business strategies, plans and objectives; our 2026 guidance for exploration and development expenditures and production our dividend policy and our intentions to continue paying dividends on a consistent basis and the timing thereof; our goal of building value by developing our assets and completing selective acquisitions; that we continually review our capital program and our ability to mitigate and adapt to changes in oil and gas prices; that we are competitive with similarly situated companies; that we do not expect to be materially affected by the renegotiation or termination of contracts in 2025; development plans for our properties; undeveloped lease expiries; when we expect to pay material income taxes; our working interest production volume for 2026 based on the future net revenue disclosed in our reserves; our risk management policy's ability to manage our exposure to fluctuations in commodity prices, foreign exchange and interest rates; our use of derivative instruments and the anticipated benefits thereof; that we market our production with attention to maximizing value and counterparty performance; the development plans for our undeveloped reserves; our future abandonment and reclamation liabilities; our funding sources for development capital expenditures and our expectations that interest or other funding

![btefooter1a.jpg](btefooter1a.jpg)<sub>5</sub>

------

costs would not make development of any of our properties uneconomic; the impact of existing and proposed governmental and environmental regulation; our assessment of our tax filing position for the years 2011 through 2015; our expectations regarding the timing of receiving a judgment with respect to our notices of appeal with the Tax Court of Canada; and our expectations regarding timing should we be unsuccessful at the Tax of Court of Canada with respect to the aforementioned notices of appeal.

In addition, there are forward-looking statements in this AIF under the headings "General Description of Our Business" and "Statement of Reserves Data" as to our reserves, including with respect thereto, the future net revenues from our reserves, pricing and inflation rates, future development costs, the development of our proved undeveloped reserves and probable undeveloped reserves, future development costs, reclamation and abandonment obligations, tax horizon, exploration and development activities and production estimates.

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; the duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; 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; 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 Corporation 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,

![btefooter1a.jpg](btefooter1a.jpg)<sub>6</sub>

------

additional taxation applicable to non-residents and foreign exchange risk; and other factors, many of which are beyond our control. Readers are cautioned that the foregoing list of risk factors is not exhaustive. New risk factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. Readers should also carefully consider the matters discussed under the heading "Risk Factors" in this AIF.

The above summary of assumptions and risks related to forward-looking statements in this AIF has been provided in order to provide Shareholders and potential investors with a more complete perspective on our current and future operations and such information may not be appropriate for other purposes. There is no representation by us that actual results achieved will be the same in whole or in part as those referenced in the forward-looking statements and we do 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 forward-looking statements contained in this AIF are expressly qualified by this cautionary statement.

The Corporation's future shareholder distributions, including but not limited to the payment of dividends and the future acquisition by the Corporation of Common Shares pursuant to a share buyback (including through its NCIB), 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) or 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 Corporation'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 Corporation has incurred or may incur in the future, including the terms of the Credit Facilities) and satisfaction of the solvency tests imposed on the Corporation under applicable corporate law. There can be no assurance of the number of Common Shares that the Corporation will acquire pursuant to a share buyback, if any, in the future. Further, the payment of dividends to shareholders is not assured or guaranteed and dividends may be reduced or suspended entirely.

This AIF contains information that may be considered a financial outlook under applicable securities laws about the Corporation's potential financial position, including, but not limited to, our 2026 guidance for development expenditures; our intentions to continue paying dividends; and when we expect to pay material income taxes, all of which are subject to numerous assumptions, risk factors, limitations and qualifications, including those set forth in the above paragraphs. The actual results of operations of the Corporation and the resulting financial results will vary from the amounts set forth in this AIF and such variations may be material. This information has been provided for illustration only and with respect to future periods are based on budgets and forecasts that are speculative and are subject to a variety of contingencies and may not be appropriate for other purposes. Accordingly, these estimates are not to be relied upon as indicative of future results. Except as required by applicable securities laws, the Corporation undertakes no obligation to update such financial outlook, whether as a result of new information, future events or otherwise. The financial outlook contained in this AIF was made as of the date of this AIF and was provided for the purpose of providing further information about the Corporation's potential future business operations. Readers are cautioned that the financial outlook contained in this AIF is not conclusive and is subject to change.

![btefooter1a.jpg](btefooter1a.jpg)<sub>7</sub>

------

**New York Stock Exchange**

As a Canadian corporation listed on the NYSE, we are not required to comply with most of the NYSE's corporate governance standards and, instead, may comply with Canadian corporate governance practices. We are, however, required to disclose the significant differences between our corporate governance practices and the requirements applicable to U.S. domestic companies listed on the NYSE. Except as summarized on our website at *www.baytexenergy.com*, we are in compliance with the NYSE corporate governance standards.

**Foreign Private Issuer Status**

The Corporation continues to qualify as a foreign private issuer for the purposes of its U.S. securities filings based on the most recent assessment performed as at June 30, 2025. The Corporation is required to reassess this conclusion annually, at the end of the second quarter. See "*Risk Factors – The Corporation could lose its status as a "foreign private issuer" in the United States*", which may result in additional compliance costs and restricted access to capital markets.

**Access to Documents**

Any document referred to in this AIF and described as being accessible on the SEDAR+ website at *www.sedarplus.ca* or on EDGAR at *www.sec.gov* (including those documents referred to as being incorporated by reference in this AIF) may be obtained free of charge from us at Suite 2800, Centennial Place, East Tower, 520 - 3rd Avenue S.W., Calgary, Alberta, Canada, T2P 0R3.

**CORPORATE STRUCTURE**

Baytex Energy Corp. was incorporated on October 22, 2010 pursuant to the provisions of the ABCA. Baytex is the successor to the business of Baytex Energy Trust, which was transitioned to Baytex on December 31, 2010.

Our head and principal office is located at Suite 2800, Centennial Place, East Tower, 520 – 3<sup>rd</sup> Avenue S.W., Calgary, Alberta, Canada, T2P 0R3. Our registered office is located at 2400, 525 – 8<sup>th</sup> Avenue S.W., Calgary, Alberta, Canada, T2P 1G1. The Common Shares are currently traded on the TSX and the NYSE under the symbol "BTE".

**Inter-Corporate Relationships**

The following table provides the name, the percentage of voting securities owned by us and the jurisdiction of incorporation, continuance, formation or organization of our material subsidiaries either, direct or indirect, as at the date hereof.

---

| | | |
|:---|:---|:---|
| | **Percentage of voting securities<br>(directly or indirectly)** | **Jurisdiction of Incorporation/<br>Formation** |
| Baytex Energy Ltd. | 100% | Alberta |

---

![btefooter1a.jpg](btefooter1a.jpg)<sub>8</sub>

------

**Our Organizational Structure**

The following simplified diagram shows the inter-corporate relationships among us and our material subsidiaries as of the date hereof.

![structurea.jpg](structurea.jpg)

**DEVELOPMENT OF OUR BUSINESS**

***2023***

Oil prices were lower in 2023 as a result of global supply growth which resulted in a balanced crude market relative to 2022 when prices were elevated as the global supply shortfall was exacerbated by uncertainty related to Russian supply. The price for WTI averaged US$77.62/bbl for the year.

On February 8, 2023 the Board of Directors appointed Ms. Angela S. Lekatsas as a Director and announced that Mr. Gregory Melchin did not intend to stand for election at the next annual meeting of shareholders.

On February 23, 2023 the Common Shares commenced trading on the NYSE.

On February 28, 2023 Baytex announced its intention to acquire Ranger by way of the Merger. The Merger was completed on June 20, 2023 pursuant to the agreement and plan of merger dated February 27, 2023, as amended from time to time, between Baytex, Ranger and a newly formed indirect wholly owned subsidiary of Baytex. As consideration under the Merger, Baytex issued approximately 311.4 million Common Shares and paid $732.8 million in cash to the former security holders of Ranger. Additionally, Baytex assumed $1.1 billion of Ranger's net debt. The cash portion of the Merger was funded with the Corporation's expanded US$1.1 billion revolving Credit Facility, a US$150 million two-year term loan facility and the net proceeds from the issuance of US$800 million of 2030 Notes. The term loan facility was fully repaid and cancelled in August of 2023.

The Merger increased our Eagle Ford scale and provided an operating platform to effectively allocate capital across the Western Canadian Sedimentary Basin and the Eagle Ford.

In conjunction with closing of the Merger, we increased direct shareholder returns to 50% of free cash flow, which allowed us to increase the value of our share buyback program and introduce a dividend. The remainder of our free cash flow was allocated to debt reduction. On June 23, 2023 we announced the renewal of our NCIB allowing us to purchase up to 68,417,028 Common Shares during the 12-month period commencing June 29, 2023 and ending June 28, 2024.

In 2023, we returned approximately $260 million to shareholders through the NCIB and dividends. During 2023, we repurchased 40.5 million Common Shares under the NCIB for approximately $222 million, representing 4.7% of our issued and outstanding Common Shares, at an average price of $5.48 per Common Share. In addition, we declared two quarterly dividends during 2023 of $0.0225 per Common Share totaling approximately $38 million.

![btefooter1a.jpg](btefooter1a.jpg)<sub>9</sub>

------

On closing of the Merger, Jeffrey E. Wojahn and Tiffany ("T.J.") Thom Cepak were appointed to the Board of Directors, providing continuity and experience with the Ranger business and expertise in U.S. regulatory and operating matters.

On November 27, 2023, we announced that we had entered into a definitive agreement to sell certain of our Viking assets located at Forgan and Plato in southwest Saskatchewan (the "**Sold Viking Assets**"), effective October 1, 2023. On December 11, 2023, we completed the divestiture of the Sold Viking Assets for proceeds of $159.7 million, including closing adjustments. Proceeds from the sale were applied against our Credit Facilities. Production from the Sold Viking Assets at the time of the sale was approximately 4,000 boe/d (100% light and medium crude oil).

On December 6, 2023 we announced our anticipated 2024 exploration and development expenditures range of $1.2 to $1.3 billion, which was designed to generate average annual production of 150,000-156,000 boe/d.

**2024**

Global benchmark prices for crude oil in 2024 were relatively consistent with 2023 as a result of global supply growth and stable demand which resulted in a balanced crude oil market. The WTI benchmark price averaged US$75.72/bbl for 2024 compared to US$77.62/bbl for 2023.

On April 1, 2024, we closed a private offering of the 2032 Notes having an aggregated principal amount of US$575 million due 2032. Proceeds from the 2032 Notes were used to redeem the remaining US$409.8 million aggregate principal amount of the outstanding 2027 Notes, pay fees and expenses associated with the offering, and repay a portion of the debt outstanding on our Credit Facilities.

On April 22, 2024 we received an exemption order allowing Baytex to purchase up to ten percent (increased from five percent) of its public float of Common Shares through the NYSE and other U.S.-based trading systems as a part of an approved NCIB. The exemption was in place until August 1, 2025. On June 26, 2024 we announced the renewal of our NCIB allowing us to purchase up to 70,112,570 Common Shares during the 12-month period commencing July 2, 2024 and ending July 1, 2025.

On May 9, 2024 we amended our Credit Facilities to, among other things, extend the term by two years to May 2028 and maintained the aggregate principal amount available thereunder of US$1.1 billion.

In 2024, we returned approximately $290 million to shareholders through our NCIB and dividends. During 2024, we repurchased 48.4 million Common Shares under our NCIB at an average price of $4.50 per Common Share for total consideration of $217.9 million. In addition, we declared four quarterly dividends of $0.0225 per Common Share, totaling approximately $72 million.

On December 3, 2024 we announced our anticipated 2025 exploration and development expenditure range of $1.2 to $1.3 billion, which was designed to generate average annual production of 150,000-154,000 boe/d.

On December 20, 2024 we announced the sale of our Kerrobert thermal asset located in southwest Saskatchewan (the "**Sold Kerrobert Asset**") for net proceeds of approximately $42 million, including closing adjustments. Proceeds from the sale were applied against our Credit Facilities. Production from the Sold Kerrobert Asset at the time of the sale was approximately 2,000 boe/d (100% heavy oil). To reflect the disposition, we updated our 2025 production guidance to 148,000 to 152,000 boe/d.

![btefooter1a.jpg](btefooter1a.jpg)<sub>10</sub>

------

**2025**

Global benchmark prices for crude oil declined in 2025 compared to 2024 as a result of increasing supply and concerns over slowing global economic activity. The WTI benchmark price averaged US$64.81/bbl for 2025 compared to US$75.72/bbl for 2024.

On March 11, 2025 we announced a strategic partnership in the Pembina Duvernay with Gibson Energy Inc. ("Gibson") and the execution of a long-term take-or-pay agreement ("Agreement"). Under the 15-year Agreement, Baytex constructed certain oil and gas infrastructure and have operating responsibility for the term of the Agreement. Gibson invested approximately $50 million of capital expenditures and receive an area of dedication and established return on investment. Construction of the infrastructure was completed in the fourth quarter of 2025.

On June 24, 2025 we announced the renewal of our NCIB allowing us to purchase up to 66,244,464 Common Shares during the 12-month period commencing July 2, 2025 and ending July 1, 2026. On July 14, 2025 we received an exemption order allowing Baytex to purchase up to ten percent of its public float of Common Shares through the NYSE and other U.S.-based trading systems as a part of an approved NCIB. Without the exemption, Baytex would be permitted to purchase up to five percent of its public float of Common Shares. The exemption is in place until July 11, 2028.

On June 27, 2025 we amended our Credit Facilities to extend the term by one year to June 27, 2029 and maintained the aggregate principal amount available thereunder of US$1.1 billion.

On November 12, 2025 Baytex announced it had entered into a definitive purchase and sale agreement to sell its U.S. Eagle Ford assets (the "**Divestiture**"). The Divestiture closed on December 19, 2025 for net proceeds of US$2.2 billion ($3.0 billion) after closing adjustments. A portion of these proceeds were used to repay our Credit Facilities, redeem the 2030 Notes, and partially redeem the 2032 Notes pursuant to a cash tender offer commenced on December 1, 2025 (the "**Tender Offer**"). Pursuant to the Tender Offer, we repurchased US$505 million principal amount of the 2032 Notes. Upon closing of the Divestiture we modified our Credit Facilities to decrease the committed amount to $750.0 million from US$1.1 billion and extend maturity from June 27, 2029 to June 27, 2030.

In 2025, we returned approximately $98 million to shareholders through our NCIB and dividends. During 2025, we repurchased 8.1 million Common Shares under our NCIB at an average price of $3.55 per Common Share for total consideration of $28.9 million. In addition, we declared four quarterly dividends of $0.0225 per Common Share, totaling approximately $69 million.

On December 22, 2025 we announced our anticipated 2026 exploration and development expenditure range of $550 to $625 million, which is designed to generate average annual production of 67,000 to 69,000 boe/d. We also announced that Mr. Chad Lundberg, formerly Chief Operating Officer, had been appointed as President and Chief Operating Officer.

**Subsequent to Year-end**

On January 1, 2026 Ms. Tiffany ("T.J.") Thom Cepak and Ms. Angela S. Lekatsas resigned as directors of the Corporation.

On March 4, 2026 we announced that Chad Lundberg, President and Chief Operating Officer, would succeed Eric Greager as Chief Executive Officer following the Corporation's annual meeting of shareholders to be held on May 7, 2026.

![btefooter1a.jpg](btefooter1a.jpg)<sub>11</sub>

------

**DESCRIPTION OF OUR BUSINESS**

**Overview**

We are engaged in the acquisition, development and production of crude oil and natural gas in the Western Canadian Sedimentary Basin. Approximately 85% of our production is weighted toward crude oil and NGLs. The Corporation and its predecessors have been in business for more than 30 years and our operating teams are well established with a track record of technical proficiency and operational success. Throughout our history we have endeavoured to create value for our stakeholders by developing our assets and completing selective acquisitions and divestitures.

**Competitive Conditions**

Baytex is in the oil and natural gas industry, which is highly competitive and capital intensive, and many competitors have financial resources which exceed our own. Baytex competes with other companies for all of its business inputs, including development prospects, access to commodity markets, acquisition opportunities, available capital and staffing. Our competitive position is similar to that of other oil and natural gas producers of a similar size and production profile. See "*Industry Conditions"* and "*Risk Factors".*

**Environmental and Social Policies** 

We have an active program to monitor and comply with all environmental laws, rules and regulations applicable to our operations. Our policies require that all employees and contractors report all breaches or potential breaches of environmental laws, rules and regulations to our senior management and all applicable governmental authorities. Any material breaches of environmental law, rules and regulations must be reported to the Board of Directors. Our Health, Safety and Environment Policy is available on our website at *www.baytexenergy.com*.

In recognition of the importance of our Health, Safety and Environment Policy and targets, including our GHG and methane emission intensity reduction targets, the mandate of the reserves and sustainability committee of the Board of Directors includes specific responsibility for the "oversight and monitoring of the Corporation's performance related to health, safety, environment, climate and other sustainability matters."

**Cyclical and Seasonal Factors**

Our operational results and financial condition are dependent on the prices received for our oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years. Such prices are determined by supply and demand factors, including weather and general economic conditions, as well as conditions in other oil and natural gas regions. Any decline in oil and natural gas prices could have an adverse effect on our financial condition. We mitigate such price risk by closely monitoring commodity markets, implementing our risk management programs and by maintaining financial liquidity. Additionally, we continually review our capital program and implement initiatives to adapt to such price changes. See "*Industry Conditions"* and "*Risk Factors".*

The level of activity in the oil and gas industry is dependent on access to areas where operations are conducted. In Canada, seasonal weather variations, including spring break-up which occurs annually, affects access in certain circumstances. Unexpected adverse weather conditions, such as flooding, extreme cold weather, heavy snowfall, heavy rainfall, and forest fires may restrict the Corporation's ability to access its properties and/or operate its wells. See "*Industry Conditions"* and "*Risk Factors".*

![btefooter1a.jpg](btefooter1a.jpg)<sub>12</sub>

------

**Renegotiation or Termination of Contracts**

As at the date hereof, we do not anticipate that any aspects of our business will be materially affected during the remainder of 2026 by the renegotiation or termination of any contracts to which we are a party.

**Personnel**

As at December 31, 2025, Baytex had 227 employees, comprised of 171 employees in our head office and 56 employees in our field operations.

**PRINCIPAL PROPERTIES**

The following is a description of our principal oil and natural gas properties on production or under development as at December 31, 2025. Unless otherwise specified, gross and net acres and well count information are as at December 31, 2025 and production information represents average working interest production for the year ended December 31, 2025. All of our properties are located onshore in the Provinces of Alberta and Saskatchewan, Canada.

***Peace River - Alberta***

In the Peace River area of northwest Alberta we produce heavy gravity crude oil and natural gas from the Bluesky formation and the Spirit River (a Clearwater equivalent) formation. The core of our Clearwater play is located on the Peavine Métis settlement. Production in the area occurs through primary and polymer flooding recovery methods. During 2025, production from the area averaged approximately 30,609 boe/d, comprised of 28,961 bbl/d of heavy crude oil, 44 bbl/d of NGL and 9,629 Mcf/d of conventional natural gas. In 2025, Baytex drilled 53 (53.0 net) horizontal multi-lateral wells in this area. As at December 31, 2025, we had proved plus probable reserves of 58 million boe (35 million proved; 23 million probable).

Baytex held approximately 335,460 net undeveloped acres in this area as at December 31, 2025.

***Lloydminster - Alberta and Saskatchewan***

Our Lloydminster assets consist of several geographically dispersed heavy crude oil operations where we target multiple Manville formations and use multi-lateral horizontal drilling and circulation string horizontal drilling to develop our inventory. In some cases, Baytex's heavy crude oil reservoirs are water flooded and polymer flooded. During 2025, production averaged approximately 12,928 boe/d, comprised of 12,700 bbl/d of heavy crude oil, 19 bbl/d of light and medium crude oil, and 1,258 Mcf/d of conventional natural gas. In 2025, Baytex drilled 67 (55.2 net) oil wells in this area. As at December 31, 2025, we had proved plus probable reserves of 89 million boe (25 million proved; 64 million probable).

Baytex held approximately 135,627 net undeveloped acres in this area at December 31, 2025.

***Duvernay - Alberta***

Baytex holds a large 100% working interest land position in the Pembina-Gilby area of the Duvernay resource play in central Alberta. Production in the area occurs from the hydraulic fracturing of horizontal wells. During 2025, production averaged 8,328 boe/d, comprised of 6,524 bbl/d of tight oil and NGL and 10,825 Mcf/d of natural gas. During 2025, Baytex drilled 9 (9.0 net) oil wells in this area. As at December 31, 2025, we had proved plus probable reserves of 82 million boe (57 million proved; 25 million probable).

Baytex held approximately 66,815 net undeveloped acres in this area at December 31, 2025.

![btefooter1a.jpg](btefooter1a.jpg)<sub>13</sub>

------

***Viking - Alberta and Saskatchewan***

Our Viking assets are located in the greater Kindersley area in southwest Saskatchewan and in the Esther area of southeastern Alberta. These assets produce light oil from the Viking formation and production occurs primarily from the hydraulic fracturing of horizontal wells. In some areas, reservoirs are placed under waterflood. These assets are characterized by shallow wells with short cycle times and a manufacturing approach to development. During 2025, production averaged 9,771 boe/d, comprised of 8,018 bbl/d of light and medium crude oil and NGL, 10,071 Mcf/d of conventional natural gas, and 74 bbl/d of heavy crude oil. In 2025, Baytex completed 85 (82.0 net) oil wells. As at December 31, 2025 we had proved plus probable reserves of 38 million boe (23 million proved; 15 million probable).

Baytex held approximately 66,092 net undeveloped acres in this area at December 31, 2025.

**Average Production**

The following table indicates our average daily production from our principal properties for the year ended December 31, 2025.

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| **Average Daily Production** <sup>(1)</sup> | **Heavy Crude Oil<br>(bbl/d)** | **Bitumen<br>(bbl/d)** | **Light and Medium Crude Oil**<br>**(bbl/d)** | **Tight Oil**<br>**(bbl/d)** | **NGL**<sup>(2)</sup><br>**(bbl/d)** | **Shale Gas<br>(Mcf/d)** | **Conven-tional Natural Gas<br>(Mcf/d)** | **Oil Equivalent<br>(boe/d)** |
| **Canada - Heavy** | | | | | | | | |
| Peace River | 28961 |  |  |  | 44 |  | 9629 | 30609 |
| Lloydminster | 12700 |  | 19 |  |  |  | 1258 | 12928 |
| Remaining properties | 1034 |  |  |  | 2 |  | 680 | 1150 |
| Total | 42695 |  | 19 |  | 46 |  | 11567 | 44687 |
| **Canada - Light** |  |  |  |  |  |  |  |  |
| Viking | 74 |  | 7752 |  | 266 |  | 10071 | 9771 |
| Duvernay |  |  |  | 3755 | 2769 | 10825 |  | 8328 |
| Remaining properties | 6 |  | 251 |  | 563 |  | 11525 | 2742 |
| Total | 80 |  | 8003 | 3755 | 3598 | 10825 | 21596 | 20841 |
| **United States** |  |  |  |  |  |  |  |  |
| Eagle Ford <sup>(3)</sup> |  |  |  | 47764 | 16698 | 90528 |  | 79551 |
| **Grand Total** | **42775** | **—** | **8022** | **51519** | **20342** | **101353** | **33163** | **145079** |

---

Note:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Before deduction of royalties and including royalty interests.

&nbsp;&nbsp;&nbsp;&nbsp;(2)Includes condensate.

&nbsp;&nbsp;&nbsp;&nbsp;(3)Eagle Ford assets were disposed of on December 19, 2025. See "*Development of our Business – 2025*".

![btefooter1a.jpg](btefooter1a.jpg)<sub>14</sub>

------

**Costs Incurred**

The following table summarizes the property acquisition, exploration and development costs by country for the year ended December 31, 2025.

---

| | | | |
|:---|:---|:---|:---|
| ($000s) | **Canada** | **United States** | **Total** |
| Property acquisition costs |  |  |  |
| &nbsp;&nbsp;&nbsp;Proved properties | 279 | 1867 | 2146 |
| &nbsp;&nbsp;&nbsp;Unproved properties | 29872 |  | 29872 |
| Property disposition | (11953) | (3011350) | (3023303) |
| Total Property acquisition costs, net | 18198 | (3009483) | (2991285) |
| Development Costs <sup>(1)</sup> | 547422 | 657719 | 1205141 |
| Exploration Costs <sup>(2)</sup> | 930 |  | 930 |
| Total | 566550 | (2351764) | (1785214) |

---

Note:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Development and facilities expenditures.

&nbsp;&nbsp;&nbsp;&nbsp;(2)Cost of land, geological and geophysical capital expenditures.

**Oil and Gas Wells**

The following table sets forth the number and status of wells in which we have a working interest as at December 31, 2025.

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Oil Wells** | **Oil Wells** | **Oil Wells** | **Oil Wells** | **Natural Gas Wells** | **Natural Gas Wells** | **Natural Gas Wells** | **Natural Gas Wells** |
| | **Producing** | **Producing** | **Non-Producing** | **Non-Producing** | **Producing** | **Producing** | **Non-Producing** | **Non-Producing** |
| | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** |
| Alberta | 1070 | 1001.8 | 808 | 569.5 | 82 | 49.7 | 196 | 140.0 |
| Saskatchewan | 2685 | 2427.0 | 1289 | 1262.4 | 66 | 34.8 | 182 | 165.9 |
| Total | 3755 | 3428.8 | 2097 | 1831.9 | 148 | 84.5 | 378 | 305.9 |

---

**Properties with No Attributed Reserves**

The following table sets forth our undeveloped land holdings as at December 31, 2025.

---

| | | |
|:---|:---|:---|
| | **Undeveloped Acres** | **Undeveloped Acres** |
| | **Gross** | **Net** |
| Alberta | 585352 | 556139 |
| Saskatchewan | 131545 | 116419 |
| Total | 716897 | 672558 |

---

Undeveloped land holdings are lands that have not been assigned reserves as at December 31, 2025. None of these undeveloped properties have high expected development or operating costs or contractual sales obligations to produce and sell at substantially lower prices than could be realized under normal market conditions.

We estimate the value of our net undeveloped land holdings at December 31, 2025 to be approximately $151 million, as compared to $251 million as at December 31, 2024. This internal evaluation generally represents the estimated replacement cost of our undeveloped land and excludes approximately 14,267 net acres of our undeveloped land that we expect to expire on or before December 31, 2026. In

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 15 |

---

------

determining replacement cost, we analyzed land sale prices paid at provincial crown land sales for properties in the vicinity of our undeveloped land holdings over the preceding three years.

**Tax Horizon**

Baytex does not expect to pay material cash income taxes prior to 2028 when forecasted using the commodity price forecasts and inflation rates as of January 1, 2026 used to prepare the Baytex Reserves Report. Baytex forecasts that once the tax horizon is reached, cash income taxes will average 8-12% of EBITDA<sup>(1)</sup> from that point onwards.

Note:

(1)Calculated in accordance with the agreement governing our Credit Facilities which is available on SEDAR+ at *www.sedarplus.ca*.

**Exploration and Development Activities** 

The following table sets forth the gross and net exploratory and development wells in which we participated during the year ended December 31, 2025.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Exploratory Wells** | **Exploratory Wells** | **Development Wells** | **Development Wells** | **Total Wells** | **Total Wells** |
| | **Gross** | **Net** | **Gross** | **Net** | **Gross** | **Net** |
| ***CANADA*** | | | | | | |
| Oil Wells |  |  | 218 | 203.2 | 218 | 203.2 |
| Natural Gas Wells |  |  | 2 | 2.0 | 2 | 2.0 |
| Stratigraphic Test Wells | 7 | 7.0 |  |  | 7 | 7.0 |
| Service Wells |  |  | 3 | 3.0 | 3 | 3.0 |
| Total | 7 | 7.0 | 223 | 208.2 | 230 | 215.2 |
| ***UNITED STATES*** <sup>(1)</sup> |  |  |  |  |  |  |
| Oil Wells |  |  | 55 | 41.5 | 55 | 41.5 |
| Natural Gas Wells |  |  | 10 | 8.3 | 10 | 8.3 |
| Total |  |  | 65 | 49.8 | 65 | 49.8 |

---

Note:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Our United States assets were disposed of on December 19, 2025. See "*Development of our Business – 2025*".

**Production Estimates**

The following table sets out the volumes of our working interest production estimated for the year ending December 31, 2026, which is reflected in the estimate of future net revenue disclosed in the forecast price tables contained under "*Statement of Reserves Data - Disclosure of Reserves Data*".

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Heavy Crude Oil<br>(bbl/d)** | **Bitumen<br>(bbl/d)** | **Light and Medium Crude Oil<br>(bbl/d)** | **Tight Oil<br>(bbl/d)** | **NGL**<br>**(bbl/d)**<sup>(1)</sup> | **Shale Gas<br>(Mcf/d)** | **Natural Gas<br>(Mcf/d)** | **Oil Equivalent<br>(boe/d)** |
| Total Proved | 37476 |  | 7823 | 4195 | 4716 | 12482 | 32140 | 61646 |
| Total Proved plus Probable | 43274 |  | 8486 | 4444 | 4968 | 13040 | 34608 | 69114 |

---

Note:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Includes condensate.

The Peace River and Lloydminster properties account for 20% or more of the estimated 2026 production volumes. Estimated 2026 production volumes for the Peace River property is 24,292 boe/d on a total proved basis and 28,277 boe/d on a total proved plus probable basis. Estimated 2026 production volumes

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 16 |

---

------

for the Lloydminster property is 14,014 boe/d on a total proved basis and 15,842 boe/d on a total proved plus probable basis.

**Production History**

The following table summarizes certain information in respect of the production, product prices received, royalties paid, production costs and resulting netback associated with our reserves data for the periods indicated below.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Three Months Ended** | **Three Months Ended** | **Three Months Ended** | **Three Months Ended** | **Year Ended** |
| | **Dec. 31, 2025** | **Sep. 30, 2025** | **Jun. 30, 2025** | **Mar. 31, 2025** | **Dec. 31, 2025** |
| **Average Sales Volume** <sup>(1)</sup> | | | | | |
| ***CANADA*** | | | | | |
| &nbsp;&nbsp;&nbsp;Light and Medium Crude Oil (bbl/d) | 7295 | 7680 | 7873 | 9268 | 8022 |
| &nbsp;&nbsp;&nbsp;Heavy Crude Oil (bbl/d) | 42628 | 45269 | 42959 | 40192 | 42775 |
| &nbsp;&nbsp;&nbsp;Bitumen (bbl/d) |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil (bbl/d) | 4584 | 4823 | 3177 | 2402 | 3755 |
| &nbsp;&nbsp;NGL (bbl/d) <sup>(2)</sup> | 4640 | 3587 | 3103 | 3228 | 3644 |
| Total liquids (bbl/d) | 59147 | 61359 | 57112 | 55090 | 58196 |
| &nbsp;&nbsp;&nbsp;Shale Gas (Mcf/d) | 14801 | 13758 | 7915 | 6705 | 10825 |
| &nbsp;&nbsp;&nbsp;Conventional Natural Gas (Mcf/d) | 34094 | 27203 | 34416 | 37038 | 33163 |
| Total (boe/d) | 67295 | 68185 | 64167 | 62380 | 65528 |
| ***UNITED STATES*** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil (bbl/d) | 41232 | 50993 | 49910 | 48971 | 47764 |
| &nbsp;&nbsp;NGL (bbl/d) <sup>(2)</sup> | 14401 | 16919 | 17993 | 17512 | 16698 |
| Total liquids (bbl/d) | 55633 | 67912 | 67903 | 66483 | 64462 |
| &nbsp;&nbsp;&nbsp;Shale Gas (Mcf/d) | 84950 | 89115 | 96151 | 91988 | 90528 |
| Total (boe/d) | 69792 | 82765 | 83928 | 81814 | 79551 |
| ***TOTAL*** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Light and Medium Crude Oil (bbl/d) | 7295 | 7680 | 7873 | 9268 | 8022 |
| &nbsp;&nbsp;&nbsp;Heavy Crude Oil (bbl/d) | 42628 | 45269 | 42959 | 40192 | 42775 |
| &nbsp;&nbsp;&nbsp;Bitumen (bbl/d) |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil (bbl/d) | 45816 | 55816 | 53087 | 51373 | 51519 |
| &nbsp;&nbsp;NGL (bbl/d) <sup>(2)</sup> | 19041 | 20506 | 21096 | 20740 | 20342 |
| Total liquids (bbl/d) | 114780 | 129271 | 125015 | 121573 | 122658 |
| &nbsp;&nbsp;&nbsp;Shale Gas (Mcf/d) | 99751 | 102873 | 104066 | 98693 | 101353 |
| &nbsp;&nbsp;&nbsp;Conventional Natural Gas (Mcf/d) | 34094 | 27203 | 34416 | 37038 | 33163 |
| Total (boe/d) | 137087 | 150950 | 148095 | 144194 | 145079 |

---

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 17 |

---

------

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Three Months Ended** | **Three Months Ended** | **Three Months Ended** | **Three Months Ended** | **Year Ended** |
| | **Dec. 31, 2025** | **Sep. 30, 2025** | **Jun. 30, 2025** | **Mar. 31, 2025** | **Dec. 31, 2025** |
| ***CANADA*** | | | | | |
| **Average Prices Received** <sup>(3)</sup> | | | | | |
| &nbsp;&nbsp;&nbsp;Light and Medium Crude Oil ($/bbl) | 75.32 | 84.90 | 81.46 | 93.45 | 84.30 |
| &nbsp;&nbsp;&nbsp;Heavy Crude Oil ($/bbl) | 58.62 | 67.05 | 64.43 | 73.51 | 65.77 |
| &nbsp;&nbsp;&nbsp;Bitumen ($/bbl) |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil ($/bbl) | 76.87 | 86.64 | 85.47 | 95.71 | 84.82 |
| &nbsp;&nbsp;NGL ($/bbl) <sup>(2)</sup> | 21.65 | 24.27 | 24.91 | 30.02 | 24.82 |
| &nbsp;&nbsp;&nbsp;Shale Gas ($/Mcf) | 2.15 | 0.70 | 1.57 | 2.00 | 1.56 |
| &nbsp;&nbsp;&nbsp;Conventional Natural Gas ($/Mcf) | 2.07 | 0.63 | 1.77 | 2.06 | 1.69 |
| Total ($/boe) <sup>(4)</sup> | 53.55 | 61.88 | 59.71 | 67.92 | 60.61 |
| **Royalties Paid** |  |  |  |  |  |
| &nbsp;&nbsp;Light and Medium Crude Oil and NGL ($/bbl) <sup>(2)(5)</sup> | 3.80 | 4.63 | 5.00 | 5.63 | 4.77 |
| &nbsp;&nbsp;&nbsp;Heavy Crude Oil ($/bbl) | 8.82 | 10.51 | 9.94 | 13.97 | 10.74 |
| &nbsp;&nbsp;&nbsp;Bitumen ($/bbl) |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil ($/bbl) | 9.00 | 11.18 | 11.17 | 10.66 | 10.43 |
| &nbsp;&nbsp;&nbsp;Shale Gas ($/Mcf) | 0.20 | 0.06 | 0.09 | 0.10 | 0.12 |
| &nbsp;&nbsp;&nbsp;Conventional Natural Gas ($/Mcf) | 0.10 | 0.02 | 0.20 |  | 0.08 |
| Total ($/boe) <sup>(6)</sup> | 6.97 | 8.55 | 8.19 | 10.55 | 8.52 |
| **Operating Expenses** <sup>(7)</sup> |  |  |  |  |  |
| &nbsp;&nbsp;Light and Medium Crude Oil and NGL ($/bbl) <sup>(2)(5)</sup> | 16.60 | 14.85 | 17.01 | 15.37 | 15.95 |
| &nbsp;&nbsp;&nbsp;Heavy Crude Oil ($/bbl) | 14.16 | 13.92 | 15.24 | 13.37 | 14.18 |
| &nbsp;&nbsp;&nbsp;Bitumen ($/bbl) |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil ($/bbl) | 6.88 | 7.43 | 8.76 | 7.89 | 7.61 |
| &nbsp;&nbsp;&nbsp;Shale Gas ($/Mcf) | 1.15 | 1.24 | 1.46 | 1.31 | 1.26 |
| &nbsp;&nbsp;&nbsp;Conventional Natural Gas ($/Mcf) | 2.38 | 2.70 | 2.52 | 2.23 | 2.44 |
| Total ($/boe) <sup>(6)</sup> | 13.84 | 13.55 | 15.08 | 13.46 | 13.98 |
| **Transportation Expenses** |  |  |  |  |  |
| &nbsp;&nbsp;Light and Medium Crude Oil and NGL ($/bbl) <sup>(2)(5)</sup> | 0.98 | 0.97 | 0.77 | 0.62 | 0.83 |
| &nbsp;&nbsp;&nbsp;Heavy Crude Oil ($/bbl) | 4.62 | 4.70 | 4.59 | 4.56 | 4.62 |
| &nbsp;&nbsp;&nbsp;Bitumen ($/bbl) |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil ($/bbl) | 1.53 | 1.95 | 1.36 | 1.41 | 1.61 |
| &nbsp;&nbsp;&nbsp;Shale Gas ($/Mcf) | 0.25 | 0.32 | 0.23 | 0.24 | 0.27 |
| &nbsp;&nbsp;&nbsp;Conventional Natural Gas ($/Mcf) | 0.36 | 0.48 | 0.41 | 0.34 | 0.39 |
| Total ($/boe) <sup>(6)</sup> | 3.44 | 3.68 | 3.52 | 3.34 | 3.50 |
| **Resulting Netback** <sup>(3)(8)</sup> |  |  |  |  |  |
| &nbsp;&nbsp;Light and Medium Crude Oil and NGL ($/bbl) <sup>(2)(5)</sup> | 33.07 | 45.15 | 42.70 | 55.44 | 44.17 |
| &nbsp;&nbsp;&nbsp;Heavy Crude Oil ($/bbl) | 31.02 | 37.92 | 34.66 | 41.61 | 36.23 |
| &nbsp;&nbsp;&nbsp;Bitumen ($/bbl) |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil ($/bbl) | 59.46 | 66.08 | 64.18 | 75.75 | 65.17 |
| &nbsp;&nbsp;&nbsp;Shale Gas ($/Mcf) | 0.55 | (0.92) | (0.21) | 0.35 | (0.09) |
| &nbsp;&nbsp;&nbsp;Conventional Natural Gas ($/Mcf) | (0.77) | (2.57) | (1.36) | (0.51) | (1.22) |
| Total ($/boe) <sup>(4)</sup> | 29.30 | 36.10 | 32.92 | 40.57 | 34.61 |

---

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 18 |

---

------

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Three Months Ended** | **Three Months Ended** | **Three Months Ended** | **Three Months Ended** | **Year Ended** |
| | **Dec. 31, 2025** | **Sep. 30, 2025** | **Jun. 30, 2025** | **Mar. 31, 2025** | **Dec. 31, 2025** |
| ***UNITED STATES*** <sup>(9)</sup> | | | | | |
| **Average Prices Received** <sup>(3)</sup> | | | | | |
| &nbsp;&nbsp;&nbsp;Tight Oil ($/bbl) | 81.62 | 88.56 | 86.77 | 100.75 | 89.66 |
| &nbsp;&nbsp;NGL ($/bbl) <sup>(2)</sup> | 28.43 | 29.18 | 29.54 | 38.22 | 31.45 |
| &nbsp;&nbsp;&nbsp;Shale Gas ($/Mcf) | 3.96 | 3.52 | 3.78 | 4.92 | 4.04 |
| Total ($/boe) <sup>(4)</sup> | 58.91 | 64.32 | 62.26 | 74.01 | 65.04 |
| **Royalties Paid** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil ($/bbl) | 22.23 | 23.12 | 23.98 | 27.78 | 24.33 |
| &nbsp;&nbsp;NGL ($/bbl) <sup>(2)</sup> | 7.81 | 7.80 | 7.77 | 10.33 | 8.45 |
| &nbsp;&nbsp;&nbsp;Shale Gas ($/Mcf) | 0.99 | 0.85 | 0.91 | 1.20 | 0.99 |
| Total ($/boe) <sup>(6)</sup> | 15.96 | 16.76 | 16.97 | 20.19 | 17.51 |
| **Operating Expenses** <sup>(7)</sup> |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil ($/bbl) | 11.22 | 9.89 | 9.56 | 9.79 | 10.07 |
| &nbsp;&nbsp;NGL ($/bbl) <sup>(2)</sup> | 11.22 | 9.89 | 9.56 | 9.79 | 10.06 |
| &nbsp;&nbsp;&nbsp;Shale Gas ($/Mcf) | 1.87 | 1.65 | 1.59 | 1.63 | 1.68 |
| Total ($/boe) <sup>(6)</sup> | 11.22 | 9.89 | 9.56 | 9.79 | 10.07 |
| **Transportation Expenses** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil ($/bbl) | 1.46 | 1.61 | 1.62 | 1.59 | 1.57 |
| &nbsp;&nbsp;NGL ($/bbl) <sup>(2)</sup> | 1.46 | 1.61 | 1.62 | 1.59 | 1.57 |
| &nbsp;&nbsp;&nbsp;Shale Gas ($/Mcf) | 0.24 | 0.27 | 0.27 | 0.27 | 0.26 |
| Total ($/boe) <sup>(6)</sup> | 1.46 | 1.61 | 1.62 | 1.59 | 1.57 |
| **Resulting Netback** <sup>(3)(8)</sup> |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Tight Oil ($/bbl) | 46.71 | 53.94 | 51.61 | 61.59 | 53.69 |
| &nbsp;&nbsp;NGL ($/bbl) <sup>(2)</sup> | 7.94 | 9.88 | 10.59 | 16.51 | 11.37 |
| &nbsp;&nbsp;&nbsp;Shale Gas ($/Mcf) | 0.86 | 0.75 | 1.01 | 1.82 | 1.11 |
| Total ($/boe) <sup>(4)</sup> | 30.27 | 36.06 | 34.11 | 42.44 | 35.89 |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Before deduction of royalties and including royalty interests.

&nbsp;&nbsp;&nbsp;&nbsp;(2)NGL includes condensate.

&nbsp;&nbsp;&nbsp;&nbsp;(3)Before the effects of commodity derivative instruments.

&nbsp;&nbsp;&nbsp;&nbsp;(4)Non-GAAP 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. See "Specified Financial Measures" in the Baytex Annual 2025 MD&A for information related to this measure, which section has been incorporated by reference herein. The Baytex Annual 2025 MD&A is available on SEDAR+ at *www.sedarplus.ca*.

&nbsp;&nbsp;&nbsp;&nbsp;(5)In Canada, NGL volumes are grouped with light crude oil volumes for reporting purposes.

&nbsp;&nbsp;&nbsp;&nbsp;(6)Supplementary financial measure. See "Royalties", "Operating Expense", and "Transportation Expense" in the Baytex Annual 2025 MD&A for information related to this measure, which section has been incorporated by reference herein. Baytex Annual 2025 MD&A is available on SEDAR+ at *www.sedarplus.ca*.

&nbsp;&nbsp;&nbsp;&nbsp;(7)Operating expenses are composed of direct costs incurred to operate both oil and gas wells. A number of assumptions are required to allocate these costs between oil, Conventional natural gas and NGL production.

&nbsp;&nbsp;&nbsp;&nbsp;(8)Netback is calculated by subtracting royalties paid, operating and transportation expenses from revenues.

&nbsp;&nbsp;&nbsp;&nbsp;(9)Our United States assets were disposed of on December 19, 2025. See "*Development of our Business - 2025*".

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 19 |

---

------

**Marketing Arrangements and Forward Contracts**

We market our operated oil and natural gas production with the objective of maximizing value and counterparty performance. We have a portfolio of sales contracts with a variety of pricing mechanisms, term commitments and customers and we also have several committed transportation and processing contracts with volume and term commitments that enable us to transport our production to sales points. The Corporation also has a risk management policy pursuant to which we utilize various derivative financial instruments and physical sales contracts to manage our exposure to fluctuations in commodity prices, foreign exchange and interest rates. We also use derivative instruments in various operational markets to optimize our supply or production chain.

When marketing and hedging we engage a number of reputable counterparties to ensure competitiveness, while also managing counterparty credit exposure. For details on our contractual commitments to sell natural gas and crude oil which were outstanding at March 4, 2026, see Note 19 to our audited consolidated financial statements for the year ended December 31, 2025. See "*Risk Factors".*

**STATEMENT OF RESERVES DATA**

The Baytex Reserves Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserves definitions contained in NI 51-101. The statement of reserves data and other oil and natural gas information set forth below is dated December 31, 2025. The effective date of the Baytex Reserves Report is December 31, 2025 and the preparation date of the statement is February 2, 2026. The Baytex Reserves Report was prepared using the average commodity price forecasts and inflation rates of McDaniel, GLJ Petroleum Consultants Ltd. and Sproule ERCE as of January 1, 2026.

**Disclosure of Reserves Data**

The following tables are a summary as at December 31, 2025 of our proved and probable heavy crude oil, bitumen, light and medium oil, tight oil, NGL, conventional natural gas and shale gas reserves and the net present value of the future net revenue attributable to such reserves evaluated in the Baytex Reserves Report. Our reserves are located in Canada (Alberta and Saskatchewan).

**All evaluations of future net revenue are after the deduction of future income tax expenses (unless otherwise noted in the tables), royalties, development costs, production costs and well abandonment costs but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of our reserves. There is no assurance that the forecast price and cost assumptions contained in the Baytex Reserves Report will be attained and variations could be material. The tables summarize the data contained in the Baytex Reserves Report and, as a result, may contain slightly different numbers and columns in the tables may not add due to rounding. Other assumptions and qualifications relating to costs and other matters are summarized in the notes to or following the tables below.**

**The recovery and reserves estimates described herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Readers should review the definitions and information contained in "*Selected Terms*** - ***Reserves Definitions*", "Selected Terms** - ***Reserves and Reserve Categories*" and "Selected Terms** - ***Development and Production Status*" in conjunction with the following tables and notes. For more information as to the risks involved, see "*Risk Factors*"*.***

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 20 |

---

------

**SUMMARY OF OIL AND NATURAL GAS RESERVES** 

**AS OF DECEMBER 31, 2025**

**FORECAST PRICES AND COSTS**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **TIGHT OIL** | **TIGHT OIL** | **LIGHT AND MEDIUM CRUDE OIL** | **LIGHT AND MEDIUM CRUDE OIL** | **HEAVY CRUDE OIL** | **HEAVY CRUDE OIL** |
| **<u>RESERVES CATEGORY</u>** | **Gross<br>(Mbbl)** | **Net<br>(Mbbl)** | **Gross<br>(Mbbl)** | **Net<br>(Mbbl)** | **Gross<br>(Mbbl)** | **Net<br>(Mbbl)** |
| PROVED: |  |  |  |  |  |  |
| &nbsp;&nbsp;Developed Producing | 4256 | 3593 | 8466 | 8029 | 38513 | 33045 |
| &nbsp;&nbsp;Developed Non-Producing |  |  |  |  | 993 | 868 |
| &nbsp;&nbsp;Undeveloped | 18464 | 15798 | 11252 | 10735 | 19254 | 17184 |
| TOTAL PROVED | 22719 | 19391 | 19718 | 18764 | 58760 | 51097 |
| PROBABLE | 10062 | 8065 | 12817 | 11876 | 41149 | 34599 |
| TOTAL PROVED PLUS PROBABLE | 32781 | 27455 | 32535 | 30640 | 99909 | 85696 |
|  | **BITUMEN** | **BITUMEN** | **SHALE GAS** | **SHALE GAS** | **CONVENTIONAL NATURAL GAS** <sup>(1)</sup> | **CONVENTIONAL NATURAL GAS** <sup>(1)</sup> |
| **<u>RESERVES CATEGORY</u>** | **Gross<br>(Mbbl)** | **Net<br>(Mbbl)** | **Gross<br>(MMcf)** | **Net<br>(MMcf)** | **Gross<br>(MMcf)** | **Net (MMcf)** |
| PROVED: |  |  |  |  |  |  |
| &nbsp;&nbsp;Developed Producing |  |  | 18277 | 16663 | 46117 | 41598 |
| &nbsp;&nbsp;Developed Non-Producing |  |  |  |  | 236 | 219 |
| &nbsp;&nbsp;Undeveloped |  |  | 55041 | 49697 | 28428 | 24806 |
| TOTAL PROVED |  |  | 73318 | 66360 | 74780 | 66623 |
| PROBABLE | 44459 | 35743 | 32051 | 28442 | 39115 | 34047 |
| TOTAL PROVED PLUS PROBABLE | 44459 | 35743 | 105369 | 94801 | 113896 | 100670 |
|  | **NATURAL GAS LIQUIDS** <sup>(2)</sup> | **NATURAL GAS LIQUIDS** <sup>(2)</sup> | **TOTAL RESERVES** | **TOTAL RESERVES** |  |  |
| **<u>RESERVES CATEGORY</u>** | **Gross<br>(Mbbl)** | **Net<br>(Mbbl)** | **Gross<br>(Mboe)** | **Net<br>(Mboe)** |  |  |
| PROVED: |  |  |  |  |  |  |
| &nbsp;&nbsp;Developed Producing | 7003 | 6115 | 68970 | 60492 |  |  |
| &nbsp;&nbsp;Developed Non-Producing | 1 | 1 | 1033 | 905 |  |  |
| &nbsp;&nbsp;Undeveloped | 17815 | 15577 | 80696 | 71712 |  |  |
| TOTAL PROVED | 24819 | 21694 | 150699 | 133109 |  |  |
| PROBABLE | 10837 | 9129 | 131185 | 109826 |  |  |
| TOTAL PROVED PLUS PROBABLE | 35657 | 30823 | 281884 | 242936 |  |  |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Conventional natural gas includes associated, non-associated and solution gas.

&nbsp;&nbsp;&nbsp;&nbsp;(2)Natural gas liquids includes condensate.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 21 |

---

------

**SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE**

**AS OF DECEMBER 31, 2025**

**FORECAST PRICES AND COSTS**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **<br>BEFORE INCOME TAXES DISCOUNTED AT (%/year)** | **<br>BEFORE INCOME TAXES DISCOUNTED AT (%/year)** | **<br>BEFORE INCOME TAXES DISCOUNTED AT (%/year)** | **<br>BEFORE INCOME TAXES DISCOUNTED AT (%/year)** | **<br>BEFORE INCOME TAXES DISCOUNTED AT (%/year)** | **UNIT VALUE BEFORE TAX** |
| **<u>RESERVES CATEGORY</u>** | **0%<br>($000s)** | **5%<br>($000s)** | **10%<br>($000s)** | **15%<br>($000s)** | **20%<br>($000s)** | **10%<br>$/boe** |
| PROVED: |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Developed Producing | 141390 | 646691 | 728771 | 724671 | 699707 | 12.05 |
| &nbsp;&nbsp;&nbsp;Developed Non-Producing | 28154 | 21281 | 16625 | 13352 | 10976 | 18.36 |
| &nbsp;&nbsp;&nbsp;Undeveloped | 1203787 | 800682 | 537689 | 359276 | 233981 | 7.50 |
| TOTAL PROVED | 1373331 | 1468655 | 1283085 | 1097299 | 944664 | 9.64 |
| PROBABLE | 3418791 | 1951626 | 1258158 | 878533 | 647708 | 11.46 |
| TOTAL PROVED PLUS PROBABLE | 4792122 | 3420281 | 2541243 | 1975833 | 1592372 | 10.46 |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | <br>**AFTER INCOME TAXES DISCOUNTED AT (%/year)** <sup>(1)</sup> | <br>**AFTER INCOME TAXES DISCOUNTED AT (%/year)** <sup>(1)</sup> | <br>**AFTER INCOME TAXES DISCOUNTED AT (%/year)** <sup>(1)</sup> | <br>**AFTER INCOME TAXES DISCOUNTED AT (%/year)** <sup>(1)</sup> | <br>**AFTER INCOME TAXES DISCOUNTED AT (%/year)** <sup>(1)</sup> |
| **<u>RESERVES CATEGORY</u>** | **0%<br>($000s)** | **5%<br>($000s)** | **10%<br>($000s)** | **15%<br>($000s)** | **20%<br>($000s)** |
| PROVED: |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Developed Producing | 141390 | 646691 | 728771 | 724671 | 699707 |
| &nbsp;&nbsp;&nbsp;Developed Non-Producing | 28154 | 21281 | 16625 | 13352 | 10976 |
| &nbsp;&nbsp;&nbsp;Undeveloped | 1060507 | 678612 | 432752 | 268337 | 154598 |
| TOTAL PROVED | 1230051 | 1346584 | 1178148 | 1006361 | 865281 |
| PROBABLE | 2718026 | 1498352 | 934827 | 632670 | 452393 |
| TOTAL PROVED PLUS PROBABLE | 3948077 | 2844936 | 2112975 | 1639031 | 1317675 |

---

Note:

&nbsp;&nbsp;&nbsp;&nbsp;(1)The after-tax net present value of future net revenue from our oil and gas properties reflects the tax burden on the properties on a theoretical stand-alone basis. It does not consider our corporate structure or any tax planning and therefore does not provide an estimate of the cumulative after-tax value of our consolidated business entities, which may be significantly different.

**TOTAL FUTURE NET REVENUE (UNDISCOUNTED)**

**AS OF DECEMBER 31, 2025**

**FORECAST PRICES AND COSTS**

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| **($000s)** | **REVENUE** | **ROYALTIES** | **OPERAT-ING COSTS** | **DEVELOP-MENT COSTS** | **ABANDON-MENT AND RECLAMA-TION COSTS** <sup>(1)</sup> | **FUTURE NET REVENUE BEFORE INCOME TAXES** | **INCOME TAXES** | **FUTURE NET REVENUE <br>AFTER INCOME TAXES** |
| **TOTAL PROVED RESERVES** | 9105427 | 1115781 | 3616433 | 1914632 | 1085249 | 1373331 | 143280 | 1230051 |
| **TOTAL PROVED PLUS PROBABLE RESERVES** | 19107852 | 2823137 | 6915775 | 3431611 | 1145206 | 4792122 | 844045 | 3948077 |

---

Note:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Includes well abandonment, decommissioning and reclamation costs for all producing and non-producing wells and facilities and to be incurred as a result of future development activity.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 22 |

---

------

**FUTURE NET REVENUE BY PRODUCT TYPE**

**AS OF DECEMBER 31, 2025**

**FORECAST PRICES AND COSTS**

---

| | | | |
|:---|:---|:---|:---|
| **RESERVES CATEGORY** | **PRODUCT TYPE** | **FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at 10%/year) <br>($000s)** | <br>**UNIT VALUE** <sup>(1)</sup><br>**($/bbl; $/Mcf)** |
| Proved | &nbsp;&nbsp;&nbsp;&nbsp;Light and Medium Crude Oil (including solution gas and associated byproducts) | 243875 | 13.00 |
|  | &nbsp;&nbsp;&nbsp;&nbsp;Heavy Crude Oil (including solution gas and associated byproducts) | 584899 | 11.45 |
|  | &nbsp;&nbsp;&nbsp;&nbsp;Tight Oil (including solution gas and associated byproducts) | 437815 | 22.58 |
|  | &nbsp;&nbsp;&nbsp;&nbsp;Conventional Natural Gas (associated and non-associated) (including associated byproducts) | 16495 | 0.47 |
|  | &nbsp;&nbsp;&nbsp;**Total** | 1283085 |  |
| Proved plus<br>Probable | &nbsp;&nbsp;&nbsp;&nbsp;Light and Medium Crude Oil (including solution gas and associated byproducts) | 539297 | 17.60 |
| Proved plus<br>Probable | &nbsp;&nbsp;&nbsp;&nbsp;Heavy Crude Oil (including solution gas and associated byproducts) | 1126147 | 13.14 |
|  | &nbsp;&nbsp;&nbsp;&nbsp;Bitumen (including solution gas and associated byproducts) | 157145 | 4.40 |
|  | &nbsp;&nbsp;&nbsp;&nbsp;Tight Oil (including solution gas and associated byproducts) | 680418 | 24.78 |
|  | &nbsp;&nbsp;&nbsp;&nbsp;Conventional Natural Gas (associated and non-associated) (including associated byproducts) | 38236 | 0.78 |
|  | &nbsp;&nbsp;&nbsp;**Total** | 2541243 |  |

---

Note:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Unit values are calculated using the 10% discount rate divided by the Major Product Type net reserves for each group.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 23 |

---

------

**Pricing Assumptions**

The forecast cost and price assumptions include increases in actual wellhead selling prices and take into account inflation with respect to future operating and capital costs. The reference pricing used in the Baytex Reserves Report is as follows:

**SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS**

**AS AT DECEMBER 31, 2025** <sup>(1)</sup>**<br>FORECAST PRICES AND COSTS**

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| **Year** | **Oil** | **Oil** | **Oil** | **Natural Gas** | **Natural Gas** | **Inflation Rate** <sup>(5)</sup><br>**(%/Yr)** | **Exchange Rate** <sup>(6)</sup><br>**($US/$Cdn)** |
| **Year** | **WTI Crude Oil**<br>**($US/bbl)** | **Edmonton Light Crude Oil** <sup>(2)</sup><br>**($Cdn/bbl)** | **Western Canadian Select** <sup>(3)</sup> **($Cdn/bbl)** | **Henry Hub**<br>**($US/MMbtu)** | **AECO** **Spot** <sup>(4)</sup><br>**($Cdn/MMbtu)** | **Inflation Rate** <sup>(5)</sup><br>**(%/Yr)** | **Exchange Rate** <sup>(6)</sup><br>**($US/$Cdn)** |
| Historical | Historical |  |  |  |  |  |  |
| 2021 | 68.00 | 80.35 | 68.85 | 3.90 | 3.55 | 3.4 | 0.80 |
| 2022 | 94.80 | 120.75 | 99.10 | 6.40 | 5.55 | 6.8 | 0.77 |
| 2023 | 77.65 | 100.40 | 79.55 | 2.55 | 2.95 | 3.9 | 0.74 |
| 2024 | 76.55 | 97.50 | 83.60 | 2.20 | 1.45 | 2.4 | 0.73 |
| 2025 | 65.50 | 85.65 | 75.05 | 3.55 | 1.85 | 2.1 | 0.72 |
| Forecast <sup>(7)</sup> | Forecast <sup>(7)</sup> |  |  |  |  |  |  |
| 2026 | 59.92 | 77.54 | 65.13 | 3.74 | 3.00 |  | 0.73 |
| 2027 | 65.10 | 83.60 | 70.43 | 3.78 | 3.30 | 2.0 | 0.74 |
| 2028 | 70.28 | 90.17 | 76.90 | 3.85 | 3.49 | 2.0 | 0.74 |
| 2029 | 71.93 | 92.32 | 78.71 | 3.93 | 3.58 | 2.0 | 0.74 |
| 2030 | 73.37 | 94.17 | 80.29 | 4.01 | 3.65 | 2.0 | 0.74 |
| 2031 | 74.84 | 96.06 | 81.90 | 4.09 | 3.72 | 2.0 | 0.74 |
| 2032 | 76.34 | 97.98 | 83.53 | 4.17 | 3.80 | 2.0 | 0.74 |
| 2033 | 77.87 | 99.93 | 85.20 | 4.26 | 3.88 | 2.0 | 0.74 |
| 2034 | 79.42 | 101.93 | 86.91 | 4.34 | 3.95 | 2.0 | 0.74 |
| 2035 | 81.01 | 103.97 | 88.65 | 4.43 | 4.03 | 2.0 | 0.74 |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Each price from the forecast was adjusted for quality differentials and transportation costs applicable to the specified product and evaluation area.

&nbsp;&nbsp;&nbsp;&nbsp;(2)Price used in the preparation of light and medium crude oil and natural gas liquids reserves in Canada.

&nbsp;&nbsp;&nbsp;&nbsp;(3)Price used in the preparation of heavy crude oil and bitumen reserves in Canada.

&nbsp;&nbsp;&nbsp;&nbsp;(4)Price used in the preparation of natural gas reserves in Canada.

&nbsp;&nbsp;&nbsp;&nbsp;(5)Inflation rates for forecasting prices and costs.

&nbsp;&nbsp;&nbsp;&nbsp;(6)Exchange rate used to generate the benchmark reference prices in this table.

&nbsp;&nbsp;&nbsp;&nbsp;(7)After 2035, prices and costs escalate at 2.0% annually and the exchange rate remains 0.74.

Weighted average prices realized by us for the year ended December 31, 2025, excluding hedging activities, were $65.77/bbl for heavy crude oil, $84.30/bbl for light and medium crude oil, $84.82/bbl for tight oil, $24.82/bbl for NGL, $1.56/Mcf for shale gas and $1.69/Mcf for Conventional natural gas.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 24 |

---

------

**RECONCILIATION OF GROSS RESERVES BY PRINCIPAL PRODUCT TYPE**

**FORECAST PRICES AND COSTS**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ***CANADA*** | **HEAVY CRUDE OIL** | **HEAVY CRUDE OIL** | **HEAVY CRUDE OIL** | **BITUMEN** | **BITUMEN** | **BITUMEN** |
| | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** |
| **December 31, 2024** | 55357 | 34190 | 89547 |  | 44489 | 44489 |
| &nbsp;&nbsp;&nbsp;&nbsp;Extensions <sup>(1)</sup> | 14174 | 10144 | 24317 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Technical Revisions <sup>(2)</sup> | 6488 | (2996) | 3492 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisitions <sup>(3)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dispositions <sup>(4)</sup> | (147) | (256) | (403) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Economic Factors <sup>(5)</sup> | (1503) | 67 | (1436) |  | (30) | (30) |
| &nbsp;&nbsp;&nbsp;&nbsp;Production <sup>(6)</sup> | (15608) |  | (15608) |  |  |  |
| **December 31, 2025** | 58760 | 41149 | 99909 |  | 44459 | 44459 |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ***CANADA*** | **LIGHT AND MEDIUM CRUDE OIL** | **LIGHT AND MEDIUM CRUDE OIL** | **LIGHT AND MEDIUM CRUDE OIL** | **TIGHT OIL** | **TIGHT OIL** | **TIGHT OIL** |
| | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** |
| **December 31, 2024** | 23604 | 13644 | 37248 | 15935 | 11406 | 27341 |
| &nbsp;&nbsp;&nbsp;&nbsp;Extensions <sup>(1)</sup> | 982 | 89 | 1070 | 7853 | (1559) | 6293 |
| &nbsp;&nbsp;&nbsp;&nbsp;Technical Revisions <sup>(2)</sup> | (664) | (1042) | (1706) | 406 | 291 | 698 |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisitions <sup>(3)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dispositions <sup>(4)</sup> | (355) | (332) | (687) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Economic Factors <sup>(5)</sup> | (950) | 458 | (491) | (104) | (76) | (180) |
| &nbsp;&nbsp;&nbsp;&nbsp;Production <sup>(6)</sup> | (2900) |  | (2900) | (1371) |  | (1371) |
| **December 31, 2025** | 19718 | 12817 | 32535 | 22719 | 10062 | 32781 |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ***CANADA*** | **NATURAL GAS LIQUIDS** <sup>(7)</sup> | **NATURAL GAS LIQUIDS** <sup>(7)</sup> | **NATURAL GAS LIQUIDS** <sup>(7)</sup> | **SHALE GAS** | **SHALE GAS** | **SHALE GAS** |
| | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** | **Proved<br>(MMcf)** | **Probable<br>(MMcf)** | **Proved Plus Probable<br>(MMcf)** |
| **December 31, 2024** | 15797 | 11400 | 27197 | 48640 | 37041 | 85680 |
| &nbsp;&nbsp;&nbsp;&nbsp;Extensions <sup>(1)</sup> | 8994 | (944) | 8050 | 26434 | (4694) | 21740 |
| &nbsp;&nbsp;&nbsp;&nbsp;Technical Revisions <sup>(2)</sup> | 1562 | 493 | 2055 | 2590 | (22) | 2568 |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisitions <sup>(3)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dispositions <sup>(4)</sup> | (66) | (33) | (99) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Economic Factors <sup>(5)</sup> | (140) | (78) | (219) | (395) | (273) | (668) |
| &nbsp;&nbsp;&nbsp;&nbsp;Production <sup>(6)</sup> | (1328) |  | (1328) | (3951) |  | (3951) |
| **December 31, 2025** | 24819 | 10837 | 35657 | 73318 | 32051 | 105369 |

---

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 25 |

---

------

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ***CANADA*** | **CONVENTIONAL NATURAL GAS** <sup>(8)</sup> | **CONVENTIONAL NATURAL GAS** <sup>(8)</sup> | **CONVENTIONAL NATURAL GAS** <sup>(8)</sup> | **OIL EQUIVALENT** | **OIL EQUIVALENT** | **OIL EQUIVALENT** |
| | **Proved<br>(MMcf)** | **Probable<br>(MMcf)** | **Proved Plus Probable<br>(MMcf)** | **Proved (Mboe)** | **Probable<br>(Mboe)** | **Proved Plus Probable<br>(Mboe)** |
| **December 31, 2024** | 74789 | 38344 | 113133 | 131265 | 127692 | 258957 |
| &nbsp;&nbsp;&nbsp;&nbsp;Extensions <sup>(1)</sup> | 13463 | 6534 | 19997 | 38652 | 8035 | 46687 |
| &nbsp;&nbsp;&nbsp;&nbsp;Technical Revisions <sup>(2)</sup> | 1854 | (5191) | (3337) | 8533 | (4122) | 4411 |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisitions <sup>(3)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dispositions <sup>(4)</sup> | (1442) | (700) | (2142) | (809) | (737) | (1546) |
| &nbsp;&nbsp;&nbsp;&nbsp;Economic Factors <sup>(5)</sup> | (1830) | 129 | (1701) | (3068) | 317 | (2751) |
| &nbsp;&nbsp;&nbsp;&nbsp;Production <sup>(6)</sup> | (12054) |  | (12054) | (23874) |  | (23874) |
| **December 31, 2025** | 74780 | 39115 | 113896 | 150699 | 131185 | 281884 |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ***UNITED STATES*** | **TIGHT OIL** | **TIGHT OIL** | **TIGHT OIL** | **NATURAL GAS LIQUIDS** <sup>(7)</sup> | **NATURAL GAS LIQUIDS** <sup>(7)</sup> | **NATURAL GAS LIQUIDS** <sup>(7)</sup> |
| | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** |
| **December 31, 2024** | 152265 | 73392 | 225657 | 76126 | 31414 | 107539 |
| &nbsp;&nbsp;&nbsp;&nbsp;Extensions <sup>(1)</sup> | 1011 | (1011) |  | 396 | (396) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisitions <sup>(3)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dispositions <sup>(4)</sup> | (135842) | (72381) | (208223) | (70426) | (31018) | (101444) |
| &nbsp;&nbsp;&nbsp;&nbsp;Production <sup>(6)</sup> | (17434) |  | (17434) | (6095) |  | (6095) |
| **December 31, 2025** |  |  |  |  |  |  |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ***UNITED STATES*** | **SHALE GAS** | **SHALE GAS** | **SHALE GAS** | **OIL EQUIVALENT** | **OIL EQUIVALENT** | **OIL EQUIVALENT** |
| | **Proved<br>(MMcf)** | **Probable<br>(MMcf)** | **Proved Plus Probable<br>(MMcf)** | **Proved<br>(Mboe)** | **Probable<br>(Mboe)** | **Proved Plus Probable<br>(Mboe)** |
| **December 31, 2024** | 291135 | 115954 | 407089 | 276913 | 124132 | 401044 |
| &nbsp;&nbsp;&nbsp;&nbsp;Extensions <sup>(1)</sup> | 1944 | (1944) |  | 1731 | (1731) |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisitions <sup>(3)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dispositions <sup>(4)</sup> | (260036) | (114010) | (374047) | (249608) | (122401) | (372008) |
| &nbsp;&nbsp;&nbsp;&nbsp;Production <sup>(6)</sup> | (33043) |  | (33043) | (29036) |  | (29036) |
| **December 31, 2025** |  |  |  |  |  |  |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ***TOTAL*** | **HEAVY CRUDE OIL** | **HEAVY CRUDE OIL** | **HEAVY CRUDE OIL** | **BITUMEN** | **BITUMEN** | **BITUMEN** |
| | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** |
| **December 31, 2024** | 55357 | 34190 | 89547 |  | 44489 | 44489 |
| &nbsp;&nbsp;&nbsp;&nbsp;Extensions <sup>(1)</sup> | 14174 | 10144 | 24317 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Technical Revisions <sup>(2)</sup> | 6488 | (2996) | 3492 |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisitions <sup>(3)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dispositions <sup>(4)</sup> | (147) | (256) | (403) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Economic Factors <sup>(5)</sup> | (1503) | 67 | (1436) |  | (30) | (30) |
| &nbsp;&nbsp;&nbsp;&nbsp;Production <sup>(6)</sup> | (15608) |  | (15608) |  |  |  |
| **December 31, 2025** | 58760 | 41149 | 99909 |  | 44459 | 44459 |

---

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 26 |

---

------

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ***TOTAL*** | **LIGHT AND MEDIUM CRUDE OIL** | **LIGHT AND MEDIUM CRUDE OIL** | **LIGHT AND MEDIUM CRUDE OIL** | **TIGHT OIL** | **TIGHT OIL** | **TIGHT OIL** |
| | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** |
| **December 31, 2024** | 23604 | 13644 | 37248 | 168200 | 84798 | 252997 |
| &nbsp;&nbsp;&nbsp;&nbsp;Extensions <sup>(1)</sup> | 982 | 89 | 1070 | 8864 | (2571) | 6293 |
| &nbsp;&nbsp;&nbsp;&nbsp;Technical Revisions <sup>(2)</sup> | (664) | (1042) | (1706) | 406 | 291 | 698 |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisitions <sup>(3)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dispositions <sup>(4)</sup> | (355) | (332) | (687) | (135842) | (72381) | (208223) |
| &nbsp;&nbsp;&nbsp;&nbsp;Economic Factors <sup>(5)</sup> | (950) | 458 | (491) | (104) | (76) | (180) |
| &nbsp;&nbsp;&nbsp;&nbsp;Production <sup>(6)</sup> | (2900) |  | (2900) | (18805) |  | (18805) |
| **December 31, 2025** | 19718 | 12817 | 32535 | 22719 | 10062 | 32781 |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ***TOTAL*** | **NATURAL GAS LIQUIDS** <sup>(7)</sup> | **NATURAL GAS LIQUIDS** <sup>(7)</sup> | **NATURAL GAS LIQUIDS** <sup>(7)</sup> | **SHALE GAS** | **SHALE GAS** | **SHALE GAS** |
| | **Proved<br>(Mbbl)** | **Probable<br>(Mbbl)** | **Proved Plus Probable<br>(Mbbl)** | **Proved<br>(MMcf)** | **Probable<br>(MMcf)** | **Proved Plus Probable<br>(MMcf)** |
| **December 31, 2024** | 91923 | 42813 | 134736 | 339775 | 152995 | 492770 |
| &nbsp;&nbsp;&nbsp;&nbsp;Extensions <sup>(1)</sup> | 9390 | (1340) | 8050 | 28378 | (6638) | 21740 |
| &nbsp;&nbsp;&nbsp;&nbsp;Technical Revisions <sup>(2)</sup> | 1562 | 493 | 2055 | 2590 | (22) | 2568 |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisitions <sup>(3)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dispositions <sup>(4)</sup> | (70493) | (31051) | (101544) | (260036) | (114010) | (374047) |
| &nbsp;&nbsp;&nbsp;&nbsp;Economic Factors <sup>(5)</sup> | (140) | (78) | (219) | (395) | (273) | (668) |
| &nbsp;&nbsp;&nbsp;&nbsp;Production <sup>(6)</sup> | (7423) |  | (7423) | (36994) |  | (36994) |
| **December 31, 2025** | 24819 | 10837 | 35657 | 73318 | 32051 | 105369 |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| ***TOTAL*** | **CONVENTIONAL NATURAL GAS** <sup>(8)</sup> | **CONVENTIONAL NATURAL GAS** <sup>(8)</sup> | **CONVENTIONAL NATURAL GAS** <sup>(8)</sup> | **OIL EQUIVALENT** | **OIL EQUIVALENT** | **OIL EQUIVALENT** |
| | **Proved<br>(MMcf)** | **Probable<br>(MMcf)** | **Proved Plus Probable<br>(MMcf)** | **Proved<br>(Mboe)** | **Probable<br>(Mboe)** | **Proved Plus Probable<br>(Mboe)** |
| **December 31, 2024** | 74789 | 38344 | 113133 | 408177 | 251824 | 660001 |
| &nbsp;&nbsp;&nbsp;&nbsp;Extensions <sup>(1)</sup> | 13463 | 6534 | 19997 | 40383 | 6304 | 46687 |
| &nbsp;&nbsp;&nbsp;&nbsp;Technical Revisions <sup>(2)</sup> | 1854 | (5191) | (3337) | 8533 | (4122) | 4411 |
| &nbsp;&nbsp;&nbsp;&nbsp;Acquisitions <sup>(3)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Dispositions <sup>(4)</sup> | (1442) | (700) | (2142) | (250417) | (123137) | (373554) |
| &nbsp;&nbsp;&nbsp;&nbsp;Economic Factors <sup>(5)</sup> | (1830) | 129 | (1701) | (3068) | 317 | (2751) |
| &nbsp;&nbsp;&nbsp;&nbsp;Production <sup>(6)</sup> | (12054) |  | (12054) | (52910) |  | (52910) |
| **December 31, 2025** | 74780 | 39115 | 113896 | 150699 | 131185 | 281884 |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Additions resulting from capital expenditures for step-out drilling in previously discovered reservoirs. The majority of extensions were in the Duvernay, Lloydminster, and Peace River business units.

&nbsp;&nbsp;&nbsp;&nbsp;(2)Positive or negative revisions to an estimate resulting from new technical data or revised interpretations on previously assigned reserves. Revisions are usually associated with reservoir performance, operating costs, or development plan changes. Positive proved plus probable revisions in the Duvernay and Peace River business unit were offset by negative revisions in the Viking business unit.

&nbsp;&nbsp;&nbsp;&nbsp;(3)Additions from the purchase of interests at the effective date of this report, plus any production from the closing date of the acquisition to December 31, 2025.

&nbsp;&nbsp;&nbsp;&nbsp;(4)Reduction from the sale of interests. Disposition volume is estimated at December 31, 2024 minus any production from December 31, 2024 to the closing date of the disposition. The Corporation disposed of non-core Canadian assets and all of its U.S. assets during 2025.

&nbsp;&nbsp;&nbsp;&nbsp;(5)Revisions to an estimate resulting from changes to the price forecast, inflation rates, or regulatory changes. Negative revisions were realized due to economic factors.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 27 |

---

------

&nbsp;&nbsp;&nbsp;&nbsp;(6)Reduction due to production between December 31, 2024 and December 31, 2025. Production averaged 145,079 boe/d in 2025.

&nbsp;&nbsp;&nbsp;&nbsp;(7)Natural gas liquids includes condensate.

&nbsp;&nbsp;&nbsp;&nbsp;(8)Conventional natural gas includes associated, non-associated and solution gas.

**Additional Information Relating to Reserves Data**

***Undeveloped Reserves***

Undeveloped reserves are attributed in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

We allocate development capital to our assets annually. We reduce risk by technically assessing the prior year's results from our development programs before committing additional capital. Furthermore, planned activity levels vary each year due to factors such as prevailing commodity prices, capital availability, operational spacing considerations, timing of infrastructure construction and regulatory processes. This approach means that in most cases it will take longer than three years to develop our proved undeveloped reserves and longer than five years to develop our proved plus probable undeveloped reserves. With the exception of our Gemini SAGD project, we plan to develop the majority of our proved undeveloped reserves over the next five years and our probable undeveloped reserves over the next seven years. Excluding our Gemini SAGD project, approximately 51 percent of our proved reserves and 45 percent of our proved plus probable reserves are developed within two years. The remainder of our reserves are scheduled to be developed beyond two years due to the extent of the drilling inventory and annual capital availability.

At our Gemini SAGD project, steam generation represents a large proportion of the capital and operating costs. Therefore, our development plans anticipate that, in order to make the most efficient use of our steam generating and oil treating facilities, the drilling and steaming of wells (once commenced) would take place over approximately 25 years. We have booked 44.5 MMbbls of probable undeveloped reserves to the Gemini SAGD project.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 28 |

---

------

<u>Proved Undeveloped Reserves</u>

The following table discloses, for each product type, the volumes of proved undeveloped reserves that were attributed during, and the volume booked at year-end for, the three most recently completed financial years.

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Light and Medium Crude Oil<br>Gross (Mbbl)** | **Light and Medium Crude Oil<br>Gross (Mbbl)** | **Tight Oil <br>Gross (Mbbl)** | **Tight Oil <br>Gross (Mbbl)** | **Heavy Crude Oil<br> Gross (Mbbl)** | **Heavy Crude Oil<br> Gross (Mbbl)** | **Bitumen<br>Gross (Mbbl)** | **Bitumen<br>Gross (Mbbl)** |
|<br>**Year** | **First Attributed** | **Booked at Year End** | **First Attributed** | **Booked at Year End** | **First Attributed** | **Booked at Year End** | **First Attributed** | **Booked at Year End** |
| 2023 | 407 | 15699 | 71679 | 88506 | 4328 | 18445 |  | 2105 |
| 2024 | 594 | 14122 | 15196 | 92759 | 4012 | 19082 |  |  |
| 2025 | 75 | 11252 | 6048 | 18464 | 6339 | 19254 |  |  |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Conventional Natural Gas<br> Gross (MMcf)** | **Conventional Natural Gas<br> Gross (MMcf)** | **Shale Gas<br> Gross (MMcf)** | **Shale Gas<br> Gross (MMcf)** | **Natural Gas Liquids<br> Gross (Mbbl)** | **Natural Gas Liquids<br> Gross (Mbbl)** |
|<br>**Year** | **First Attributed** | **Booked at Year End** | **First Attributed** | **Booked at Year End** | **First Attributed** | **Booked at Year End** |
| 2023 | 769 | 23948 | 93446 | 201607 | 18527 | 54631 |
| 2024 | 1819 | 24622 | 35230 | 188509 | 8243 | 53117 |
| 2025 | 8556 | 28428 | 19434 | 55041 | 6531 | 17815 |

---

<u>Probable Undeveloped Reserves</u>

The following table discloses, for each product type, the volumes of probable undeveloped reserves that were attributed during, and the volume booked at year-end for, the three most recently completed financial years.

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Light and Medium Crude Oil<br>Gross (Mbbl)** | **Light and Medium Crude Oil<br>Gross (Mbbl)** | **Tight Oil <br>Gross (Mbbl)** | **Tight Oil <br>Gross (Mbbl)** | **Heavy Crude Oil<br> Gross (Mbbl)** | **Heavy Crude Oil<br> Gross (Mbbl)** | **Bitumen<br>Gross (Mbbl)** | **Bitumen<br>Gross (Mbbl)** |
|<br>**Year** | **First Attributed** | **Booked at Year End** | **First Attributed** | **Booked at Year End** | **First Attributed** | **Booked at Year End** | **First Attributed** | **Booked at Year End** |
| 2023 | 247 | 11560 | 55029 | 68578 | 4450 | 21271 |  | 45110 |
| 2024 | 328 | 10551 | 1417 | 66263 | 3735 | 20703 |  | 44489 |
| 2025 | 188 | 10012 |  | 8306 | 10771 | 27004 |  | 44459 |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Conventional Natural Gas<br> Gross (MMcf)** | **Conventional Natural Gas<br> Gross (MMcf)** | **Shale Gas<br> Gross (MMcf)** | **Shale Gas<br> Gross (MMcf)** | **Natural Gas Liquids<br> Gross (Mbbl)** | **Natural Gas Liquids<br> Gross (Mbbl)** |
|<br>**Year** | **First Attributed** | **Booked at Year End** | **First Attributed** | **Booked at Year End** | **First Attributed** | **Booked at Year End** |
| 2023 | 828 | 19672 | 55986 | 118276 | 12638 | 33386 |
| 2024 | 1800 | 20598 | 7295 | 115555 | 1612 | 33333 |
| 2025 | 5211 | 21935 |  | 25188 |  | 8184 |

---

**Significant Factors or Uncertainties**

The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 29 |

---

------

The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. As circumstances change and additional data becomes available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, commodity prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices and reservoir performance. Such revisions can be either positive or negative.

In the event that prices for oil and gas are not consistent with those used to prepare the Baytex Reserves Report, the volume of our reserves, their net present value and our expected revenues will differ, perhaps materially so, from those stated in the Baytex Reserves Report.

In connection with our operations, we will be liable for our share of ongoing environmental obligations and for the ultimate reclamation of our surface leases, wells and facilities. The total liability associated with these existing surface leases, wells and facilities, inflated at 2% per year, is estimated to be $1,025 million undiscounted ($220 million discounted at 10 percent). This is comprised of $365 million undiscounted ($25 million discounted at 10 percent) associated with active properties, $282 million undiscounted ($154 million discounted at 10 percent) associated with inactive properties, and $378 million undiscounted ($41 million discounted at 10 percent) associated with facilities.

**Future Development Costs**

The following table sets forth development costs deducted in the estimation of the future net revenue attributable to the reserve categories noted below (using forecast prices and costs).

**FUTURE DEVELOPMENT COSTS**

**AS OF DECEMBER 31, 2025** 

**FORECAST PRICES AND COSTS**

**($000s)**

---

| | | |
|:---|:---|:---|
| | **Proved Reserves** | **Proved plus Probable Reserves** |
| 2026 | 358545 | 442334 |
| 2027 | 504930 | 617943 |
| 2028 | 510960 | 693845 |
| 2029 | 342894 | 656620 |
| 2030 | 146454 | 247956 |
| Remaining | 50849 | 772913 |
| Total (undiscounted) | 1914632 | 3431611 |

---

We expect to fund the development costs of our reserves through a combination of internally generated cash flow, debt and equity financing. Planned activity levels vary each year due to factors such as capital availability, prevailing commodity prices and regulatory processes.

There can be no guarantee that funds will be available or that our Board of Directors will allocate funding to develop all of the reserves attributed in the Baytex Reserves Report. Failure to develop those reserves could have a negative impact on our future cash flow.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 30 |

---

------

The interest or other costs of external funding are not included in the reserves and future net revenue estimates set forth herein and would reduce reserves and future net revenue to some degree depending upon the funding sources utilized and the costs thereof. We do not anticipate that interest or other funding costs would make development of any of these properties uneconomic.

**RISK FACTORS**

You should carefully consider the following risk factors, as well as the other information contained in this AIF and our other public filings before making an investment decision. If any of the risks described below materialize, our business, reputation, financial condition, results of operations and cash flow could be materially and adversely affected, which may materially affect the market price of our securities. The risks described below may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. Residents of the United States and other non-residents of Canada should have additional regard to the risk factors under the heading "*Certain Risks for United States and other non-resident Shareholders".*

The information set forth below contains forward-looking statements, which are qualified by the information contained in the section of this AIF entitled "*Special Notes to Reader - Forward-Looking Statements*".

**Risks Relating to Our Business and Operations**

***Crude oil and natural gas prices are volatile. An extended period of low oil and natural gas prices could have a material adverse effect on the Corporation's business, results of operations, or cash flows and financial condition***

Our financial condition is substantially dependent on, and highly sensitive to, the prevailing prices of crude oil and natural gas. Low prices for crude oil and natural gas produced by us could have a material adverse effect on our operations, financial condition and the value and amount of our reserves.

Prices for crude oil and natural gas fluctuate in response to changes in the supply of, and demand for, crude oil and natural gas, market uncertainty and a variety of additional factors beyond our control. Crude oil prices are primarily determined by international supply and demand. Factors which affect crude oil prices include the actions of OPEC, OPEC+, the condition of the Canadian, United States, European and Asian economies, the impacts of geopolitical events, including the Russian Ukrainian war, geopolitical developments in Venezuela and conflicts and hostilities in the Middle East, the imposition of tariffs or other adverse economic or political development in the United States, Europe, the Middle East, Africa, South America or Asia, the impact of pandemics/epidemics, government regulation, the supply of crude oil in North America and internationally, the ability to secure adequate transportation for products, the availability of alternate fuel sources and weather conditions. Additionally, the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. Natural gas prices realized by us are affected primarily in North America by supply and demand, weather conditions, industrial demand, prices of alternate sources of energy and developments related to the market for liquefied natural gas.

In particular, tariffs or other restrictive measures or countermeasures affecting trade between Canada and the United States and between the United States and other countries, if implemented for any period of time, could have a significant impact on the market for oil and natural gas products, especially with respect to oil and gas produced in Canada, and could result in, among other things, price volatility, an increase to the cost of materials used in oil and gas operations, a relative weakening of the Canadian dollar, widening differentials, and decreased demand due to lower economic activity. For more information with respect to tariffs, see "*Industry Conditions - Tariffs*".

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 31 |

---

------

All of these factors are beyond our control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further compound this volatility when commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars.

Our financial performance also depends on revenues from the sale of commodities which differ in quality and location from underlying commodity prices quoted on financial exchanges. Of particular importance are the price differentials between our light/medium crude oil and heavy crude oil (in particular the light/heavy differential) and quoted market prices. Not only are these discounts influenced by regional supply and demand factors, they are also influenced by other factors such as transportation costs, capacity and interruptions, refining demand, storage capacity, the availability and cost of diluents used to blend and transport product and the quality of the oil produced, all of which are beyond our control. In addition, there is not sufficient pipeline capacity for Canadian crude oil to access the American refinery complex or tidewater to access world markets and the availability of additional transport capacity via rail is more expensive and variable, therefore, the price for Canadian crude oil is very sensitive to pipeline and refinery outages, which contributes to this volatility.

Decreases to or prolonged periods of low commodity prices, particularly for oil, may negatively impact our ability to meet guidance targets, maintain our business and meet all of our financial obligations as they come due. It could also result in the shut-in of currently producing wells without an equivalent decrease in expenses due to fixed costs, a delay or cancellation of existing or future drilling, development or construction programs, un-utilized long-term transportation commitments and a reduction in the value and amount of our reserves.

We conduct assessments of the carrying value of our assets in accordance with Canadian GAAP. If crude oil and natural gas forecast prices change, the carrying value of our assets could be subject to revision and our net earnings could be adversely affected.

***Our success is highly dependent on our ability to develop existing properties and add to our oil and natural gas reserves***

Our oil and natural gas reserves are a depleting resource and decline as such reserves are produced. As a result, our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Future oil and natural gas exploration may involve unprofitable efforts, not only from unsuccessful wells, but also from wells that are productive but do not produce sufficient hydrocarbons to return a profit. Completion of a well does not assure a profit on the investment. Drilling hazards or environmental liabilities or damages and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells. Field operating conditions include, but are not limited to, delays or failure in obtaining governmental, landowner or other stakeholder approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow from operating activities to varying degrees.

There is no assurance we will be successful in developing our reserves or acquiring additional reserves at acceptable costs. Without these reserves additions, our reserves will deplete and as a consequence production from and the average reserve life of our properties will decline, which may adversely affect our business, financial condition, results of operations and prospects.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 32 |

---

------

***The amount of oil and natural gas that we can produce and sell is subject to the availability and cost of gathering, processing and pipeline systems***

We deliver our products through gathering, processing and pipeline systems to which we do not own and purchasers of our products rely on third party infrastructure to deliver our products to market. The lack of access to capacity in any of the gathering, processing and pipeline systems could result in our inability to realize the full economic potential of our production or in a reduction of the price offered for our production. Alternately, a substantial decrease in the use of such systems can increase the cost we incur to use them. In addition, many of the pipeline systems that we use are controlled by a single company and rates are set through a regulatory process, as a result we are subject to the outcome of those regulatory processes. Any significant change in market factors, regulatory decisions or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could harm our business and, in turn, our financial condition.

Access to the pipeline capacity for the export of crude oil from Canada has, at times, been inadequate for the amount of Canadian production being exported. This has resulted in significantly lower prices being realized by Canadian producers compared with the WTI price and the Brent price for crude oil. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability to export oil and natural gas from Canada. There can be no certainty that current investment in pipelines will provide sufficient long-term take-away capacity or that currently operating systems will remain in service. There is also no certainty that short-term operational constraints on pipeline systems, arising from pipeline interruption and/or increased supply of crude oil, will not occur.

There is no certainty that crude-by-rail transportation and other alternative types of transportation for our production will be sufficient to address any gaps caused by operational constraints on pipeline systems. In addition, our crude-by-rail shipments may be impacted by service delays, inclement weather, derailment or blockades and could adversely impact our crude oil sales volumes or the price received for our product. Crude oil produced and sold by us may be involved in a derailment or incident that results in legal liability or reputational harm.

A portion of our production may be processed through facilities controlled by third parties. From time to time these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuance or decrease of operations could materially adversely affect our ability to process our production and to deliver the same for sale.

***Water use restrictions and/or limited access to water or other fluids may impact the Corporation's ability to fracture its wells or carry out waterflood operations***

The Corporation undertakes or intends to undertake certain hydraulic fracturing, SAGD, CSS and waterflooding programs. To undertake such operations the Corporation needs to have access to sufficient volumes of water, or other liquids. There is no certainty that the Corporation will have access to the required volumes of water. In addition, in certain areas there may be restrictions on water use for activities such as hydraulic fracturing, SAGD, CSS and waterflooding. If the Corporation is unable to access such water it may not be able to undertake hydraulic fracturing, SAGD, CSS or waterflooding activities, which may reduce the amount of oil and natural gas that the Corporation is ultimately able to produce from its reserves.

***The anticipated benefits of acquisitions may not be achieved and the Corporation may dispose of assets for less than their carrying value on the financial statements***

Acquisition of oil and gas properties is a key element of maintaining and growing reserves and production and the success of any acquisition will depend on several factors and involves potential risks and uncertainties. Competition for these assets has been and will continue to be intense. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive candidates, we may not be

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 33 |

---

------

able to complete the acquisition or do so on commercially acceptable terms. Achieving the benefits of acquisitions depends on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner and the Corporation's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Corporation. The integration of acquired businesses and assets may require substantial management effort, time and resources diverting management's focus from other strategic opportunities and operational matters. Additionally, significant acquisitions can change the nature of our operations and business if acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.

Even though we assess and review the properties we seek to acquire in a manner consistent with what we believe to be industry practice, such reviews are limited in scope, inexact and not capable of identifying all existing or potentially adverse conditions. As a result, the anticipated and desired benefits of an acquisition may not materialize, and may have a material and adverse effect on our business, financial performance and results of operations.

Management continually assesses the value and contribution of its Corporation's assets. In this regard, certain assets may be periodically disposed of so that the Corporation can focus its efforts and resources more efficiently. Depending on the state of the market for such assets, certain assets of the Corporation, if disposed of, may realize less on disposition than their carrying value on the financial statements of the Corporation.

***Variations in foreign exchange rates could adversely affect our financial condition***

World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canada/U.S. foreign exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact our production revenues. Future Canadian/U.S. exchange rates could accordingly impact the future value of Baytex's reserves as determined by independent reserves evaluators. Although a low value of the Canadian dollar relative to the U.S. dollar may positively impact the price the Corporation receives for crude oil and natural gas production it could also result in an increase in the price of certain goods used in operations which may have a negative impact on the Corporation's financial results.

***Availability and cost of capital or borrowing to maintain and/or fund future development and acquisitions***

The business of exploring for, developing or acquiring reserves is capital intensive. If external sources of capital (including, but not limited to, debt and equity financing) become limited or unavailable on commercially reasonable terms, our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves may be impaired. Unpredictable financial markets and the associated credit impacts may impede our ability to secure and maintain cost effective financing and limit our ability to achieve timely access to capital on acceptable terms and conditions. If external sources of capital become limited or unavailable, our ability to make capital investments, continue our business plan, meet all of our financial obligations as they come due and maintain existing properties may be impaired.

Our ability to obtain additional capital is dependent on, among other things, a general interest in energy industry investments and, in particular, interest in our securities. If we are unable to maintain our indebtedness and financial ratios at levels acceptable to investors, or should our business prospects deteriorate, our ability to access additional capital could decrease. Additionally, from time to time, our securities may not meet the investment criteria or characteristics of a particular institutional or other investor, including institutional investors who are not willing or able to hold securities of oil and gas companies for reasons unrelated to financial or operational performance. This may include changes to

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 34 |

---

------

market-based factors or investor strategies, including ESG, or responsible investing criteria/rankings (for example, ESG, social impact or environmental scores), the implementation of new financial market regulations and fossil fuel divestment initiatives undertaken by governments, pension funds and/or other institutional investors. These events would adversely affect the value of our outstanding securities and existing debt and our ability to obtain new financing, and may increase our borrowing costs.

From time to time, we may enter into transactions which may be financed in whole or in part with debt or equity. The level of our indebtedness, from time to time, could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise. Additionally, from time to time, we may issue securities from treasury in order to reduce debt, complete acquisitions and/or optimize our capital structure.

***There are numerous uncertainties inherent in estimating quantities of recoverable oil and natural gas reserves, including many factors beyond our control***

The reserves estimates included in this AIF are estimates only. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable oil and natural gas reserves and the future net revenues therefrom are based upon a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies, historical production from the properties, initial production rates, production decline rates, the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities and estimates of future commodity prices and capital costs, all of which may vary considerably from actual results.

All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our reserves as at December 31, 2025 are estimated using forecast prices and costs as set forth under *"Statement of Reserves Data - Pricing Assumptions"*. If we realize lower prices for crude oil, natural gas liquids and natural gas and they are substituted for the estimated price assumptions, the present value of estimated future net revenues for our reserves and net asset value would be reduced and the reduction could be significant. Our actual production, revenues, royalties, taxes and development, abandonment and operating expenditures with respect to our reserves will likely vary from such estimates, and such variances could be material.

Estimates of reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Reserve reports based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations in the previously estimated reserves and such variances could be material.

***Restrictions and/or costs associated with regulatory initiatives to combat climate change and the physical risks of climate change may have a material adverse affect on our business***

*Regulatory and Policy Initiatives*

Our exploration and production facilities and other operational activities emit GHGs. As such, GHG emissions regulation (including carbon taxes) enacted in jurisdictions where we operate will impact us. In addition, certain of our assets have a higher GHG emissions intensity than others and may be disproportionately impacted.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 35 |

---

------

Negative consequences which could result from new GHG emissions regulation include, but are not limited to: increased operating costs, additional taxes, increased construction and development costs, additional monitoring and compliance costs, a requirement to redesign or retrofit current facilities, permitting delays, additional costs associated with the purchase of emission credits or allowances, the availability to use necessary third-party services and facilities that we rely on, and reduced demand for crude oil. Additionally, if GHG emissions regulation differs by region or type of production, all or part of our production could be subject to costs which are disproportionately higher than those of other producers.

The direct or indirect costs of compliance with GHG emissions regulation may have a material adverse affect on our business, financial condition, results of operations and prospects. At this time, it is not possible to predict whether compliance costs will have a material adverse affect on our financial condition, results of operations or prospects.

Although we provide for the necessary amounts in our annual capital budget to fund our currently estimated obligations, there can be no assurance that we will be able to satisfy our actual future obligations associated with GHG emissions from such funds. For more information on the evolution and status of climate change and related environmental legislation, see "*Industry Conditions - Climate Change Regulation and Litigation*".

*Physical Risk*

Climate change has been linked to extreme weather conditions. Extreme hot and cold weather, heavy snowfall, heavy rain fall, hurricanes, drought and wildfires may restrict our ability to access our properties, cause operational difficulties including damage to machinery and facilities. Extreme weather also increases the risk of personnel injury as a result of dangerous working conditions. Certain assets are located where they are exposed to forest fires, floods, heavy rains, hurricanes, drought and other extreme weather conditions which can lead to significant downtime, damage to such assets and/or increased costs of construction and maintenance. Moreover, extreme weather conditions may lead to disruptions in our ability to transport produced oil and natural gas as well as goods and services in our supply chain.

***An energy transition that lessens demand for petroleum products may have an adverse affect on our business***

A transition away from the use of petroleum products, which may include conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and renewable energy, could reduce demand for oil and natural gas. Certain jurisdictions have implemented policies or incentives to decrease the use of fossil fuels and encourage the use of renewable fuel alternatives, which may lessen demand for petroleum products and put downward pressure on commodity prices. In addition, advancements in energy efficient products have a similar effect on the demand for oil and gas products. The Corporation cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Corporation's business and financial condition by decreasing its cash flow from operating activities and the value of its assets.

***Failure to retain or replace our leadership and key personnel may have an adverse affect on our business***

Our success is dependent upon our management, our leadership capabilities and the quality and competency of our talent. Contributions of the existing management team to the immediate and near-term operations of the Corporation are likely to be of central importance. In addition, certain of the Corporation's current employees may have significant institutional knowledge that must be transferred to other employees prior to their departure from the workforce. If we are unable to retain key personnel and critical talent or to attract and retain new talent with the necessary leadership, professional and technical

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 36 |

---

------

competencies, it could have a material adverse effect on our financial condition, results of operations and prospects.

***Income tax laws or other laws or government incentive programs or regulations relating to our industry may in the future be changed or interpreted in a manner that adversely affects us and our Shareholders***

Income tax laws and government incentive programs relating to the oil and gas industry may change in a manner that adversely affects our financial condition, results of operations and prospects.

In addition, tax authorities having jurisdiction over us or our Shareholders may disagree with the manner in which we calculate our income for tax purposes or could change their administrative practices to our detriment or the detriment of our Shareholders. We file all required income tax returns and believe that we are in full compliance with the applicable tax legislation. However, such returns are subject to audit and reassessment by the applicable taxation authority. At present, the Canadian tax authorities have reassessed the returns of certain of our subsidiaries. For further details, see *"Legal Proceedings and Regulatory Actions"*. Any such reassessment may have an impact on current and future taxes payable. We believe appropriate provisions for current and deferred income taxes have been made in our Financial Statements; however, it is difficult to predict the outcome of audit findings by tax authorities or their final adjudication by the courts. These findings may increase the amount of our tax liabilities and adversely affect our business, financial condition and results of operations.

***We may participate in larger projects and may have more concentrated risk in certain areas of our operations***

We have a variety of exploration, development and construction projects underway at any given time. Project delays may result in delayed revenue receipts and cost overruns may result in projects being uneconomic. Our ability to complete projects is dependent on general business, community relationships and market conditions as well as other factors beyond our control, including the availability of skilled labour and manpower, the availability and proximity of pipeline capacity and rail terminals, weather, environmental and regulatory matters, ability to access lands, availability of drilling and other equipment and supplies, and availability of processing capacity.

***We could experience adverse impacts associated with a high concentration of activity and tighter drilling spacing***

We are subject to drilling, completion and operating risks, including our ability to efficiently execute large-scale project development, as we could experience delays, curtailments and other adverse impacts associated with a high concentration of activity and tighter drilling spacing. A higher concentration of activity and tighter drilling spacing may increase the frequency of operational shut-ins and unintentional communication with other adjacent wells and reduce the total recoverable reserves from the reservoir.

***Our financial performance is significantly affected by the cost of developing and operating our assets***

Our development and operating costs are affected by a number of factors including, but not limited to: price inflation, increased costs due to tariffs, access to skilled and unskilled labour, availability of equipment, scheduling delays, trucking and fuel costs, failure to maintain quality construction standards, the cost of new technologies and supply chain disruptions. Labour costs, natural gas, electricity, water, diluent and chemicals are examples of some of the operating and other costs that are susceptible to significant fluctuation. Increases to development and operating costs could have a material adverse effect on our financial condition, results of operations or prospects.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 37 |

---

------

***Our information technology systems are subject to certain risks***

We utilize and have become increasingly dependent upon a number of information technology systems for the administration and management of our business and are subject to a variety of information technology and system risks as a part of our normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Corporation's information technology systems by third parties or insiders. If our ability to access and use these systems is interrupted and cannot be quickly and easily restored then such event could have a material adverse effect on us. Furthermore, although the Corporation has security measures and controls in line with industry-accepted standards in place to mitigate these risks, a breach of its security measures disruption of critical information technology services, and/or a loss of information could occur and result in a loss of material and confidential information and reputation, breach of privacy laws, and/or disruption to business activities. The significance of any such event is difficult to quantify but may in certain circumstances be material and could have a material adverse effect on the Corporation's business, financial condition, results of operations or our reputation, and any damages may not be adequately covered by the Corporation's current insurance coverage. In addition, our vendors, suppliers and other businesses partners may separately suffer disruptions as a result of such security breaks which may directly or indirectly affect our business activities.

The Corporation's IT systems may incorporate artificial intelligence ("AI"), and development of these capabilities is ongoing. AI introduces risks and unintended consequences that could affect adoption and business operations. Algorithms and training methods may be flawed, and reliance on AI without adequate safeguards can lead to inaccurate outcomes or operational vulnerabilities.

AI also poses data privacy, cyber-security, and intellectual property risks. Improper use may result in unauthorized disclosure of sensitive information or outputs that infringe copyrights, patents, or privacy rights. As legal and regulatory frameworks for AI remain uncertain, future compliance obligations could impose significant costs or limit the Corporation's ability to integrate AI tools.

***Adverse results from litigation may have an adverse affect on our business and reputation***

In the normal course of our operations, we currently are and from time to time in the future may become involved in, be named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions. In addition, we retained liability for certain legal proceedings related to our prior ownership of assets located in the U.S. Potential litigation may develop in relation to personal injuries, including resulting from exposure to hazardous substances, property damage, property taxes, land and access rights, and environmental issues, including claims relating to contamination or natural resource damages and contract disputes.

The Corporation establishes legal provisions for known and potential claims for which payment is probable and can be reliably estimated. The Corporation also has comprehensive liability insurance coverage; however such insurance does not cover all risks to which we might be exposed and in other cases, may only partially cover losses incurred by the Corporation. The outcome with respect to outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to us and could have a material adverse effect on our assets, liabilities, business, financial condition and results of operations. Furthermore, even if we prevail in any such legal proceedings, the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from business operations, which could have an adverse effect on our financial condition. For further details, see "*Legal Proceedings and Regulatory Actions*".

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 38 |

---

------

***Current or future controls, legislation or regulations applicable to the oil and gas industry could adversely affect us***

*Operations*

The oil and gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, completion operations, including the use of hydraulic fracturing, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government. All such controls, regulations and legislation are subject to revocation, amendment or administrative change, some of which have historically been material and in some cases materially adverse. The exercise of discretion by governmental authorities under existing controls, legislation or regulations, the implementation of new controls, legislation or regulations or the modification of existing controls, legislation or regulations affecting the oil and gas industry could reduce demand for crude oil and natural gas, increase our costs, or delay or restrict our operations, all of which would have a material adverse effect on our financial condition, results of operations or prospects. See "*Industry Conditions*".

*Environment*

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state, provincial and local laws and regulations. Environmental legislation provides for, among other things, the initiation and approval of new oil and natural gas projects, and restrictions and prohibitions on the spill, release or emission of various substances produced in association with oil and natural gas industry operations. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. New environmental legislation at the federal, state, and provincial levels may increase uncertainty among oil and natural gas industry participants as the new laws are implemented, and the effects of the new rules and standards are felt in the oil and natural gas industry. See "*Industry Conditions*".

Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liabilities and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Corporation to incur costs to remedy such discharge. Although the Corporation believes that it is in material compliance with current applicable environmental legislation, no assurance can be given that environmental compliance requirements will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

*The Corporation may have to pay certain costs associated with abandonment and reclamation*

The Corporation will need to comply with the terms and conditions of environmental and regulatory approvals and all legislation regarding the abandonment of its projects and reclamation of the project lands at the end of their economic life, which may result in substantial abandonment and reclamation costs. Any failure to comply with the terms and conditions of the Corporation's approvals and legislation may result in the imposition of fines and penalties, which may be material. Generally, abandonment and reclamation costs are substantial. The Corporation records a provision for abandonment and reclamation costs in its financial statements, this provision requires significant judgment and reflects the Corporation's best estimate of the costs to complete the required abandonment and reclamation work. Actual results may be significantly different than the estimated amounts.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 39 |

---

------

*Foreign Investment and Competition Act Legislation*

In addition to regulatory requirements mentioned above, our business and financial condition could be influenced by federal legislation affecting, in particular, foreign investment, through legislation such as the *Competition Act* (Canada) and the *Investment Canada Act* (Canada).

***New regulations on hydraulic fracturing may lead to operational delays, increased costs and/or decreased production volumes***

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate the production of oil and natural gas. Specifically, hydraulic fracturing enables the production of commercial quantities of oil and natural gas from reservoirs that were previously unproductive. Hydraulic fracturing has featured prominently in recent political, media and activist commentary on the subject of water usage, induced seismicity events and environmental damage. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third party or governmental claims, and could increase the Corporation's costs of compliance and doing business as well as delay the development of oil and natural gas resources from shale formations, which are not commercial without the use of hydraulic fracturing, or could effectively prevent the development of crude oil and natural gas. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

***Regulations regarding the disposal of fluids used in the Corporation's operations may increase its costs of compliance or subject it to regulatory penalties or litigation***

The safe disposal of hydraulic fracturing fluids (including the additives) and water recovered from oil and natural gas wells is subject to ongoing regulatory review by the federal, provincial and state governments, including its effect on fresh water supplies and the ability of such water to be recycled, amongst other things. While it is difficult to predict the impact of any regulations that may be enacted in response to such review, the implementation of stricter regulations may increase the Corporation's costs of compliance.

***Acquiring, developing and exploring for oil and natural gas involves many physical hazards. We have not insured and cannot fully insure against all risks related to our operations***

Our crude oil and natural gas operations are subject to all of the risks normally incidental to the: (i) storing, transporting, processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling and completion of crude oil and natural gas wells; including horizontal multi-well pad developments; and (iii) operation and development of crude oil and natural gas properties, including, but not limited to: encountering unexpected formations or pressures, premature declines of reservoir pressure or productivity, blowouts, fires, explosions, equipment failures and other accidents, gaseous leaks, uncontrollable or unauthorized flows of crude oil, natural gas or well fluids, migration of harmful substances, oil spills, corrosion, adverse weather conditions, pollution, acts of vandalism, theft and terrorism and other adverse risks to the environment.

If any of the foregoing risks were to materialize, we could sustain material losses as a result of injury or loss of life, damage to, or destruction of, property, natural resources or equipment, including the costs of repair or replacement, pollution or other environmental harm, interruptions to our ongoing operations, including the reduction or shutting-in of existing production, regulatory investigations and administrative, civil and criminal penalties, and limitation or suspension of current or future operations.

Although we maintain insurance in accordance with customary industry practice, we are not fully insured against all of these risks nor are all such risks insurable and in certain circumstances we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. In addition, the nature of these risks is such that liabilities could exceed policy limits, in

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 40 |

---

------

which event we could incur significant costs that could have a material adverse effect on our business, financial condition, results of operations and prospects.

***Our thermal heavy oil projects face additional risks compared to conventional oil and gas production***

Our thermal heavy oil projects are capital intensive projects which rely on specialized production technologies. Certain current technologies for the recovery of heavy oil, such as CSS and SAGD, are energy intensive, requiring significant consumption of natural gas and other fuels in the production of steam that is used in the recovery process. The amount of steam required in the production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing and levels of production using new technologies. A large increase in recovery costs could cause certain projects that rely on CSS, SAGD or other new technologies to become uneconomic, which could have an adverse effect on our financial condition and our reserves. There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies cannot be assured.

Project economics and our earnings may be reduced if increases in operating costs are incurred. Factors which could affect operating costs include, without limitation: the costs imposed by GHG emissions regulations, labour costs, the cost of catalysts and chemicals, the cost of natural gas and electricity, water handling and availability, power outages, produced sand causing issues of erosion, hot spots and corrosion, reliability of facilities, maintenance costs, the cost to transport sales products and the cost to dispose of certain by-products.

***We may be unable to compete successfully with other organizations in the oil and natural gas industry, or obtain required vendor services to compete***

The oil and natural gas industry is highly competitive in all of its phases. The Corporation competes with numerous other entities in the exploration for, and the development, production and marketing of, oil and natural gas, as well as for capital, acquisitions of reserves and/or resources, undeveloped lands, skilled/qualified labour, access to drilling rigs, service rigs and other equipment and materials such as drilling rigs, hydraulic fracturing pumping equipment and related skilled personnel, access to processing facilities, pipeline and refining capacity, as well as many other services, and in many other respects, with a substantial number of other organizations, many of which may have greater technical and financial resources than the Corporation. As a result, such competition can significantly increase costs and some of the Corporation's competitors may have greater opportunities and be able to access, services or vendors that the Corporation is not able to access, thereby limiting its ability to compete.

***Our Credit Facilities may not provide sufficient liquidity and a failure to renew our Credit Facilities at maturity could adversely affect our financial condition***

Our Credit Facilities and any replacement credit facilities may not provide sufficient liquidity. The amounts available under our Credit Facilities may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms, if at all. There can be no assurance that the amount of our Credit Facilities will be adequate for our future financial obligations, including future capital expenditures, or that we will be able to obtain additional funds. In the event we are unable to refinance our debt obligations, it may impact our ability to fund ongoing operations. In the event that the Credit Facilities are not extended prior to maturity, indebtedness under the Credit Facilities will be repayable at that time. There is also a risk that the Credit Facilities will not be renewed for the same amount or on the same terms. See "*Description of Capital Structure*".

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 41 |

---

------

***Expansion into New Activities***

Our operations and the expertise of our management are currently focused primarily on oil and natural gas production, exploration and development in the Provinces of Alberta and Saskatchewan. In the future, we may acquire or move into new industry related activities or new geographical areas and may acquire different energy-related assets. As a result, we may face unexpected risks or, alternatively, our exposure to one or more existing risk factors may be significantly increased, which may in turn result in our future operational and financial conditions being adversely affected.

***Indigenous Land and Rights Claims***

Opposition by Indigenous groups to the conduct of the Corporation's operations, development or exploratory activities in any of the jurisdictions in which the Corporation conducts business may negatively impact it in terms of public perception, diversion of management's time and resources, and legal and other advisory expenses, and could adversely impact the Corporation's progress and ability to explore and develop properties.

Indigenous peoples have claimed Indigenous rights and title in portions of Western Canada. We are not aware that any claims have been made in respect of our properties and assets. However, if a claim arose and was successful, such claim may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, the process of addressing such claims, regardless of the outcome, is expensive and time consuming and could result in delays in the construction of infrastructure systems and facilities which could have a material adverse effect on our business and financial results.

***Public perception and its influence on the regulatory regime***

Concern over the impact of oil and gas development on the environment and climate change has received considerable attention in the media and recent public commentary, and the social value proposition of resource development is being challenged. Additionally, certain pipeline leaks, rail car derailments, major weather events and induced seismicity events have gained media, environmental and other stakeholder attention. Future laws and regulation may be impacted by such incidents, which could have a material adverse effect on our financial condition, results of operations or prospects.

***We are subject to risk of default by the counterparties to our contracts and our counterparties may deem us to be a default risk***

We are subject to the risk that counterparties to our risk management contracts, marketing arrangements and investments of cash and cash equivalents, operating agreements and other suppliers of products and services may default on their obligations under such agreements or arrangements, including as a result of liquidity requirements or insolvency. Furthermore, low oil and natural gas prices increase the risk of bad debts related to our joint venture and industry partners. A failure by such counterparties to make payments or perform their operational or other obligations to us may adversely affect our results of operations, cash flow from operating activities and financial position. Conversely, our counterparties may deem us to be at risk of defaulting on our contractual obligations. These counterparties may require that we provide additional credit assurances by prepaying anticipated expenses or posting letters of credit, which would decrease our available liquidity and increase our costs.

***Geopolitical risk and conflicts in or around major oil and gas producing nations can significantly impact commodity prices and, therefore the financial condition of the oil and gas industry***

Existing or future conflicts in major oil and gas producing nations and the international response may have potential wide-ranging consequences for global market volatility and economic conditions, including affecting crude oil and natural gas prices. Financial and trade sanctions that may be imposed against countries involved in such conflicts may have continued far-reaching effects on the global economy,

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 42 |

---

------

energy and commodity prices. The short-, medium- and long-term implications of any such conflicts is difficult to predict with any degree of certainty. Depending on the extent, duration, and severity of such conflict(s), it may have the effect of heightening many of the other risks described herein, including, without limitation, risks relating to global market volatility and economic conditions; cybersecurity threats; crude oil and natural gas prices; inflationary pressures, interest rates and costs of capital; change in trade relations and policies, including the potential for tariffs; and supply chains and cost-effective and timely transportation.

***Our hedging activities may negatively impact our income and our financial condition***

In response to fluctuations in commodity prices, foreign exchange and interest rates, we may utilize various derivative financial instruments and physical sales contracts to manage our exposure under a hedging program. The terms of these arrangements may limit the benefit to us of favourable changes in these factors, including receiving less than the market price for our production, and for certain assets will result in us paying royalties at a reference price which is higher than the hedged price. We may also suffer financial loss due to hedging arrangements if we are unable to produce oil or natural gas to fulfill our delivery obligations. There is also increased exposure to counterparty credit risk. To the extent that our current hedging agreements are beneficial to us, these benefits will only be realized for the period and for the commodity quantities in those contracts. In addition, there is no certainty that we will be able to obtain additional hedges at prices that have an equivalent benefit to us, which may adversely impact our revenues in future periods. For more information about our commodity hedging program, see *"Description of our Business - Marketing Arrangements and Forward Contracts"*.

***Failure to comply with the covenants in the agreements governing our debt could adversely affect our financial condition***

We are required to comply with the covenants in our Credit Facilities and the 2032 Notes. If we fail to comply with such covenants, are unable to repay or refinance amounts owned at maturity or pay the debt service charges or otherwise commit an event of default, such as bankruptcy, it could result in the seizure and/or sale of our assets by our creditors. The proceeds from any sale of our assets would be applied to satisfy amounts owed to the secured creditors and then unsecured creditors. Only after the proceeds of that sale were applied towards our debt would the remainder, if any, be available for the benefit of our Shareholders.

***Conflicts of interest may arise between the Corporation and its directors and officers***

Circumstances may arise where directors and officers of the Corporation are directors or officers of other companies involved in the oil and gas industry which are in competition to, or otherwise in conflict with, the interests of the Corporation. Directors are required to abstain from voting on matters when they are in conflict. Employees, including officers, are not permitted to partake in activities that do not support the best interests of the Corporation. Where employee conflicts exist, they are to be provided in writing to our Human Resources Department, which discloses all conflicts to Chief Legal Officer. See "*Directors and Officers – Conflicts*" and the Corporation's Code of Business Conduct and Ethics at *www.baytexenergy.com*.

**Risks Related to Ownership of our Securities**

***Changes in market-based factors may adversely affect the trading price of the Common Shares***

The market price of our Common Shares is sensitive to a variety of market-based factors including, but not limited to, commodity prices, interest rates, foreign exchange rates, the decision of certain indices to include our Common Shares and the comparability of the Common Shares to other securities. Any changes in these market-based factors may adversely affect the trading price of the Common Shares.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 43 |

---

------

***Forward-Looking Information rely upon assumptions which may not prove correct***

Shareholders and prospective investors are cautioned not to place undue reliance on our forward-looking information. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking information or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.

Additional information on the risks, assumption and uncertainties are found under the heading "*Special Notes to Reader – Forward-Looking Statements*" of this AIF.

***Dividends on the Corporation's Common Shares and Common Share repurchases are variable***

The future acquisition by the Corporation of Common Shares pursuant to a share buyback (including through its NCIB) and the payment of dividends, if any, and the level thereof is uncertain. Any decision to acquire Common Shares pursuant to a share buyback or to pay dividends will be subject to the discretion of the Board and may depend on a variety of factors, including, without limitation, the Corporation's business performance, financial condition, financial requirements, commodity prices, 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 the Corporation under applicable corporate law. In the future, there can be no assurance of the number of Common Shares that the Corporation will acquire pursuant to a share buyback and there can be no assurance that dividends will be paid or, if paid the amount of such dividends.

***The Corporation could lose its status as a "foreign private issuer" in the United States***

The Corporation is required to assess its "foreign private issuer" ("FPI") status under U.S. securities laws on an annual basis at the end of its second quarter. While the Corporation currently qualifies as an FPI, it could lose its FPI status in the future. If the Corporation were to lose its status as an FPI it would be required to fully comply with both U.S. and Canadian securities and accounting requirements applicable to domestic issuers in each country. In addition, if the Corporation loses its FPI status, it would be required to report as a U.S. domestic issuer and be subject to other U.S. securities laws applicable to U.S. domestic issuers. The regulatory and compliance costs to the Corporation under U.S. securities laws as a U.S. domestic issuer may be significantly greater than the costs the Corporation incurs as a foreign private issuer. For example, as a U.S. domestic issuer, the Corporation would be required to file periodic reports and registration statements with the SEC on U.S. domestic issuer forms, which are more detailed and extensive in certain respects than the forms available to the Corporation as a foreign private issuer. The Corporation would also be required to report its oil and gas reserves and production information in accordance with applicable U.S. disclosure requirements. Such conversion and modifications would involve additional costs and may restrict the Corporation's access to capital markets for a period of time until it has satisfied SEC reporting requirements. In addition, the Corporation may lose its ability to rely upon exemptions from certain corporate governance requirements on U.S. stock exchanges that are available to FPIs, which could also increase its costs.

**Certain Risks for United States and other non-resident Shareholders**

***The ability of investors resident in the United States to enforce civil remedies is limited***

We are a corporation incorporated under the laws of the Province of Alberta, Canada, our principal office is located in Calgary, Alberta and a substantial portion of our assets are located outside the United States. Most of our directors and officers and the representatives of the experts who provide services to us (such as our auditors and our independent qualified reserves evaluators), and all or a substantial portion of their assets are located outside the United States. As a result, it may be difficult for investors in the United States to effect service of process within the United States upon such directors, officers and

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 44 |

---

------

representatives of experts who are not residents of the United States or to enforce against them judgments of the United States courts based upon civil liability under the United States federal securities laws or the securities laws of any state within the United States. There is doubt as to the enforceability in Canada against us or any of our directors, officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or securities laws of any state within the United States.

***Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States***

We report our production and reserves quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.

We incorporate additional information with respect to production and reserves which is either not required to be included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes (before deduction of Crown and other royalties). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves, whereas the SEC rules require that a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, be utilized.

We have included in this AIF estimates of proved reserves and proved plus probable reserves. Probable reserves have a lower certainty of recovery than proved reserves. The SEC requires oil and gas issuers in their filings with the SEC to disclose only proved reserves but permits the optional disclosure of probable reserves. The SEC definitions of proved reserves and probable reserves are different than NI 51-101; therefore, proved, probable and proved plus probable reserves disclosed in this AIF may not be comparable to United States standards.

As a consequence of the foregoing, our reserves estimates and production volumes in this AIF may not be comparable to those made by companies utilizing United States reporting and disclosure standards.

***There is additional taxation applicable to non-residents***

Tax legislation in Canada may impose withholding or other taxes on the cash dividends, stock dividends or other property transferred by us to non-resident shareholders. These taxes may be reduced pursuant to tax treaties between Canada and the non-resident shareholder's jurisdiction of residence. Evidence of eligibility for a reduced withholding rate must be filed by the non-resident shareholder in prescribed form with their broker (or in the case of registered shareholders, with the transfer agent). In addition, the country in which the non-resident shareholder is resident may impose additional taxes on such dividends. Any of these taxes may change from time to time.

**INDUSTRY CONDITIONS**

Companies operating in the oil and natural gas industry are subject to extensive controls and regulation in respect of operations (including land tenure, exploration, development, production, refining and upgrading, transportation, and marketing) as a result of legislation enacted by various levels of government. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry in western Canada.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 45 |

---

------

**Pricing and Marketing**

*Oil*

In Canada, producers of oil are entitled to negotiate sales contracts directly with oil purchasers. Worldwide supply and demand factors primarily determine oil prices; however, prices are also influenced by regional markets and transportation issues. The specific price depends in part on oil quality, prices of competing fuels, distance to market, availability of transportation, value of refined products, the supply/demand balance and contractual terms of sale.

Oil can be exported from Canada provided that an order approving such export has been obtained from the National Energy Board of Canada (the "**NEB**") and the term of the export contract does not exceed one year in the case of light crude oil and two years in the case of heavy crude oil. Any Canadian oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export license from the NEB.

*Natural Gas*

In Canada, producers of natural gas are entitled to negotiate sales contracts directly with purchasers. Supply and demand determine the price of natural gas, which is calculated at the sale point, being the wellhead, the outlet of a gas processing plant, on a gas transmission system, at a storage facility, at the inlet to a utility system or at the point of receipt by the consumer. Accordingly, the price for natural gas is dependent upon such producer's own arrangements (whether long or short-term contracts and the specific point of sale). As natural gas is also traded on trading platforms such as the Natural Gas Exchange (NGX), Intercontinental Exchange or the New York Mercantile Exchange (NYMEX) in the United States, spot and future prices can also be influenced by supply and demand fundamentals on these platforms.

Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada. Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada. Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m<sup>3</sup>/day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or for a larger quantity requires an export license from the NEB.

**North American Free Trade**

The North American Free Trade Agreement among the governments of Canada, the United States and Mexico came into force on January 1, 1994. On July 1, 2020 this agreement was updated and replaced by the United States Mexico Canada Agreement "**USMCA**". In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods of the party maintaining the restriction as compared to the proportion prevailing in the most recent 36-month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply.

All three signatory countries are prohibited from imposing a minimum or maximum export price requirement in any circumstance where any other form of quantitative restriction is prohibited. The signatory countries are also prohibited from imposing a minimum or maximum import price requirement, except as permitted in enforcement of countervailing and anti-dumping orders and undertakings. USMCA requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 46 |

---

------

arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of which are important for Canadian oil and natural gas exports.

The USMCA is scheduled to be reviewed on July 1, 2026, where the U.S., Mexico, and Canada will determine whether to extend the agreement for another 16-year term (until 2042) or enter annual reviews until 2036. If a party initiates a withdrawal from the USMCA, such withdrawal will take effect 6 months following notification.

**Tariffs**

On February 1, 2025, the new U.S. administration issued an executive order directing the United States to impose new tariffs on imports from Canada. The tariffs were implemented on March 4, 2025. The tariffs are an additional 25% rate of duty on all imports from Canada except Canadian energy resources exports, which are subject to a 10% tariff. The impact of these tariffs is subject to a number of factors including duration, change in the amount, scope and nature, and any mitigating actions that may become available is also currently uncertain. The tariffs do not generally apply to USMCA compliant goods.

On February 20, 2026, the U.S. Supreme Court ("SCOTUS") held that the Trump administration lacked legal authority to impose certain tariffs under the International Emergency Economic Powers Act and U.S. Customs and Border Protection announced that it would cease collecting the affected tariffs. In response to the SCOTUS decision, the Trump administration indicated that it intends to impose alternative tariffs or adopt other trade measures on its trading partners, including Canada. SCOTUS' decision, the Trump's administration's response and the ongoing USMCA review add further uncertainty regarding whether crude oil, natural gas, and NGL exports to the U.S. could ultimately be subject to tariffs or other trade measures. These dynamics influence export costs, market access, and demand for Canadian energy products. The impact of continuing or new tariffs or other trade measures on the Canadian economy and Canadian energy producers is uncertain.

**Royalties and Incentives**

In addition to federal regulation, each province in Canada has legislation and regulations that govern royalties, production rates and other matters. The royalty regime is a significant factor in the profitability of hydrocarbon production. Royalties payable on production from lands other than Crown lands in Canada are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain taxes and royalties. Royalties from production on Crown lands in Canada are determined by governmental regulation and are generally calculated as a percentage of the value of gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced.

From time to time, the federal and provincial governments in Canada create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are generally introduced to encourage specific types of exploration and development activity.

**Land Tenure**

In the Provinces of Alberta and Saskatchewan, the rights to crude oil and natural gas are predominantly owned by the provincial government. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses, and permits for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. Government and private leases are generally granted for an initial fixed term but may generally be continued provided certain minimum levels of drilling operations or production have been achieved and all lease rentals have been timely paid, subject to certain exceptions.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 47 |

---

------

To develop minerals, including oil and gas, it is necessary for the mineral estate owner(s) to have access to the surface estate. Under common law in Canada, the mineral estate is considered the "dominant" estate with the right to extract minerals subject to reasonable use of the surface. Each province has developed and adopted their own statutes that operators must follow both prior to drilling and following drilling, including notification requirements and the provision of compensation for lost land use and surface damages. The surface rights required for pipelines and facilities are generally governed by leases, easements, rights-of-way, permits or licenses granted by landowners or governmental authorities.

**Liability Management Rating Programs**

The Provinces of Alberta and Saskatchewan both have liability management programs in respect of conventional upstream oil and gas wells, facilities and pipelines. Both programs require a licensee whose deemed liabilities equal or exceed its deemed assets within the jurisdiction to provide a security deposit. In response to energy company insolvencies and the associated financial risk, Alberta and Saskatchewan have expanded their liability management programs to become more stringent in recent years. Additional measures of corporate health, beyond simple asset and liability ratios, are now utilized to determine whether a company can hold, transfer or acquire well licenses. These holistic assessments of companies have reduced the number of parties which can acquire assets. Alberta and Saskatchewan have also introduced mandatory asset retirement obligation spending programs. These programs require a licensee to spend a set percentage of its deemed inactive liability, each year, on abandonment, decommissioning and reclamation.

**Environmental Regulation**

The oil and natural gas industry is currently subject to stringent environmental regulation pursuant to a variety of municipal, provincial, state and federal controls, laws, rules and regulations governing the spill, release or emission of materials into the environment, or otherwise relating to environmental protection, all of which is subject to governmental review and revision from time to time. Such controls, laws, rules and regulations, among other things, require the acquisition of permits or other approvals to conduct drilling and other regulated activities; restrict the types, quantities and concentration of various substances that can be released into the environment or injected into formations in connection with oil and natural gas drilling and production activities; limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; impose specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from drilling and production operations. In addition, controls, laws, rules and regulations set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. Compliance with such controls, laws and regulations can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, remedial obligations, civil liability and the imposition of material administrative, civil and criminal penalties.

Environmental legislation in the Province of Alberta is, for the most part, set out in the Environmental Protection and Enhancement Act and the Oil and Gas Conservation Act, which impose strict environmental standards with respect to releases of effluents and emissions, including monitoring and reporting obligations, and impose significant penalties for non-compliance. Environmental legislation in the Province of Saskatchewan is, for the most part, set out in the Environmental Management and Protection Act, 2002 and the Oil and Gas Conservation Act, which regulate harmful or potentially harmful activities and substances, any release of such substances, and remediation obligations.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 48 |

---

------

**Climate Change Regulation and Litigation**

Canada's climate plan includes a target to reduce GHG emissions by 40-45% from 2005 levels by 2030 and a commitment to reaching net zero emissions by 2050 has been legislated. Several policy measures have been put in place to assist in achieving these targets. In 2022, Canada released its first Emissions Reduction Plan under the Canadian Net-Zero Emissions Accountability Act. It models a pathway to achieving Canada's 2030 target and includes a 42% reduction in oil and gas sectorial emissions from current levels. In December 2025, Canada finalized Enhanced Methane Regulations to reduce oil and gas methane emissions. The rules take effect for new facilities January 1, 2028, with full implementation at all sites by 2030. They strive to achieve a 72% reduction in oil and gas methane emissions by 2030 (from 2012 levels). The previous regulations were designed to reduce methane emissions by 40% to 45% by 2025. In November 2024, a draft of the Oil and Gas Sector Emissions Cap Regulations (the "**Cap**") was released. In November 2025, the governments of Canada and Alberta signed an memorandum of understanding pursuant to which the federal government committed to not implementing the Cap and both governments committed to developing sector-specific stringency factors for large Alberta emitters under the Technology Innovation and Emission Reduction ("**TIER**"), concluding an agreement on industrial carbon pricing, and establishing a minimum effective credit price of $130 per tonne. In November 2025 the Federal government released its Budget which included Canada's Climate Competitiveness Strategy. There was an acknowledgement that the Oil and Gas Emissions Cap would not be required if there are effective carbon markets, enhanced methane regulations and deployment of carbon capture in the sector.

Canadian provincial and federal climate policies, including carbon pricing regulations and methane regulations, have financial and operating impacts on our business.

*Carbon Pricing*

In 2019, the Government of Canada implemented the federal Greenhouse Gas Pollution Pricing Act (the GGPPA). The Act established a federal benchmark carbon pollution pricing system applied to fuel and combustible waste. The Federal government amended the GGPPA in April 2025 – zeroing the consumer carbon price. The future emissions threshold and carbon pricing schedule for industrial emitters under the Federal pricing system has remained unclear and we monitor policy changes that impact our operations.

Enacted federal carbon pricing impacts provincial jurisdictions that do not have an equivalent Output-Based Pricing System in place. The Provinces of Saskatchewan and Alberta, where Baytex operates, have performance standards in place which determine our financial exposure to the federal carbon pollution pricing system. Both provinces have obtained and must maintain federal equivalency for their programs. These provincial programs have associated compliance costs when performance standards, relative to an emissions benchmark, cannot be fully met. Compliance costs differ by province depending on the performance standard requirement and compliance cost rate. Emissions coverage under the performance standards included stationary combustion (since 2019) and flaring (since 2023) emissions.

There are direct costs of compliance fees where performance standards apply. Registering our facilities in provincial performance standards limits the financial exposure of compliance fees. In the Province of

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 49 |

---

------

Saskatchewan, the Output-Based Performance Standard regulation applies to facilities emitting more than 25,000 tonne CO2e. In the Province of Alberta, the Technology Innovation and Emission Reduction regulation applies to facilities that emit more than 100,000 tonne CO2e. In both provinces none of our facilities meet these thresholds; however, in previous years we opted into the provincial regulations by aggregating our operated facilities and, as a result, our operated facilities were not subject to the federal carbon pollution pricing system. Regulatory compliance offset credits are generated in the provincial compliance programs if emissions are reduced beyond the annual compliance rate reduction requirement.

*Methane Regulations*

In 2018, Environment and Climate Change Canada (ECCC) set in place federal regulations for methane emissions from the oil and gas sector which came into force January 1, 2020. These regulations were initially set to achieve a methane reduction from upstream oil and gas facilities of 40-45% below 2012 levels by 2025. The Provinces take responsibility for energy and natural resources within their boundaries and have bodies to govern these activities. The Provinces of Alberta and Saskatchewan have developed GHG emissions reduction programs of their own that have achieved equivalency under the federal regulations. These programs have increasing regulatory stringency in subsequent years and, if specified climate-related outcomes are not met, additional regulations could come into force. In December 2025, ECCC finalized Enhanced Methane Regulations to reduce oil and gas methane emissions. The rules take effect for new facilities January 1, 2028, with full implementation at all sites by 2030. They strive to achieve a 72% reduction in oil and gas methane emissions by 2030 (from 2012 levels). Updates to provincial methane regulations and equivalency agreements are anticipated in early 2026.

Tightening methane regulations in future years may require retrofitting existing sites, equipment upgrades, GHG reduction project planning, capital investment, air monitoring and other reporting requirements. Additional future costs will be associated with equipment, projects, monitoring and reporting. We continue to monitor ongoing developments and proposed regulations to ensure regulatory compliance can be achieved.

*Litigation*

In addition, certain municipal entities and advocacy organizations have threatened to sue oil companies in Canada for damage caused by climate change. Certain large oil companies have also been sued in the United States under securities laws for failing to disclose the risks associated with climate change. At this time we cannot predict if we will be included in any such litigation, whether the legal theories advanced in such lawsuits will be accepted by the courts or the potential impact of any such lawsuits.

**Indigenous Rights**

Constitutionally mandated government-led consultation with and, if applicable, accommodation of, indigenous groups impacted by regulated industrial activity, as well as proponent-led consultation and accommodation or benefit sharing initiatives, play an increasingly important role in the Western Canadian oil and gas industry. In addition, Canada is a signatory to the United Nations Declaration of the Rights of Indigenous Peoples (UNDRIP) and the principles set forth therein may continue to influence the role of Indigenous engagement in the development of the oil and gas industry in Western Canada. In December 2020, the federal government introduced Bill C-15: An Act respecting the United Nations Declaration on the Rights of Indigenous Peoples Act (Bill C-15). The intention of Bill C-15, if passed, is to establish a process whereby the Government of Canada will take all measures necessary to ensure the laws of Canada are consistent with the principles of UNDRIP and to implement an action plan to address UNDRIP's objectives.

Continued development of common law precedent regarding existing laws relating to Indigenous consultation and accommodation as well as the adoption of new laws such as UNDRIP and Bill C-15 are expected to continue to add uncertainty to the ability of entities operating in the Canadian oil and gas

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 50 |

---

------

industry to execute on major resource development and infrastructure projects, including, among other projects, pipelines.

**Occupational Health and Safety**

The Corporation's operations must be carried out in accordance with safe work procedures, rules and policies contained in applicable safety legislation. Such legislation requires that every employer ensures the health and safety of all persons at any of its work sites and all workers engaged in the work of that employer. The legislation, which provides for incident reporting procedures, also requires every employer to ensure all of its employees are aware of their duties and responsibilities under the applicable legislation. Penalties under applicable occupational health and safety legislation include significant fines and incarceration.

**General**

Implementation of more stringent environmental regulations on our operations could affect the capital and operating expenditures and plans for our operations. In addition to the agencies that directly regulate oil and gas operations, there are other state and local conservation and environmental protection agencies that regulate air quality, water quality, fish, wildlife, visual quality, transportation, noise, spills, incidents and transportation.

We believe that, in all material respects, we are in compliance with, and have complied with, all applicable environmental laws and regulations. We have made and will continue to make expenditures in our efforts to comply with all applicable environmental regulations and requirements. We consider these a normal, recurring cost of our ongoing operations and not an extraordinary cost of compliance with governmental regulations. We believe that our continued compliance with existing requirements has been accounted for and will not have a material adverse impact on our financial condition, results of operations and operating cash flows. However, we cannot predict the passage of or quantify the potential impact of any more stringent future laws and regulations at this time.

**DIVIDENDS**

Commencing in the third quarter of 2023, the Corporation began paying a quarterly dividend on the first business day of each quarter to Shareholders of record on the 15th day of the month prior to the payment date.

Although the Corporation strives to maintain consistent dividend payments, the amount of cash dividends to be paid on Common Shares, if any, will be at the discretion of the Board of Directors and may vary based on a variety of factors. These factors include fluctuations in the price of oil and gas, exchange rates and production rates, reserves growth, the size of development drilling programs and the portion thereof funded from cash flow and the overall level of debt and working capital of the Corporation, the prevailing economic and competitive environment, the taxability of Baytex, Baytex's ability to raise capital, the amount of capital expenditures, the satisfaction of solvency tests imposed by the *Business Corporations Act* (Alberta) for the declaration and payment of dividends and other conditions existing from time to time. There can be no guarantee that Baytex will maintain the quantum or frequency of its dividends.

The agreements governing the Credit Facilities and the 2032 Notes stipulate that distributions to Shareholders and share repurchases are not permitted if the Corporation is in default under the agreements or the payment of such distribution would cause an event of default.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 51 |

---

------

The following table sets forth the amount of cash dividends declared per Common Share by the Corporation for the periods indicated.

---

| | |
|:---|:---|
| **Declaration Date** | **Dividend<br>$ per Common Share** |
| July 27, 2023 | 0.0225 |
| November 2, 2023 | 0.0225 |
| February 28, 2024 | 0.0225 |
| May 9, 2024 | 0.0225 |
| July 25, 2024 | 0.0225 |
| October 31, 2024 | 0.0225 |
| March 4, 2025 | 0.0225 |
| May 5, 2025 | 0.0225 |
| July 31, 2025 | 0.0225 |
| October 30, 2025 | 0.0225 |

---

**DESCRIPTION OF CAPITAL STRUCTURE**

**Share Capital**

Baytex is authorized to issue an unlimited number of Common Shares without nominal or par value and 10,000,000 Preferred Shares, without nominal or par value, issuable in series. As at the date of this AIF, there are no Preferred Shares outstanding.

The following is a summary of certain provisions of the share capital of Baytex. For a complete description of these provisions, please refer to Baytex's Articles of Incorporation, available on the SEDAR+ website at *www.sedarplus.ca* (filed on January 10, 2011).

*Common Shares*

Holders of Common Shares are entitled to notice of meetings of the holders of Common Shares and to attend the meetings and to one vote per Common Share at such meetings (other than for meetings of a class or series of shares of the Corporation other than the Common Shares).

Holders of Common Shares will be entitled to receive dividends as and when declared by the Board, subject to prior satisfaction of all preferential rights to dividends attached to shares of other classes of shares of the Corporation ranking in priority to the Common Shares in respect of dividends.

Holders of Common Shares will be entitled in the event of any liquidation, dissolution or winding-up of the Corporation, whether voluntary or involuntary, or any other distribution of the assets of the Corporation among its shareholders for the purpose of winding-up its affairs, and subject to prior satisfaction of all preferential rights to return of capital on dissolution attached to all shares of other classes of shares of the Corporation ranking in priority to the Common Shares in respect of return of capital on dissolution, to share rateably, together with the holders of shares of any other class of shares of the Corporation ranking equally with the Common Shares in respect of return of capital on dissolution, in such assets of the Corporation as are available for distribution.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 52 |

---

------

*Preferred Shares*

Preferred Shares may be issued from time to time in one or more series, each series to consist of such number of shares as may be authorized by the Board, and subject to the provisions of the ABCA, the Board may fix the rights, restrictions, privileges, conditions and designations attached to each series of Preferred Shares. The Preferred Shares shall be entitled to preference over the Common Shares and any other shares of the Corporation ranking junior to the Preferred Shares with respect to payment of dividends and the distribution of assets in the event of liquidation, dissolution or winding-up of the Corporation, whether voluntary or involuntary, to the extent fixed in the case of each respective series, and may also be given such other preferences over the Common Shares and any other shares of the Corporation ranking junior to the Preferred Shares as may be fixed in the case of each such series.

**Senior Notes**

On April 1, 2024, we issued US$575 million aggregate principal amount of 2032 Notes bearing interest at a rate of 7.375%. The 2032 Notes were issued at 99.266% of par and are redeemable at our option, in whole or in part, at specified redemption prices on or after March 15, 2027 and will be redeemable at par from March 15, 2029 to maturity. Following certain open market repurchases and the Tender Offer, the principal amount of 2032 Notes outstanding is $95.9 million.

For a complete description of the 2032 Notes, reference should be made to the applicable debt indenture, copies of which are accessible on the SEDAR+ website at *www.sedarplus.ca*. See *"Material Contracts"*.

**Credit Facilities**

Our Credit Facilities consist of $750.0 million of revolving credit facilities and are comprised of a $50 million operating loan and a $700 million syndicated revolving loan. The Credit Facilities are secured and, unless extended by the lenders, will mature on June 27, 2030.

For additional details regarding the covenants in our Credit Facilities and our compliance therewith, see the Baytex Annual 2025 MD&A*.* Also see *"Material Contracts"*.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 53 |

---

------

**MARKET FOR SECURITIES**

The Common Shares are listed and trade on the TSX and the NYSE under the symbol "BTE". The following tables set forth the price range and trading volume of the Common Shares on the TSX and on all Canadian Exchanges ('Composite') for the periods indicated.

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Canada TSX Trading** | **Canada TSX Trading** | **Canada TSX Trading** | **Canada Composite Trading** | **Canada Composite Trading** | **Canada Composite Trading** | **US NYSE Trading** | **US NYSE Trading** | **US NYSE Trading** |
| | **Price Range** | **Price Range** | | **Price Range** | **Price Range** | | **Price Range** | **Price Range** | |
| | **High <br>($)** | **Low <br>($)** |<br>**Volume <br>Traded** | **High <br>($)** | **Low <br>($)** |<br>**Volume <br>Traded** | **High (US$)** | **Low (US$)** |<br>**Volume Traded** |
| <u>2025</u> |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;January | 3.93 | 3.49 | 90046429 | 3.93 | 3.49 | 230099255 | 2.75 | 2.40 | 47403799 |
| &nbsp;&nbsp;&nbsp;&nbsp;February | 3.69 | 3.18 | 70667472 | 3.69 | 3.18 | 150183173 | 2.58 | 2.22 | 52556053 |
| &nbsp;&nbsp;&nbsp;&nbsp;March | 3.28 | 2.82 | 106713620 | 3.28 | 2.82 | 245187816 | 2.31 | 1.95 | 68133705 |
| &nbsp;&nbsp;&nbsp;&nbsp;April | 3.20 | 2.08 | 133341212 | 3.21 | 2.10 | 316524609 | 2.23 | 1.48 | 67180081 |
| &nbsp;&nbsp;&nbsp;&nbsp;May | 2.69 | 2.07 | 122914064 | 2.69 | 2.07 | 272987693 | 1.94 | 1.49 | 73462852 |
| &nbsp;&nbsp;&nbsp;&nbsp;June | 2.91 | 2.32 | 150866634 | 2.91 | 2.32 | 318974183 | 2.12 | 1.70 | 109904009 |
| &nbsp;&nbsp;&nbsp;&nbsp;July | 3.02 | 2.47 | 119490553 | 3.02 | 2.47 | 255235774 | 2.20 | 1.81 | 79948549 |
| &nbsp;&nbsp;&nbsp;&nbsp;August | 3.05 | 2.73 | 95682091 | 3.05 | 2.73 | 191965598 | 2.23 | 1.97 | 53373354 |
| &nbsp;&nbsp;&nbsp;&nbsp;September | 3.58 | 3.03 | 122454595 | 3.58 | 3.03 | 269227565 | 2.61 | 2.18 | 62999232 |
| &nbsp;&nbsp;&nbsp;&nbsp;October | 3.59 | 3.12 | 119733937 | 3.59 | 3.12 | 264333732 | 2.56 | 2.21 | 64807222 |
| &nbsp;&nbsp;&nbsp;&nbsp;November | 4.57 | 3.27 | 145242310 | 4.60 | 3.27 | 335073112 | 3.24 | 2.33 | 72583574 |
| &nbsp;&nbsp;&nbsp;&nbsp;December | 4.52 | 4.15 | 94953338 | 4.52 | 4.15 | 201538937 | 3.25 | 3.01 | 44999762 |

---

**DIRECTORS AND OFFICERS**

**Directors of the Corporation**

The following table sets forth the name, municipality of residence, age as at December 31, 2025, year of appointment as a director of the Corporation and principal occupation for each of the current directors of the Corporation.

---

| | | | |
|:---|:---|:---|:---|
| **Name and Municipality<br>of Residence** | **Age** | **Director Since** | **Principal Occupation for Past Five Years** |
| **Mark R. Bly** <sup>(1)</sup><br>Incline Village, Nevada | 66 | November 2017 | Corporate director. |
| **Trudy M. Curran** <sup>(2)(3)</sup><br>Calgary, Alberta | 63 | July 2016 | Corporate director. |
| **Eric T. Greager** <sup>(4)</sup><br>Denver, Colorado | 56 | November 2022 | Chief Executive Officer of the Corporation since December 2025. President and Chief Executive Officer of the Corporation since November 2022. Previously served as President and Chief Executive Officer of Civitas Resources (formerly Bonanza Creek Energy, Inc.). |
| **Don G. Hrap** <sup>(5)(6)</sup><br>Houston, Texas | 66 | March 2020 | Corporate director. |
| **Jennifer A. Maki** <sup>(3)(6)</sup><br>North York, Ontario | 55 | September 2019 | Corporate director. |
| **David L. Pearce** <sup>(3)(5)</sup><br>Calgary, Alberta | 71 | August 2018 | Deputy Chairman, Azimuth Capital Management. |

---

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 54 |

---

------

---

| | | | |
|:---|:---|:---|:---|
| **Name and Municipality<br>of Residence** | **Age** | **Director Since** | **Principal Occupation for Past Five Years** |
| **Stephen D.L. Reynish** <sup>(2)(6)(7)</sup><br>Calgary, Alberta | 67 | November 2020 | Corporate director. Previously, President and Chief Executive Officer of Enlighten Innovations from October 2020 until October 2022. |
| **Jeffery E. Wojahn** <sup>(2)(5)(8)</sup><br>Denver, Colorado | 62 | June 2023 | Corporate director. |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Chair of the Board and *ex officio* member of all board committees to which he is not appointed.

&nbsp;&nbsp;&nbsp;&nbsp;(2)Member of our Nominating and Governance Committee.

&nbsp;&nbsp;&nbsp;&nbsp;(3)Member of our Human Resources and Compensation Committee.

&nbsp;&nbsp;&nbsp;&nbsp;(4)Effective December 19, 2025, Mr. Greager's title changed from President and Chief Executive Officer to Chief Executive Officer.

&nbsp;&nbsp;&nbsp;&nbsp;(5)Member of our Reserves and Sustainability Committee.

&nbsp;&nbsp;&nbsp;&nbsp;(6)Member of our Audit Committee.

&nbsp;&nbsp;&nbsp;&nbsp;(7)Stephen D.L. Reynish was appointed to the Audit Committee effective February 2, 2026.

&nbsp;&nbsp;&nbsp;&nbsp;(8)Jeffery E. Wojahn was appointed to the Reserves and Sustainability Committee effective February 2, 2026.

**Officers of the Corporation**

The following table sets forth the name, municipality of residence, age as at December 31, 2025, position held with the Corporation and principal occupation of each of the officers of the Corporation.

---

| | | | |
|:---|:---|:---|:---|
| **Name and Municipality<br>of Residence** | **Age** | **Office** | **Principal Occupation for Past Five Years** |
| **Eric T. Greager** <sup>(1)</sup><br>Denver, Colorado | 56 | Chief Executive Officer | Chief Executive Officer of the Corporation since December 2025. President and Chief Executive Officer of the Corporation since November 2022. Previously served as President and Chief Executive Officer of Civitas Resources (formerly Bonanza Creek Energy, Inc.). |
| **Chad L. Kalmakoff**<br>Calgary, Alberta | 49 | Chief Financial Officer | Chief Financial Officer of the Corporation since November 2022. Previously served as Vice President, Finance of the Corporation since September 2015. |
| **Chad E. Lundberg** <sup>(2)</sup><br>Calgary, Alberta | 44 | President and Chief Operating Officer | President and Chief Operating Officer of the Corporation since December 2025. Previously served as Chief Operating Officer since June 2023; Chief Operating & Sustainability Officer since July 2021; and Vice President, Light Oil since December 2018. |
| **James R. Maclean**<br>Calgary, Alberta | 46 | Chief Legal Officer and Corporate Secretary | Chief Legal Officer and Corporate Secretary of the Corporation since June 2023. Previously served as Vice President, General Counsel and Corporate Secretary since February 2022; and as General Counsel and Corporate Secretary since August 2018. |
| **Brian G. Ector**<br>Calgary, Alberta | 57 | SVP, Capital Markets and Investor Relations | SVP, Capital Markets and Investor Relations of the Corporation since June 2023. Previously served as Vice President, Capital Markets since August 2018. |
| **Kendall D. Arthur**<br>Calgary, Alberta | 45 | SVP and General Manager, Cdn. Heavy Oil Operations | SVP and General Manager, Canadian Heavy Oil Operations at the Corporation since June 2023. Previously served as Vice President, Heavy Oil at the Corporation since December 2018. |

---

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 55 |

---

------

---

| | | | |
|:---|:---|:---|:---|
| **Name and Municipality<br>of Residence** | **Age** | **Office** | **Principal Occupation for Past Five Years** |
| **Nicole Frechette** Calgary, Alberta | 42 | VP and General Manager, Cdn. Light Oil Operations | VP and General Manager, Canadian Light Oil Operations at the Corporation since June 2023. Previously served as Vice President, Light Oil from February 2022; Subsurface Manager, Light Oil from August 2021; and held various senior technical and leadership roles with Repsol and Talisman Energy from 2005 until August 2021. |
| **Chris M.P. Lessoway**<br>Calgary, Alberta | 41 | VP, Finance & Treasurer | Vice President of Finance and Treasurer of the Corporation since June 2023. Previously served as Financial Controller of the Corporation since June 2017. |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Effective December 19, 2025, Mr. Greager's title changed from President and Chief Executive Officer to Chief Executive Officer.

&nbsp;&nbsp;&nbsp;&nbsp;(2)Effective December 19, 2025, Mr. Lundberg's title changed from Chief Operating Officer to President and Chief Operating Officer.

**Ownership of Securities by Management**

As at the date of this AIF, the directors and officers of Baytex, as a group, beneficially owned, or controlled or directed, directly or indirectly, 4,674,473 Common Shares.

**Corporate Cease Trade Orders or Bankruptcies**

To the Corporation's knowledge, no director or executive officer of Baytex (nor any personal holding company of any of such persons) is, as of the date of this AIF, or was within ten years before the date of this AIF, a director, chief executive officer or chief financial officer of any company (including Baytex), that was subject to a cease trade order (including a management cease trade order), an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, in each case that was in effect for a period of more than 30 consecutive days (collectively, an "**Order**") that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer or was subject to an order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer.

Other than as disclosed below, to the Corporation's knowledge, no director or executive officer of Baytex (nor any personal holding company of any of such persons), or shareholder holding a sufficient number of our securities to materially affect control of us, is, as of the date of this AIF, or has been within the ten years before the date of this AIF, a director or executive officer of any company (including Baytex) that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver-manager or trustee appointed to hold its assets or has, within the ten years before the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver-manager or trustee appointed to hold the assets of the director, executive officer or shareholder.

David Pearce is a director of Courser Energy Ltd. formerly Kaisen Energy Corp. ("Kaisen"). On December 8, 2021, Kaisen sought and obtained protection under the Companies' Creditors Arrangement Act ("CCAA") pursuant to an Order (the "Initial Order") of the Court of Queen's Bench of Alberta (the "Court"). The Initial Order authorized Kaisen to begin a Court-supervised restructuring and granted Kaisen various

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 56 |

---

------

relief, including but not limited to, an initial stay of proceedings against Kaisen and its assets, appointing Ernst & Young Inc. as Monitor (the "Monitor"), and providing Kaisen the opportunity to prepare and file a plan of arrangement under the CCAA for the consideration of its creditors and other stakeholders. On December 17, 2021, the Court approved a plan of arrangement under the CCAA including provisions relating to receiving creditor and stakeholder approval for the plan of arrangement. On March 16, 2022, the Monitor filed a Plan Implementation Certificate confirming that the Plan, as approved by affected creditors and the Court is effective in accordance with its terms and the Sanction Order. As a result, the CCAA proceedings have now concluded and the Monitor has been discharged.

Trudy Curran, a director of Baytex, was a director of Great Panther Mining Ltd. ("Great Panther") from June 9, 2021 to December 15, 2022. On September 6, 2022, Great Panther filed a notice of intention to make a proposal under the Bankruptcy and Insolvency Act (Canada), which provided Great Panther with creditor protection while it sought to restructure its affairs. On November 18, 2022, the British Columbia Securities Commission issued a cease trade order in respect of Great Panther's securities as a result of its inability to file its quarterly continuous disclosure documents in accordance with Canadian securities laws. On December 16, 2022, Great Panther made a voluntary assignment into bankruptcy under the Bankruptcy and Insolvency Act (Canada) and Alvarez & Marsal Canada Inc. was appointed licensed insolvency trustee of Great Panther's estate.

**Penalties or Sanctions**

To the Corporation's knowledge, no director or executive officer of Baytex (nor any personal holding company of any of such persons), or shareholder holding a sufficient number of our securities to materially affect control of us, has been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority or any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

**Conflicts**

There are potential conflicts of interest to which the directors and officers of Baytex will be subject in connection with the operations of Baytex. In particular, certain of the directors and officers of Baytex are involved in managerial or director positions with other oil and gas companies whose operations may, from time to time, be in direct competition with those of Baytex or with entities which may, from time to time, provide financing to, or make equity investments in, competitors of Baytex. Conflicts, if any, will be subject to the procedures and remedies available under the ABCA. The ABCA provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director will disclose his interest in such contract or agreement and will refrain from voting on any matter in respect of such contract or agreement unless otherwise provided in the ABCA.

Our audit committee is responsible for reviewing all related party transactions and its mandate specifies that the audit committee is responsible for ensuring the nature and extent of such transactions are properly disclosed.

**AUDIT COMMITTEE INFORMATION**

**Audit Committee Mandate and Terms of Reference**

The text of the Audit Committee's Mandate and Terms of Reference is attached as Appendix C to this AIF.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 57 |

---

------

**Composition of the Audit Committee**

The members of our Audit Committee are Jennifer A. Maki, Don G. Hrap and Steve D.L. Reynish. The relevant education and experience of each Audit Committee member is outlined below:

---

| | |
|:---|:---|
| **Name** | **Relevant Education and Experience** |
| Jennifer A. Maki <sup>(1)(2)(3)</sup><br>*Committee Chair* | Bachelor of Commerce degree from Queen's University and a postgraduate diploma from the Institute of Chartered Accountants of Ontario. Formerly served as CEO of Vale Canada and Executive Director of Vale-SA-Base Metals. Prior thereto, CFO and Executive Vice President of Vale-SA-Base Metals. Before joining Vale/Inco, worked at PricewaterhouseCoopers LLP for 10 years. Ms. Maki has been named a Fellow of the Chartered Professional Accountants by CPA Ontario and also earned the CERT Certificate in Cybersecurity Oversight from the Software Engineering Institute at Carnegie Mellon University. |
| Don G. Hrap <sup>(1)(2)</sup> | Bachelor of Science in Mechanical Engineering and a Master in Business Administration. From 2009-2018, he served as President, Lower 48 at ConocoPhillips with strong breadth and depth of experience across several U.S. oil resource plays. Prior to this at ConocoPhillips, Mr. Hrap was Senior Vice President of Western Canada Gas. He joined ConocoPhillips in 2006 through the merger with Burlington Resources, serving as Senior Vice President of Operations for Burlington Canada. Earlier, he was Vice President for the North American Division at Gulf Canada Resources, where he worked for 17 years. |
| Steve D.L. Reynish<sup>(1)(2)</sup> | Mr. Reynish holds a Masters in Engineering and a Master of Business Administration earned in the UK. Formerly served as Chief Executive Officer of Enlighten Innovations and prior to that was an Executive Vice President at Suncor Energy Inc. for eight years, which included a period as interim Chief Financial Officer. Additionally, the President of Marathon Oil Canada, which he joined through its acquisition of Western Oil Sands. Prior to his entry into Canada, he held senior positions within the Anglo American Group, including Vice President of Mining of Anglo Base Metals in Johannesburg and Chief Executive Officer of Bindura Nickel in Zimbabwe. |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Independent director.

&nbsp;&nbsp;&nbsp;&nbsp;(2)Financially literate within the meaning of National Instrument 52-110 - Audit Committees and the NYSE listing standards.

&nbsp;&nbsp;&nbsp;&nbsp;(3)An "Audit Committee Financial Expert" pursuant to the SEC's definition of the term.

**Pre**-**Approval of Policies and Procedures**

Although the Audit Committee has not adopted specific policies and procedures for the engagement of non-audit services by our auditors, it does pre-approve all non-audit services to be provided to us and our subsidiaries by the external auditors. The pre-approval for recurring services, such as preliminary work on the integrated audit, securities filings, translation of our financial statements and related MD&A into the French language and tax and tax-related services, is provided on an annual basis and other services are subject to pre-approval as required.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 58 |

---

------

**External Auditor Service Fees**

The following table provides information about the fees billed to us and our subsidiaries for professional services rendered by our external auditors, during fiscal 2025 and 2024:

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| Year | Audit Fees <sup>(1)</sup> | Audit-Related Fees <sup>(2)</sup> | Tax Fees <sup>(3)</sup> | All Other Fees <sup>(4)</sup> | Total |
| 2025 | $2268 | $– $| 33 | $– $| 2301 |
| 2024 | $2228 | $– $| 274 | $– $| 2502 |

---

Notes:

&nbsp;&nbsp;&nbsp;&nbsp;(1)Audit fees consist of fees for the audit of our annual financial statements or services that are normally provided in connection with statutory and regulatory filings or engagements. In addition to the fees for annual audits of financial statements and review of quarterly financial statements, services in this category for fiscal 2025 and 2024 also include amounts for audit work performed in relation to the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 relating to internal control over financial reporting.

&nbsp;&nbsp;&nbsp;&nbsp;(2)Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not reported as Audit Fees.

&nbsp;&nbsp;&nbsp;&nbsp;(3)Tax fees include fees for tax compliance, tax advice and tax planning.

&nbsp;&nbsp;&nbsp;&nbsp;(4)Other fees include all other non-audit services.

**LEGAL PROCEEDINGS AND REGULATORY ACTIONS**

Other than as disclosed below, there are no legal proceedings involving claims for damages for which the potential exposure is more than 10% of our current assets to which we are or were a party, or in respect of which any of our property is or was the subject of, during the most recently completed financial year, nor are there any such material legal proceedings that the Company knows to be contemplated.

In June 2016, certain indirect subsidiary entities received reassessments from the 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 and we estimate it could take between two and 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 Tax Court of Canada, additional appeals are available; a process that we estimate could take another two years and potentially longer.

We remain confident that the tax filings of the affected entities are correct and will defend our tax filing positions. During 2023, we purchased $272.5 million of insurance coverage for a premium of $50.3 million which will help manage the litigation risk associated with this matter. The most recent statement of account issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $244.2 million and a late filing penalty in respect of the 2011 tax year of $4.1 million.

By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. First, the reassessments allege that the trusts were resettled and the resulting successor trusts were not able to access the losses of the predecessor trusts. Second, the reassessments allege that the general anti-avoidance rule of the Tax Act 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 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

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 59 |

---

------

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.

**INTEREST OF INSIDERS AND OTHERS IN MATERIAL TRANSACTIONS**

There were no material interests, direct or indirect, of our directors and executive officers, any holder of Common Shares who beneficially owns or controls or directs, directly or indirectly, more than 10 percent of the outstanding Common Shares, or any known associate or affiliate of such persons, in any transactions within the three most recently completed financial years or since the beginning of our last completed financial year which has materially affected or is reasonably expected to materially affect us.

**TRANSFER AGENT AND REGISTRAR**

Odyssey Trust Company, at its principal offices in Calgary, Alberta, Vancouver, British Columbia and Toronto, Ontario, is the transfer agent and registrar for the Common Shares in Canada. Odyssey Transfer US Inc., at its principal office in Denver, Colorado is the transfer agent and registrar for the Common Shares in the United States. Computershare Trust Company, N.A., at its principal office in Canton, Massachusetts, is the transfer agent and registrar for the Corporation's outstanding 2032 Notes.

**MATERIAL CONTRACTS**

Except for contracts entered into in the ordinary course of business, the only material contracts entered into by us within the most recently completed financial year, or before the most recently completed financial year but are still material and are still in effect, are the following:

a.the Securities Purchase Agreement by and among BTE USA Intermediate, Inc., as Seller, Baytex Energy USA, Inc. as the Subject Company, and Eagle Ford BuyerCo, LLC, as Purchaser, dated as of November 12, 2025 (filed on SEDAR+ on November 21, 2025);

b.the credit agreement in respect of the Credit Facilities (filed on SEDAR+ on December 22, 2025);

c.the indenture among Baytex, as issuer, certain of its subsidiaries, as guarantors, and Computershare Trust Company, N.A., as indenture trustee, dated April 1, 2024 which governs the 2032 Notes (filed on SEDAR+ on February 18, 2025);

d.our share award incentive plan (filed on SEDAR+ on April 18, 2016) and our subsequently amended share award incentive plan (filed on January 28, 2018, March 1, 2022 and February 23, 2023); and

e.our investor and registration rights agreement (filed on SEDAR+ on March 1, 2023).

Copies of each of these contracts are accessible on the SEDAR+ website at *www.sedarplus.ca*.

**INTERESTS OF EXPERTS**

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a report, valuation, statement or opinion described or included in a filing, or referred to in a filing, made under National Instrument 51-102 - Continuous Disclosure Obligations by us during, or related to, our most recently completed financial year other than McDaniel, our independent qualified reserves evaluator. None of the designated professionals of McDaniel have any registered or beneficial interests, direct or indirect, in any of our securities or other property or of our associates or affiliates either at the time they prepared a report, valuation, statement or opinion, at any time thereafter or to be received by them.

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 60 |

---

------

KPMG LLP are the auditors of the Corporation and have confirmed with respect to the Corporation, that they are independent within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations, and also that they are independent accountants with respect to the Corporation under all relevant U.S. professional and regulatory standards.

In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of Baytex or of any associate or affiliate of Baytex.

**ADDITIONAL INFORMATION**

Additional information relating to us can be found on our website and on the SEDAR+ website at *www.sedarplus.ca*. Further information, including directors' and officers' remuneration and indebtedness, principal holders of our securities and securities issued and authorized for issuance under our equity compensation plans will be contained in our Information Circular - Proxy Statement for the annual meeting of Shareholders. Additional financial information is contained in our consolidated financial statements for the year ended December 31, 2025 and the related Baytex Annual 2025 MD&A which are accessible on the SEDAR+ website at *www.sedarplus.ca*.

For additional copies of this AIF and the materials listed in the preceding paragraph, please contact:

Baytex Energy Corp. <br>Suite 2800, Centennial Place, East Tower

520 – 3<sup>rd</sup> Avenue S.W.

Calgary, Alberta T2P 0R3

Phone: (587) 952-3000

Fax: (587) 952-3029

Website: *www.baytexenergy.com*

---

| | |
|:---|:---|
| ![btefooter1a.jpg](btefooter1a.jpg) | 61 |

---

------

**APPENDIX A**

**REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE**

**Form 51-101F3**

Management of Baytex Energy Corp. ("**Baytex**") is responsible for the preparation and disclosure of information with respect to Baytex's oil and natural gas activities in accordance with securities regulatory requirements. This information includes reserves data.

Independent qualified reserves evaluators have evaluated Baytex's reserves data. The report of the independent qualified reserves evaluators is presented below.

The Reserves and Sustainability Committee of the Board of Directors of Baytex (the "**Reserves Committee**") has:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.reviewed Baytex's procedures for providing information to the independent qualified reserves evaluators;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.reviewed the reserves data with management and the independent qualified reserves evaluator.

The Reserves Committee has reviewed Baytex's procedures for assembling and reporting other information associated with oil and natural gas activities and has reviewed that information with management. The Board of Directors of Baytex has, on the recommendation of the Reserves Committee, approved:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluators on the reserves data; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

---

| | |
|:---|:---|
| <u>(signed)</u> *<u>"Eric T. Greager"</u>* | <u>(signed)</u> *<u>"Chad E. Lundberg"</u>* |
| Eric T. Greager | Chad E. Lundberg |
| Chief Executive Officer | President and Chief Operating Officer |
| <u>(signed)</u> *<u>"Don G. Hrap"</u>* | <u>(signed)</u> *<u>"David L. Pearce"</u>* |
| Don G. Hrap | David L. Pearce |
| Director and Chair of the Reserves and Sustainability Committee | Director and Member of the Reserves and Sustainability Committee |

---

March 4, 2026

------

**APPENDIX B**

**REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR**

**Form 51-101F2**

To the Board of Directors of Baytex Energy Corp. (the "Company"):

1. We have evaluated the Company's reserves data as at December 31, 2025. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2025 estimated using forecast prices and costs.

2. The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

3. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).

4. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

5. The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved + probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended December 31, 2025, and identifies the respective portions thereof that we have evaluated and reported on to the Company's Board of Directors:

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **Independent Qualified Reserves Evaluator** | **Effective Date of<br> Evaluation <br>Report** | **Location of Reserves** | **Net Present Value of Future Net Revenue $M<br>(before income taxes, 10% discount rate)** | **Net Present Value of Future Net Revenue $M<br>(before income taxes, 10% discount rate)** | **Net Present Value of Future Net Revenue $M<br>(before income taxes, 10% discount rate)** | **Net Present Value of Future Net Revenue $M<br>(before income taxes, 10% discount rate)** |
| **Independent Qualified Reserves Evaluator** | **Effective Date of<br> Evaluation <br>Report** | **Location of Reserves** | **Audited** | **Evaluated** | **Reviewed** | **Total** |
| McDaniel | December 31, 2025 | Canada |  | **2541243** |  | **2541243** |

---

6. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

7. We have no responsibility to update our report referred to in paragraph 5 for events and circumstances occurring after the effective date of our report.

8. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above:

**MCDANIEL & ASSOCIATES CONSULTANTS LTD.**

'signed by Michael Verney"

_________________________

Michael Verney, P.Eng.

Executive Vice President

Calgary, Alberta, Canada

February 2, 2026

------

**APPENDIX C**

**BAYTEX ENERGY CORP.**

**AUDIT COMMITTEE**

**MANDATE AND TERMS OF REFERENCE**

**ROLE AND OBJECTIVE**

The Audit Committee (the "<u>Committee</u>") is a committee of the board of directors (the "<u>Board</u>") of Baytex Energy Corp. (the "<u>Corporation</u>") to which the Board has delegated certain of its responsibilities. The primary responsibility of the Committee is to review the interim and annual financial statements of the Corporation and to recommend their approval or otherwise to the Board. The Committee is also responsible for reviewing and determining, in its capacity as a committee of the Board, the appointment and compensation of the external auditors of the Corporation, overseeing the work of the external auditors, including the nature and scope of the audit of the annual financial statements of the Corporation, pre-approving services to be provided by the external auditors and reviewing the assessments prepared by management and the external auditors on the effectiveness of the Corporation's internal controls over financial reporting. The objectives of the Committee are to assist the Board in monitoring and overseeing:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.the preparation and disclosure of the financial statements of the Corporation and related matters;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.communication between directors and the external auditors;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.the external auditors' qualifications and independence;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.compliance with legal and regulatory requirements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.the performance of the Corporation's external auditor;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6.the integrity, credibility and objectivity of financial reports and statements; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;7.the relationship among the Committee, all independent directors, management and the external auditors.

**MEMBERSHIP OF THE COMMITTEE**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.The Committee shall be comprised of not less than three members all of whom are "independent" directors and "financially literate" within the meaning of National Instrument 52-110 "Audit Committees" and the laws, rules and regulations of the U.S. Securities and Exchange Commission ("SEC") and the New York Stock Exchange ("NYSE"), as applicable, subject to any permitted phase-in periods that may apply. The members of the Committee shall be appointed by the Board from time to time based on the recommendation of the Nominating & Governance Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.At least one member of the Committee shall have accounting or related financial management expertise, as the Board interprets such qualification in its business judgment. For certainty, any member of the Committee that qualifies as an "audit committee financial expert" under the rules of the SEC will be deemed to meet this requirement. Members of the Committee may not be "affiliates" of the Corporation or any subsidiary of the Corporation. Subject to any permitted exceptions, members of the Committee may not accept, directly or indirectly, any consulting, advisory, or other compensatory fee from the Corporation or any subsidiary thereof. Corporation.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.A member of the Committee may not simultaneously serve on the audit committees of more than three public companies, unless the Board first determines that such simultaneous service would not impair the ability of such member to effectively serve on the Committee. Any such determination must be publicly disclosed in accordance with the rules of the NYSE.

------

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.The Board shall appoint a Chair of the Committee, who shall be an independent director.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.Any member of the Committee may be removed or replaced at any time by the Board and shall cease to be a member of the Committee as soon as such member ceases to be a director. The Board may fill vacancies on the Committee by appointment from among its members. If and whenever a vacancy shall exist on the Committee, the remaining members may exercise all its powers so long as a quorum remains. Subject to the foregoing, each member of the Committee shall hold such office until the close of the next annual meeting of shareholders of the Corporation following appointment as a member of the Committee.

**MANDATE AND RESPONSIBILITIES OF THE COMMITTEE**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.It is the responsibility of the Committee to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.recommend the audit firm to be nominated as the Corporation's auditors, for approval by the shareholders of the Corporation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.oversee the staffing, planning, and execution of the audit by the external auditor. The external auditors shall report directly to the Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.It is the responsibility of the Committee to satisfy itself on behalf of the Board with respect to the Corporation's internal control systems by:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.identifying, monitoring and mitigating business risks, as detailed further below; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.ensuring compliance with legal, ethical and regulatory requirements.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.It is a primary responsibility of the Committee to review with **management** and the **external auditors** the interim and annual financial statements of the Corporation, including disclosures made under "Management's Discussion and Analysis", prior to their submission to the Board for approval. The review process should include, without limitation:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.reviewing major issues regarding accounting policies and principles and financial statement presentations, including any changes in accounting principles, or in their application;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.reviewing major issues as to the adequacy of the Corporation's internal controls and any special audit steps adopted in light of material or significant control deficiencies;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.reviewing significant management judgments, estimates and assumptions that affect the application of accounting policies and their reported amounts;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.reviewing analyses prepared by management and/or the external auditors setting forth significant financial reporting issues and judgments made in connection with the preparation of the financial statements, including analyses of the effects of alternative GAAP methods on the financial statements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;e.reviewing accounting treatment of unusual or non-recurring transactions;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;f.ascertaining compliance with covenants under loan agreements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;g.reviewing disclosure requirements for commitments and contingencies;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;h.reviewing adjustments raised by the external auditors, whether or not included in the financial statements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;i.reviewing unresolved differences between management and the external auditors;

------

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;j.reviewing the type and presentation of information to be included in the Corporation's earnings press releases (paying particular attention to any use of "pro forma" or "adjusted" non-GAAP information prior to their public release);<br>

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;k.reviewing the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on the financial statements of the Corporation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;l.obtaining explanations of significant variances with comparative reporting periods; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;m.determining through inquiry if there are any related party transactions and ensuring that the nature and extent of such transactions are properly disclosed.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.The Committee is to review all public disclosure of audited or unaudited financial information by the Corporation before its release (and, if applicable, prior to its submission to the Board for approval), including the interim and annual financial statements of the Corporation, management's discussion and analysis of results of operations and financial condition, earnings press releases, the annual information form and any annual report filed with the U.S. Securities and Exchange Commission. The Committee must be satisfied that adequate procedures are in place for the review of the Corporation's disclosure of financial information and shall periodically assess the accuracy of those procedures.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.The Committee shall discuss the Corporation's earnings press releases, as well as financial information and earnings guidance provided to analysts and rating agencies, recognizing that this review and discussion may be done generally (consisting of a discussion of the types of information to be disclosed and the types of presentations to be made).

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6.With respect to the **external auditors** of the Corporation, the Committee shall:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.in its capacity as a committee of the Board, be directly responsible for the compensation, retention and oversight of the work of the external auditors (including resolution of disagreements between management and the auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the listed issuer, including the terms of their engagement for the integrated audit;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.review annually with the external auditors their plan for the audit and, upon completion of the audit, their reports upon the financial statements of the Corporation and its subsidiaries.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.review with the external auditors their assessment of the internal controls of the Corporation, their written reports containing recommendations for improvement, and management's response and follow-up to any identified weaknesses.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.meet with the external auditors at least four times per year (in connection with their review of the interim and annual financial statements) and at such other times as the external auditors and the Committee consider appropriate.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;e.review with the external auditors any problems or difficulties the external auditors may have encountered during the provision of its audit services and management's response, including any restrictions on the scope of activities or access to the requested information and any significant disagreements with management;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;f.the Committee must pre-approve all services to be provided to the Corporation or its subsidiaries by the external auditors. In pre-approving any service, the Committee shall consider the impact that the provision of such service may have on the external auditors' independence. The Committee may delegate to one or more of its members the authority to pre-approve services, provided that the member report to the Committee at the next scheduled meeting such pre-approval and the member comply with applicable laws, rules

------

and regulations and such other procedures as may be established by the Committee from time to time.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;g.when there is to be a change in the external auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;h.at least annually, review the qualifications, performance and independence of the external auditors including:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;i.review the experience and qualifications of the senior members of the external auditors' team;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;ii.confirm with the external auditors that it is in compliance with applicable legal, regulatory and professional standards relating to auditor independence;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;iii.review annual reports from the external auditors regarding its independence and consider whether there are any non-audit services or relationships that may affect the objectivity and independence of the external auditors and, if so, recommend to the Board to take appropriate action to satisfy itself of the independence of the external auditor; and obtain and review such reports from the external auditors as may be required by applicable legal and regulatory requirements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;iv.assess performance of the auditors through discussions and or surveys of management and the Board obtain and review a report by the external auditors describing the firm's internal quality-control procedures; any material issues raised by the most recent internal quality-control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps taken to deal with any such issues; and (to assess the external auditors' independence) all relationships between the external auditors and the Corporation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;v.review and evaluate the lead partner of the external auditor;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;vi.ensure the regular rotation of the lead audit partner as required by law, and consider whether, in order to assure continuing external auditor independence, there should be regular rotation of the audit firm itself. The Committee should present its conclusions with respect to the external auditors to the full Board.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;vii.review and approve the Corporation's hiring policies regarding employees and former employees of the present and former external auditors of the Corporation.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;7.Periodically review with management the need for an internal audit function.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;8.The Committee shall review the risk assessment and risk management policies and procedures of the Corporation used to identify, manage and mitigate the principle business risks facing the Corporation (as assigned to the Committee under the Corporation's Enterprise Risk Management system) which is to include reviewing with management:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.foreign currency, interest rate and commodity price risk mitigation strategies, including the use of derivative financial instruments and compliance with the Corporation's Hedging Instruments Risk Management Policy;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.credit risk;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.the insurance coverages maintained by the Corporation;

------

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.any legal claims or other contingency, including tax assessments that could have a material effect on the financial position or operation results of the Corporation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;e.the adequacy of the security measures that are in place in respect of the Corporation's information systems and the information technology utilized by the Corporation, including cyber risk.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;9.&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall establish procedures for the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by employees of the Corporation and its subsidiary entities of concerns regarding questionable accounting or auditing matters, as well as, other matters submitted through the Whistleblower program.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;10. The Committee shall have the authority to investigate any financial activity of the Corporation. All employees of the Corporation and its subsidiary entities are to cooperate as requested by the Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;11. The Committee shall report forthwith any issues arising in connection with its duties, the results of meetings and reviews undertaken and any associated recommendations to the Board.

**<u>MEETINGS AND ADMINISTRATIVE MATTERS</u>**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.At all meetings of the Committee every question shall be decided by a majority of the votes cast. In case of an equality of votes, the Chair of the meeting shall not be entitled to a second or casting vote.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.The Chair shall preside at all meetings of the Committee, unless the Chair is not present, in which case the members of the Committee present shall designate from among the members present a Chair for purposes of the meeting.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.A quorum for meetings of the Committee shall be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Committee shall be the same as those governing the Board unless otherwise determined by the Committee or the Board.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.Meetings of the Committee should be scheduled to take place at least four times per year and at such other times as the Chair may determine.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.Agendas, approved by the Chair, shall be circulated to Committee members along with background information on a timely basis prior to the Committee meetings.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6.The Committee may invite those officers, directors and employees of the Corporation and its subsidiary entities as it may see fit from time to time to attend at meetings of the Committee and assist thereat in the discussion and consideration of the matters being considered by the Committee, provided that the Chief Financial Officer of the Corporation shall attend all meetings of the Committee, unless otherwise excused from all or part of any such meeting by the Chair of the meeting.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;7.Minutes of the Committee's meetings will be recorded and maintained and made available to any director who is not a member of the Committee upon request.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;8.The Committee shall meet periodically with management and the independent auditor in separate in-camera sessions.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;9.The Committee shall conduct an annual evaluation of its performance in fulfilling its duties and responsibilities under this mandate, and shall assess the adequacy of the reporting and information provided by management to support the Committee's oversight responsibilities.

------

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;10.The Committee may retain persons having special expertise and/or obtain independent professional advice, including, without limitation, independent counsel or other advisors, as it determines necessary to carry out its duties, at the expense of the Corporation.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;11.The Corporation shall provide appropriate funding, as determined by the Committee, in its capacity as a committee of the Board, for payment of (i) compensation to any external auditors engaged for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Corporation; (ii) compensation to any advisors employed by the Committee; and (iii) ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;12.Any issues arising from the Committee's meetings that bear on the relationship between the Board and management should be communicated to the Chair of the Board or the Lead Independent Director, as applicable, by the Committee Chair.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;13.At least annually, the Committee shall, in a manner it determines to be appropriate, review and assess the adequacy of its mandate and recommend to the Board of Directors any improvements to this mandate that the Committee determines to be appropriate.

*Approved by the Board of Directors on July 25, 2024*

## Exhibit 99.2

?xml version='1.0' encoding='ASCII'? bte-20251231_d2

 **Exhibit 99.2**

**MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING**

The management of Baytex Energy Corp. (the "Company") is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision of our Chief Executive Officer and our Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on our assessment, we have concluded that as of December 31, 2025, our internal control over financial reporting was effective.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2025 has been audited by KPMG LLP, the Company's Independent Registered Public Accounting Firm, who also audited the Company's consolidated financial statements for the year ended December 31, 2025.

**MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS**

Management, in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board, has prepared the accompanying consolidated financial statements of the Company. Financial and operating information presented throughout this Annual Report is consistent with that shown in the consolidated financial statements.

Management is responsible for the integrity of the financial information. Internal control systems are designed and maintained to provide reasonable assurance that assets are safeguarded from loss or unauthorized use and to produce reliable accounting records for financial reporting purposes.

KPMG LLP were appointed by the Company's Board of Directors to express an audit opinion on the consolidated financial statements. Their examination included such tests and procedures, as they considered necessary, to provide a reasonable assurance that the consolidated financial statements are presented fairly in accordance with IFRS.

The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board of Directors exercises this responsibility through the Audit Committee, with assistance from the Reserves Committee regarding the annual review of our petroleum and natural gas reserves. The Audit Committee meets regularly with management and the Independent Registered Public Accounting Firm to ensure that management's responsibilities are properly discharged, to review the consolidated financial statements and recommend that the consolidated financial statements be presented to the Board of Directors for approval. The Audit Committee also considers the independence of KPMG LLP and reviews their fees. The Independent Registered Public Accounting Firm has access to the Audit Committee without the presence of management.

---

| | |
|:---|:---|
| *<u>/s/ Eric T. Greager</u>* | *<u>/s/ Chad L. Kalmakoff</u>* |
| Eric T. Greager | Chad L. Kalmakoff |
| Chief Executive Officer | Chief Financial Officer |
| Baytex Energy Corp. | Baytex Energy Corp. |
| March 4, 2026 | |

---

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;

------

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

To the Shareholders and Board of Directors of Baytex Energy Corp.

***Opinion on the Consolidated Financial Statements***

We have audited the accompanying consolidated statements of financial position of Baytex Energy Corp. (the Company) as of December 31, 2025 and 2024, the related consolidated statements of income (loss) and comprehensive income (loss), changes in equity, and cash flows for the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and its financial performance and its cash flows for the years then ended, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in *Internal Control – Integrated Framework (2013)* issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 4, 2026 expressed an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

***Basis for Opinion***

These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

***Critical Audit Matters***

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

***Assessment of the recoverable amount of oil and gas properties***

As discussed in note 6 to the consolidated financial statements, the Company identified indicators of impairment and indicators of impairment reversal as of December 31, 2025 related to the Company's Viking and Lloydminster cash generating units ("CGUs"), respectively. The Company therefore determined the recoverable amount as of December 31, 2025 of each of the CGUs and recorded an impairment of $148.0 million in the carrying amount of the Viking CGU. The determination of recoverable amount of a CGU involves numerous estimates, including cash flows associated with estimated proved plus probable oil and gas reserves of the CGU ("CGU reserves cash flows") and the discount rate. The estimation of CGU reserves cash flows in the reserve report involves the expertise of independent qualified reserve evaluators, who take into consideration assumptions related to forecasted production volumes, royalty obligations, operating and capital costs and commodity prices (collectively "CGU reserve report assumptions"). The Company engages independent qualified reserve evaluators to estimate CGU reserves cash flows.

We identified the assessment of the recoverable amount of the Viking and Lloydminster CGUs as a critical audit matter. Changes in CGU reserve report assumptions and discount rates could have had a significant impact on the estimate of recoverable amounts and the resulting impairment or impairment reversal in the carrying amount of oil and gas properties relating to the CGUs. A high degree of auditor judgment was required to evaluate the Company's estimates of CGU reserves cash flows, and related CGU reserve report assumptions, and the discount rates, which were inputs into the calculation of recoverable amounts. Additionally, the evaluation of these recoverable amounts required the involvement of valuation professionals with specialized skills and knowledge.

------

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the Company's determination of the recoverable amount of each of the CGUs, including the discount rate

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the Company's determination of the CGU reserve report assumptions and resulting CGU reserves cash flows.

We evaluated the competence, capabilities and objectivity of the independent qualified reserve evaluators engaged by the Company, who estimated the CGU reserves cash flows. We evaluated the methodology used by the independent qualified reserves evaluators to estimate the CGU reserves cash flows for compliance with the applicable regulatory standards. We compared the current year actual CGU production volumes, royalty obligations, operating and capital costs to those estimates used in the prior year estimate of proved reserves by CGU to assess the Company's ability to accurately forecast. We assessed the forecasted commodity prices used in the estimate of the CGU reserves cash flows by comparing them to those published by other reserve engineering companies. We assessed the forecasted production volumes, royalty obligations, operating and capital costs assumptions used in the current year estimate of the CGU reserves cash flows by comparing them to historical results.

We involved valuation professionals with specialized skills and knowledge, who assisted in:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• evaluating the Company's determination of discount rates by comparing the inputs of the discount rates against publicly available market data for comparable assets and assessing the resulting discount rates

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• evaluating the Company's estimate of recoverable amount of the CGUs by comparing to publicly available market data and valuation metrics for comparable entities.

***Impact of estimated oil and gas reserves on depletion expense related to continuing operations***

As discussed in note 3 to the consolidated financial statements, the Company depletes its oil and gas properties using the unit-of-production method by depletable area. Under such method, capitalized costs are depleted over estimated proved plus probable oil and gas reserves by depletable area ("area reserves"). As discussed in note 6 to the consolidated financial statements, the Company recorded depletion expense related to continuing operations of $480.0 million for the year ended December 31, 2025. The estimation of area reserves involves the expertise of independent qualified reserve evaluators who take into consideration assumptions related to forecasted production volumes, royalty obligations, operating and capital costs and commodity prices (collectively "area reserve report assumptions"). The Company engages independent qualified reserve evaluators to estimate area reserves.

We identified the assessment of the impact of estimated area reserves on depletion expense related to continuing operations as a critical audit matter. Changes in area reserve report assumptions could have had a significant impact on the calculation of depletion expense of the depletable area. A high degree of auditor judgment was required in evaluating the area reserves, and related area reserve report assumptions, which were used in the calculation of depletion expense.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the Company's calculation of depletion expense by depletable area

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the Company's determination of area reserve report assumptions and resulting area reserves.

We assessed the calculation of depletion expense for compliance with International Financial Reporting Standards as issued by the International Accounting Standards Board. We evaluated the competence, capabilities and objectivity of the independent qualified reserve evaluators engaged by the Company. We evaluated the methodology used by the independent qualified reserve evaluators to estimate area reserves for compliance with the applicable regulatory standards. We compared the current year actual production volumes, royalty obligations, operating and capital costs to those estimates used in the prior year estimate of proved reserves for a selection of CGUs to assess the Company's ability to accurately forecast. We assessed the forecasted commodity prices used in the estimate of area reserves by comparing them to those published by other reserves engineering companies. We assessed the forecasted production volumes, royalty obligations, operating and capital costs assumptions used in the estimate of area reserves for a selection of CGUs by comparing them to historical results.

*<u>/s/ KPMG LLP</u>*

Chartered Professional Accountants

We have served as the Company's auditor since 2016.

Calgary, Canada

March 4, 2026

------

**REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**

To the Shareholders and Board of Directors of Baytex Energy Corp.

***Opinion on Internal Control Over Financial Reporting***

We have audited Baytex Energy Corp.'s (the Company) internal control over financial reporting as of December 31, 2025, based on criteria established in *Internal Control - Integrated Framework (2013)* issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in *Internal Control - Integrated Framework (2013)* issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated statements of financial position of the Company as of December 31, 2025 and 2024, the related consolidated statements of income (loss) and comprehensive income (loss), changes in equity, and cash flows for the years then ended, and the related notes (collectively, the consolidated financial statements), and our report dated March 4, 2026 expressed an unqualified opinion on those consolidated financial statements.

***Basis for Opinion***

The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

***Definition and Limitations of Internal Control Over Financial Reporting***

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

*<u>/s/ KPMG LLP</u>*

Chartered Professional Accountants

Calgary, Canada

March 4, 2026

------

**Baytex Energy Corp.**

**Consolidated Statements of Financial Position**

*(thousands of Canadian dollars)*

---

| | | | |
|:---|:---|:---|:---|
| **As at** | Notes | **December 31, 2025** | December 31, 2024 |
| **ASSETS** |  |  |  |
| Current assets |  |  |  |
| &nbsp;&nbsp;&nbsp;Cash | 19 | $**953113** | $16610 |
| &nbsp;&nbsp;&nbsp;Trade receivables | 15, 19 | **135230** | 387266 |
| &nbsp;&nbsp;&nbsp;Prepaids and other assets |  | **35008** | 20178 |
| &nbsp;&nbsp;&nbsp;Financial derivatives | 19 | **28898** | 25573 |
| &nbsp;&nbsp;&nbsp;Assets held for sale | 4 | **38117** |  |
|  |  | **1190366** | 449627 |
| Non-current assets |  |  |  |
| &nbsp;&nbsp;&nbsp;Exploration and evaluation assets | 5 | **133585** | 124355 |
| &nbsp;&nbsp;&nbsp;Oil and gas properties | 6 | **1918435** | 6921168 |
| &nbsp;&nbsp;&nbsp;Other plant and equipment |  | **7648** | 8025 |
| &nbsp;&nbsp;&nbsp;Lease assets | 8 | **20812** | 22068 |
| &nbsp;&nbsp;&nbsp;Prepaids and other assets | 16 | **28224** | 56290 |
| &nbsp;&nbsp;&nbsp;Deferred income tax asset | 16 | **46344** | 178212 |
|  |  | $**3345414** | $7759745 |
| **LIABILITIES** |  |  |  |
| Current liabilities |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Trade payables | 19 | $**236373** | $512473 |
| &nbsp;&nbsp;&nbsp;&nbsp;Share-based compensation liability | 13 | **26108** | 18806 |
| &nbsp;&nbsp;&nbsp;&nbsp;Dividends payable | 1219 | **17268** | 17598 |
| &nbsp;&nbsp;&nbsp;&nbsp;Financial derivatives | 19 | **2406** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Liabilities related to asset held for sale | 4 | **23710** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Lease obligations | 8 | **7175** | 9193 |
| &nbsp;&nbsp;&nbsp;&nbsp;Asset retirement obligations | 11 | **17138** | 15656 |
|  |  | **330178** | 573726 |
| Non-current liabilities |  |  |  |
| &nbsp;&nbsp;&nbsp;Other long-term liabilities |  | **—** | 20887 |
| &nbsp;&nbsp;&nbsp;Share-based compensation liability | 13 | **8694** | 5926 |
| &nbsp;&nbsp;&nbsp;Financial derivatives | 19 | **—** | 1645 |
| &nbsp;&nbsp;&nbsp;Credit facilities | 9 | **1138** | 324346 |
| &nbsp;&nbsp;&nbsp;Long-term notes | 10 | **93834** | 1932890 |
| &nbsp;&nbsp;&nbsp;Lease obligations | 8 | **15844** | 15459 |
| &nbsp;&nbsp;&nbsp;Asset retirement obligations | 11 | **506677** | 625295 |
| &nbsp;&nbsp;&nbsp;Deferred income tax liability | 16 | **—** | 88561 |
|  |  | **956365** | 3588735 |
| **SHAREHOLDERS' EQUITY** |  |  |  |
| Shareholders' capital | 12 | **6072562** | 6137479 |
| Contributed surplus |  | **397681** | 361854 |
| Accumulated other comprehensive income |  | **13356** | 1093261 |
| Deficit |  | **(4094550)** | (3421584) |
|  |  | **2389049** | 4171010 |
|  |  | $**3345414** | $7759745 |

---

Subsequent events (notes 4 and 12) and Commitments and Contingencies (note 21)

See accompanying notes to the consolidated financial statements.

---

| | |
|:---|:---|
| *<u>/s/ Jennifer A. Maki</u>* | *<u>/s/ Don G. Hrap</u>* |
| Jennifer A. Maki | Don G. Hrap |
| Director, Baytex Energy Corp. | Director, Baytex Energy Corp. |

---

------

**Baytex Energy Corp.** 

**Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)**

*(thousands of Canadian dollars, except per common share amounts and weighted average common shares)* 

---

| | | | |
|:---|:---|:---|:---|
| **Years Ended December 31** | Notes | **2025** | 2024 Revised <sup>(1)</sup> |
| **Revenue, net of royalties** |  |  |  |
| &nbsp;&nbsp;Petroleum and natural gas sales | 15 | $**1684648** | $1874046 |
| &nbsp;&nbsp;Royalties |  | **(203833)** | (261205) |
|  |  | **1480815** | 1612841 |
| **Expenses** |  |  |  |
| &nbsp;&nbsp;Operating |  | **334317** | 336069 |
| &nbsp;&nbsp;Transportation |  | **83697** | 84211 |
| &nbsp;&nbsp;Blending and other |  | **234990** | 263943 |
| &nbsp;&nbsp;General and administrative |  | **67903** | 58363 |
| &nbsp;&nbsp;Transaction costs |  | **—** | 1539 |
| &nbsp;&nbsp;Exploration and evaluation | 5 | **5534** | 779 |
| &nbsp;&nbsp;Depletion and depreciation |  | **484932** | 483314 |
| &nbsp;&nbsp;Impairment | 6 | **148000** |  |
| &nbsp;&nbsp;Share-based compensation | 13 | **24041** | 11871 |
| &nbsp;&nbsp;Financing and interest | 17 | **322017** | 244951 |
| &nbsp;&nbsp;Financial derivatives loss (gain) | 19 | **17071** | (2101) |
| &nbsp;&nbsp;Foreign exchange (gain) loss | 18 | **(94019)** | 155895 |
| &nbsp;&nbsp;Gain on dispositions |  | **(2528)** | (4134) |
| &nbsp;&nbsp;Other expense (income) |  | **7970** | (5141) |
|  |  | **1633925** | 1629559 |
| **Net loss before income taxes from continuing operations** |  | **(153110)** | (16718) |
| **Income taxes** | 16 |  |  |
| &nbsp;&nbsp;Current income tax expense |  | **9721** | 17821 |
| &nbsp;&nbsp;Deferred income tax expense |  | **114014** | 62914 |
|  |  | **123735** | 80735 |
| **Net loss from continuing operations** |  | $**(276845)** | $(97453) |
| **Net (loss) income from discontinued operations** | 7 | $**(326934)** | $334050 |
| **Net (loss) income** |  | $**(603779)** | $236597 |
| **Other comprehensive (loss) income** |  |  |  |
| &nbsp;&nbsp;Foreign currency translation adjustment |  | **(213231)** | 402344 |
| &nbsp;&nbsp;Reclassification of cumulative foreign currency translation of discontinued foreign operations | 7 | **(866674)** |  |
| **Comprehensive (loss) income** |  | $**(1683684)** | $638941 |
| **Net (loss) income per common share** |  |  |  |
| &nbsp;&nbsp;Continuing operations - basic |  | $**(0.36)** | $(0.12) |
| &nbsp;&nbsp;Discontinued operations - basic |  | $**(0.43)** | $0.41 |
| &nbsp;&nbsp;Net (loss) income per share - basic |  | $**(0.78)** | $0.29 |
| &nbsp;&nbsp;Continuing operations - diluted |  | $**(0.36)** | $(0.12) |
| &nbsp;&nbsp;Discontinued operations - diluted |  | $**(0.43)** | $0.41 |
| &nbsp;&nbsp;Net (loss) income per share - diluted |  | $**(0.78)** | $0.29 |
| **Weighted average common shares** | 14 |  |  |
| &nbsp;&nbsp;Basic |  | **769180** | 803435 |
| &nbsp;&nbsp;Diluted |  | **769180** | 807711 |

---

*(1)Comparative period has been revised to reflect current period presentation. See Note 7 for additional information.* 

See accompanying notes to the consolidated financial statements.

------

**Baytex Energy Corp.** 

**Consolidated Statements of Changes in Equity** 

*(thousands of Canadian dollars)* 

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | Notes | Shareholders'<br> capital | Contributed<br> surplus | Accumulated<br> other<br> comprehensive<br> income | Deficit | **Total equity** |
| **Balance at December 31, 2023** |  | $6527289 | $193077 | $690917 | $(3586196) | $**3825087** |
| &nbsp;&nbsp;Vesting of share awards | 12 | 1167 |  |  |  | **1167** |
| &nbsp;&nbsp;Repurchase of common shares for cancellation | 12 | (390977) | 168777 |  |  | **(222200)** |
| &nbsp;&nbsp;Dividends declared | 12 |  |  |  | (71985) | **(71985)** |
| &nbsp;&nbsp;Comprehensive income |  |  |  | 402344 | 236597 | **638941** |
| **Balance at December 31, 2024** |  | $6137479 | $361854 | $1093261 | $(3421584) | $**4171010** |
| &nbsp;&nbsp;Vesting of share awards | 12 | 330 |  |  |  | **330** |
| &nbsp;&nbsp;Repurchase of common shares for cancellation | 12 | (65247) | 35827 |  |  | **(29420)** |
| &nbsp;&nbsp;Dividends declared | 12 |  |  |  | (69187) | **(69187)** |
| &nbsp;&nbsp;Comprehensive loss |  |  |  | (213231) | (603779) | **(817010)** |
| &nbsp;&nbsp;Reclassification of cumulative foreign currency translation of discontinued foreign operations | 7 |  |  | (866674) |  | **(866674)** |
| **Balance at December 31, 2025** |  | $6072562 | $397681 | $13356 | $(4094550) | $**2389049** |

---

See accompanying notes to the consolidated financial statements.

------

**Baytex Energy Corp.** 

**Consolidated Statements of Cash Flows**

*(thousands of Canadian dollars)*

---

| | | | |
|:---|:---|:---|:---|
| **Years Ended December 31** | Notes | **2025** | 2024 |
| **CASH PROVIDED BY (USED IN):** |  |  |  |
| **Operating activities** |  |  |  |
| Net (loss) income |  | $**(603779)** | $236597 |
| Adjustments for: |  |  |  |
| &nbsp;&nbsp;Unrealized foreign exchange (gain) loss | 18 | **(88538)** | 153930 |
| &nbsp;&nbsp;Exploration and evaluation | 5 | **5534** | 779 |
| &nbsp;&nbsp;Depletion and depreciation |  | **1264692** | 1385910 |
| &nbsp;&nbsp;Impairment | 6 | **148000** |  |
| &nbsp;&nbsp;Non-cash financing and accretion | 17 | **170886** | 62270 |
| &nbsp;&nbsp;Unrealized financial derivatives gain | 19 | **(2564)** | (654) |
| &nbsp;&nbsp;Loss on dispositions |  | **508080** | 1220 |
| &nbsp;&nbsp;Costs of disposal | 7 | **(26383)** |  |
| &nbsp;&nbsp;Deferred income tax expense | 16 | **112241** | 114927 |
| &nbsp;&nbsp;Asset retirement obligations settled | 11 | **(20318)** | (28793) |
| &nbsp;&nbsp;Change in non-cash working capital | 20 | **18111** | (17922) |
| Cash flows from operating activities |  | **1485962** | 1908264 |
| **Financing activities** |  |  |  |
| Decrease in credit facilities | 9 | **(334253)** | (539676) |
| Debt issuance costs |  | **(2997)** | (25023) |
| Payments on lease obligations | 8 | **(13272)** | (15510) |
| Net proceeds from issuance of long-term notes | 10 | **—** | 780936 |
| Redemption of long-term notes | 10 | **(1879806)** | (580913) |
| Repurchase of common shares | 12 | **(29420)** | (222200) |
| Dividends declared | 12 | **(69187)** | (71985) |
| Change in non-cash working capital | 20 | **(1620)** | 6200 |
| Cash flows used in financing activities |  | **(2330555)** | (668171) |
| **Investing activities** |  |  |  |
| Additions to exploration and evaluation assets | 5 | **(930)** |  |
| Additions to oil and gas properties | 6 | **(1205141)** | (1256633) |
| Additions to other plant and equipment |  | **(2281)** | (5370) |
| Additions to assets held for sale | 4 | **(38117)** |  |
| Advances received for assets held for sale | 4 | **23334** |  |
| Property acquisitions |  | **(32018)** | (52415) |
| Proceeds from dispositions, net of cash disposed |  | **3018427** | 46495 |
| Change in non-cash working capital | 20 | **17822** | (11375) |
| Cash flows from (used in) investing activities |  | **1781096** | (1279298) |
| Change in cash |  | **936503** | (39205) |
| Cash, beginning of year |  | **16610** | 55815 |
| **Cash, end of year** |  | $**953113** | $16610 |
| **Supplementary information** |  |  |  |
| Interest paid |  | $**202494** | $200218 |
| Income taxes paid |  | $**22094** | $19430 |

---

See accompanying notes to the consolidated financial statements.

------

**Baytex Energy Corp.** 

**Notes to the Consolidated Financial Statements** 

For the years ended December 31, 2025 and 2024

*(all tabular amounts in thousands of Canadian dollars, except per common share amounts)*

**1.&nbsp;&nbsp;&nbsp;&nbsp;REPORTING ENTITY**

Baytex Energy Corp. (the "Company" or "Baytex") is an energy company engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin. The Company's common shares are traded on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE. The Company's head and principal office is located at 2800, 520 – 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.

**2.&nbsp;&nbsp;&nbsp;&nbsp;BASIS OF PREPARATION**

The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board (the "IASB"). The material accounting policies set forth below were consistently applied to all periods presented.

The consolidated financial statements were approved by the Board of Directors of Baytex on March 4, 2026.

The consolidated financial statements have been prepared on a historical cost basis, with the exception of certain fair value measurements noted in the material accounting policies set forth below. The consolidated financial statements are presented in Canadian dollars which is the functional currency of the Company. References to "US$" are to United States ("U.S.") dollars. All financial information is rounded to the nearest thousand, except per share amounts or where otherwise indicated.

The Company's Canadian operations are presented herein as continuing operations and its U.S. operations have been classified and presented as discontinued operations. A segment note is no longer presented as there is only one operating segment remaining at period end. See Note 7 - "Discontinued Operations" for additional information.

**Measurement Uncertainty and Judgments**

Management makes judgments and assumptions about the future in deriving estimates used in preparation of these consolidated financial statements in accordance with IFRS. Sources of estimation uncertainty include estimates used to determine economically recoverable oil, natural gas, and natural gas liquids ("NGL") reserves, the recoverable amount of long-lived assets or cash-generating units ("CGUs"), the fair value of financial derivatives, the provision for asset retirement obligations and the provision for income taxes and the related deferred tax assets and liabilities.

The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets, liabilities, revenues and expenses. These judgments, estimates and assumptions are based on all relevant information available, including considerations related to various regulatory and legislative requirements, to the Company at the time of financial statement preparation. Actual results could be materially different from those estimates as the effect of future events cannot be determined with certainty. Revisions to estimates are recognized prospectively. The key areas of judgment or estimation uncertainty that have a significant risk of causing material adjustment to the reported amounts of assets, liabilities, revenues, and expenses are discussed below.

*Reserves*

The Company uses estimates of oil, natural gas and NGL reserves in the calculation of depletion, evaluating the recoverability of deferred income tax assets and in the estimation of recoverable amount for non-financial assets. The process to estimate reserves is complex and requires significant judgment. Estimates of the Company's reserves are evaluated annually by an independent qualified reserves evaluator and represent the estimated recoverable quantities of oil, natural gas and NGL reserves and the related cash flows. This evaluation of reserves is prepared in accordance with the reserves definition contained in National Instrument 51-101 *Standards of Disclosure for Oil and Gas Activities* and the Canadian Oil and Gas Evaluation Handbook.

Estimates of economically recoverable oil, natural gas and NGL reserves and the related cash flows are based on a number of factors and assumptions. Changes to estimates and assumptions such as forecasted commodity prices, production volumes, capital and operating costs and royalty obligations could have a significant impact on reported reserves. Other estimates include ultimate reserve recovery, marketability of oil and natural gas and other geological, economic and technical factors. Changes in the Company's reserves estimates can have a significant impact on the calculation of depletion, the recoverability of deferred income tax assets and in the estimation of recoverable amount estimates for non-financial assets.

------

*Cash-generating Units*

The Company's oil and gas properties are aggregated into CGUs which are the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. The aggregation of assets in CGUs requires management judgment and is based on geographical proximity, shared infrastructure and similar exposure to market risk.

*Identification of Impairment or Impairment Reversal Indicators*

Judgment is required to assess when indicators of impairment or impairment reversal exist and when a calculation of the recoverable amount is required. The CGUs comprising oil and gas properties are reviewed at each reporting date to assess whether there is any indication of impairment or impairment reversal. These indicators can be internal such as changes in estimated proved plus probable oil and gas reserves and internally estimated oil and gas resources, or external such as market conditions impacting discount rates or market capitalization. The assessment for each CGU considers significant changes in the forecasted cash flows including reservoir performance, the number of development locations and timing of development, forecasted commodity prices, production volumes, capital and operating costs and royalty obligations.

*Measurement of Recoverable Amounts*

If indicators of impairment or impairment reversal are determined to exist, the recoverable amount of an asset or CGU is calculated based on the higher of value-in-use ("VIU") and fair value less cost of disposal ("FVLCD"). These calculations require the use of estimates and assumptions including cash flows associated with proved plus probable oil and gas reserves and the discount rate used to present value future cash flows. Any changes to these estimates and assumptions could impact the calculation of the recoverable amount and the carrying value of assets.

*Asset Retirement Obligations*

The Company's provision for asset retirement obligations is based on estimated costs to abandon and reclaim wells and facilities, the estimated time period during which these costs will be incurred in the future, and risk-free discount rates and inflation rates derived from observable market data. The provision for asset retirement obligations represents management's best estimate of the present value of the future abandonment and reclamation costs required under current regulatory requirements. The timing of asset retirement obligation expenditures may occur earlier than estimated. The timing of asset retirement obligations is supported by externally evaluated reserves with consideration by the Company of regulatory requirements.

*Income Taxes*

Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and there are differing interpretations requiring management judgment. Income tax filings are subject to audit and re-assessment and changes in facts, circumstances and interpretations of the applicable legislative requirements may result in a material change to the Company's provision for income taxes.

**Environmental 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.

**3.&nbsp;&nbsp;&nbsp;&nbsp;MATERIAL ACCOUNTING POLICIES** 

**Consolidation**

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies to obtain benefits from its activities. Intercompany transactions are eliminated in preparation of the consolidated financial statements.

------

Many of the Company's exploration, development and production activities are conducted through jointly owned assets. The consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses generated by jointly owned assets.

**Revenue Recognition** 

Revenue from the sale of light oil and condensate, heavy oil, NGL, and natural gas is recognized based on the consideration specified in contracts with customers. Baytex recognizes revenue by unit of production and when control of the product transfers to the customer and collection is reasonably assured. This is generally at the point in time when the customer obtains legal title to the product and it is physically transferred to the customer at the agreed upon delivery point.

Contracts are evaluated based on the nature of the performance obligations, including the Company's role as either principal or agent. Where the Company acts as principal and has primary responsibility for the transaction, revenue is recognized on a gross basis. Where the Company acts as agent, revenue is recognized on a net basis.

The transaction price for variable price contracts is based on a representative commodity price index, and typically includes adjustments for quality, location, delivery method, or other factors depending on the agreed upon terms of the contract. The amount of revenue recorded varies depending on the grade, quality and quantities of oil or natural gas transferred to customers. Market conditions, which impact the Company's ability to negotiate certain components of the transaction price, can also cause the amount of revenue recorded to fluctuate from period to period.

Pipeline tariffs, tolls and fees charged to other entities for the use of pipelines and facilities owned by Baytex are evaluated by management to determine if these originate from contracts with customers or from incidental or collaborative arrangements. Pipeline tariffs, tolls and fees charged to other entities that are from contracts with customers are recognized in revenue when the related services are provided.

**Exploration and Evaluation ("E&E") Assets** 

Once the legal right to explore has been acquired, costs directly associated with an exploration program are capitalized as E&E assets until results of the exploration program have been evaluated. Costs capitalized as E&E assets include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing of initial production results.

E&E expenditures are costs incurred in an area where technical feasibility and commercial viability has not yet been determined. The technical feasibility and commercial viability is dependent on whether extracting petroleum and natural gas resources is demonstrable. If the asset is determined not to be technically feasible or commercially viable the accumulated E&E assets associated with the exploration project are charged to E&E expense in the period the determination is made.

Upon determination of technical feasibility and commercial viability, as evidenced by demonstrating the ability to extract mineral resources and management's intention to develop the E&E asset, the accumulated costs associated with the exploration project are tested for impairment and transferred to oil and gas properties.

**Oil and Gas Properties**

Oil and gas properties are initially recorded at cost and include the costs to acquire, develop, complete geological and geophysical surveys, drill and complete wells for production, and construct and install infrastructure including wellhead equipment and processing facilities.

Oil and gas properties includes costs related to planned major inspection, overhaul and turnaround activities to maintain items of oil and gas properties and benefit future years of operations. Replacements outside of a major inspection, overhaul or turnaround are recognized as oil and gas properties when it is probable the economic benefits of the replacement will be realized by the Company in the future. The carrying amount of any replaced or disposed item of oil and gas properties is derecognized. Repair and maintenance costs incurred for servicing an item of oil and gas properties is recorded as operating expense as incurred.

**Depletion**

The costs associated with oil and gas properties are depleted on a unit-of-production basis by depletable area over proved plus probable reserves once commercial production has commenced. Forecasted capital costs required to bring proved plus probable reserves into production are included in the depletable base. For purposes of the depletion calculation, petroleum and natural gas reserves are converted to a common unit of measurement on the basis of their relative energy content where six thousand cubic feet of natural gas equates to one barrel of oil equivalent.

------

**Impairment or Impairment Reversal**

*Non-financial Assets*

The Company reviews its oil and gas properties and E&E assets at a CGU level for indicators of impairment or impairment reversal at the end of each reporting period. E&E assets are also assessed for impairment upon transfer to oil and gas properties. The recoverable amount of the asset is estimated if indicators of impairment or impairment reversal exist.

When reviewing for indicators of impairment or impairment reversal, and testing for impairment or impairment reversal when indicators have been identified, assets are grouped together at a CGU level. The recoverable amount of an asset or CGU is the higher of its FVLCD and its VIU. The determination of recoverable amount includes estimates of proved plus probable oil and gas reserves and the associated cash flows. Factors that impact these cash flows include forecasted CGU production volumes, royalty obligations, operating costs, capital costs, commodity prices, taxes, along with inflation and discount rates used to estimate present value. FVLCD is the amount that would be obtained from the sale of an asset or CGU in an arm's length transaction. In determining FVLCD, recent comparable market transactions are considered if available. In the absence of such transactions, an appropriate valuation model is used. VIU is assessed using the present value of the estimated future cash flows of the asset or CGU. The estimated future cash flows are adjusted for risks specific to the asset or CGU and are discounted using a discount rate based on the Company's weighted average cost of capital adjusted for risks specific to the CGU.

Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. The impairment reduces the carrying amount of the individual assets in the CGU on a pro-rata basis.

Impairments may be reversed for all CGUs and individual assets when there is indication that a previously recognized impairment may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. An impairment may be reversed only to the extent that the CGU's revised carrying amount does not exceed the carrying amount that would have been determined, net of depreciation and depletion, had no impairment been recognized.

Impairments and impairment reversals are recorded in net income or loss in the period the impairment or impairment reversal occurs.

**Leases** 

A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. A lease obligation and corresponding right-of-use asset ("lease asset") are recognized at the commencement of the lease. The present value of the lease obligation is based on the future lease payments and is discounted using the Company's incremental borrowing rate when the rate implicit in the lease is not readily available. The Company uses a single discount rate for a portfolio of leases with similar characteristics. The lease asset is recognized at the amount of the lease obligation, adjusted for lease incentives received and initial direct costs, on commencement of the lease. Depreciation is recognized on the lease asset over the shorter of the estimated useful life of the asset or the lease term.

Lease payments are allocated between the liability and interest expense. Interest expense is recognized on the lease obligations using the effective interest rate method and payments are applied against the lease obligation.

**Asset Retirement Obligations**

The Company recognizes asset retirement obligations when it has a legal or constructive obligation as a result of past events, it is probable that an outflow of economic resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. The Company's asset retirement obligations are based on its net ownership in wells and facilities. Management estimates the costs to abandon and reclaim the wells and facilities using existing technology and the estimated time period during which these costs will be incurred in the future.

Asset retirement obligations are recognized for future asset retirement costs associated with the abandonment and reclamation of the Company's E&E assets and oil and gas properties. Asset retirement obligations are measured at the present value of management's best estimate of the future cash flows required to settle the present obligation, discounted using the risk-free rate. The present value of the liability is capitalized as part of the cost of the related asset and depleted over its useful life. The asset retirement obligation is accreted until the date of expected settlement of the retirement obligation and is recognized within financing and interest expense in net income or loss. Changes in the future cash flow estimates resulting from revisions to the estimated timing or amount of undiscounted cash flows or the discount rates are recognized as changes in the asset retirement obligation provision and related asset at each reporting date.

------

**Foreign Currency Translation**

*Foreign Transactions*

Transactions in foreign currencies are translated to Canadian dollars at the exchange rates prevailing at the time of the transactions. Foreign currency assets and liabilities are translated to Canadian dollars at the period-end exchange rate and revenue and expenses are translated to Canadian dollars using the average exchange rate for the period. Realized and unrealized gains and losses resulting from the settlement or translation of foreign currency transactions are included in net income or loss.

*Foreign Operations*

The Company had U.S operations owned via U.S. subsidiaries. The assets and liabilities of foreign operations are translated to Canadian dollars at exchange rates in effect at the period-end exchange rate. Revenue and expenses of foreign operations are translated to Canadian dollars using the average exchange rate for the period. Foreign exchange differences are included in other comprehensive income or loss. The cumulative foreign currency translation differences are reclassified from shareholders' equity to net income or loss upon discontinuation of the foreign operations.

**Financial Instruments**

Financial assets are initially classified into two categories: measured at amortized cost or fair value through profit or loss ("FVTPL").

The measurement category for each class of financial asset and financial liability is set forth in the following table.

---

| | |
|:---|:---|
| **Financial Instrument** | **Classification** |
| Cash | Amortized cost |
| Trade receivables | Amortized cost |
| Financial derivatives | Fair value through profit or loss |
| Trade payables | Amortized cost |
| Dividends payable | Amortized cost |
| Credit facilities | Amortized cost |
| Long-term notes | Amortized cost |

---

Debt issuance costs related to the amendment of the Company's credit facilities or the issuance of long-term notes are capitalized and amortized as financing costs over the term of the credit facilities or long-term notes. For a financial asset or a financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to, or deducted from, the fair value on initial recognition and amortized through net income or loss over the term of the financial instrument. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or a financial liability classified as FVTPL are expensed at inception of the contract.

The Company formally documents its risk management objectives and strategies to manage exposures to fluctuations in commodity prices, interest rates and foreign currency exchange rates. The Company has not designated its financial derivative contracts as effective accounting hedges, and therefore has not applied hedge accounting. As a result, the Company applies the fair value method of accounting for all derivative instruments. The fair values of these instruments are based on quoted market prices or, in their absence, third-party market indications and forecasts. Attributable transaction costs are recognized in net income or loss when incurred.

The Company accounts for its physical delivery sales contracts as executory contracts. These contracts are entered into and held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements. As such, these contracts are not considered to be derivative financial instruments and are not recorded at fair value on the statements of financial position. Settlements on these physical delivery sales contracts are recognized in revenue in the period the product is delivered to the sales point.

**Income Taxes** 

Current and deferred income taxes are recognized in net income or loss, except when they relate to items that are recognized directly in equity, in which case the current and deferred taxes are also recognized directly in equity.

------

Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates enacted at the end of the reporting period. The Company recognizes the financial statement impact of a tax filing position when it is probable that the position will be upheld. The asset or liability is measured based on an assessment of probable outcomes and their associated probabilities.

The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and the corresponding tax basis used in the computation of taxable income. Deferred income tax liabilities are generally recognized for all taxable temporary differences. Deferred income tax assets are recognized for all deductible temporary differences to the extent future recovery is probable. The carrying amount of deferred income tax assets is reviewed at the end of each reporting period and reduced or increased to the extent that it is no longer probable or becomes probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. Deferred income taxes are calculated using enacted or substantively enacted tax rates. Deferred income tax balances are adjusted for any changes in the enacted or substantively enacted tax rates and the adjustment is recognized in the period that the rate change occurs.

Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and there are differing interpretations requiring management judgment. Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in future periods, which requires management judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future periods, which requires management judgment. Income tax filings are subject to audit and re-assessment and changes in facts, circumstances and interpretations of the standards may result in a material change to the Company's provision for income taxes.

**Assets Held for Sale**

Assets are classified as held for sale if it is highly probable their carrying amounts will be recovered through a sale rather than through future operating cash flows. This conditions is met when the sale is highly probable and the asset is available for immediate sale in its present condition. Immediately before the assets are classified as held for sale, they are assessed for indicators of impairment or reversal of impairment and are measured at the lower of their carrying amount and fair value less costs of disposal. Any impairment charges are recognized in net income or loss. Assets held for sale and their associated liabilities are classified as current assets and any liabilities associated with assets held for sale are classified as current liabilities.

**Future Accounting Pronouncements**

IFRS 18 *Presentation and Disclosure in Financial Statements* was issued in April 2024 and replaces IAS 1 *Presentation of Financial Statements*. The Standard introduces a more defined structure to the statements of income or loss and comprehensive income or loss, including new categories of income and expenses, defined subtotals, and required disclosure of management-defined performance measures. The Standard is required to be adopted retrospectively and is effective for fiscal years beginning on or after January 1, 2027, with early adoption permitted. The Company is evaluating the impact that this standard will have on the consolidated financial statements.

IFRS 9 *Financial Instruments* and IFRS 7 *Financial Instruments: Disclosures* were amended in May 2024 to clarify the date of recognition and derecognition of financial assets and liabilities. The amendments are effective for fiscal years beginning on or after January 1, 2026, and the Company has determined that the impact from this amendment is immaterial.

**4.&nbsp;&nbsp;&nbsp;&nbsp;ASSETS HELD FOR SALE**

In March 2025, Gibson Energy Inc. ("Gibson") and Baytex entered into a 15-year take-or-pay agreement under which Baytex constructed certain oil and gas infrastructure funded by Gibson over the period of construction. As at December 31, 2025, construction was complete, with $38.1 million of construction costs incurred, $23.3 million of advances received from Gibson and $0.4 million of construction payables outstanding. The oil and gas infrastructure assets were classified as assets held for sale at December 31, 2025 at their carrying value, which is equivalent to the fair value less costs to sell.

In February 2026, ownership transferred to Gibson upon completion and acceptance in accordance with the Construction and Conveyance Agreement. No gain or loss was recognized on transfer as the assets were sold at cost.

------

**5.&nbsp;&nbsp;&nbsp;&nbsp;EXPLORATION AND EVALUATION ASSETS**

---

| | | |
|:---|:---|:---|
| | **December 31, 2025** | December 31, 2024 |
| **Balance, beginning of year** | $**124355** | $90919 |
| &nbsp;&nbsp;Capital expenditures | **930** |  |
| &nbsp;&nbsp;Property acquisitions | **34148** | 39355 |
| &nbsp;&nbsp;Divestitures | **(8577)** | (2009) |
| &nbsp;&nbsp;Exploration and evaluation expense | **(5534)** | (779) |
| &nbsp;&nbsp;Transfers to oil and gas properties (note 6) | **(11737)** | (3131) |
| **Balance, end of year** | $**133585** | $124355 |

---

At December 31, 2024 and 2025, the Company assessed its 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 its CGUs.

**6.&nbsp;&nbsp;&nbsp;&nbsp;OIL AND GAS PROPERTIES**

---

| | | | |
|:---|:---|:---|:---|
| | **Cost** | **Accumulated<br> depletion** | **Net book value** |
| **Balance, December 31, 2023** | $**15526017** | $**(8906984)** | $**6619033** |
| &nbsp;&nbsp;&nbsp;Capital expenditures | 1256633 |  | 1256633 |
| &nbsp;&nbsp;&nbsp;Property acquisitions | 16437 |  | 16437 |
| &nbsp;&nbsp;&nbsp;Transfers from exploration and evaluation assets (note 5) | 3131 |  | 3131 |
| &nbsp;&nbsp;&nbsp;Transfers from lease assets (note 8) | 8210 |  | 8210 |
| &nbsp;&nbsp;&nbsp;Change in asset retirement obligations (note 11) | 25253 |  | 25253 |
| &nbsp;&nbsp;&nbsp;Divestitures | (187103) | 135742 | (51361) |
| &nbsp;&nbsp;&nbsp;Foreign currency translation | 794766 | (378871) | 415895 |
| &nbsp;&nbsp;&nbsp;Depletion |  | (1372063) | (1372063) |
| **Balance, December 31, 2024** | $**17443344** | $**(10522176)** | $**6921168** |
| &nbsp;&nbsp;&nbsp;Capital expenditures | 1205141 |  | 1205141 |
| &nbsp;&nbsp;&nbsp;Property acquisitions | 2147 |  | 2147 |
| &nbsp;&nbsp;&nbsp;Transfers from exploration and evaluation assets (note 5) | 11737 |  | 11737 |
| &nbsp;&nbsp;&nbsp;Change in asset retirement obligations (note 11) | (11311) |  | (11311) |
| &nbsp;&nbsp;&nbsp;Divestitures (note 7) | (10838470) | 6250607 | (4587863) |
| &nbsp;&nbsp;&nbsp;Impairment loss |  | (148000) | (148000) |
| &nbsp;&nbsp;&nbsp;Foreign currency translation | (450006) | 230586 | (219420) |
| &nbsp;&nbsp;Depletion <sup>(1)</sup> |  | (1255164) | (1255164) |
| **Balance, December 31, 2025** | $**7362582** | $**(5444147)** | $**1918435** |

---

*(1)Inclusive of depletion expense related to continuing operations of $480.0 million (2024 - $473.8 million) and discontinued operations $775.1 million (2024 - $898.3 million).* 

At December 31, 2025, the Company assessed its oil and gas properties for indicators of impairment or impairment reversal and concluded that the estimation of recoverable amount was not required for three of five CGUs. The Company identified indicators of impairment for oil and gas properties in its Viking CGU due to negative technical revisions in proved plus probable reserves. The recoverable amount for the Viking CGU was not sufficient to support its carrying value which resulted in an impairment of $148.0 million recorded at December 31, 2025. The Company identified indicators of impairment reversal for oil and gas properties in its Lloydminster CGU due to a decrease in the asset-specific discount rate. The recoverable amount for the Lloydminster CGU supports its carrying value and no impairment reversal was recorded at December 31, 2025. The recoverable amount is based on a fair value less costs of disposal model using estimated cash flows associated with proved plus probable reserves from an independent reserve report prepared as at December 31, 2025 utilizing a discount rate based on Baytex's corporate weighted average cost of capital adjusted for asset specific factors. The after-tax discount rates applied to the cash flows were between 12% and 14%.

------

At December 31, 2025, the recoverable amount of the Viking and Lloydminster CGUs were calculated using the following benchmark reference prices for the years 2026 to 2035 adjusted for commodity differentials specific to the CGUs. The prices and costs subsequent to 2035 have been adjusted for inflation at an annual rate of 2.0%.

---

| | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | 2026 | 2027 | 2028 | 2029 | 2030 | 2031 | 2032 | 2033 | 2034 | 2035 |
| WTI crude oil (US$/bbl) | 59.92 | 65.10 | 70.28 | 71.93 | 73.37 | 74.84 | 76.34 | 77.87 | 79.42 | 81.01 |
| WCS heavy oil ($/bbl) | 65.13 | 70.43 | 76.90 | 78.71 | 80.29 | 81.90 | 83.53 | 85.20 | 86.91 | 88.65 |
| Edmonton par oil ($/bbl) | 77.54 | 83.60 | 90.17 | 92.32 | 94.17 | 96.06 | 97.98 | 99.93 | 101.93 | 103.97 |
| AECO gas ($/mmbtu) | 3.00 | 3.30 | 3.49 | 3.58 | 3.65 | 3.72 | 3.80 | 3.88 | 3.95 | 4.03 |

---

The following table demonstrates the sensitivity of the estimated recoverable amount of the Lloydminster and Viking CGUs to reasonably possible changes in key assumptions inherent in the calculation.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Recoverable amount | Impairment loss (reversal) | Change in discount rate of 1% | Change in oil price of $2.50/bbl | Change in gas price of $0.25/mcf |
| Lloydminster CGU | $327216 | $— | $27250 | $82500 | $500 |
| Viking CGU | 407201 | 148000 | 19000 | 45500 | 3500 |

---

At December 31, 2024, the Company assessed its oil and gas properties for indicators of impairment or impairment reversal and concluded that the estimation of recoverable amount was not required for any of its CGUs.

------

**7.&nbsp;&nbsp;&nbsp;&nbsp;DISCONTINUED OPERATIONS**

On December 19, 2025, the Company completed the disposition of the operated and non-operated assets in its Eagle Ford CGUs. The Eagle Ford CGUs represent a geographical area of the Company's operations, therefore, its results have been classified as discontinued operations in accordance with IFRS 5 *Non-current Assets Held for Sale and Discontinued Operations*. Upon disposition of the Company's U.S. operations, the cumulative foreign currency translation recognized in accumulated other comprehensive income of $866.7 million was reclassified from shareholders' equity to net income or loss.

The following table summarizes the Company's financial results from discontinued operations:

---

| | | |
|:---|:---|:---|
| **Years Ended December 31** | **2025** | 2024 |
| **Revenue, net of royalties** |  |  |
| Petroleum and natural gas sales | $**1888524** | $2334909 |
| Royalties | **(508305)** | (618881) |
|  | **1380219** | 1716028 |
| **Expenses** |  |  |
| Operating | **292424** | 317880 |
| Transportation | **45683** | 48931 |
| General and administrative | **35622** | 23383 |
| Depletion and depreciation | **779760** | 902596 |
| Share-based compensation | **9268** | 6001 |
| Financing and interest | **22985** | 23423 |
| Foreign exchange gain | **(3624)** |  |
| Loss on dispositions | **—** | 5354 |
| Other income | **(4061)** | (1548) |
|  | **1178057** | 1326020 |
| **Net income before income taxes - operations** | **202162** | 390008 |
| **Income taxes - operations** |  |  |
| Current income tax (recovery) expense - operations | **(8485)** | 3945 |
| Deferred income tax (recovery) expense - operations | **(1773)** | 52013 |
|  | **(10258)** | 55958 |
| **Net income - operations** | $**212420** | $334050 |
| Loss on disposition after tax | **(539354)** |  |
| **Net (loss) income - discontinued operations** | $**(326934)** | $334050 |

---

------

---

| | | |
|:---|:---|:---|
| | **USD** | **CAD** <sup>(1)</sup> |
| **Consideration** | | |
| Total cash consideration received | $2188322 | $3011897 |
| Costs to sell | (19169) | (26383) |
| Net consideration received | $**2169153** | $**2985514** |
| **Net assets disposed** |  |  |
| Oil and gas properties | $(3320890) | $(4570708) |
| Cash | (3543) | (4876) |
| Working capital <sup>(2)</sup> | 35817 | 49299 |
| Lease assets | (6372) | (8771) |
| Lease obligations | 6983 | 9611 |
| Asset retirement obligations | 65698 | 90424 |
| Deferred income tax liability | 52476 | 72225 |
| Carrying value of net assets disposed | $**(3169831)** | $**(4362796)** |
| Loss on disposition before reclassification of foreign currency translation | (1000678) | (1377282) |
| Current income tax expense - disposition | (20758) | (28746) |
| Reclassification of cumulative foreign currency translation of discontinued foreign operations |  | 866674 |
| Loss on disposition after tax | $**(1021436)** | $**(539354)** |

---

*(1)Exchange rate used to translate the U.S. denominated values above is the rate as at the closing date being CAD/USD 1.37635.*

*(2)Working capital includes $193.8 million (US$140.8 million) of trade receivables, $4.7 million (US$3.4 million) of prepaids and other assets, and $247.8 million (US$180.1 million) of trade payables and share-based compensation liability.*

The following table summarizes cash flows from discontinued operations reported in the consolidated statements of cash flows:

---

| | | |
|:---|:---|:---|
| **Years Ended December 31** | **2025** | 2024 |
| **Cash provided by (used in) discontinued operations:** |  |  |
| &nbsp;&nbsp;Operating activities | $**940645** | $1280427 |
| &nbsp;&nbsp;Financing activities | **(207371)** | (85592) |
| &nbsp;&nbsp;Investing activities | **2371215** | (787098) |
| **Increase in cash from discontinued operations** | $**3104489** | $407737 |

---

------

**8.&nbsp;&nbsp;&nbsp;&nbsp;LEASES**

**Lease Assets**

Baytex had the following right-of-use assets:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Office Leases** | **Field Equipment** | **Vehicles and Other** | **Total** |
| **Balance, December 31, 2023** | $**15226** | $**12029** | $**890** | $**28145** |
| &nbsp;&nbsp;Additions | 157 | 7290 | 423 | 7870 |
| &nbsp;&nbsp;Modifications |  | 1752 | 267 | 2019 |
| &nbsp;&nbsp;Depreciation | (2650) | (5093) | (850) | (8593) |
| &nbsp;&nbsp;Transfers to oil and gas properties (note 6) |  | (8210) |  | (8210) |
| &nbsp;&nbsp;Foreign currency translation | 358 | 475 | 4 | 837 |
| **Balance, December 31, 2024** | $**13091** | $**8243** | $**734** | $**22068** |
| &nbsp;&nbsp;Additions | 106 | 17918 | 1052 | 19076 |
| &nbsp;&nbsp;Dispositions | (2896) | (5865) | (8) | (8769) |
| &nbsp;&nbsp;Modifications | (1904) | 4579 | (68) | 2607 |
| &nbsp;&nbsp;Depreciation | (2393) | (10642) | (760) | (13795) |
| &nbsp;&nbsp;Foreign currency translation | (159) | (216) |  | (375) |
| **Balance, December 31, 2025** | $**5845** | $**14017** | $**950** | $**20812** |

---

**Lease Obligations**

Baytex had the following future commitments associated with its lease obligations:

---

| | | |
|:---|:---|:---|
| | **December 31, 2025** | December 31, 2024 |
| Less than 1 year | $**8487** | $10788 |
| 1 - 3 years | **10690** | 9175 |
| 3 - 5 years | **7097** | 7200 |
| After 5 years | **—** | 1928 |
| Total lease payments | $**26274** | $29091 |
| Amounts representing interest over the term of the lease | **(3255)** | (4439) |
| Present value of net lease payments | $**23019** | $24652 |
| Less current portion of lease obligations | **7175** | 9193 |
| Non-current portion of lease obligations | $**15844** | $15459 |

---

The Company recorded interest expense related to its lease obligations of $1.3 million and recorded lease payments, excluding interest, of $13.3 million for the year ended December 31, 2025 ($1.3 million and $15.5 million, respectively for the year ended December 31, 2024).

**9.&nbsp;&nbsp;&nbsp;&nbsp;CREDIT FACILITIES**

---

| | | |
|:---|:---|:---|
| | **December 31, 2025** | December 31, 2024 |
| Credit facilities - U.S. dollar denominated <sup>(1)</sup> | $**1400** | $206826 |
| Credit facilities - Canadian dollar denominated | **—** | 134381 |
| Credit facilities - principal <sup>(2)</sup> | $**1400** | $341207 |
| Unamortized debt issuance costs | **(262)** | (16861) |
| Credit facilities | $**1138** | $324346 |

---

*(1)U.S. dollar denominated credit facilities balance was US$1.0 million as at December 31, 2025 (December 31, 2024 - US$143.6 million).*

*(2)The decrease in the principal amount of the credit facilities outstanding from December 31, 2024 to December 31, 2025 is the result of net repayments of $334.3 million and a decrease in the reported amount of U.S. denominated debt of $5.6 million due to foreign exchange.*

------

On December 19, 2025, concurrent with the closing of the Eagle Ford asset sale, Baytex modified its credit facilities (the "Credit Facilities") to decrease the committed amount to $750 million from US$1.1 billion and extend its maturity to June 27, 2030 from June 27, 2029. There were no changes to the financial covenants as a result of the modification. The Credit Facilities modification was considered significant and the related debt issuance costs were written off to financing and interest in the period.

At December 31, 2025, Baytex had $750 million of revolving credit facilities that mature on June 27, 2030. The Credit Facilities are secured and are comprised of a $50 million operating loan and a $700 million syndicated revolving loan.

The Credit Facilities contain standard commercial covenants, in addition to the financial covenants detailed below, related to debt incurrence, restricted payments, certain transactions and compliance with applicable laws. Noncompliance with these covenants may result in an event of default, at which point the carrying value of the debt could become repayable within a 12-month period after the reporting date. Baytex continues to be in compliance with all financial and commercial covenants under its debt agreements.

Advances under the Baytex Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank's prime lending rate, Canadian Overnight Repo Rate Average rates or Secured Overnight Financing Rates, plus applicable margins.

The weighted average interest rate on the Credit Facilities was 6.7% for the year ended December 31, 2025 (7.6% for the year ended December 31, 2024).

The following table summarizes the financial covenants applicable to the Credit Facilities and the Company's compliance therewith at December 31, 2025.

---

| | | |
|:---|:---|:---|
| **Covenant Description** | **Position as at December 31, 2025** | **Covenant** |
| Senior Secured Debt <sup>(1)</sup> to Bank EBITDA <sup>(2)</sup> (Maximum Ratio) | **0.0:1.0** | 3.5:1.0 |
| Interest Coverage <sup>(3)</sup> (Minimum Ratio) | **4.4:1.0** | 3.5:1.0 |
| Total Debt <sup>(4)</sup> to Bank EBITDA <sup>(2)</sup> (Maximum Ratio) | **0.1:1.0** | 4.0:1.0 |

---

*(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreement and is defined as the principal amount of the Credit Facilities and other secured obligations identified in the credit facility agreement. As at December 31, 2025, the Company's Senior Secured Debt totaled $5.8 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 dispositions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the year ended December 31, 2025 was $712.4 million.*

*(3)"Interest coverage" is calculated in accordance with the credit facility agreement and is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis including the impact of material dispositions as if they had occurred at the beginning of the twelve month period. Financing and interest expenses for the year ended December 31, 2025 was $160.1 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 December 31, 2025, the Company's Total Debt totaled $101.7 million of principal amounts outstanding.*

At December 31, 2025, Baytex had $4.4 million of outstanding letters of credit (December 31, 2024 - $5.8 million outstanding).

------

**10.&nbsp;&nbsp;&nbsp;&nbsp;LONG-TERM NOTES** 

---

| | | |
|:---|:---|:---|
| | **December 31, 2025** | December 31, 2024 |
| 8.50% notes due April 30, 2030 <sup>(1)</sup> | $**—** | $1152360 |
| 7.375% notes due March 15, 2032 <sup>(2)</sup> | **95947** | 828259 |
| Total long-term notes - principal <sup>(3)</sup> | $**95947** | $1980619 |
| Unamortized debt issuance costs | **(2113)** | (47729) |
| Total long-term notes - net of unamortized debt issuance costs | $**93834** | $1932890 |

---

*(1)The 8.50% notes were fully repaid on December 22, 2025. The U.S. dollar denominated principal outstanding of the 8.50% notes was US$800.0 million as at December 31, 2024.*

*(2)The U.S. dollar denominated principal outstanding of the 7.375% notes was US$70.0 million as at December 31, 2025 (December 31, 2024 - US$575.0 million).*

*(3)The decrease in the principal amount of long-term notes outstanding from December 31, 2024 to December 31, 2025 is the result of the repurchase and cancellation of US$1.3 billion ($1.8 billion) and changes in the reported amount of U.S. denominated debt of $90.2 million due to changes in the CAD/USD exchange rate used to translate the U.S. denominated amount of long-term notes outstanding.*

During the year ended December 31, 2025, Baytex repurchased and cancelled US$800.0 million principal amount of the 8.50% Senior Notes at 105.205% of par value and US$505.0 million principal amount of the 7.375% Senior Notes at 103.807% of par value and recorded an early redemption expense of $85.4 million.

On April 1, 2024, Baytex closed a private offering of the US$575.0 million aggregate principal amount of senior unsecured notes due 2032 ("7.375% Senior Notes"), of which US$70.0 million is outstanding as of December 31, 2025. The 7.375% Senior Notes were priced at 99.266% of par to yield 7.500% per annum, bear interest at a rate of 7.375% per annum and mature on March 15, 2032. 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 2024, Baytex recorded early redemption expense of $24.4 million which is the call premium paid on the redemption of the 8.75% Senior Notes.

The long-term notes do not contain any significant financial maintenance covenants but do contain standard commercial covenants for debt incurrence, restricted payments, certain transactions and compliance with applicable laws. Noncompliance with these covenants may result in an event of default, at which point the carrying value of the debt could become repayable within a 12 month period after the reporting date. These standard commercial covenants do not prohibit the incurrence of indebtedness under the Credit Facilities, as long as the total debt incurred, including the Credit Facilities, does not exceed a specified threshold. Baytex continues to be in compliance with all financial and commercial covenants under its debt agreements.

**11.&nbsp;&nbsp;&nbsp;&nbsp;ASSET RETIREMENT OBLIGATIONS**

---

| | | |
|:---|:---|:---|
| | **December 31, 2025** | December 31, 2024 |
| **Balance, beginning of year** | $**640951** | $623399 |
| &nbsp;&nbsp;Liabilities incurred <sup>(1)</sup> | **20794** | 32635 |
| &nbsp;&nbsp;&nbsp;Liabilities settled | **(20318)** | (28793) |
| &nbsp;&nbsp;&nbsp;Liabilities acquired from property acquisitions | **—** | 814 |
| &nbsp;&nbsp;&nbsp;Liabilities divested (note 7) | **(104223)** | (9482) |
| &nbsp;&nbsp;&nbsp;Accretion | **23012** | 21226 |
| &nbsp;&nbsp;Change in estimate <sup>(1)</sup> | **(7442)** | 10113 |
| &nbsp;&nbsp;Changes in discount rates and inflation rates <sup>(1)(2)</sup> | **(24663)** | (17495) |
| &nbsp;&nbsp;&nbsp;Foreign currency translation | **(4296)** | 8534 |
| **Balance, end of year** | $**523815** | $640951 |
| Less current portion of asset retirement obligations | **17138** | 15656 |
| Non-current portion of asset retirement obligations | $**506677** | $625295 |

---

*(1)The total of these items reflects the total change in asset retirement obligations of $11.3 million per Note 6 - Oil and Gas Properties ($25.3 million increase in 2024).*

*(1)The discount and inflation rates used to calculate the liability at December 31, 2025 were 3.9% and 2.0% respectively (December 31, 2024 - 3.3% and 1.8%). The discount and inflation rates used prior to the closing of the sale of our U.S. operations on December 19, 2025 were 4.8% and 2.3%, respectively (December 31, 2024 - 4.0% and 2.3%).*

------

At December 31, 2025, the undiscounted, uninflated amount of estimated cash flows required to settle the asset retirement obligations is $674.9 million (December 31, 2024 - $845.0 million). At December 31, 2025, the undiscounted, inflated amount of estimated cash flows required to settle the asset retirement obligations is $915.0 million (December 31, 2024 - $1.2 billion). The discounted amount of estimated cash flow required to settle the asset retirement obligations at December 31, 2025 is $523.8 million (December 31, 2024 - $641.0 million), with expenditures expected to be incurred over the next 52 years. The estimated timing of these cash flows is summarized in the following table.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Total** | 2026-2030 | 2031-2035 | 2036-2040 | 2041 and beyond |
| Asset retirement obligations | $**523815** | $83024 | $151350 | $107635 | $181806 |

---

**12.&nbsp;&nbsp;&nbsp;&nbsp;SHAREHOLDERS' CAPITAL**

The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10.0 million preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. As at December 31, 2025, no preferred shares have been issued by the Company and all common shares issued were fully paid. The holders of common shares may receive dividends as declared from time to time and are entitled to one vote per share at any meeting of the holders of common shares. All common shares rank equally with regard to the Company's net assets in the event the Company is wound-up or terminated.

---

| | | |
|:---|:---|:---|
|  | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Number of Common Shares<br>*(000s)* | Amount |
| **Balance, December 31, 2023** | **821681** | $**6527289** |
| &nbsp;&nbsp;&nbsp;Vesting of share awards | 272 | 1167 |
| &nbsp;&nbsp;&nbsp;Common shares repurchased and cancelled | (48363) | (390977) |
| **Balance, December 31, 2024** | **773590** | $**6137479** |
| &nbsp;&nbsp;&nbsp;Vesting of share awards | 112 | 330 |
| &nbsp;&nbsp;&nbsp;Common shares repurchased and cancelled | (8134) | (65247) |
| **Balance, December 31, 2025** | **765568** | $**6072562** |

---

**Normal Course Issuer Bid ("NCIB") Share Repurchases**

On June 24, 2025, Baytex announced that the TSX accepted the renewal of the NCIB under which Baytex is 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 the Company's public float, as defined by the TSX, as at June 18, 2025. Baytex obtained an exemption order from the Canadian securities regulators which permits the company to purchase its common shares through the NYSE and other U.S.-based trading systems. On June 18, 2025, Baytex had 768.3 million common shares outstanding.

During the year ended December 31, 2025, Baytex recorded $29.4 million related to common share repurchases, which includes $28.9 million of consideration paid for the repurchase and cancellation of common shares as well as $0.5 million of federal tax levied on equity repurchases.

Purchases are made on the open market at prices prevailing at the time of the transaction. During the year ended December 31, 2025, Baytex repurchased and cancelled 8.1 million common shares at an average price of $3.55 per share for total consideration of $28.9 million. During 2024, Baytex repurchased and cancelled 48.4 million common shares at an average price of $4.50 per share for total consideration of $217.9 million. The total consideration paid includes the commissions and fees paid as part of the transaction and is recorded as a reduction to shareholders' equity. The shares repurchased and cancelled are accounted for as a reduction in shareholders' capital at historical cost, with any discount paid recorded to contributed surplus and any premium paid recorded to retained earnings.

During the year ended December 31, 2025, Baytex recorded a $0.5 million liability related to the 2% federal tax on equity repurchases (December 31, 2024 - $4.3 million), which is charged to shareholders' capital.

------

**Dividends**

The following dividends were declared by Baytex during the year ended December 31, 2025:

---

| | | | |
|:---|:---|:---|:---|
| Record Date | Payable Date | Per Share Amount | Dividend Amount |
| March 14, 2025 | April 1, 2025 | $0.0225 | $17289 |
| June 13, 2025 | July 2, 2025 | 0.0225 | 17304 |
| September 15, 2025 | October 1, 2025 | 0.0225 | 17326 |
| December 15, 2025 | January 2, 2026 | 0.0225 | 17268 |
| **Total dividends declared** | **Total dividends declared** | **Total dividends declared** | $**69187** |

---

On March 4, 2026, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on April 1, 2026 for shareholders of record on March 13, 2026.

**13.&nbsp;&nbsp;&nbsp;&nbsp;SHARE-BASED COMPENSATION PLAN**

For the year ended December 31, 2025, the Company recorded share-based compensation expense of $24.0 million ($11.9 million for the year ended December 31, 2024) which is related to the cash-settled awards for continuing operations. For the year ended December 31, 2025, the Company recorded share-based compensation expense of $9.3 million ($6.0 million for the year ended December 31, 2024) which is related to the cash-settled awards for discontinued operations.

The Company's closing share price on December 31, 2025 was $4.44 (December 31, 2024 - $3.70).

The maximum number of common shares issuable under the Share Award Incentive Plan (and any other long-term incentive plans of the Company) shall not exceed 3.8% of the then-issued and outstanding common shares.

Liabilities associated with cash-settled awards are determined based on the fair value of the award at grant date and are subsequently revalued at each period end until the date of settlement. This valuation incorporates the period-end share price, the number of awards outstanding at each period end, and certain management estimates, such as estimated forfeitures and the performance multiplier, if applicable. Share-based compensation expense related to cash-settled awards is recognized in the consolidated statements of income or loss and comprehensive income or loss over the relevant service period with a corresponding increase or decrease in share-based compensation liability. Classification of the associated short-term and long-term liabilities is dependent on the expected payout dates of the individual awards.

**Share Award Incentive Plan**

The Company has a full-value award plan (the "Share Award Incentive Plan") pursuant to which restricted awards and performance awards (collectively, "Share Awards") may be granted to directors, officers and employees of the Company and its subsidiaries. Pursuant to the Share Award Incentive Plan, Baytex has the option to settle amounts payable related to Share Awards in cash on the settlement date.

A restricted award entitles the holder of each award to receive one common share of Baytex per restricted award or the equivalent cash value at the time of vesting. A performance award entitles the holder of each award to receive between zero and two common shares per performance award or the cash equivalent value on vesting; the number of common shares issued is determined by a performance multiplier. The multiplier can range between zero and two and is calculated based on a number of factors determined and approved by the Board of Directors on an annual basis. The multiplier is dependent on the performance of the Company relative to predefined corporate performance measures for a particular period. The number of Share Awards is adjusted to account for the payment of dividends from the grant date to the applicable issue date. The Share Awards vest in equal tranches on the first, second and third anniversaries of the grant date and are expensed over the vesting period using the graded vesting method. The cumulative expense is recognized at fair value at each period end and is included in share-based compensation liability.

The weighted average fair value of Share Awards granted during the year ended December 31, 2025 was $2.92 per restricted and performance award ($4.24 for the year ended December 31, 2024).

------

**Incentive Award Plan**

Baytex has an Incentive Award Plan whereby the participants of the plan are entitled to receive a cash payment equal to the value of one Baytex common share per incentive award at the time of vesting. The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date and are expensed over the vesting period using the graded vesting method. The cumulative expense is recognized at fair value at each period end and is included in share-based compensation liability.

The weighted average fair value of share awards granted during the year ended December 31, 2025 was $2.93 per incentive award ($4.34 for the year ended December 31, 2024).

**Deferred Share Unit Plan ("DSU Plan")**

Baytex has a DSU Plan whereby each independent director of Baytex is entitled to receive a cash payment equal to the value of one Baytex common share per DSU award on the date at which they cease to be a member of the Board. The awards vest immediately upon being granted and are expensed in full on the grant date. The units are recognized at fair value at each period end and are included in share-based compensation liability.

The weighted average fair value of share awards granted during the year ended December 31, 2025 was $2.88 per DSU award ($4.46 for the year ended December 31, 2024).

The number of awards outstanding is detailed below:

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| *(000s)* | Restricted awards | Performance awards | Incentive awards | Director Share Units | Total |
| **Balance, December 31, 2023** | **2279** | **3355** | **4483** | **1245** | **11362** |
| &nbsp;&nbsp;&nbsp;Granted | 13 | 2416 | 3671 | 335 | 6435 |
| &nbsp;&nbsp;&nbsp;Added by performance factor |  | 524 |  |  | 524 |
| &nbsp;&nbsp;&nbsp;Vested | (1457) | (2449) | (2577) | (162) | (6645) |
| &nbsp;&nbsp;&nbsp;Forfeited | (9) | (364) | (302) |  | (675) |
| **Balance, December 31, 2024** | **826** | **3482** | **5275** | **1418** | **11001** |
| &nbsp;&nbsp;&nbsp;Granted | 5 | 3905 | 5927 | 528 | 10365 |
| &nbsp;&nbsp;&nbsp;Forfeited by performance factor |  | (243) |  |  | (243) |
| &nbsp;&nbsp;&nbsp;Vested | (804) | (2113) | (3798) |  | (6715) |
| &nbsp;&nbsp;&nbsp;Forfeited | (4) | (191) | (1952) |  | (2147) |
| **Balance, December 31, 2025** | **23** | **4840** | **5452** | **1946** | **12261** |

---

**14.&nbsp;&nbsp;&nbsp;&nbsp;PER SHARE AMOUNTS**

Baytex calculates basic income or loss per share based on the net income or loss attributable to shareholders using the weighted average number of shares outstanding during the period. Diluted income per share amounts reflect the potential dilution that could occur if share awards were converted to common shares. The treasury stock method is used to determine the dilutive effect of share awards whereby the potential conversion of share awards and the amount of compensation expense, if any, attributed to future services are assumed to be used to purchase common shares at the average market price during the year.

The following table summarizes the weighted average common shares used in calculating net income or loss per share.

---

| | | |
|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 |
| *(000s)* | **2025** | 2024 |
| Weighted average common shares - basic | **769180** | 803435 |
| Dilutive effect of share-based compensation | **—** | 4276 |
| Weighted average common shares - diluted | **769180** | 807711 |

---

For the year ended December 31, 2025, all share awards were excluded from the calculation of diluted loss per share as their effect was anti-dilutive given the Company recorded a loss. For the year ended December 31, 2024, no share awards were excluded from the calculation of diluted income per share as their effect was dilutive.

------

**15.&nbsp;&nbsp;&nbsp;&nbsp;PETROLEUM AND NATURAL GAS SALES**

Petroleum and natural gas sales from contracts with customers for the Company's continuing and discontinued operations is set forth in the following table.

---

| | | |
|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 <sup>(1)</sup> |
| Light oil and condensate | $**366523** | $421383 |
| Heavy oil | **1261899** | 1403022 |
| NGL | **29583** | 26017 |
| Natural gas | **26643** | 23624 |
| Total petroleum and natural gas sales - continuing operations | $**1684648** | $1874046 |
| Total petroleum and natural gas sales - discontinued operations | $**1888524** | $2334909 |

---

*(1)Comparative period revised to reflect current period presentation. Refer to Note 7 - "Discontinued Operations".*

Included in trade receivables at December 31, 2025 is $102.3 million of accrued receivables related to delivered volumes (December 31, 2024 - $325.7 million).

For the year ended December 31, 2025, the Company had four customers that each accounted for 10% or more of total petroleum and natural gas sales for continuing operations. Petroleum and natural gas sales recorded for each of these customers for the year ended December 31, 2025 is summarized in the following table.

---

| | | |
|:---|:---|:---|
| | **Petroleum and natural gas sales by customer - continuing operations** | **% of Total petroleum and natural gas sales - continuing operations** |
| Customer 1 | $**360653** | **21%** |
| Customer 2 | $**275044** | **16%** |
| Customer 3 | $**218734** | **13%** |
| Customer 4 | $**210679** | **13%** |

---

**16.&nbsp;&nbsp;&nbsp;&nbsp;INCOME TAXES**

The provision for income taxes has been computed as follows:

---

| | | |
|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 |
| Net loss before income taxes from continuing operations | $**(153110)** | $(16718) |
| Expected income taxes at the statutory rate of 24.16% (2024 – 24.38%) <sup>(1)</sup> | **(36991)** | (4076) |
| Increase (decrease) in income taxes resulting from: |  |  |
| &nbsp;&nbsp;Effect of foreign exchange | **(11022)** | 19354 |
| &nbsp;&nbsp;Effect of change in statutory rates <sup>(2)</sup> | **—** | 8287 |
| &nbsp;&nbsp;Effect of rate adjustments for foreign jurisdictions | **55** | (3790) |
| &nbsp;&nbsp;Effect of change in deferred tax benefit not recognized <sup>(3)(4)</sup> | **159299** | 38070 |
| &nbsp;&nbsp;Repatriation and related taxes | **9639** | 17999 |
| &nbsp;&nbsp;Adjustments, assessments and other | **2755** | 4891 |
| Income tax expense - continuing operations | $**123735** | $80735 |

---

*(1)The expected income tax rate decreased due to changes in the provincial apportionment of Canadian income.*

*(2)On December 11, 2024, Luxembourg enacted a reduction of the statutory corporate income tax rate to 23.87% from 24.94%, applicable to tax years beginning on January 1, 2025. This change resulted in a deferred tax expense in 2024 on the deferred tax assets of Baytex's Luxembourg subsidiary.*

*(3)A deferred tax asset of $19.9 million remains unrecognized due to uncertainty surrounding future capital gains (December 31, 2024 - $31.8 million). The unrecognized deferred income tax asset relates to realized and unrealized foreign exchange losses arising from the repayment of previously issued U.S. dollar denominated long-term notes and from the translation of U.S. dollar denominated long-term notes currently outstanding.*

*(4)A deferred tax asset of $587.7 million remains unrecognized due to uncertainty surrounding future income earned in foreign jurisdictions (December 31, 2024 - $99.4 million). The unrecognized deferred tax asset relates to non-capital losses, of which $1.8 billion will expire from 2032 to 2042, and $714 million does not have an expiry date.*

------

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 2023, we purchased $272.5 million of insurance coverage for a premium of $50.3 million which will help manage the litigation risk associated with this matter. The most recent statement of account issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $244.2 million and a late filing penalty in respect of the 2011 tax year of $4.1 million.

By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. First, the reassessments allege that the trusts were resettled and the resulting successor trusts were not able to access the losses of the predecessor 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.

For the year-ended December 31, 2025, Baytex has determined that it meets the requirements of safe-harbor provisions in all the jurisdictions in which we operate and therefore does not anticipate owing any top-up taxes under Pillar Two legislation.

A continuity of the net deferred income tax asset or liability is detailed in the following tables:

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| As at | January 1, 2025 | Recognized in Net Loss | Discontinued Operations <sup>(3)</sup> | Foreign Currency Translation Adjustment | **December 31, 2025** |
| Taxable temporary differences: |  |  |  |  |  |
| &nbsp;&nbsp;Petroleum and natural gas properties | $(848321) | $50636 | $562971 | $27955 | $**(206759)** |
| &nbsp;&nbsp;Financial derivatives | (5834) | (566) |  |  | **(6400)** |
| &nbsp;&nbsp;Other | (14599) | 14109 |  |  | **(490)** |
| Deductible temporary differences: |  |  |  |  |  |
| &nbsp;&nbsp;Asset retirement obligations | 153805 | (8199) | (18138) | (914) | **126554** |
| &nbsp;&nbsp;Non-capital losses <sup>(1)(2)</sup> | 648342 | (183391) | (343716) | (25822) | **95413** |
| &nbsp;&nbsp;Finance costs | 156258 | 13397 | (127119) | (4510) | **38026** |
| Net deferred income tax asset (liability) | $89651 | $(114014) | $73998 | $(3291) | $**46344** |

---

*(1)Canadian non-capital loss carry-forwards at December 31, 2025 totaled $392.7 million, which will expire from 2033 to 2044.*

*(2)A deferred income tax asset of $0.5 million has been recognized in respect of non-capital losses of a wholly owned financing subsidiary of Baytex; which losses will be offset against future interest income to be earned as a result of an internal debt restructuring.*

*(3)On December 19, 2025, the Company disposed of its operated and non-operated assets in the Eagle Ford and immediately thereafter liquidated its U.S. subsidiaries, resulting in the extinguishment of the related deferred tax assets and liabilities.*

------

---

| | | | | |
|:---|:---|:---|:---|:---|
| As at | January 1, 2024 | Recognized in Net Income | Foreign Currency Translation Adjustment | **December 31, 2024** |
| Taxable temporary differences: |  |  |  |  |
| &nbsp;&nbsp;Petroleum and natural gas properties | $(706101) | $(100286) | $(41934) | $**(848321)** |
| &nbsp;&nbsp;Financial derivatives | (2738) | (3096) |  | **(5834)** |
| &nbsp;&nbsp;Other | (13046) | (1434) | (119) | **(14599)** |
| Deductible temporary differences: |  |  |  |  |
| &nbsp;&nbsp;Asset retirement obligations | 150856 | 1138 | 1811 | **153805** |
| &nbsp;&nbsp;Non-capital losses <sup>(1)(2)</sup> | 647561 | (44671) | 45452 | **648342** |
| &nbsp;&nbsp;Finance costs | 115280 | 33422 | 7556 | **156258** |
| Net deferred income tax asset (liability) <sup>(3)</sup> | $191812 | $(114927) | $12766 | $**89651** |

---

*(1)Non-capital loss carry-forwards at December 31, 2024 totaled $3.3 billion. Canadian non-capital loss carry-forwards of $0.4 billion expire between 2034 and 2043. Foreign non-capital loss carry-forwards total $2.9 billion of which $1.4 billion will expire from 2032 to 2040, and $1.5 billion does not have an expiry date.*

*(2)&nbsp;&nbsp;&nbsp;&nbsp;A deferred income tax asset of $178.2 million has been recognized in respect of non-capital losses of a wholly owned financing subsidiary of Baytex; which losses will be offset against future interest income to be earned as a result of an internal debt restructuring.*

*(3) &nbsp;&nbsp;&nbsp;&nbsp;The net deferred income tax asset as at December 31, 2024 is comprised of a deferred income tax asset of $178.2 million and a deferred income tax liability of $88.6 million.*

**17.&nbsp;&nbsp;&nbsp;&nbsp;FINANCING AND INTEREST**

---

| | | |
|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 <sup>(1)</sup> |
| Interest on Credit Facilities | $**10885** | $38326 |
| Interest on long-term notes | **149214** | 148968 |
| Interest on lease obligations | **1333** | 1338 |
| Cash interest | $**161432** | $188632 |
| Amortization of debt issue costs | **56116** | 14704 |
| Accretion of asset retirement obligations | **19114** | 17265 |
| Net early redemption expense | **85355** | 24350 |
| Financing and interest - continuing operations | $**322017** | $244951 |
| Financing and interest - discontinued operations | $**22985** | $23423 |

---

*(1)Comparative period revised to reflect current period presentation. Refer to Note 7 - "Discontinued Operations".*

**18.&nbsp;&nbsp;&nbsp;&nbsp;FOREIGN EXCHANGE**

---

| | | |
|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 <sup>(1)</sup> |
| Unrealized foreign exchange (gain) loss | $**(88538)** | $153930 |
| Realized foreign exchange (gain) loss | **(5481)** | 1965 |
| Foreign exchange (gain) loss - continuing operations | $**(94019)** | $155895 |
| Foreign exchange gain - discontinued operations | $**(3624)** | $— |

---

*(1)Comparative period revised to reflect current period presentation. Refer to Note 7 - "Discontinued Operations".*

**19.&nbsp;&nbsp;&nbsp;&nbsp;FINANCIAL INSTRUMENTS AND RISK MANAGEMENT**

The Company's financial assets and liabilities are comprised of cash, trade receivables, trade payables, dividends payable, financial derivatives, Credit Facilities and long-term notes. The fair value of cash, trade receivables, trade payables and dividends payable approximates carrying value due to the short term to maturity. The fair value of the Credit Facilities is equal to the principal amount outstanding as the Credit Facilities bear interest at floating rates and credit spreads that are indicative of market rates. The fair value of the long-term notes is determined based on market prices.

------

The carrying value and fair value of the Company's financial instruments carried on the consolidated statements of financial position are classified into the following categories:

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **December 31, 2025** | **December 31, 2025** | December 31, 2024 | December 31, 2024 | |
| | **Carrying value** | **Fair value** | Carrying value | Fair value | Fair Value Measurement Hierarchy |
| **Financial Assets** |  |  |  |  |  |
| *FVTPL* |  |  |  |  |  |
| Financial Derivatives | $**28898** | $**28898** | $25573 | $25573 | Level 2 |
| Total | $**28898** | $**28898** | $25573 | $25573 |  |
| *Amortized cost* |  |  |  |  |  |
| Cash | $**953113** | $**953113** | $16610 | $16610 |  |
| Trade receivables | **135230** | **135230** | 387266 | 387266 |  |
| Total | $**1088343** | $**1088343** | $403876 | $403876 |  |
| **Financial Liabilities** |  |  |  |  |  |
| *FVTPL* |  |  |  |  |  |
| Financial Derivatives | $**(2406)** | $**(2406)** | $(1645) | $(1645) | Level 2 |
| Total | $**(2406)** | $**(2406)** | $(1645) | $(1645) |  |
| *Amortized cost* |  |  |  |  |  |
| Trade payables | $**(236373)** | $**(236373)** | $(512473) | $(512473) |  |
| Dividends payable | **(17268)** | **(17268)** | (17598) | (17598) |  |
| Credit Facilities <sup>(1)</sup> | **(1138)** | **(1400)** | (324346) | (341207) |  |
| Long-term notes | **(93834)** | **(99808)** | (1932890) | (1990598) | Level 1 |
| Total | $**(348613)** | $**(354849)** | $(2787307) | $(2861876) |  |

---

*(1) &nbsp;&nbsp;&nbsp;&nbsp;The difference in the carrying value and fair value of the Credit Facilities is due to unamortized debt issuance costs. Refer to Note 9.*

Baytex classifies the fair value of financial instruments according to the following hierarchy based on the number of observable inputs used to value the instruments:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

There were no transfers between Level 1 and Level 2 during the years ended December 31, 2025 or 2024.

**Foreign Currency Risk** 

In entities with a Canadian dollar functional currency, Baytex is exposed to fluctuations in foreign exchange rates as a result of the U.S. dollar portion of its Credit Facilities, long-term notes and crude oil sales based on U.S. dollar benchmark prices. The Company's net income or loss and cash flow will therefore be impacted by fluctuations in foreign exchange rates.

A $0.01 increase or decrease in the CAD/USD foreign exchange rate on the revaluation of outstanding U.S. dollar denominated assets and liabilities would impact net income or loss before income taxes by approximately $0.6 million.

The carrying amounts of the Company's U.S. dollar denominated monetary assets and liabilities recorded in entities with a Canadian dollar functional currency at the reporting date are as follows:

---

| | | | | |
|:---|:---|:---|:---|:---|
| | Assets | Assets | Liabilities | Liabilities |
| | **December 31, 2025** | December 31, 2024 | **December 31, 2025** | December 31, 2024 |
| U.S. dollar denominated | **US$22,204** | US$21,450 | **US$84,500** | US$1,399,881 |

---

------

**Commodity Price Risk**

Baytex utilizes financial derivative contracts or physical delivery contracts to manage the risk associated with changes in commodity prices. The use of derivatives is governed by a Risk Management Policy approved by the Board of Directors of Baytex which sets out limits on the use of derivatives. Baytex does not use financial derivatives for speculative purposes.

The reported value of commodity financial derivatives is sensitive to changes in forecasted commodity prices. For crude oil contracts outstanding as at December 31, 2025, a US$1.00/bbl change in the underlying benchmark crude oil prices would impact net income or loss before income taxes by approximately $19.0 million. For natural gas contracts outstanding as at December 31, 2025, a US$0.25 change in the underlying benchmark natural gas prices would impact net income or loss before income taxes by approximately $0.9 million.

*Financial Derivative Contracts*

Baytex had the following commodity financial derivative contracts outstanding as at March 4, 2026.

---

| | | | | |
|:---|:---|:---|:---|:---|
| | Remaining Period | Volume | Price/Unit <sup>(1)</sup> | Index |
| **Oil** |  |  |  |  |
| Basis differential | Jan 2026 to Mar 2026 | 2,500 bbl/d | WTI less US$13.35/bbl | WCS |
| Basis differential | Apr 2026 to Jun 2026 | 2,500 bbl/d | WTI less US$12.55/bbl | WCS |
| Basis differential | Jul 2026 to Sep 2026 | 2,500 bbl/d | WTI less US$13.05/bbl | WCS |
| Basis differential | Jan 2026 to Dec 2026 | 19,500 bbl/d | WTI less US$13.13/bbl | WCS |
| Basis differential | Oct 2026 to Dec 2026 | 2,500 bbl/d | WTI less US$13.75/bbl | WCS |
| Basis differential | Jan 2026 to Mar 2026 | 1,000 bbl/d | WTI less US$4.00/bbl | MSW |
| Basis differential | Apr 2026 to Jun 2026 | 1,000 bbl/d | WTI less US$3.75/bbl | MSW |
| Basis differential | Jul 2026 to Sep 2026 | 1,000 bbl/d | WTI less US$3.50/bbl | MSW |
| Basis differential | Oct 2026 to Dec 2026 | 1,000 bbl/d | WTI less US$4.25/bbl | MSW |
| Purchased put option <sup>(2)</sup> | Jan 2026 to Jun 2026 | 2,000 bbl/d | US$60.00/bbl | WTI |
| Sold call option <sup>(2)</sup> | Jan 2026 to Jun 2026 | 2,000 bbl/d | US$70.00/bbl | WTI |
| Collar <sup>(2)</sup> | Jan 2026 to Mar 2026 | 2,000 bbl/d | US$60.00/US$75.00/bbl | WTI |
| Collar <sup>(2)</sup> | Jan 2026 to Mar 2026 | 2,000 bbl/d | US$60.00/US$75.55/bbl | WTI |
| Collar | Jan 2026 to Jun 2026 | 5,000 bbl/d | US$60.00/US$67.00/bbl | WTI |
| Collar | Jan 2026 to Apr 2026 | 2,500 bbl/d | US$60.00/US$68.00/bbl | WTI |
| Collar | Jan 2026 to Jun 2026 | 5,000 bbl/d | US$60.00/US$66.00/bbl | WTI |
| Collar | Jan 2026 to Jun 2026 | 5,000 bbl/d | US$60.00/US$64.00/bbl | WTI |
| Collar | Jan 2026 to Jun 2026 | 5,000 bbl/d | US$60.00/US$65.00/bbl | WTI |
| Collar | Jan 2026 to Jun 2026 | 2,500 bbl/d | US$60.00/US$68.00/bbl | WTI |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Natural gas** | | | | |
| Swap | Jan 2026 to Dec 2026 | 2,000 GJ/d | $3.21/GJ | AECO |
| Basis differential | Jan 2026 to Dec 2026 | 2,500 mmbtu/d | NYMEX less US$1.66/mmbtu | NYMEX/AECO |
| Collar | Jan 2026 to Dec 2026 | 2,500 mmbtu/d | US$4.00/US$5.10/mmtbu  | NYMEX |

---

*(1)Based on the weighted average price per unit for the period.* 

*(2)Contracts include deferred premiums to be paid throughout the contract term. The weighted average deferred premium is $0.70/bbl.*

The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives.

---

| | | |
|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 |
| Realized financial derivatives loss (gain) | $**19635** | $(1447) |
| Unrealized financial derivatives gain | **(2564)** | (654) |
| Financial derivatives loss (gain) | $**17071** | $(2101) |

---

------

**Liquidity Risk**

Liquidity risk is the risk that Baytex will encounter difficulty in meeting obligations associated with financial liabilities. Baytex manages its liquidity risk through cash and debt management. Such strategies include management of forecasted and actual cash flows from operating, financing and investing activities, available capacity under the existing Credit Facilities, and opportunities to issue additional debt or equity securities.

The timing of undiscounted cash outflows relating to financial liabilities as at December 31, 2025 is outlined in the table below:

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Total** | 2026 | 2027-2028 | 2029-2030 | 2031 and beyond |
| Trade payables | $**236373** | $236373 | $— | $— | $— |
| Financial derivatives | **2406** | 2406 |  |  |  |
| Credit Facilities - principal | **1400** |  |  | 1400 |  |
| Long-term notes - principal <sup>(1)</sup> | **95947** |  |  |  | 95947 |
| Interest on long-term notes <sup>(2)</sup> | **43929** | 7076 | 14152 | 14152 | 8549 |
| Total | $**380055** | $**245855** | $**14152** | $**15552** | $**104496** |

---

*(1)The US$70.0 million principal amount of 7.375% senior unsecured notes is due March 15, 2032.*

*(2)Excludes interest on Credit Facilities as interest payments on Credit Facilities fluctuate based on amounts outstanding and the prevailing interest rate at the time of borrowing.*

**Credit Risk** 

Credit risk is the risk that a counterparty to a financial asset will default resulting in Baytex incurring a loss. As at December 31, 2025, the Company is exposed to credit risk with respect to its cash, trade receivables and financial derivatives. Baytex manages these risks through the selection and monitoring of credit-worthy counterparties.

Most of the Company's trade receivables relate to petroleum and natural gas sales. Baytex reviews its exposure to individual entities on a regular basis and manages its credit risk by entering into sales contracts after reviewing the creditworthiness of the entity. Letters of credit or parental guarantees may be obtained prior to the commencement of business with certain counterparties. Credit risk may also arise from financial derivative instruments. Baytex's financial derivative contracts are subject to master netting agreements that create a legally enforceable right to offset by the counterparty the related financial assets and financial liabilities. The maximum exposure to credit risk is equal to the carrying value of the financial assets. The Company considers all financial assets that are not impaired or past due to be of good credit quality.

The majority of the Company's credit exposure on trade receivables at December 31, 2025 relates to accrued revenues. Accounts receivable from purchasers of the Company's petroleum and natural gas sales are typically collected on the 25th day of the month following production. Joint interest receivables are typically collected within one to three months following production.

Should the Company determine that the ultimate collection of a receivable is in doubt, the carrying amount of trade receivables is reduced by adjusting the allowance for doubtful accounts and recording a charge to net income or loss. If the Company subsequently determines the accounts receivable is uncollectible, the receivable and allowance for doubtful accounts are adjusted accordingly. As at December 31, 2025, allowance for doubtful accounts was $1.1 million (December 31, 2024 - $1.0 million).

In determining whether amounts past due are collectible, the Company will assess the nature of the past due amounts as well as the credit worthiness and past payment history of the counterparty. Baytex has estimated the lifetime expected credit loss as at and for the year ended December 31, 2025 to be nominal.

The Company's trade receivables, net of the allowance for doubtful accounts, were aged as follows:

---

| | | |
|:---|:---|:---|
| | **December 31, 2025** | December 31, 2024 |
| Current (less than 30 days) | $**132257** | $383968 |
| 31-60 days | **783** | 1224 |
| 61-90 days | **311** | 492 |
| Past due (more than 90 days) | **1879** | 1582 |
|  | $**135230** | $387266 |

---

The Company manages credit risk by allocating cash and cash equivalents across major Canadian financial institutions that maintain a minimum investment-grade credit rating, thereby reducing exposure to any single counterparty.

------

**20.&nbsp;&nbsp;&nbsp;&nbsp;SUPPLEMENTAL INFORMATION**

**Changes in Non-Cash Working Capital Items**

---

| | | |
|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 |
| Trade receivables | $**257783** | $(47861) |
| Prepaids and other assets | **(7275)** | 8531 |
| Trade payables | **(276100)** | 35178 |
| Share-based compensation liability | **10070** | (11000) |
| Dividends payable | **(330)** | (783) |
| Non-cash working capital disposed | **49299** | (6390) |
|  | $**33447** | $(22325) |
| Changes in non-cash working capital related to: |  |  |
| &nbsp;&nbsp;&nbsp;Operating activities | $**18111** | $(17922) |
| &nbsp;&nbsp;&nbsp;Financing activities | **(1620)** | 6200 |
| &nbsp;&nbsp;&nbsp;Investing activities | **17822** | (11375) |
| &nbsp;&nbsp;&nbsp;Transfers to equity | **(330)** | (1167) |
| Foreign currency translation on non-cash working capital | **(536)** | 1939 |
|  | $**33447** | $(22325) |

---

**Income Statement Presentation**

Baytex's consolidated statements of income (loss) and comprehensive income (loss) are prepared according to the nature of expense, with the exception of employee compensation costs which are included in both operating expense and general and administrative expense line items.

The following table details the amount of total employee compensation costs included in the operating expense and general and administrative expense.

---

| | | |
|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 <sup>(1)</sup> |
| Operating | $**12372** | $13340 |
| General and administrative | **43687** | 36583 |
| Total employee compensation costs - continuing operations | $**56059** | $49923 |
| Total employee compensation costs - discontinued operations | $**55670** | $38429 |

---

*(1)Comparative period revised to reflect current period presentation. Refer to Note 7 - "Discontinued Operations".*

**21.&nbsp;&nbsp;&nbsp;&nbsp;COMMITMENTS AND CONTINGENCIES**

Baytex has a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact the Company's cash flow from operations in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow (note 23). These obligations as of December 31, 2025 and the expected timing of funding of these obligations, are noted in the table below.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Total** | 2026 | 2027-2028 | 2029-2030 | 2031 and beyond |
| Processing agreements | $**4969** | $948 | $563 | $533 | $2925 |
| Transportation agreements | **134312** | 40249 | 51388 | 13416 | 29259 |
| Total | $**139281** | $**41197** | $**51951** | $**13949** | $**32184** |

---

Baytex also has ongoing obligations related to the abandonment and reclamation of well sites and facilities which have reached the end of their economic lives (note 11). 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 wellsites and facilities are undertaken regularly in accordance with applicable legislative requirements.

------

The Company is, from time-to-time, subject to various claims, demands, audits and other proceedings covering matters that arise in the ordinary course of business activities. Such claims and other proceedings often relate to labour, tax, environmental, title or commercial matters. Baytex retains liability for matters related to our prior ownership of assets located in the U.S. Resolution of these matters may have an unfavorable financial or operating impact on the Company. Certain conditions may exist as at December 31, 2025 which may result in a loss to the Company. However, the Company believes that none of these matters are expected to have a material effect on the results of operations or financial position of the Company.

The Company establishes legal provisions for known and potential claims for which payment is probable and can be reliably estimated. The Company also has comprehensive liability insurance coverage; however such insurance does not cover all risks to which we might be exposed and in other cases, may only partially cover losses incurred by the Company.

**22.&nbsp;&nbsp;&nbsp;&nbsp;RELATED PARTIES**

Transactions with key management personnel and directors are noted in the table below.

---

| | | |
|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 <sup>(1)</sup> |
| Short-term employee benefits | $**7370** | $6460 |
| Share-based compensation | **14648** | 9761 |
| Total compensation for key management personnel - continuing operations | $**22018** | $16221 |
| Total compensation for key management personnel - discontinued operations | $**4705** | $1154 |

---

*(1)Comparative period revised to reflect current period presentation.*

**23.&nbsp;&nbsp;&nbsp;&nbsp;CAPITAL MANAGEMENT**

The Company's capital management objective is to maintain a strong financial position that provides flexibility to execute its development programs, provide returns to shareholders and optimize its portfolio through strategic acquisitions. Baytex assesses its capital structure in response to operational requirements and changes in economic conditions. At December 31, 2025, the Company's capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, trade payables, share-based compensation liability, dividends payable, other long-term liabilities, cash and the Credit Facilities.

In order to manage its capital structure and liquidity, Baytex may from time-to-time issue 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.

The capital-intensive nature of Baytex's operations requires the maintenance of adequate sources of liquidity to fund ongoing exploration and development. Baytex's capital resources consist primarily of adjusted funds flow, available Credit Facilities and proceeds received from the divestiture of oil and gas properties. The following capital management measures and ratios are used to monitor current and projected sources of liquidity.

**Net (Cash) Debt** 

The Company uses net (cash) debt to monitor its current financial position and to evaluate existing sources of liquidity. The Company defines net (cash) debt to be the sum of our Credit Facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade payables, dividends payable, share-based compensation liability, other long-term liabilities, cash, trade receivables, and prepaids and other assets. Baytex also uses net (cash) debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations.

------

The following table reconciles net (cash) debt to amounts disclosed in the primary financial statements.

---

| | | |
|:---|:---|:---|
| | **December 31, 2025** | December 31, 2024 |
| Credit Facilities | $**1138** | $324346 |
| Unamortized debt issuance costs - Credit Facilities (note 9) | **262** | 16861 |
| Long-term notes | **93834** | 1932890 |
| Unamortized debt issuance costs - Long-term notes (note 10) | **2113** | 47729 |
| Trade payables | **236373** | 512473 |
| Cash | **(953113)** | (16610) |
| Dividends payable | **17268** | 17598 |
| Share-based compensation liability | **34802** | 24732 |
| Other long-term liabilities | **—** | 20887 |
| Trade receivables | **(135230)** | (387266) |
| Prepaids and other assets | **(63232)** | (76468) |
| Net (Cash) Debt | $**(765785)** | $2417172 |

---

**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.

---

| | | |
|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 |
| Cash flows from operating activities | $**1485962** | $1908264 |
| Change in non-cash working capital | **(18111)** | 17922 |
| Asset retirement obligations settled | **20318** | 28793 |
| Transaction costs | **26383** | 1539 |
| Adjusted funds flow | $**1514552** | $1956518 |

---

## Exhibit 99.3

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 1

**BAYTEX ENERGY CORP. &nbsp;&nbsp;&nbsp;&nbsp;Exhibit 99.3**

**Management's Discussion and Analysis**

**For the years ended December 31, 2025 and 2024**

**Dated March 4, 2026**

The following is management's discussion and analysis ("MD&A") of the operating and financial results of Baytex Energy Corp. for the years ended December 31, 2025 and 2024. This information is provided as of March 4, 2026. In this MD&A, references to "Baytex", the "Company", "we", "us" and "our" and similar terms refer to Baytex Energy Corp. and its subsidiaries on a consolidated basis, except where the context requires otherwise. The results for the three months and year ended December 31, 2025 ("Q4/2025" and "2025") have been compared with the results for the three months and year ended December 31, 2024 ("Q4/2024" and "2024"). This MD&A should be read in conjunction with the Company's audited consolidated financial statements ("consolidated financial statements") for the years ended December 31, 2025 and 2024, together with the accompanying notes and the Annual Information Form ("AIF") for the year ended December 31, 2025. These documents and additional information about Baytex are accessible on the SEDAR+ website at www.sedarplus.ca and through the U.S. Securities and Exchange Commission at www.sec.gov. All amounts are in Canadian dollars, unless otherwise stated, and all tabular amounts are in thousands of Canadian dollars, except for percentages and per common share amounts or as otherwise noted. Operating and financial results for our continuing operations are presented separately from the operating and financial results of discontinued operations. Presentation of comparative period results has been revised to reflect current period presentation.

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 issued by the International Accounting Standards Board ("IASB"). The terms "operating netback", "free cash flow", "average royalty rate", "heavy oil, net of blending and other expense" and "total sales, net of blending and other expense" are specified financial measures that do not have any standardized meaning as prescribed by IFRS and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. This MD&A also contains the terms "adjusted funds flow" and "net (cash) 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 Canadian energy company based in Calgary, Alberta. Following the disposition of our U.S. operations in Q4/2025, Baytex has oil and natural gas assets in Western Canada primarily comprised of Viking and Duvernay light oil assets along with heavy oil assets in Peace River and Lloydminster.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 1

**PRESENTATION OF CONTINUING AND DISCONTINUED OPERATIONS**

On December 19, 2025, we completed the disposition of the operated and non-operated Eagle Ford assets which comprised our U.S. operating segment. This operating segment represented a geographical area of our operations and its results have been classified as discontinued operations. The financial results for the year ended December 31, 2025 and December 31, 2024 are disaggregated between continuing and discontinued operations in the table below.

In this MD&A, references to "Canada", "Canadian operations" and similar terms refer to the continuing operations of Baytex Energy Corp. and references to "U.S. operations", "Eagle Ford" and similar terms refer to the discontinued operations.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **2025** | **2025** | **2025** | 2024 | 2024 | 2024 |
| **Years Ended December 31** | **Continuing** | **Discontinued** | **Total** | Continuing | Discontinued | Total |
| **Revenue, net of royalties** |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Petroleum and natural gas sales | $**1684648** | $**1888524** | $**3573172** | $1874046 | $2334909 | $4208955 |
| &nbsp;&nbsp;&nbsp;Royalties | **(203833)** | **(508305)** | **(712138)** | (261205) | (618881) | (880086) |
|  | **1480815** | **1380219** | **2861034** | 1612841 | 1716028 | 3328869 |
| **Expenses** |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Operating | **334317** | **292424** | **626741** | 336069 | 317880 | 653949 |
| &nbsp;&nbsp;&nbsp;Transportation | **83697** | **45683** | **129380** | 84211 | 48931 | 133142 |
| &nbsp;&nbsp;&nbsp;Blending and other | **234990** | **—** | **234990** | 263943 |  | 263943 |
| &nbsp;&nbsp;&nbsp;General and administrative | **67903** | **35622** | **103525** | 58363 | 23383 | 81746 |
| &nbsp;&nbsp;&nbsp;Transaction costs | **—** | **—** | **—** | 1539 |  | 1539 |
| &nbsp;&nbsp;&nbsp;Exploration and evaluation | **5534** | **—** | **5534** | 779 |  | 779 |
| &nbsp;&nbsp;&nbsp;Depletion and depreciation | **484932** | **779760** | **1264692** | 483314 | 902596 | 1385910 |
| &nbsp;&nbsp;&nbsp;Impairment | **148000** | **—** | **148000** |  |  |  |
| &nbsp;&nbsp;&nbsp;Share-based compensation | **24041** | **9268** | **33309** | 11871 | 6001 | 17872 |
| &nbsp;&nbsp;&nbsp;Financing and interest | **322017** | **22985** | **345002** | 244951 | 23423 | 268374 |
| &nbsp;&nbsp;&nbsp;Financial derivatives loss (gain) | **17071** | **—** | **17071** | (2101) |  | (2101) |
| &nbsp;&nbsp;&nbsp;Foreign exchange (gain) loss | **(94019)** | **(3624)** | **(97643)** | 155895 |  | 155895 |
| &nbsp;&nbsp;&nbsp;(Gain) loss on dispositions | **(2528)** | **510608** | **508080** | (4134) | 5354 | 1220 |
| &nbsp;&nbsp;&nbsp;Other expense (income) | **7970** | **(4061)** | **3909** | (5141) | (1548) | (6689) |
|  | **1633925** | **1688665** | **3322590** | 1629559 | 1326020 | 2955579 |
| **Net (loss) income before income taxes** | **(153110)** | **(308446)** | **(461556)** | (16718) | 390008 | 373290 |
| **Income taxes** |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Current income tax expense | **9721** | **20261** | **29982** | 17821 | 3945 | 21766 |
| &nbsp;&nbsp;&nbsp;Deferred income tax expense (recovery) | **114014** | **(1773)** | **112241** | 62914 | 52013 | 114927 |
|  | **123735** | **18488** | **142223** | 80735 | 55958 | 136693 |
| **Net (loss) income** | $**(276845)** | $**(326934)** | $**(603779)** | $(97453) | $334050 | $236597 |

---

**2025 ANNUAL HIGHLIGHTS**

Baytex delivered strong operating results in 2025. Annual production of 145,079 boe/d was consistent with our full year plan after adjusting for the disposition of the Eagle Ford assets on December 19, 2025, and reflects strong results from our drilling programs in Western Canada and the Eagle Ford in Texas. We invested $1.2 billion in exploration and development expenditures and generated free cash flow<sup>(1)</sup> of $274.9 million in 2025.

Exploration and development expenditures totaled $1.2 billion for 2025. In Canada, we invested $548.4 million and generated production of 65,528 boe/d during 2025 compared to 63,948 boe/d in 2024 which reflects strong well performance from our light oil Duvernay assets and heavy oil development which more than offset the effect of the disposition of our Kerrobert thermal asset in Q4/2024. In the U.S. we invested $657.7 million during 2025 and production averaged 79,551 boe/d compared to 89,100 boe/d in 2024 when we invested $767.1 million.

*(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.*

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 2

Oil prices were volatile in 2025 due to concerns over global economic conditions along with increasing supply. The average WTI benchmark price for 2025 was US$64.81/bbl which was US$10.91/bbl lower than an average of US$75.72/bbl for 2024. Our financial results for 2025 reflect lower realized pricing which resulted in adjusted funds flow<sup>(1)</sup> of $1.5 billion and cash flows from operating activities of $1.5 billion for 2025 compared to 2024 when we generated adjusted funds flow of $2.0 billion and cash flows from operating activities of $1.9 billion.

Baytex completed the disposition of the operated and non-operated Eagle Ford assets on December 19, 2025. Proceeds of approximately US$2.2 billion (after closing adjustments) were used to repay a significant portion of our outstanding debt and to restart our share buyback program. The divestiture positions Baytex as a focused Canadian energy producer with high-quality heavy oil operations as well as an attractive position in the Pembina Duvernay.

Net cash<sup>(1)</sup> was $765.8 million at December 31, 2025 compared to net debt<sup>(1)</sup> of $2.4 billion at December 31, 2024. Our net cash<sup>(1)</sup> position at December 31, 2025 reflects proceeds received from the disposition of the Eagle Ford assets which were used for the repayment of our credit facilities, all of the 8.50% Senior Notes due 2030 and the majority of the 7.375% Senior Notes due 2032. Free cash flow of $274.9 million generated throughout 2025 was allocated to debt repayment along with $98.0 million of shareholder returns including share buybacks and quarterly dividends.

*(1)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.*

**GUIDANCE** 

Our 2026 annual guidance reflects our plans for the continuing Canadian operations, which includes exploration and development expenditures of $550 - $625 million and is designed to generate annual production of 67,000 - 69,000 boe/d.

The following table compares our 2025 revised annual guidance and 2026 annual guidance to our 2025 results. Production, exploration and development expenditures, and expenses for 2025 were consistent with our revised annual guidance for 2025, which reflects our ongoing efforts to deliver strong operating results while we maintain a competitive cost structure.

---

| | | | |
|:---|:---|:---|:---|
| | 2025 Annual Guidance | 2025 Results <sup>(1)</sup> | 2026 Annual Guidance <sup>(2)</sup> |
| Exploration and development expenditures <sup>(3)</sup> | ~ $1.2 billion | $1.21 billion | $550 - $625 million |
| Production (boe/d) <sup>(3)</sup> | ~ 148,000 | 145079 | 67000 - 69000 |
| Expenses: |  |  |  |
| &nbsp;&nbsp;Average royalty rate <sup>(3)(4)</sup> | ~ 22% | 21.3% | 15% |
| &nbsp;&nbsp;Operating <sup>(5)(6)</sup>  | $11.75 - $12.00/boe | $11.84/boe | $13.75 - $14.25/boe |
| &nbsp;&nbsp;Transportation <sup>(6)(7)</sup>  | $2.40 - $2.55/boe | $2.44/boe | $3.40 - $3.60/boe |
| &nbsp;&nbsp;General and administrative <sup>(3)(6)</sup> | $95 million ($1.76/boe) | $103.5 million ($1.96/boe) |  |
| &nbsp;&nbsp;Cash Interest <sup>(6)(7)</sup> | $180 million ($3.33/boe) | $174.1 million ($3.29/boe) |  |
| &nbsp;&nbsp;Current Income Taxes <sup>(5)</sup> | < 1% of EBITDA <sup>(8)</sup> | 1.7% of EBITDA <sup>(8)</sup> |  |
| Leasing expenditures | $15 million | $13 million | $7 million |
| Asset retirement obligations settled | $20 million | $20 million | $20 million |

---

*(1)Includes both continuing and discontinued operations up to closing of the Eagle Ford disposition on December 19, 2025.*

*(2)As announced on December 22, 2025.*

*(3)As announced on July 31, 2025.*

*(4)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)As announced on October 30, 2025.*

*(6)Refer to Operating Expense, Transportation Expense, General and Administrative Expense and Financing and Interest Expense sections of this MD&A for description of the composition of these measures.*

*(7)As announced on December 3, 2024.*

*(8)EBITDA is calculated in accordance with our amended credit facilities agreement which is available on SEDAR+ at www.sedarplus.ca.*

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 3

**RESULTS OF OPERATIONS** 

**Production**

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 | Change |
| **Daily Production** |  |  |  |
| Liquids (bbl/d) |  |  |  |
| &nbsp;&nbsp;&nbsp;Light oil and condensate | **11897** | 11983 | (1)% |
| &nbsp;&nbsp;&nbsp;Heavy oil | **42775** | 42313 | 1% |
| &nbsp;&nbsp;&nbsp;Natural Gas Liquids ("NGL") | **3524** | 2749 | 28% |
| Total liquids (bbl/d) | **58196** | 57045 | 2% |
| Natural gas (mcf/d) | **43988** | 41412 | 6% |
| Daily production (boe/d) - continuing operations | **65528** | 63948 | 2% |
| Daily production (boe/d) - discontinued operations | **79551** | 89100 | (11)% |
| Total production (boe/d) | **145079** | 153048 | (5)% |
| **Production Mix - continuing operations** |  |  |  |
| Light oil and condensate | **19%** | 19% | —% |
| Heavy oil | **65%** | 66% | (1%) |
| NGL | **5%** | 4% | 1% |
| Natural gas | **11%** | 11% | —% |

---

Production from continuing operations in Canada increased to 65,528 boe/d in 2025 compared to 63,948 boe/d in 2024. Our successful light and heavy oil development programs resulted in production that was 1,580 boe/d higher than 2024 despite the disposition of 2,000 boe/d of heavy oil production from the Kerrobert thermal assets in Q4/2024.

Production from discontinued operations of 79,551 boe/d for 2025 was lower than 89,100 boe/d for 2024 which reflects lower activity on the non-operated Eagle Ford assets prior to disposition of all of the Eagle Ford assets on December 19, 2025.

Total production of 145,079 boe/d was consistent with our revised annual guidance of approximately 148,000 boe/d after adjusting for the Eagle Ford disposition on December 19, 2025. We expect production in 2026 to average 67,000 - 69,000 boe/d which reflects growth from our light and heavy oil development activity in Canada.

**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**

Global benchmark prices for crude oil declined in 2025 compared to 2024 as a result of increasing supply and concerns over slowing global economic activity. The WTI benchmark price averaged US$64.81/bbl for 2025 compared to US$75.72/bbl for 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 2025 compared to 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 $85.53/bbl for 2025 compared to $97.59/bbl for 2024. Edmonton par traded at a US$3.62/bbl discount to WTI in 2025 compared to a discount of US$4.49/bbl for 2024.

We compare the price received for our heavy oil production in Canada to the WCS heavy oil benchmark. The WCS benchmark price for 2025 averaged $75.06/bbl compared to $83.56/bbl for 2024. The WCS heavy oil differential to WTI was US$11.11/bbl in 2025 compared to US$14.73/bbl in 2024 due to the additional egress capacity from the Trans Mountain pipeline expansion.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 4

**Natural Gas**

Natural gas prices in Canada were higher in 2025 compared to 2024 which reflects incremental demand and lower inventory levels. Our natural gas pricing is 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 $1.86/mcf during 2025 which is higher than $1.44/mcf during 2024.

The following tables compare select benchmark prices and our average realized selling prices for the years ended December 31, 2025 and 2024.

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 | Change |
| **Benchmark Averages** |  |  |  |
| &nbsp;&nbsp;WTI oil (US$/bbl) <sup>(1)</sup> | **64.81** | 75.72 | (10.91) |
| &nbsp;&nbsp;Edmonton par oil ($/bbl) <sup>(2)</sup> | **85.53** | 97.59 | (12.06) |
| &nbsp;&nbsp;&nbsp;Edmonton par oil differential to WTI (US$/bbl) | **(3.62)** | (4.49) | 0.87 |
| &nbsp;&nbsp;WCS heavy oil ($/bbl) <sup>(3)</sup> | **75.06** | 83.56 | (8.50) |
| &nbsp;&nbsp;&nbsp;WCS heavy oil differential to WTI (US$/bbl) | **(11.11)** | (14.73) | 3.62 |
| &nbsp;&nbsp;AECO 7A natural gas price ($/mcf) <sup>(4)</sup> | **1.86** | 1.44 | 0.42 |
| &nbsp;&nbsp;AECO 5A natural gas price ($/mcf) <sup>(5)</sup> | **1.68** | 1.45 | 0.23 |
| &nbsp;&nbsp;&nbsp;CAD/USD average exchange rate | **1.3978** | 1.3700 | 0.0278 |

---

*(1)WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.* 

*(2)Edmonton par refers to the average posting price for the benchmark MSW crude oil.*

*(3)WCS refers to the average posting price for the benchmark WCS heavy oil.* 

*(4)AECO 7A refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").*

*(5)AECO 5A refers to the AECO arithmetic average daily index price published by the Canadian Gas Price Reporter ("CGPR").*

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| | **2025** | 2024 | Change |
| **Average Realized Sales Prices** |  |  |  |
| Light oil and condensate ($/bbl) <sup>(1)</sup> | $**84.41** | $96.08 | $(11.67) |
| Heavy oil, net of blending and other expense ($/bbl) <sup>(2)</sup> | **65.77** | 73.55 | (7.78) |
| NGL ($/bbl) <sup>(1)</sup> | **23.00** | 25.85 | (2.85) |
| Natural gas ($/mcf) <sup>(1)</sup> | **1.66** | 1.56 | 0.10 |
| Total sales, net of blending and other expense ($/boe) <sup>(2)</sup> - continuing operations | $**60.61** | $68.79 | $(8.18) |
| Total sales ($/boe) <sup>(2)</sup> - discontinued operations | $**65.04** | $71.60 | $(6.56) |
| Total sales, net of blending and other expense ($/boe) <sup>(2)</sup> | $**63.04** | $70.43 | $(7.39) |

---

*(1)Calculated as light oil and condensate, NGL or natural gas sales divided by barrels of oil equivalent production volume 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.*

**Average Realized Sales Prices**

Our total sales, net of blending and other expense per boe was $60.61/boe for 2025 for our continuing Canadian operations compared to $68.79/boe for 2024. The decrease in realized pricing was primarily due to lower benchmark oil pricing in 2025 relative to 2024.

We compare our light oil realized price in Canada to the Edmonton par benchmark price. Lower benchmark prices resulted in our realized light oil and condensate price of $84.41/bbl for 2025 compared to $96.08/bbl in 2024. Our realized price represents a discount of $1.12/bbl to the Edmonton par benchmark compared to $1.51/bbl in 2024 which reflects production growth from our Duvernay light oil assets in 2025.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 5

Our Canadian realized heavy oil price, net of blending and other expense<sup>(1)</sup> was lower in 2025 compared to 2024 which reflects the decrease in WCS benchmark pricing. Our realized pricing for 2025 represents a discount to the WCS benchmark of $9.29/bbl compared to $10.01/bbl for 2024 which reflects lower blending costs in 2025.

In Canada, 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 of the underlying products. Expressed in Canadian dollars, our realized NGL price<sup>(2)</sup> was 25% of WTI in 2025 and 2024.

We compare our Canadian realized natural gas price to the AECO benchmark price. A portion of our natural gas sales is based on the daily index prices which fluctuate independently from the associated monthly index prices. Our realized natural gas price of $1.66/mcf for 2025 reflects higher benchmark prices compared to 2024 when our realized price was $1.56/mcf.

Our total sales for discontinued operations was $65.04/boe for 2025 compared to $71.60/boe for 2024 which was primarily a result of lower benchmark oil prices.

*(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, NGL or natural gas sales divided by barrels of oil equivalent production volume for the applicable period.* 

**PETROLEUM AND NATURAL GAS SALES**

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands)* | **2025** | 2024 | Change |
| Oil sales |  |  |  |
| &nbsp;&nbsp;&nbsp;Light oil and condensate | $**366523** | $421383 | $(54860) |
| &nbsp;&nbsp;&nbsp;Heavy oil | **1261899** | 1403022 | (141123) |
| &nbsp;&nbsp;&nbsp;NGL | **29583** | 26017 | 3566 |
| Total liquids sales | **1658005** | 1850422 | (192417) |
| Natural gas sales | **26643** | 23624 | 3019 |
| Total petroleum and natural gas sales | **1684648** | 1874046 | (189398) |
| Blending and other expense | **(234990)** | (263943) | 28953 |
| Total sales, net of blending and other expense <sup>(1)</sup> - continuing operations | $**1449658** | $1610103 | $(160445) |
| Total sales - discontinued operations | $**1888524** | $2334909 | $(446385) |
| Total sales, net of blending and other expense <sup>(1)</sup> | $**3338182** | $3945012 | $(606830) |

---

*(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.*

Total sales, net of blending and other expense for continuing operations was $1.4 billion for 2025 compared to $1.6 billion reported for 2024. The decrease in our realized pricing for 2025 relative to 2024 resulted in a $195.6 million decrease in total sales, net of blending and other expense which was partially offset by higher production which contributed to a $35.2 million increase in total sales, net of blending and other expense, relative to 2024.

Total sales from our discontinued operations were $1.9 billion in 2025 compared to $2.3 billion in 2024. The decrease in total sales prior to the disposition of our U.S. operations in December 2025 reflects lower production along with lower realized pricing in 2025 relative to 2024.

Total sales, net of blending and other expense of $3.3 billion for 2025 was $0.6 billion lower than $3.9 billion for 2024 which reflects lower benchmark oil prices and a decrease in daily production from the Eagle Ford operations prior to the disposition in December 2025.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 6

**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 depending on 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 years ended December 31, 2025 and 2024.

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands except for % and per boe)* | **2025** | 2024 | Change |
| Royalties - continuing operations | $**203833** | $261205 | $(57372) |
| Average royalty rate <sup>(1)(2)</sup> - continuing operations | **14.1%** | 16.2% | (2.1%) |
| Royalties per boe <sup>(3)</sup> - continuing operations | $**8.52** | $11.16 | $(2.64) |
| Royalties - discontinued operations | $**508305** | $618881 | $(110576) |
| Average royalty rate <sup>(1)(2)</sup> - discontinued operations | **26.9%** | 26.5% | 0.4% |
| Royalties per boe <sup>(3)</sup> - discontinued operations | $**17.51** | $18.98 | $(1.47) |
| Total royalties | $**712138** | $880086 | $(167948) |
| Total average royalty rate <sup>(1)(2)</sup> | **21.3%** | 22.3% | (1.0%) |
| Royalties per boe <sup>(3)</sup>  | $**13.45** | $15.71 | $(2.26) |

---

*(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 for continuing, discontinued or total operations.*

Royalties for continuing operations were $203.8 million or 14.1% of total sales, net of blending and other expense for 2025 compared to $261.2 million or 16.2% in 2024. Total royalty expense for continuing operations was lower in 2025 due to lower total sales, net of blending and other expense, relative to 2024. Our average royalty rate of 14.1% for 2025 was lower than 16.2% for 2024 primarily due to lower benchmark commodity prices for oil.

Royalties for discontinued operations were $508.3 million or 26.9% of total sales in 2025 compared to $618.9 million or 26.5% of total sales in 2024. The decrease in royalties for discontinued operations in 2025 relative to 2024 reflects lower production and realized pricing prior to the disposition of our U.S. operations in December 2025.

Total royalties were $712.1 million or 21.3% of total sales, net of blending and other expense for 2025 which reflects lower realized pricing and production compared to 2024 when total royalties were $880.1 million or 22.3% of total sales, net of blending and other expense. Our total average royalty rate of 21.3% for 2025 was consistent with our annual guidance of approximately 22% for 2025. We expect our average royalty rate to be approximately 15% for 2026 which is consistent with 2025 and reflects the lower royalty rate applicable to our continuing Canadian operations.

**OPERATING EXPENSE**

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands except for per boe)* | **2025** | 2024 | Change |
| Operating expense - continuing operations | $**334317** | $336069 | $(1752) |
| Operating expense per boe <sup>(1)</sup> - continuing operations | $**13.98** | $14.36 | $(0.38) |
| Operating expense - discontinued operations | $**292424** | $317880 | $(25456) |
| Operating expense per boe <sup>(1)</sup> - discontinued operations | $**10.07** | $9.75 | $0.32 |
| Total operating expense | $**626741** | $653949 | $(27208) |
| Total operating expense per boe <sup>(1)</sup> | $**11.84** | $11.67 | $0.17 |

---

*(1)Operating expense per boe is calculated as operating expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.*

Operating expense for continuing operations was $334.3 million ($13.98/boe) for 2025 compared to $336.1 million ($14.36/boe) for 2024. Total operating expense in 2025 was consistent with 2024 while per boe operating costs were lower which reflects our cost savings initiatives and production growth in 2025.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 7

Operating expense for discontinued operations was $292.4 million ($10.07/boe) for 2025 compared to $317.9 million ($9.75/boe) in 2024. The decrease in total operating expense reflects lower production prior to the disposition of our U.S. operations in December 2025.

Lower production resulted in total operating expense of $626.7 million ($11.84/boe) for 2025 which was lower compared to $653.9 million ($11.67/boe) for 2024. Total operating expense of $11.84/boe for 2025 was consistent with our revised annual guidance of $11.75 - $12.00/boe. We expect annual operating expense of $13.75 - $14.25/boe for 2026 which is consistent with the 2025 results from our continuing Canadian operations.

**TRANSPORTATION EXPENSE**

Transportation expense includes the costs to move production to the sales point. The largest component of transportation expense relates to the trucking of oil in Canada to pipeline and rail terminals which can vary depending on trucking rates and hauling distances as we seek to optimize sales prices.

The following table compares our transportation expense for the years ended December 31, 2025 and 2024.

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands except for per boe)* | **2025** | 2024 | Change |
| Transportation expense - continuing operations | $**83697** | $84211 | $(514) |
| Transportation expense per boe <sup>(1)</sup> - continuing operations | $**3.50** | $3.60 | $(0.10) |
| Transportation expense - discontinued operations | $**45683** | $48931 | $(3248) |
| Transportation expense per boe <sup>(1)</sup> - discontinued operations | $**1.57** | $1.50 | $0.07 |
| Total transportation expense | $**129380** | $133142 | $(3762) |
| Total transportation expense per boe <sup>(1)</sup> | $**2.44** | $2.38 | $0.06 |

---

*(1)Transportation expense per boe is calculated as transportation expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.*

Transportation expense for continuing operations was $83.7 million ($3.50/boe) for 2025 which is consistent with $84.2 million ($3.60/boe) for 2024.

Transportation expense for discontinued operations was $45.7 million ($1.57/boe) for 2025 compared to $48.9 million ($1.50/boe) in 2024. The decrease in transportation expense reflects lower production from the Eagle Ford operations prior to closing the disposition in December 2025.

Total transportation expense of $129.4 million ($2.44/boe) in 2025 reflects lower production compared to 2024 when total transportation expense was $133.1 million ($2.38/boe). Total transportation expense of $2.44/boe in 2025 was consistent with our revised annual guidance of $2.40 - $2.55/boe for 2025. We expect annual transportation expense of $3.40 - $3.60/boe for 2026 which is consistent with our 2025 results from our continuing Canadian operations.

**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 for continuing operations was $235.0 million for 2025 compared to $263.9 million for 2024. Lower blending and other expense is primarily a result of a decrease in the cost of condensate purchased for blending in 2025 compared to 2024.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 8

**FINANCIAL DERIVATIVES**

As part of our normal operations, we are exposed to movements in commodity prices, foreign exchange rates, interest rates and changes in our share price. In an effort to manage these exposures, we utilize various financial derivative contracts which are intended to reduce the volatility in our free cash flow. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets fluctuate and as new contracts are entered. The following table summarizes the results of our financial derivative contracts for the years ended December 31, 2025 and 2024.

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands)* | **2025** | 2024 | Change |
| Realized financial derivatives gain (loss) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil | $**(26896)** | $(9186) | $(17710) |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas | **7261** | 10633 | (3372) |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $**(19635)** | $1447 | $(21082) |
| Unrealized financial derivatives gain (loss) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil | $**530** | $7548 | $(7018) |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas | **2034** | (6894) | 8928 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $**2564** | $654 | $1910 |
| Total financial derivatives gain (loss) |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Crude oil | $**(26366)** | $(1638) | $(24728) |
| &nbsp;&nbsp;&nbsp;&nbsp;Natural gas | **9295** | 3739 | 5556 |
| &nbsp;&nbsp;&nbsp;&nbsp;Total | $**(17071)** | $2101 | $(19172) |

---

We recorded a financial derivatives loss of $17.1 million for 2025 compared to a gain of $2.1 million for 2024. The realized financial derivatives loss of $19.6 million for 2025 resulted from $26.9 million of losses on crude oil contracts which was primarily related to WCS contracts outstanding during 2025 and was partially offset by $7.3 million of gains on natural gas contracts. The unrealized financial derivatives gain of $2.6 million for 2025 resulted from a $0.5 million gain on crude oil contracts and a $2.0 million gain on natural gas contracts. The fair value of our financial derivative contracts resulted in a net asset of $26.5 million at December 31, 2025 compared to a net asset of $23.9 million at December 31, 2024.

Refer to Note 19 of the consolidated financial statements for a complete listing of our outstanding contracts at March 4, 2026.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 9

**OPERATING NETBACK**

The following table summarizes our operating netback on a per boe basis for the years ended December 31, 2025 and 2024.

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ per boe except for volume)* | **2025** | 2024 | Change |
| Daily production (boe/d) - continuing operations | **65528** | 63948 | 2% |
| Daily production (boe/d) - discontinued operations | **79551** | 89100 | (11)% |
| Total production (boe/d) | **145079** | 153048 | (5)% |
| Operating netback: |  |  |  |
| Total sales, net of blending and other expense <sup>(1)</sup> | $**60.61** | $68.79 | $(8.18) |
| Less: |  |  |  |
| &nbsp;&nbsp;Royalties <sup>(2)</sup> | **(8.52)** | (11.16) | 2.64 |
| &nbsp;&nbsp;Operating expense <sup>(2)</sup> | **(13.98)** | (14.36) | 0.38 |
| &nbsp;&nbsp;Transportation expense <sup>(2)</sup> | **(3.50)** | (3.60) | 0.10 |
| Operating netback <sup>(1)</sup> - continuing operations | $**34.61** | $39.67 | $(5.06) |
| Operating netback <sup>(1)</sup> - discontinued operations | $**35.89** | $41.37 | $(5.48) |
| Operating netback <sup>(1)</sup> | $**35.31** | $40.67 | $(5.36) |
| Realized financial derivatives gain (loss) <sup>(3)</sup> | **(0.37)** | 0.03 | (0.40) |
| Operating netback after financial derivatives <sup>(1)</sup> | $**34.94** | $40.70 | $(5.76) |

---

*(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.*

*(2)Refer to Royalties, Operating Expense and Transportation Expense sections in this MD&A for a description of the composition these measures.*

*(3)Calculated as realized financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period.*

Our operating netback for continuing operations of $34.61/boe for 2025 was lower than $39.67/boe for 2024 due to the decrease in our realized price, which resulted in lower per unit sales net of royalties. Combined operating and transportation expense for 2025 was consistent with 2024.

Operating netback for discontinued operations was $35.89/boe for 2025 which was lower than $41.37/boe for 2024 primarily due to lower realized prices. Our total operating netback for continuing and discontinued operations net of realized gains and losses on financial derivatives was $34.94/boe for 2025 compared to $40.70/boe for 2024.

Total operating netback after financial derivatives of $34.94/boe for 2025 reflects lower realized prices net of royalties compared to $40.70/boe for 2024.

**GENERAL AND ADMINISTRATIVE EXPENSE**

General and administrative ("G&A") expense includes head office and corporate costs such as salaries and employee benefits, public company costs and administrative recoveries earned for operating exploration and development activities on behalf of our working interest partners. G&A expense fluctuates with head office staffing levels and the level of operated exploration and development activity during the period.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 10

The following table summarizes our G&A expense for the years ended December 31, 2025 and 2024.

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands except for per boe)* | **2025** | 2024 <sup>(1)</sup> | Change |
| Gross general and administrative expense - continuing operations | $**74832** | $66189 | $8643 |
| Overhead recoveries - continuing operations | **(6929)** | (7826) | $897 |
| General and administrative expense - continuing operations | $**67903** | $58363 | $9540 |
| General and administrative expense per boe <sup>(2)</sup> - continuing operations | $**2.84** | $2.49 | $0.35 |
| General and administrative expense - discontinued operations <sup>(3)</sup> | $**35622** | $23383 | $12239 |
| General and administrative expense per boe <sup>(2)</sup> - discontinued operations | $**1.23** | $0.72 | $0.51 |
| Total gross general and administrative expense | $**130754** | $107743 | $23011 |
| Total overhead recoveries | $**(27229)** | $(25997) | $(1232) |
| Total general and administrative expense | $**103525** | $81746 | $21779 |
| Total general and administrative expense per boe <sup>(2)</sup> | $**1.96** | $1.46 | $0.50 |

---

*(1)Comparative period revised to reflect current period presentation. Refer to Note 7 of the consolidated financial statements for additional information.* 

*(2)General and administrative expense per boe is calculated as general and administrative expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.*

*(3)General and administrative expense for discontinued operations is net of recoveries.*

G&A expense for continuing operations of $67.9 million ($2.84/boe) for 2025 increased from $58.4 million ($2.49/boe) in 2024 due to increases in variable compensation related to the current and prior period, along with higher data systems costs and professional fees.

G&A expense for discontinued operations of $35.6 million ($1.23/boe) for 2025 was higher than $23.4 million ($0.72/boe) for 2024 due to severance costs related to the Eagle Ford disposition and higher costs related to information technology projects.

Total G&A expense of $103.5 million ($1.96/boe) for 2025 was consistent with expectations and above our revised annual guidance of $95 million ($1.76/boe) due to the severance costs related to the Eagle Ford disposition.

**FINANCING AND INTEREST EXPENSE**

Financing and interest expense includes interest on our credit facilities, the 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.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 11

The following table summarizes our financing and interest expense for the years ended December 31, 2025 and 2024.

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands except for per boe)* | **2025** | 2024 <sup>(1)</sup> | Change |
| Interest on credit facilities | $**10885** | $38326 | $(27441) |
| Interest on long-term notes | **149214** | 148968 | 246 |
| Interest on lease obligations | **1333** | 1338 | (5) |
| Cash interest - continuing operations | $**161432** | $188632 | $(27200) |
| Amortization of debt issue costs | **56116** | 14704 | 41412 |
| Accretion of asset retirement obligations | **19114** | 17265 | 1849 |
| Net early redemption expense | **85355** | 24350 | 61005 |
| Financing and interest expense - continuing operations | $**322017** | $244951 | $77066 |
| Cash interest per boe <sup>(2)</sup> - continuing operations | $**6.75** | $8.06 | $(1.31) |
| Financing and interest expense per boe <sup>(2)</sup> - continuing operations | $**13.46** | $10.47 | $2.99 |
| Financing and interest expense - discontinued operations | $**22985** | $23423 | $(438) |
| Financing and interest expense per boe <sup>(2)</sup> - discontinued operations | $**0.79** | $0.72 | $0.07 |
| Total cash interest | $**174116** | $206104 | $(31988) |
| Total cash interest per boe <sup>(2)</sup> | $**3.29** | $3.68 | $(0.39) |
| Total financing and interest expense | $**345002** | $268374 | $76628 |
| Total financing and interest expense per boe <sup>(2)</sup> | $**6.52** | $4.79 | $1.73 |

---

*(1)Comparative period revised to reflect current period presentation. Refer to Note 7 of the consolidated financial statements for additional information.* 

*(2)Calculated as cash interest or financing and interest expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.*

Financing and interest expense for continuing operations reflects balances outstanding on our credit facilities in addition to principal amounts of long-term notes outstanding prior to repayment concurrent with closing of the Eagle Ford disposition.

Financing and interest expense for continuing operations was $322.0 million ($13.46/boe) in 2025 compared to $245.0 million ($10.47/boe) in 2024. Higher interest costs in 2025 relative to 2024 include costs incurred for the early redemption of the 8.50% senior notes in Q4/2025. Cash interest of $161.4 million ($6.75/boe) in 2025 reflects lower debt outstanding in addition to lower rates applicable to our credit facilities compared to 2024 when cash interest was $188.6 million ($8.06/boe). The weighted average interest rate applicable on our credit facilities was 6.7% in 2025 compared to 7.6% in 2024.

Accretion of asset retirement obligations of $19.1 million for 2025 was consistent with $17.3 million for 2024. Amortization of debt issue costs was higher in 2025 relative to 2024 primarily due to the de-recognition of deferred issuance costs associated with the long-term notes that were redeemed in Q4/2025. We also recorded an early redemption expense of $85.4 million in 2025 related to the redemption of the US$800 million 8.50% senior notes and the majority of the 7.375% senior notes. During 2024, Baytex recorded early redemption expense of $24.4 million related to the redemption of the 8.75% Senior Notes.

Total cash interest of $174.1 million ($3.29/boe) for 2025 was lower than our revised annual guidance of $180 million ($3.33/boe) due to lower debt balances following repayment of nearly all of our outstanding debt concurrent with closing of the Eagle Ford disposition.

**EXPLORATION AND EVALUATION EXPENSE**

Exploration and evaluation ("E&E") expense is related to the expiry of leases and the de-recognition of costs for exploration programs that have not demonstrated commercial viability and technical feasibility. E&E expense will vary depending on the timing of expiring leases, the accumulated costs of the expiring leases and the economic facts and circumstances related to the Company's exploration programs. Exploration and evaluation expense from continuing operations was $5.5 million for 2025 compared to $0.8 million for 2024.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 12

**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 years ended December 31, 2025 and 2024.

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands except for per boe)* | **2025** | 2024 <sup>(1)</sup> | Change |
| Depletion and depreciation - continuing operations | $**484932** | $483314 | $1618 |
| Depletion and depreciation per boe <sup>(2)</sup> - continuing operations | $**20.28** | $20.65 | $(0.37) |
| Depletion and depreciation - discontinued operations | $**779760** | $902596 | $(122836) |
| Depletion and depreciation per boe <sup>(2)</sup> - discontinued operations | $**26.85** | $27.68 | $(0.83) |
| Total depletion and depreciation | $**1264692** | $1385910 | $(121218) |
| Total depletion and depreciation per boe <sup>(2)</sup> | $**23.88** | $24.74 | $(0.86) |

---

*(1)Comparative period revised to reflect current period presentation. Refer to Note 7 of the consolidated financial statements for additional information.* 

*(2)Depletion and depreciation expense per boe is calculated as depletion and depreciation expense divided by barrels of oil equivalent production volume for the applicable period for continuing, discontinued or total operations.*

Depletion and depreciation expense for continuing operations was $484.9 million ($20.28/boe) for 2025 which was consistent with $483.3 million ($20.65/boe) for 2024. Depletion and depreciation expense for discontinued operations was $779.8 million ($26.85/boe) for 2025 which was lower than $902.6 million ($27.68/boe) for 2024 which reflects lower production.

Total depletion and depreciation was $1.3 billion ($23.88/boe) for 2025 compared to $1.4 billion ($24.74/boe) for 2024. The decrease in total depletion and depreciation was primarily due to lower production from our U.S. operations prior to the disposition in December 2025.

**IMPAIRMENT**

At December 31, 2025, the Company assessed its oil and gas properties for indicators of impairment or impairment reversal and concluded that the estimation of recoverable amount was not required for three of five CGUs. The Company identified indicators of impairment for oil and gas properties in its Viking CGU due to negative technical revisions in proved plus probable reserves. The recoverable amount for the Viking CGU was not sufficient to support its carrying value which resulted in an impairment of $148.0 million recorded at December 31, 2025. The Company identified indicators of impairment reversal for oil and gas properties in its Lloydminster CGU due to a decrease in the asset-specific discount rate. The recoverable amount for the Lloydminster CGU supports its carrying value and no impairment reversal was recorded at December 31, 2025. The recoverable amount is based on a fair value less costs of disposal model using estimated cash flows associated with proved plus probable reserves from an independent reserve report prepared as at December 31, 2025 utilizing a discount rate based on Baytex's corporate weighted average cost of capital adjusted for asset specific factors. The after-tax discount rates applied to the cash flows were between 12% and 14%.

At December 31, 2025, the recoverable amount of the two CGUs were calculated using the following benchmark reference prices for the years 2026 to 2035 adjusted for commodity differentials specific to the CGUs. The prices and costs subsequent to 2035 have been adjusted for inflation at an annual rate of 2.0%.

---

| | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | 2026 | 2027 | 2028 | 2029 | 2030 | 2031 | 2032 | 2033 | 2034 | 2035 |
| WTI crude oil (US$/bbl) | 59.92 | 65.10 | 70.28 | 71.93 | 73.37 | 74.84 | 76.34 | 77.87 | 79.42 | 81.01 |
| WCS heavy oil ($/bbl) | 65.13 | 70.43 | 76.90 | 78.71 | 80.29 | 81.90 | 83.53 | 85.20 | 86.91 | 88.65 |
| Edmonton par oil ($/bbl) | 77.54 | 83.60 | 90.17 | 92.32 | 94.17 | 96.06 | 97.98 | 99.93 | 101.93 | 103.97 |
| AECO gas ($/mmbtu) | 3.00 | 3.30 | 3.49 | 3.58 | 3.65 | 3.72 | 3.80 | 3.88 | 3.95 | 4.03 |

---

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 13

The following table demonstrates the sensitivity of the estimated recoverable amount of the Lloydminster and Viking CGUs to reasonably possible changes in key assumptions inherent in the calculation.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Recoverable amount | Impairment loss (reversal) | Change in discount rate of 1% | Change in oil price of $2.50/bbl | Change in gas price of $0.25/mcf |
| Lloydminster CGU | $327216 | $— | $27250 | $82500 | $500 |
| Viking CGU | 407201 | 148000 | 19000 | 45500 | 3500 |

---

At December 31, 2024 and 2025, the Company assessed its 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 its CGUs.

**SHARE-BASED COMPENSATION EXPENSE**

Share-based compensation ("SBC") expense includes expense associated with our Share Award Incentive Plan, Incentive Award Plan, and Deferred Share Unit Plan. SBC expense associated with equity-settled awards is recognized in net income or loss over the vesting period of the awards with a corresponding increase in contributed surplus. SBC expense associated with cash-settled awards is recognized in net income or loss over the vesting period of the awards with a corresponding share-based compensation liability. SBC expense varies with the quantity of unvested share awards outstanding and changes in the market price of our common shares.

We recorded SBC expense of $24.0 million for 2025 within our continuing operations compared to $11.9 million for 2024. SBC expense for 2025 reflects an increase in our share price which resulted in higher SBC expense relative to 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.

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands except for exchange rates)* | **2025** | 2024 <sup>(1)</sup> | Change |
| Unrealized foreign exchange (gain) loss | $**(88538)** | $153930 | $(242468) |
| Realized foreign exchange (gain) loss | **(5481)** | 1965 | (7446) |
| Foreign exchange (gain) loss - continuing operations | $**(94019)** | $155895 | $(249914) |
| Foreign exchange gain - discontinued operations | $**(3624)** | $— | $(3624) |
| Total foreign exchange gain | $**(97643)** | $155895 | $(253538) |
| CAD/USD exchange rates: |  |  |  |
| &nbsp;&nbsp;&nbsp;At beginning of period | **1.4405** | 1.3205 |  |
| &nbsp;&nbsp;&nbsp;At end of period | **1.3715** | 1.4405 |  |

---

*(1)Comparative period revised to reflect current period presentation. Refer to Note 7 of the consolidated financial statements for additional information.*

We recorded an unrealized foreign exchange gain of $88.5 million for 2025 within our continuing operations which reflects a decrease in the reported amount of the U.S. dollar denominated long-term notes and credit facilities due to a strengthening of the Canadian dollar relative to the U.S. dollar at the date of repayment in December 2025 compared to December 31, 2024. The unrealized foreign exchange loss of $153.9 million for 2024 is due an increase in the reported amount of the U.S dollar denominated long-term notes and credit facilities due to a weakening of the Canadian dollar relative to the U.S. dollar at December 31, 2024 compared to 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 operations. We recorded a realized foreign exchange gain of $5.5 million for 2025 within our continuing operations compared to a loss of $2.0 million for 2024.

We recorded a total foreign exchange gain of $97.6 million for 2025 compared to a loss of $155.9 million for 2024.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 14

**INCOME TAXES** 

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands)* | **2025** | 2024 <sup>(1)</sup> | Change |
| Current income tax expense | $**9721** | $17821 | $(8100) |
| Deferred income tax expense | **114014** | 62914 | 51100 |
| Income tax expense - continuing operations | $**123735** | $80735 | $43000 |
| Income tax expense - discontinued operations | $**(10258)** | $55958 | $(66216) |

---

*(1)Comparative period revised to reflect current period presentation. Refer to Note 7 of the consolidated financial statements for additional information.*

Current income tax expense for our continuing operations was $9.7 million for 2025 compared to $17.8 million recorded in 2024. Current income tax is lower in 2025 due to lower taxes incurred on the repatriation of earnings from the U.S. operations. We recorded deferred income tax expense of $114.0 million for 2025 compared to $62.9 million for 2024. The increase in deferred tax expense in 2025 primarily relates to the valuation allowance placed against our foreign tax attributes as a result of the sale of the Eagle Ford assets.

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 and we estimate it could take between two and 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 Tax Court of Canada, additional appeals are available; a process that we estimate could take another two years and potentially longer.

We remain confident that the tax filings of the affected entities are correct and will defend our tax filing positions. During 2023, we purchased $272.5 million of insurance coverage for a premium of $50.3 million which will help manage the litigation risk associated with this matter. The most recent statement of account issued by the CRA assert taxes owing by the trusts of $244.8 million, late payment interest of $244.2 million and a late filing penalty in respect of the 2011 tax year of $4.1 million.

By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. First, the reassessments allege that the trusts were resettled and the resulting successor trusts were not able to access the losses of the predecessor 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.

The following table summarizes our Canadian tax pools from continuing operations.

---

| | | |
|:---|:---|:---|
| **Canadian Tax Pools** *($ thousands)* | **December 31, 2025** | December 31, 2024 |
| Canadian oil and natural gas property expenditures | $**273133** | $282604 |
| Canadian development expenditures | **608073** | 516475 |
| Undepreciated capital costs | **301519** | 282056 |
| Non-capital losses | **392737** | 447993 |
| Capital losses | **81956** | 60493 |
| Financing costs and other | **122421** | 71670 |
| Total Canadian tax pools | $**1779839** | $1661291 |

---

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 15

**NET INCOME (LOSS) AND ADJUSTED FUNDS FLOW**

The components of adjusted funds flow and net income or loss for the years ended December 31, 2025 and 2024 are set forth in the following table.

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands)* | **2025** | 2024 <sup>(1)</sup> | Change |
| Petroleum and natural gas sales | $**1684648** | $1874046 | $(189398) |
| Royalties | **(203833)** | (261205) | 57372 |
| Revenue, net of royalties | **1480815** | 1612841 | (132026) |
| **Expenses** |  |  |  |
| &nbsp;&nbsp;&nbsp;Operating | **(334317)** | (336069) | 1752 |
| &nbsp;&nbsp;&nbsp;Transportation | **(83697)** | (84211) | 514 |
| &nbsp;&nbsp;&nbsp;Blending and other | **(234990)** | (263943) | 28953 |
| **Operating netback** <sup>(2)</sup> | $**827811** | $928618 | $(100807) |
| &nbsp;&nbsp;&nbsp;General and administrative | **(67903)** | (58363) | (9540) |
| &nbsp;&nbsp;&nbsp;Cash interest | **(161432)** | (188632) | 27200 |
| &nbsp;&nbsp;&nbsp;Realized financial derivatives (loss) gain | **(19635)** | 1447 | (21082) |
| &nbsp;&nbsp;&nbsp;Realized foreign exchange gain (loss) | **5481** | (1965) | 7446 |
| &nbsp;&nbsp;&nbsp;Other income (expense) | **(7970)** | 5141 | (13111) |
| &nbsp;&nbsp;&nbsp;Current income tax expense | **(9721)** | (17821) | 8100 |
| &nbsp;&nbsp;&nbsp;Cash share-based compensation | **(24041)** | (11871) | (12170) |
| **Adjusted funds flow** <sup>(3)</sup> | $**542590** | $656554 | $(113964) |
| &nbsp;&nbsp;&nbsp;Transaction costs | **—** | (1539) | 1539 |
| &nbsp;&nbsp;&nbsp;Exploration and evaluation | **(5534)** | (779) | (4755) |
| &nbsp;&nbsp;&nbsp;Depletion and depreciation | **(484932)** | (483314) | (1618) |
| &nbsp;&nbsp;&nbsp;Non-cash financing and interest | **(160585)** | (56319) | (104266) |
| &nbsp;&nbsp;&nbsp;Unrealized financial derivatives gain (loss) | **2564** | 654 | 1910 |
| &nbsp;&nbsp;&nbsp;Unrealized foreign exchange gain (loss) | **88538** | (153930) | 242468 |
| &nbsp;&nbsp;&nbsp;Gains on dispositions | **2528** | 4134 | (1606) |
| &nbsp;&nbsp;&nbsp;Impairment | **(148000)** |  | (148000) |
| &nbsp;&nbsp;&nbsp;Deferred income tax (expense) recovery | **(114014)** | (62914) | (51100) |
| **Net income (loss) from continuing operations** | $**(276845)** | $(97453) | $(179392) |
| **Net income (loss) from discontinued operations** | $**(326934)** | $334050 | $(660984) |
| **Total net income (loss)** | $**(603779)** | $236597 | $(840376) |

---

*(1)Comparative period revised to reflect current period presentation. Refer to Note 7 of the consolidated financial statements for additional information.* 

*(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.*

*(3)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.*

We generated adjusted funds flow from continuing operations of $542.6 million for 2025 compared to $656.6 million for 2024. The decrease in adjusted funds flow for 2025 was primarily due to the decrease in realized pricing that resulted in lower revenues net of royalties partially offset by lower operating and transportation expense.

We reported a net loss from continuing operations of $276.8 million for 2025 compared to a net loss from continuing operations of $97.5 million for 2024. The net loss from continuing operations for 2025 includes an impairment loss along with higher financing and interest charges related to the Eagle Ford disposition, partially offset by an unrealized foreign exchange gain in 2025.

The total net loss for 2025 includes a $510.6 million loss recorded on the Eagle Ford disposition which includes a $866.7 million reclassification of the cumulative foreign exchange gain associated with discontinued operations.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 16

**OTHER COMPREHENSIVE (LOSS) INCOME**

Other comprehensive (loss) income reflects the foreign currency translation adjustment on the U.S. net assets prior to disposition in December 2025 which is not recognized in net income or loss. The foreign currency translation loss of $213.2 million for 2025 relates to the change in value of our U.S. net assets and is mainly due to the strengthening of the Canadian dollar relative to the U.S. dollar at the date of the Eagle Ford disposition compared to December 31, 2024. The CAD/USD exchange rate was 1.3764 CAD/USD at December 18, 2025 compared to 1.4405 CAD/USD at December 31, 2024.

**CAPITAL EXPENDITURES**

Capital expenditures for the years ended December 31, 2025 and 2024 are summarized as follows.

---

| | | | |
|:---|:---|:---|:---|
| | Years Ended December 31 | Years Ended December 31 | Years Ended December 31 |
| *($ thousands)* | **2025** | 2024 | Change |
| Drilling, completion and equipping | $**478710** | $399817 | $78893 |
| Facilities and other | **69642** | 89669 | (20027) |
| Exploration and development expenditures - continuing operations | $**548352** | $489486 | $58866 |
| Exploration and development expenditures - discontinued operations | **657719** | 767147 | $(109428) |
| Total exploration and development expenditures | $**1206071** | $1256633 | $(50562) |
| Property acquisitions - continuing operations | $**30151** | $48889 | $(18738) |
| Proceeds from dispositions - continuing operations | $**(11953)** | $(41149) | $29196 |
| Property acquisitions - discontinued operations | $**1867** | $3526 | $(1659) |
| Proceeds from dispositions - discontinued operations | $**(3011350)** | $(5346) | $(3006004) |

---

Exploration and development expenditures for continuing operations were $548.4 million in 2025 compared to $489.5 million in 2024. Drilling and completion spending of $478.7 million in 2025 was higher than $399.8 million in 2024 which reflects increased development activity on our Duvernay light oil properties and Lloydminster heavy oil properties.

Exploration and development expenditures on the U.S. operations of $657.7 million for 2025 reflects lower activity on the non-operated Eagle Ford properties prior to closing of the disposition on December 19, 2025 compared to 2024 when exploration and development expenditures were $767.1 million.

Total exploration and development expenditures of $1.21 billion for 2025 were consistent with our revised annual guidance of approximately $1.2 billion. We expect annual exploration and development expenditures of $550 - $625 million for 2026 which is designed to generate production growth in our heavy and light oil operations.

**CAPITAL RESOURCES AND LIQUIDITY**

Our capital management objective is to maintain a strong financial position that provides flexibility to execute our development programs, provide returns to shareholders and optimize our portfolio through strategic acquisitions. Baytex assesses its capital structure in response to operational requirements and changes in economic conditions. At December 31, 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 liquidity. There is no certainty that any of these additional sources of capital would be available if required.

At December 31, 2025 we had net cash<sup>(1)</sup> of $765.8 million compared to net debt<sup>(1)</sup> of $2.4 billion at December 31, 2024 which reflects the repayment of our Credit Facilities, all of the 8.50% Senior Notes and the majority of the 7.375% Senior Notes concurrent with the sale of the Eagle Ford assets. Free cash flow<sup>(2)</sup> of $274.9 million generated in 2025 was allocated to debt repayment along with $98.0 million of shareholder returns including share buybacks and quarterly dividends.

*(1)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.*

*(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.*

**Credit Facilities**

At closing of the Eagle Ford asset sale, on December 19, 2025 we modified our credit facilities (the "Credit Facilities") to decrease the committed amount to $750.0 million from US$1.1 billion and extend maturity from June 27, 2029 to June 27, 2030. There were no changes to the financial covenants as a result of the modification.

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 Canadian Prime Rate, U.S. Base Rate, Canadian Overnight Repo Rate Average rates or secured overnight financing rates ("SOFR"), plus applicable margins.

The weighted average interest rate on the Credit Facilities was 6.7% for 2025, which is lower than 7.6% for 2024 due to lower applicable benchmark rates.

At December 31, 2025, Baytex had $4.4 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 December 31, 2025.

---

| | | |
|:---|:---|:---|
| **Covenant Description** | **Position as at December 31, 2025** | **Covenant** |
| Senior Secured Debt <sup>(1)</sup> to Bank EBITDA <sup>(2)</sup> (Maximum Ratio) | **0.0:1.0** | 3.5:1.0 |
| Interest Coverage <sup>(3)</sup> (Minimum Ratio) | **4.4:1.0** | 3.5:1.0 |
| Total Debt <sup>(4)</sup> to Bank EBITDA <sup>(2)</sup> (Maximum Ratio) | **0.1:1.0** | 4.0:1.0 |

---

*(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreement and is defined as the principal amount of the Credit Facilities and other secured obligations identified in the credit facility agreement. As at December 31, 2025, the Company's Senior Secured Debt totaled $5.8 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 dispositions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the twelve months ended December 31, 2025 was $712.4 million.* 

*(3)"Interest coverage" is calculated in accordance with the credit facility agreement and is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis including the impact of material dispositions as if they had occurred at the beginning of the twelve month period. Financing and interest expenses for the twelve months ended December 31, 2025 were $160.1 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 December 31, 2025, our Total Debt was $101.7 million.*

**Long-Term Notes**

During 2025, Baytex repurchased and cancelled all of the US$800.0 million principal amount of the 8.50% Senior Notes at 105.205% of par value, and US$505.0 million principal amount of the 7.375% Senior Notes at 103.807% of par value. At December 31, 2025 there was US$70.0 million aggregate principal amount of the 7.375% Senior Notes outstanding.

The 7.375% Senior Notes were issued on April 1, 2024 and US$70.0 million remains outstanding as of December 31, 2025. The 7.375% Senior Notes mature on March 15, 2032 and are redeemable at our option, in whole or in part, at specified redemption prices on or after March 15, 2027 and will be redeemable at par from March 15, 2029 to maturity.

Baytex is subject to certain financial and commercial covenants related to its Credit Facilities and long-term notes. Noncompliance with these covenants may result in an event of default, at which point the carrying value of the debt could become repayable within a 12 month period after the reporting date.

**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 year ended December 31, 2025, we issued 0.1 million common shares pursuant to our share-based compensation program. As at December 31, 2025, we had 765.6 million common shares issued and outstanding and no preferred shares issued and outstanding. As at March 2, 2026 there were 740.1 million common shares issued and outstanding and no preferred shares issued and outstanding.

During the year ended December 31, 2025, we repurchased 8.1 million common shares under our normal course issuer bid ("NCIB") at an average price of $3.55 per share for total consideration of $28.9 million. At December 31, 2025, we had 62.8 million shares remaining on our NCIB which expires on July 2, 2025. We have obtained an exemption order from the Canadian securities regulators which permits us to purchase its common shares through the NYSE and other U.S. based trading systems.

For the year ended December 31, 2025 we recorded a $0.5 million charge to shareholders' capital related to the federal tax on equity repurchases (December 31, 2024 - $4.3 million).

Our shareholder returns include a quarterly dividend of $0.0225 per share. Total dividends of $69.2 million were declared during 2025. On March 4, 2026, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on April 1, 2026 for shareholders of record on March 13, 2026. These dividends are designated as "eligible dividends" for Canadian income tax purposes. For U.S. income tax purposes, Baytex's dividends are considered "qualified dividends."

**Contractual Obligations and Contingencies**

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 December 31, 2025 and the expected timing for funding these obligations are noted in the table below.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| *($ thousands)* | **Total** | 2026 | 2027-2028 | 2029-2030 | 2031 and beyond |
| Credit Facilities - principal | $**1400** | $— | $— | $1400 | $— |
| Long-term notes - principal | **95947** |  |  |  | 95947 |
| Interest on long-term notes <sup>(1)</sup> | **43929** | 7076 | 14152 | 14152 | 8549 |
| Lease obligations - principal | **26274** | 8487 | 10690 | 7097 |  |
| Processing agreements | **4969** | 948 | 563 | 533 | 2925 |
| Transportation agreements | **134312** | 40249 | 51388 | 13416 | 29259 |
| Total | $**306831** | $56760 | $76793 | $36598 | $136680 |

---

*(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.

The Company is, from time-to-time, subject to various claims, demands, audits and other proceedings covering matters that arise in the ordinary course of business activities. Such claims and other proceedings often relate to labour, tax, personal injury, environmental, title or commercial matters. Baytex retains liability for matters related to our prior ownership of assets located in the U.S. Resolution of these matters may have an unfavorable financial or operating impact on the Company. Certain conditions may exist as at December 31, 2025 which may result in a loss to the Company. However, the Company believes that none of these matters are expected to have a material effect on the results of operations or financial position of the Company.

The Company establishes legal provisions for known and potential claims for which payment is probable and can be reliably estimated. The Company also has comprehensive liability insurance coverage; however such insurance does not cover all risks to which we might be exposed and in other cases, may only partially cover losses incurred by the Company.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 17

**FOURTH QUARTER OPERATING AND FINANCIAL RESULTS**

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | Three Months Ended December 31 | Three Months Ended December 31 | Three Months Ended December 31 | Three Months Ended December 31 | Three Months Ended December 31 | Three Months Ended December 31 |
| | **2025** | **2025** | **2025** | 2024 | 2024 | 2024 |
| *($ thousands except for per boe)* | **Canada** | **Discontinued Operations**<sup>(1)</sup> | **Total** | Canada | Discontinued Operations<sup>(1)</sup> | Total |
| **Total daily production** |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Light oil and condensate (bbl/d) | **12031** | **42109** | **54140** | 11568 | 53093 | 64661 |
| &nbsp;&nbsp;&nbsp;Heavy oil (bbl/d) | **42628** | **—** | **42628** | 42227 |  | 42227 |
| &nbsp;&nbsp;&nbsp;NGL (bbl/d) | **4488** | **13524** | **18012** | 3519 | 17689 | 21208 |
| **Total liquids (bbl/d)** | **59147** | **55633** | **114780** | 57314 | 70782 | 128096 |
| &nbsp;&nbsp;&nbsp;Natural gas (mcf/d) | **48895** | **84950** | **133845** | 48113 | 100679 | 148792 |
| **Total production (boe/d)** | **67295** | **69792** | **137087** | 65332 | 87562 | 152894 |
| **Operating netback ($/boe)** |  |  |  |  |  |  |
| &nbsp;&nbsp;Light oil and condensate ($/bbl) <sup>(2)</sup> | $**75.88** | $**81.66** | $**80.38** | $93.66 | $97.05 | $96.44 |
| &nbsp;&nbsp;Heavy oil, net of blending and other expense ($/bbl) <sup>(3)</sup> | **58.62** | **—** | **58.62** | 70.05 |  | 70.05 |
| &nbsp;&nbsp;NGL ($/bbl) <sup>(2)</sup> | **19.89** | **24.87** | **23.63** | 26.06 | 29.70 | 29.09 |
| &nbsp;&nbsp;Natural gas ($/mcf) <sup>(2)</sup> | **2.10** | **3.96** | **3.28** | 1.43 | 3.02 | 2.50 |
| **Total sales, net of blending and other per boe** <sup>(3)</sup> | $**53.55** | $**58.91** | $**56.28** | $64.31 | $68.31 | $66.60 |
| &nbsp;&nbsp;Royalties per boe <sup>(4)</sup> | **(6.97)** | **(15.96)** | **(11.54)** | (10.05) | (18.16) | (14.69) |
| &nbsp;&nbsp;Operating expense per boe <sup>(4)</sup> | **(13.84)** | **(11.22)** | **(12.51)** | (13.12) | (8.29) | (10.36) |
| &nbsp;&nbsp;Transportation expense per boe <sup>(4)</sup> | **(3.44)** | **(1.46)** | **(2.43)** | (3.59) | (1.43) | (2.35) |
| **Operating netback per boe** <sup>(3)</sup> | $**29.30** | $**30.27** | $**29.80** | $37.55 | $40.43 | $39.20 |
| **Financial** |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Petroleum and natural gas sales | $**381556** | $**378259** | $**759815** | $466706 | $550311 | $1017017 |
| &nbsp;&nbsp;&nbsp;Royalties | **(43132)** | **(102449)** | **(145581)** | (60396) | (146279) | (206675) |
| **Revenue, net of royalties** | $**338424** | $**275810** | $**614234** | $406310 | $404032 | $810342 |
| &nbsp;&nbsp;&nbsp;Operating | **(85708)** | **(72026)** | **(157734)** | (78878) | (66812) | (145690) |
| &nbsp;&nbsp;&nbsp;Transportation | **(21314)** | **(9352)** | **(30666)** | (21595) | (11515) | (33110) |
| &nbsp;&nbsp;&nbsp;Blending and other | **(50039)** | **—** | **(50039)** | (80148) |  | (80148) |
| **Operating netback** <sup>(3)</sup> | $**181363** | $**194432** | $**375795** | $225689 | $325705 | $551394 |
| &nbsp;&nbsp;&nbsp;General and administrative | **—** | **—** | **(34963)** |  |  | (20433) |
| &nbsp;&nbsp;&nbsp;Cash interest | **—** | **—** | **(38581)** |  |  | (48769) |
| &nbsp;&nbsp;&nbsp;Realized financial derivatives gain (loss) | **—** | **—** | **1013** |  |  | (2115) |
| &nbsp;&nbsp;&nbsp;Other | **—** | **—** | **(41733)** |  |  | (18191) |
| **Adjusted funds flow** <sup>(5)</sup> | $**181363** | $**194432** | $**261531** | $225689 | $325705 | $461886 |
| **Net (loss) income** | $**(163790)** | $**(465994)** | $**(856887)** | $113551 | $113172 | $(38477) |
| Exploration and development expenditures | $**92720** | $**81358** | $**174078** | $108971 | $89206 | $198177 |
| Property acquisitions | **5217** | **327** | **5544** | 12305 | 316 | 12621 |
| Proceeds from dispositions | **(159)** | **(3011899)** | **(3012058)** | (41517) | (822) | (42339) |
| Net (cash) debt <sup>(5)</sup> |  |  | $**(765785)** |  |  | $2417172 |

---

*(1)Discontinued operations reflects the operating and financial results from the Eagle Ford assets prior to disposition on December 19, 2025. Refer to Note 7 of the consolidated financial statements for additional information.* 

*(2)Calculated as light oil and condensate, NGL or natural gas sales divided by barrels of oil equivalent production volume for the applicable period.*

*(3)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.*

*(4)Calculated as royalties expense, operating expense or transportation expense divided by barrels of oil equivalent production volume for the applicable period.*

*(5)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.*

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 18

---

| | | | |
|:---|:---|:---|:---|
| | Three Months Ended December 31 | Three Months Ended December 31 | Three Months Ended December 31 |
| | **2025** | 2024 | Change |
| **Benchmark Averages** |  |  |  |
| &nbsp;&nbsp;WTI oil (US$/bbl) <sup>(1)</sup> | **59.14** | 70.27 | (11.13) |
| &nbsp;&nbsp;Edmonton par oil ($/bbl) <sup>(2)</sup> | **76.49** | 94.98 | (18.49) |
| &nbsp;&nbsp;&nbsp;Edmonton par oil differential to WTI (US$/bbl) | **(4.30)** | (2.39) | (1.91) |
| &nbsp;&nbsp;WCS heavy oil ($/bbl) <sup>(3)</sup> | **66.88** | 80.77 | (13.89) |
| &nbsp;&nbsp;&nbsp;WCS heavy oil differential to WTI (US$/bbl) | **(11.19)** | (12.54) | 1.35 |
| &nbsp;&nbsp;AECO 7A natural gas price ($/mcf) <sup>(4)</sup> | **2.34** | 1.46 | 0.88 |
| &nbsp;&nbsp;AECO 5A natural gas price ($/mcf) <sup>(5)</sup> | **2.23** | 1.48 | 0.75 |
| &nbsp;&nbsp;&nbsp;CAD/USD average exchange rate | **1.3949** | 1.3992 | (0.0043) |

---

*(1)WTI refers to the arithmetic average of NYMEX prompt month WTI for the applicable period.* 

*(2)Edmonton par refers to the average posting price for the benchmark MSW crude oil.*

*(3)WCS refers to the average posting price for the benchmark WCS heavy oil.* 

*(4)AECO 7A refers to the AECO arithmetic average month-ahead index price published by the Canadian Gas Price Reporter ("CGPR").*

*(5)AECO 5A refers to the AECO arithmetic average daily index price published by the Canadian Gas Price Reporter ("CGPR").*

**Continuing Operations**

We invested $92.7 million on exploration and development in Q4/2025 and generated production of 67,295 boe/d which was 1,963 boe/d higher than 65,332 boe/d reported for Q4/2024 when we invested $109.0 million on exploration and development. The increase in production reflects our successful heavy oil development program and Duvernay production growth which more than offset the impact of the Q4/2024 disposition of 2,000 boe/d of heavy oil production from Kerrobert Thermal.

Lower light and heavy oil benchmark pricing resulted in a realized price of $53.55/boe for Q4/2025 which was $10.76/boe lower than $64.31/boe for Q4/2024. Operating netback<sup>(1)</sup> of $181.4 million ($29.30/boe) for Q4/2025 reflects lower realized pricing relative to Q4/2024 when we reported operating netback of $225.7 million ($37.55/boe) for our Canadian operations.

**Discontinued Operations**

In the U.S., exploration and development expenditures were $81.4 million and production averaged 69,792 boe/d for Q4/2025 which is 17,770 boe/d lower than 87,562 boe/d reported for Q4/2024 when we spent $89.2 million. Lower production in Q4/2025 relative to Q4/2024 reflects reduced activity on the non-operated Eagle Ford property along with the disposition of the U.S. assets on December 19, 2025.

The MEH benchmark averaged US$60.70/bbl in Q4/2025 which was US$11.70/boe lower than US$72.40/bbl during Q4/2024 and resulted in a realized price of $58.91/boe which was $9.40/boe lower than our realized price of $68.31/boe in Q4/2024. Operating netback of $194.4 million ($30.27/boe) was $131.3 million ($10.16/boe) lower than $325.7 million ($40.43/boe) for Q4/2024 which reflects lower benchmark commodity prices along with the disposition of the Eagle Ford assets on December 19, 2025.

**Total Q4/2025 Financial Results**

We generated adjusted funds flow<sup>(2)</sup> of $261.5 million in Q4/2025 compared to $461.9 million in Q4/2024. The decrease in adjusted funds flow for Q4/2025 relative to Q4/2024 reflects lower benchmark pricing and the disposition of the U.S. operations on December 19, 2025. Proceeds from the disposition were used to repay all of our outstanding credit facilities and the majority of the long-term notes which resulted in net cash<sup>(2)</sup> was $765.8 million at Q4/2025 compared to net debt of $2.4 billion in Q4/2024.

We recorded a net loss of $856.9 million in Q4/2025 compared to net loss of $38.5 million in Q4/2024. The net loss for Q4/2025 includes the $510.6 million loss on the Eagle Ford disposition recorded net of the cumulative foreign exchange gain along with a $148.0 million impairment loss on our Viking CGU due to changes in proved plus probable reserves.

*(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.*

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 19

**QUARTERLY FINANCIAL INFORMATION**

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **2025** | **2025** | **2025** | **2025** | 2024 | 2024 | 2024 | 2024 |
| *($ thousands, except per common share amounts)* | **Q4** | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 |
| Total petroleum and natural gas sales | **759815** | 927648 | 886579 | 999130 | 1017017 | 1074623 | 1133123 | 984192 |
| Net (loss) income - continuing operations <sup>(3)</sup> | **(334057)** | (28451) | 103018 | (17355) | (124903) | 96204 | 13751 | (82505) |
| &nbsp;&nbsp;&nbsp;Per common share - basic | **(0.43)** | (0.04) | 0.13 | (0.02) | (0.16) | 0.12 | 0.02 | (0.10) |
| &nbsp;&nbsp;&nbsp;Per common share - diluted | **(0.43)** | (0.04) | 0.13 | (0.02) | (0.16) | 0.12 | 0.02 | (0.10) |
| Total net (loss) income | **(856887)** | 31968 | 151549 | 69591 | (38477) | 185219 | 103898 | (14043) |
| &nbsp;&nbsp;&nbsp;Per common share - basic | **(1.12)** | 0.04 | 0.20 | 0.09 | (0.05) | 0.23 | 0.13 | (0.02) |
| &nbsp;&nbsp;&nbsp;Per common share - diluted | **(1.12)** | 0.04 | 0.20 | 0.09 | (0.05) | 0.23 | 0.13 | (0.02) |
| Adjusted funds flow <sup>(1)</sup> | **261531** | 422232 | 366919 | 463870 | 461886 | 537947 | 532839 | 423846 |
| &nbsp;&nbsp;&nbsp;Per common share - basic | **0.34** | 0.55 | 0.48 | 0.60 | 0.59 | 0.68 | 0.65 | 0.52 |
| &nbsp;&nbsp;&nbsp;Per common share - diluted | **0.34** | 0.55 | 0.48 | 0.60 | 0.59 | 0.67 | 0.65 | 0.52 |
| Free cash flow <sup>(2)</sup> | **76486** | 142688 | 3188 | 52529 | 254838 | 220159 | 180673 | (88) |
| &nbsp;&nbsp;&nbsp;Per common share - basic | **0.10** | 0.19 |  | 0.07 | 0.33 | 0.28 | 0.22 |  |
| &nbsp;&nbsp;&nbsp;Per common share - diluted | **0.10** | 0.18 |  | 0.07 | 0.33 | 0.28 | 0.22 |  |
| Cash flows from operating activities | **227657** | 472676 | 354312 | 431317 | 468865 | 550042 | 505584 | 383773 |
| &nbsp;&nbsp;&nbsp;Per common share - basic | **0.30** | 0.62 | 0.46 | 0.56 | 0.60 | 0.69 | 0.62 | 0.47 |
| &nbsp;&nbsp;&nbsp;Per common share - diluted | **0.30** | 0.61 | 0.46 | 0.56 | 0.60 | 0.69 | 0.62 | 0.47 |
| Dividends declared | **17268** | 17326 | 17304 | 17289 | 17598 | 17732 | 18161 | 18494 |
| &nbsp;&nbsp;&nbsp;Per common share – basic | **0.0225** | 0.0225 | 0.0225 | 0.0225 | 0.0225 | 0.0225 | 0.0225 | 0.0225 |
| Exploration and development expenditures | **174078** | 270364 | 356532 | 405097 | 198177 | 306332 | 339573 | 412551 |
| &nbsp;&nbsp;&nbsp;Canada | **92720** | 123579 | 147734 | 184319 | 108971 | 120473 | 101916 | 158126 |
| &nbsp;&nbsp;&nbsp;U.S. | **81358** | 146785 | 208798 | 220778 | 89206 | 185859 | 237657 | 254425 |
| Property acquisitions | **5544** | 24024 | 1193 | 1257 | 12621 | 1042 | 3349 | 35403 |
| Proceeds from dispositions | **(3012058)** | (8254) | (725) | (2266) | (42339) | (1436) | (2695) | (25) |
| Net (cash) debt <sup>(1)</sup> | **(765785)** | 2244358 | 2293940 | 2390250 | 2417172 | 2493269 | 2639014 | 2639841 |
| Total assets | **3345414** | 7601389 | 7552013 | 7824576 | 7759745 | 7614157 | 7770926 | 7717495 |
| Common shares outstanding | **765568** | 768317 | 768317 | 770039 | 773590 | 787328 | 804977 | 821322 |
| **Daily production** |  |  |  |  |  |  |  |  |
| Total production (boe/d) | **137087** | 150950 | 148095 | 144194 | 152894 | 154468 | 154194 | 150620 |
| &nbsp;&nbsp;&nbsp;Continuing operations (boe/d) | **67295** | 68185 | 64167 | 62380 | 65332 | 64668 | 63688 | 62081 |
| &nbsp;&nbsp;&nbsp;Discontinued operations (boe/d) | **69792** | 82765 | 83928 | 81814 | 87562 | 89800 | 90506 | 88540 |
| **Benchmark prices** |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;WTI oil (US$/bbl) | **59.14** | 64.93 | 63.74 | 71.42 | 70.27 | 75.10 | 80.57 | 76.96 |
| &nbsp;&nbsp;&nbsp;WCS heavy ($/bbl) | **66.88** | 75.14 | 74.10 | 84.33 | 80.77 | 83.98 | 91.72 | 77.73 |
| &nbsp;&nbsp;&nbsp;Edmonton Light ($/bbl) | **76.49** | 86.20 | 84.15 | 95.27 | 94.98 | 97.91 | 105.30 | 92.16 |
| &nbsp;&nbsp;&nbsp;CAD/USD avg exchange rate | **1.3949** | 1.3774 | 1.3840 | 1.4350 | 1.3992 | 1.3636 | 1.3684 | 1.3488 |
| &nbsp;&nbsp;&nbsp;AECO gas ($/mcf) | **2.34** | 1.00 | 2.07 | 2.02 | 1.46 | 0.81 | 1.44 | 2.05 |
| &nbsp;&nbsp;Total sales, net of blending and other expense ($/boe) <sup>(2)</sup> | **56.28** | 63.22 | 61.16 | 71.38 | 66.60 | 71.97 | 75.93 | 67.12 |
| &nbsp;&nbsp;Royalties ($/boe) <sup>(4)</sup> | **(11.54)** | (13.05) | (13.16) | (16.02) | (14.69) | (15.75) | (17.14) | (15.26) |
| &nbsp;&nbsp;Operating expense ($/boe) <sup>(4)</sup> | **(12.51)** | (11.54) | (11.95) | (11.38) | (10.36) | (11.76) | (11.95) | (12.65) |
| &nbsp;&nbsp;Transportation expense ($/boe) <sup>(4)</sup> | **(2.43)** | (2.54) | (2.44) | (2.35) | (2.35) | (2.60) | (2.37) | (2.18) |
| **Operating netback ($/boe)** <sup>(2)</sup> | **29.80** | 36.09 | 33.61 | 41.63 | 39.20 | 41.86 | 44.47 | 37.03 |
| &nbsp;&nbsp;Financial derivatives gain (loss) ($/boe) <sup>(4)</sup> | **0.08** | (0.62) | (0.88) | (0.01) | (0.15) | 0.02 | (0.16) | 0.40 |
| **Operating netback after financial derivatives ($/boe)** <sup>(2)</sup> | **29.88** | 35.47 | 32.73 | 41.62 | 39.05 | 41.88 | 44.31 | 37.43 |

---

*(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)Previously disclosed amounts have been revised to conform with current period presentation.*

*(4)Calculated as royalties expense, operating expenses, transportation expense or financial derivatives gain or loss divided by barrels of oil equivalent production volume for the applicable period.*

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 20

Our results for the previous eight quarters reflect the disciplined execution of our capital programs while oil and natural gas prices have fluctuated along with acquisition and disposition activity. Production of 137,087 boe/d in Q4/2025 reflects the Eagle Ford disposition on December 19, 2025 which resulted in lower reported production compared to an average of approximately 151,000 boe/d over the previous seven quarters presented. Our successful light and heavy oil development programs in Canada resulted in production of 67,295 boe/d for Q4/2025 compared to 62,081 boe/d in Q1/2024 despite the Kerrobert Thermal disposition completed in Q4/2024.

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. Lower benchmark prices resulted in realized pricing of $56.28/boe for Q4/2025 and operating netback after financial derivatives of $29.88/boe. Adjusted funds flow is directly impacted by our average daily production and changes in benchmark commodity prices which are the basis for our realized sales price. Adjusted funds flow<sup>(1)</sup> of $261.5 million and cash flows from operating activities of $227.7 million for Q4/2025 reflect the disposition of the Eagle Ford assets on December 19, 2025 along with our realized pricing.

On December 19, 2025, we completed the disposition of the Eagle Ford assets which resulted in a net cash<sup>(1)</sup> position of $765.8 million at Q4/2025 compared to a net debt position of $2.6 billion at Q1/2024. The change in net (cash) debt also reflects free cash flow<sup>(2)</sup> of $930.6 million generated in the period since Q1/2024, along with $366.4 million allocated to shareholder returns.

*(1)Capital management measure. Refer to the Specified Financial Measures section in this MD&A for further information.*

*(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section in this MD&A for further information.*

**ENVIRONMENTAL REGULATIONS**

As a result of our involvement in the exploration for and production of oil and natural gas we are subject to various emissions, carbon and other environmental regulations. Refer to the AIF for the year ended December 31, 2025 for a full description of the risks associated with these regulations and how they may impact our business in the future.

**Reporting Regulations**

Environmental reporting for public enterprises continues to evolve and the Company may be subject to additional future disclosure requirements. The International Sustainability Standards Board ("ISSB") has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. The Canadian Sustainability Standards Board has released voluntary standards for reporting periods starting on or after January 1, 2025 that are aligned with the ISSB release and include suggestions for Canadian-specific modifications. The Canadian Securities Administrators ("CSA") have also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth additional reporting requirements for Canadian Public Companies. In April 2025, the CSA announced it is pausing development of new sustainability reporting requirements to allow issuers to adapt to recent developments in the U.S. and globally. Baytex continues to monitor developments on these reporting requirements and has not yet quantified the cost to comply with these regulations.

**OFF BALANCE SHEET TRANSACTIONS**

We do not have any material financial arrangements that are excluded from the consolidated financial statements as at December 31, 2025, nor are any such arrangements outstanding as of the date of this MD&A.

**CRITICAL ACCOUNTING ESTIMATES**

The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets, liabilities, revenues and expenses. These judgments, estimates and assumptions are based on all relevant information available, including considerations related to various regulatory and legislative requirements, to the Company at the time of financial statement preparation. Actual results could be materially different from those estimates as the effect of future events cannot be determined with certainty. Revisions to estimates are recognized prospectively. The key areas of judgment or estimation uncertainty that have a significant risk of causing material adjustment to the reported amounts of assets, liabilities, revenues, and expenses are discussed below.

**Reserves**

The Company uses estimates of oil, natural gas and NGL reserves in the calculation of depletion, evaluating the recoverability of deferred income tax assets and in the estimation of recoverable amount for non-financial assets. The process to estimate reserves is complex and requires significant judgment. Estimates of the Company's reserves are evaluated annually by an independent qualified reserves evaluator and represent the estimated recoverable quantities of oil, natural gas and NGL reserves and the

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 21

related cash flows. This evaluation of reserves is prepared in accordance with the reserves definition contained in National Instrument 51-101 *Standards of Disclosure for Oil and Gas Activities* and the Canadian Oil and Gas Evaluation Handbook.

Estimates of economically recoverable oil, natural gas and NGL reserves and the related cash flows are based on a number of factors and assumptions. Changes to estimates and assumptions such as forecasted commodity prices, production volumes, capital and operating costs and royalty obligations could have a significant impact on reported reserves. Other estimates include ultimate reserve recovery, marketability of oil and natural gas and other geological, economic and technical factors. Changes in the Company's reserves estimates can have a significant impact on the calculation of depletion, the recoverability of deferred income tax assets and in the estimation of recoverable amount estimates for non-financial assets.

**Cash-generating Units**

The Company's oil and gas properties are aggregated into CGUs which are the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. The aggregation of assets in CGUs requires management judgment and is based on geographical proximity, shared infrastructure and similar exposure to market risk.

**Identification of Impairment and Impairment Reversal Indicators**

Judgment is required to assess when indicators of impairment or impairment reversal exist and when a calculation of the recoverable amount is required. The CGUs comprising oil and gas properties are reviewed at each reporting date to assess whether there is any indication of impairment or impairment reversal. These indicators can be internal such as changes in estimated proved plus probable oil and gas reserves and internally estimated oil and gas resources, or external such as market conditions impacting discount rates or market capitalization. The assessment for each CGU considers significant changes in the forecasted cash flows including reservoir performance, the number of development locations and timing of development, forecasted commodity prices, production volumes, capital and operating costs and royalty obligations.

**Measurement of Recoverable Amounts**

If indicators of impairment or impairment reversal are determined to exist, the recoverable amount of an asset or CGU is calculated based on the higher of value-in-use ("VIU") and fair value less cost of disposal ("FVLCD"). These calculations require the use of estimates and assumptions including cash flows associated with proved plus probable oil and gas reserves and the discount rate used to present value future cash flows. Any changes to these estimates and assumptions could impact the calculation of the recoverable amount and the carrying value of assets.

**Asset Retirement Obligations**

The Company's provision for asset retirement obligations is based on estimated costs to abandon and reclaim wells and facilities, the estimated time period during which these costs will be incurred in the future, and risk-free discount rates and inflation rates derived from observable market data. The provision for asset retirement obligations represents management's best estimate of the present value of the future abandonment and reclamation costs required under current regulatory requirements. The timing of asset retirement obligation expenditures may occur earlier than estimated. The timing of asset retirement obligations is supported by externally evaluated reserves with consideration by the Company of regulatory requirements.

**Income Taxes**

Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and there are differing interpretations requiring management judgment. Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in future periods, which requires management judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future periods, which requires management judgment. Income tax filings are subject to audit and re-assessment and changes in facts, circumstances and interpretations of the standards may result in a material change to the Company's provision for income taxes.

**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 (cash) 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.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 22

**Non-GAAP Financial Measures**

*Total sales, net of blending and other expense and heavy oil, net of blending and other expense*

Total sales, net of blending and other expense and heavy oil, net of blending and other expense represent the total revenues and heavy oil revenues realized from produced volumes during a period, respectively. Total sales, net of blending and other expense is comprised of total petroleum and natural gas sales adjusted for blending and other expense. Heavy oil, net of blending and other expense is calculated as heavy oil sales less blending and other expense. We believe including the blending and other expense associated with purchased volumes is useful when analyzing our realized pricing for produced volumes against benchmark commodity prices.

The following table reconciles heavy oil, net of blending and other expense to amounts disclosed in the primary financial statements from continuing operations.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Years Ended December 31 | Years Ended December 31 |
| *($ thousands)* | **December 31, 2025** | September 30, 2025 | December 31, 2024 | **2025** | 2024 |
| Petroleum and natural gas sales | $**381556** | $437905 | $466706 | $**1684648** | $1874046 |
| Light oil and condensate <sup>(1)</sup> | **(83991)** | (99188) | (99679) | **(366523)** | (421383) |
| NGL <sup>(1)</sup> | **(8212)** | (7250) | (8438) | **(29583)** | (26017) |
| Natural gas sales <sup>(1)</sup> | **(9424)** | (2462) | (6310) | **(26643)** | (23624) |
| Heavy oil sales | $**279929** | $329005 | $352279 | $**1261899** | $1403022 |
| Blending and other expense - heavy oil <sup>(2)</sup> | **(50039)** | (49750) | (80148) | **(234990)** | (263943) |
| Heavy oil, net of blending and other expense - continuing operations | $**229890** | $279255 | $272131 | $**1026909** | $1139079 |

---

*(1)Component of petroleum and natural gas sales; see Note 15 Petroleum and Natural Gas Sales in the consolidated financial statements for the year ended December 31, 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 from continuing operations.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Years Ended December 31 | Years Ended December 31 |
| *($ thousands)* | **December 31, 2025** | September 30, 2025 | December 31, 2024 | **2025** | 2024 |
| Petroleum and natural gas sales | $**381556** | $437905 | $466706 | $**1684648** | $1874046 |
| Blending and other expense | **(50039)** | (49750) | (80148) | **(234990)** | (263943) |
| Total sales, net of blending and other expense | $**331517** | $388155 | $386558 | $**1449658** | $1610103 |
| Royalties | **(43132)** | (53645) | (60396) | **(203833)** | (261205) |
| Operating expense | **(85708)** | (84994) | (78878) | **(334317)** | (336069) |
| Transportation expense | **(21314)** | (23060) | (21595) | **(83697)** | (84211) |
| Operating netback - continuing operations | $**181363** | $226456 | $225689 | $**827811** | $928618 |
| Realized financial derivatives gain (loss) <sup>(1)</sup> | **1013** | (8580) | (2115) | **(19635)** | 1447 |
| Operating netback after realized financial derivatives - continuing operations | $**182376** | $217876 | $223574 | $**808176** | $930065 |

---

*(1)Realized financial derivatives gain or loss is a component of financial derivatives gain or loss; see Note 19 Financial Instruments and Risk Management in the consolidated financial statements for the year ended December 31, 2025 for further information.* 

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 23

*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 | Three Months Ended | Three Months Ended | Years Ended December 31 | Years Ended December 31 |
| *($ thousands)* | **December 31, 2025** | September 30, 2025 | December 31, 2024 | **2025** | 2024 |
| Cash flows from operating activities | $**227657** | $472676 | $468865 | $**1485962** | $1908264 |
| Change in non-cash working capital | **(226)** | (55961) | (13428) | **(18111)** | 17922 |
| Transaction costs | **26383** |  |  | **26383** | 1539 |
| Additions to exploration and evaluation assets | **—** |  |  | **(930)** |  |
| Additions to oil and gas properties | **(174078)** | (270364) | (198177) | **(1205141)** | (1256633) |
| Payments on lease obligations | **(3250)** | (3663) | (2422) | **(13272)** | (15510) |
| Free cash flow | $**76486** | $142688 | $254838 | $**274891** | $655582 |

---

**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 (cash) debt* 

We use net (cash) debt to monitor our current financial position and to evaluate existing sources of liquidity. We also use net (cash) debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations. Net (cash) 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.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 24

The following table summarizes our calculation of net (cash) debt.

---

| | | | |
|:---|:---|:---|:---|
| | As at | As at | As at |
| *($ thousands)* | **December 31, 2025** | September 30, 2025 | December 31, 2024 |
| Credit Facilities | $**1138** | $166841 | $324346 |
| Unamortized debt issuance costs - Credit Facilities <sup>(1)</sup> | **262** | 15504 | 16861 |
| Long-term notes | **93834** | 1815230 | 1932890 |
| Unamortized debt issuance costs - Long-term notes <sup>(1)</sup> | **2113** | 40375 | 47729 |
| Trade payables | **236373** | 554057 | 512473 |
| Share-based compensation liability | **34802** | 24666 | 24732 |
| Dividends payable | **17268** | 17326 | 17598 |
| Other long-term liabilities | **—** | 20163 | 20887 |
| Cash | **(953113)** | (10417) | (16610) |
| Trade receivables | **(135230)** | (324287) | (387266) |
| Prepaids and other assets | **(63232)** | (75100) | (76468) |
| Net (cash) debt | $**(765785)** | $2244358 | $2417172 |

---

*(1)Unamortized debt issuance costs were obtained from Note 9 Credit Facilities and Note 10 Long-term Notes from the consolidated financial statements for the year ended December 31, 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, transaction costs and cash premiums on derivatives.

Adjusted funds flow is reconciled to amounts disclosed in the primary financial statements in the following table.

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | Three Months Ended | Three Months Ended | Three Months Ended | Years Ended December 31 | Years Ended December 31 |
| *($ thousands)* | **December 31, 2025** | September 30, 2025 | December 31, 2024 | **2025** | 2024 |
| Cash flows from operating activities | $**227657** | $472676 | $468865 | $**1485962** | $1908264 |
| Change in non-cash working capital | **(226)** | (55961) | (13428) | **(18111)** | 17922 |
| Asset retirement obligations settled | **7717** | 5517 | 6449 | **20318** | 28793 |
| Transaction costs | **26383** |  |  | **26383** | 1539 |
| Adjusted funds flow | $**261531** | $422232 | $461886 | $**1514552** | $1956518 |

---

**CONTROLS AND PROCEDURES**

**Disclosure Controls and Procedures**

As of December 31, 2025, an evaluation was conducted to determine the effectiveness of our "disclosure controls and procedures" (as defined in the United States by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act") and in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings ("NI 52-109")) under the supervision of and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer of Baytex (collectively the "certifying officers"). Based on that evaluation, the certifying officers concluded that our disclosure controls and procedures are effective to ensure that the information required to be disclosed in the reports that we file or submit under the Exchange Act or under Canadian securities legislation is (i) recorded, processed, summarized and reported within the time periods specified in the applicable rules and forms and (ii) accumulated and communicated to our management, including the certifying officers, to allow timely decisions regarding the required disclosure.

It should be noted that while the certifying officers believe that our disclosure control and procedures provide a reasonable level of assurance that they are effective, they do not expect that our disclosure controls and procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute assurance that the objectives of the control system are met.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 25

**Internal Control Over Financial Reporting**

Management is responsible for establishing and maintaining adequate internal control over the Company's financial reporting. Internal control over our financial reporting is a process designed under the supervision of and with the participation of management, including the certifying officers, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation.

Management has assessed the effectiveness of our "internal control over financial reporting" as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act and as defined by NI 52-109. The assessment was based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded that our internal control over financial reporting was effective as of December 31, 2025.

The effectiveness of our internal control over financial reporting as of December 31, 2025 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their Report of Independent Registered Public Accounting Firm.

**Changes in Internal Control over Financial Reporting**

No changes were made to our internal control over financial reporting during the year ended December 31, 2025 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

**SELECTED ANNUAL INFORMATION**

The following table summarizes key annual financial and operating information over the three most recently completed financial years.

---

| | | | |
|:---|:---|:---|:---|
| *($ thousands, except per common share amounts)* | **2025** | 2024 | 2023 |
| Revenues, net of royalties - continuing operations | **1480815** | 1612841 | 1515873 |
| Total revenues, net of royalties | **2861034** | 3328869 | 2712829 |
| Adjusted funds flow <sup>(1)</sup> | **1514552** | 1956518 | 1594350 |
| &nbsp;&nbsp;&nbsp;Per common share - basic | **1.97** | 2.44 | 2.26 |
| &nbsp;&nbsp;&nbsp;Per common share - diluted | **1.97** | 2.42 | 2.26 |
| Net (loss) income - continuing operations | **(276845)** | (97453) | (40641) |
| &nbsp;&nbsp;&nbsp;Per common share - basic | **(0.36)** | (0.12) | (0.06) |
| &nbsp;&nbsp;&nbsp;Per common share - diluted | **(0.36)** | (0.12) | (0.06) |
| Total net (loss) income | **(603779)** | 236597 | (233356) |
| &nbsp;&nbsp;&nbsp;Per common share - basic | **(0.78)** | 0.29 | (0.33) |
| &nbsp;&nbsp;&nbsp;Per common share - diluted | **(0.78)** | 0.29 | (0.33) |
| Dividends declared | **69187** | 71985 | 37519 |
| &nbsp;&nbsp;&nbsp;Per common share – basic | **0.090** | 0.090 | 0.045 |
| Total assets | **3345414** | 7759745 | 7460931 |
| Credit facilities - principal | **1400** | 341207 | 864736 |
| Long-term notes - principal | **95947** | 1980619 | 1597475 |
| Total sales, net of blending and other expense ($/boe) <sup>(2)</sup> | **63.04** | 70.43 | 70.82 |
| Total production (boe/d) | **145079** | 153048 | 122154 |

---

*(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.*

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 26

**FORWARD-LOOKING STATEMENTS**

*In the interest of providing our shareholders and potential investors with information regarding Baytex, including management's assessment of the Company's future plans and operations, certain statements in this document are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). In some cases, forward-looking statements can be identified by terminology such as "anticipate", "believe", "continue", "could", "estimate", "expect", "forecast", "intend", "may", "objective", "ongoing", "outlook", "potential", "plan", "project", "should", "target", "would", "will" or similar words suggesting future outcomes, events or performance. The forward-looking statements contained in this document speak only as of the date of this document and are expressly qualified by this cautionary statement.*

*Specifically, this document contains forward-looking statements relating to but not limited to: our 2026 guidance for: exploration and development expenditures, average daily production, royalty rate and operating expense, transportation expense, lease expenditures and asset retirement obligations settled; the 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; that our exploration and development spending in 2026 is designed to generate production growth and support our development plans; our objective to maintain a strong financial position to execute development programs, deliver shareholder returns and optimize our portfolio through strategic acquisitions; that we may from time to time, issue or repurchase debt or equity securities, enter into business transactions or adjust capital spending to manage liquidity; our intent to fund certain financial obligations with cash flow from operations, the expected timing of the financial obligations and the potential for losses associated with claims. 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, 2025, to be filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission not later than March 31, 2026 and in our other public filings.*

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 27

*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.*

**RISK FACTORS**

We are focused on long-term strategic planning and have identified key risks, uncertainties and opportunities associated with our business that can impact the financial and operational results. Listed below is a description of these risks and uncertainties.

**Risks Relating to Our Business and Operations**

***Crude oil and natural gas prices are volatile. An extended period of low oil and natural gas prices could have a material adverse effect on the Company's business, results of operations, or cash flows and financial condition***

Our financial condition is substantially dependent on, and highly sensitive to, the prevailing prices of crude oil and natural gas. Low prices for crude oil and natural gas produced by us could have a material adverse effect on our operations, financial condition and the value and amount of our reserves.

Prices for crude oil and natural gas fluctuate in response to changes in the supply of, and demand for, crude oil and natural gas, market uncertainty and a variety of additional factors beyond our control. Crude oil prices are primarily determined by international supply and demand. Factors which affect crude oil prices include the actions of OPEC, OPEC+, the condition of the Canadian, United States, European and Asian economies, the impacts of geopolitical events, including the Russian Ukrainian war, geopolitical developments in Venezuela and conflicts and hostilities in the Middle East, the imposition of tariffs or other adverse economic or political development in the United States, Europe, the Middle East, Africa, South America or Asia, the impact of pandemics/epidemics, government regulation, the supply of crude oil in North America and internationally, the ability to secure adequate transportation for products, the availability of alternate fuel sources and weather conditions. Additionally, the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. Natural gas prices realized by us are affected primarily in North America by supply and demand, weather conditions, industrial demand, prices of alternate sources of energy and developments related to the market for liquefied natural gas.

In particular, tariffs or other restrictive measures or countermeasures affecting trade between Canada and the United States and between the United States and other countries, if implemented for any period of time, could have a significant impact on the market for oil and natural gas products, especially with respect to oil and gas produced in Canada, and could result in, among other things, price volatility, an increase to the cost of materials used in oil and gas operations, a relative weakening of the Canadian dollar, widening differentials, and decreased demand due to lower economic activity. For more information with respect to tariffs, see "*Industry Conditions - Tariffs*" in the AIF for the year ended December 31, 2025.

All of these factors are beyond our control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further compound this volatility when commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 28

Our financial performance also depends on revenues from the sale of commodities which differ in quality and location from underlying commodity prices quoted on financial exchanges. Of particular importance are the price differentials between our light/medium crude oil and heavy crude oil (in particular the light/heavy differential) and quoted market prices. Not only are these discounts influenced by regional supply and demand factors, they are also influenced by other factors such as transportation costs, capacity and interruptions, refining demand, storage capacity, the availability and cost of diluents used to blend and transport product and the quality of the oil produced, all of which are beyond our control. In addition, there is not sufficient pipeline capacity for Canadian crude oil to access the American refinery complex or tidewater to access world markets and the availability of additional transport capacity via rail is more expensive and variable, therefore, the price for Canadian crude oil is very sensitive to pipeline and refinery outages, which contributes to this volatility.

Decreases to or prolonged periods of low commodity prices, particularly for oil, may negatively impact our ability to meet guidance targets, maintain our business and meet all of our financial obligations as they come due. It could also result in the shut-in of currently producing wells without an equivalent decrease in expenses due to fixed costs, a delay or cancellation of existing or future drilling, development or construction programs, un-utilized long-term transportation commitments and a reduction in the value and amount of our reserves.

We conduct assessments of the carrying value of our assets in accordance with IFRS. If crude oil and natural gas forecast prices change, the carrying value of our assets could be subject to revision and our net earnings could be adversely affected.

***Our success is highly dependent on our ability to develop existing properties and add to our oil and natural gas reserves***

Our oil and natural gas reserves are a depleting resource and decline as such reserves are produced. As a result, our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Future oil and natural gas exploration may involve unprofitable efforts, not only from unsuccessful wells, but also from wells that are productive but do not produce sufficient hydrocarbons to return a profit. Completion of a well does not assure a profit on the investment. Drilling hazards or environmental liabilities or damages and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells. Field operating conditions include, but are not limited to, delays or failure in obtaining governmental, landowner or other stakeholder approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow from operating activities to varying degrees.

There is no assurance we will be successful in developing our reserves or acquiring additional reserves at acceptable costs. Without these reserves additions, our reserves will deplete and as a consequence production from and the average reserve life of our properties will decline, which may adversely affect our business, financial condition, results of operations and prospects.

***The amount of oil and natural gas that we can produce and sell is subject to the availability and cost of gathering, processing and pipeline systems***

We deliver our products through gathering, processing and pipeline systems to which we do not own and purchasers of our products rely on third party infrastructure to deliver our products to market. The lack of access to capacity in any of the gathering, processing and pipeline systems could result in our inability to realize the full economic potential of our production or in a reduction of the price offered for our production. Alternately, a substantial decrease in the use of such systems can increase the cost we incur to use them. In addition, many of the pipeline systems that we use are controlled by a single company and rates are set through a regulatory process, as a result we are subject to the outcome of those regulatory processes. Any significant change in market factors, regulatory decisions or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could harm our business and, in turn, our financial condition.

Access to the pipeline capacity for the export of crude oil from Canada has, at times, been inadequate for the amount of Canadian production being exported. This has resulted in significantly lower prices being realized by Canadian producers compared with the WTI price and the Brent price for crude oil. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability to export oil and natural gas from Canada. There can be no certainty that current investment in pipelines will provide sufficient long-term take-away capacity or that currently operating systems will remain in service. There is also no certainty that short-term operational constraints on pipeline systems, arising from pipeline interruption and/or increased supply of crude oil, will not occur.

There is no certainty that crude-by-rail transportation and other alternative types of transportation for our production will be sufficient to address any gaps caused by operational constraints on pipeline systems. In addition, our crude-by-rail shipments may be impacted by service delays, inclement weather, derailment or blockades and could adversely impact our crude oil sales volumes or the price received for our product. Crude oil produced and sold by us may be involved in a derailment or incident that results in legal liability or reputational harm.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 29

A portion of our production may be processed through facilities controlled by third parties. From time to time these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuance or decrease of operations could materially adversely affect our ability to process our production and to deliver the same for sale.

***Water use restrictions and/or limited access to water or other fluids may impact the Company's ability to fracture its wells or carry out waterflood operations***

The Company undertakes or intends to undertake certain hydraulic fracturing, SAGD, CSS and waterflooding programs. To undertake such operations the Company needs to have access to sufficient volumes of water, or other liquids. There is no certainty that the Company will have access to the required volumes of water. In addition, in certain areas there may be restrictions on water use for activities such as hydraulic fracturing, SAGD, CSS and waterflooding. If the Company is unable to access such water it may not be able to undertake hydraulic fracturing, SAGD, CSS or waterflooding activities, which may reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves.

***The anticipated benefits of acquisitions may not be achieved and the Company may dispose of assets for less than their carrying value on the financial statements***

Acquisition of oil and gas properties is a key element of maintaining and growing reserves and production and the success of any acquisition will depend on several factors and involves potential risks and uncertainties. Competition for these assets has been and will continue to be intense. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive candidates, we may not be able to complete the acquisition or do so on commercially acceptable terms. Achieving the benefits of acquisitions depends on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner and the Company's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Company. The integration of acquired businesses and assets may require substantial management effort, time and resources diverting management's focus from other strategic opportunities and operational matters. Additionally, significant acquisitions can change the nature of our operations and business if acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties. To the extent that acquired properties are substantially different than our existing properties, our ability to efficiently realize the expected economic benefits of such transactions may be limited.

Even though we assess and review the properties we seek to acquire in a manner consistent with what we believe to be industry practice, such reviews are limited in scope, inexact and not capable of identifying all existing or potentially adverse conditions. As a result, the anticipated and desired benefits of an acquisition may not materialize, and may have a material and adverse effect on our business, financial performance and results of operations.

Management continually assesses the value and contribution of its Company's assets. In this regard, certain assets may be periodically disposed of so that the Company can focus its efforts and resources more efficiently. Depending on the state of the market for such assets, certain assets of the Company, if disposed of, may realize less on disposition than their carrying value on the financial statements of the Company.

***Variations in foreign exchange rates could adversely affect our financial condition***

World oil prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canada/U.S. foreign exchange rate that may fluctuate over time. A material increase in the value of the Canadian dollar may negatively impact our production revenues. Future Canadian/U.S. exchange rates could accordingly impact the future value of Baytex's reserves as determined by independent reserves evaluators. Although a low value of the Canadian dollar relative to the U.S. dollar may positively impact the price the Company receives for crude oil and natural gas production it could also result in an increase in the price of certain goods used in operations which may have a negative impact on the Company's financial results.

***Availability and cost of capital or borrowing to maintain and/or fund future development and acquisitions***

The business of exploring for, developing or acquiring reserves is capital intensive. If external sources of capital (including, but not limited to, debt and equity financing) become limited or unavailable on commercially reasonable terms, our ability to make the necessary capital investments to maintain or expand our oil and natural gas reserves may be impaired. Unpredictable financial markets and the associated credit impacts may impede our ability to secure and maintain cost effective financing and limit our ability to achieve timely access to capital on acceptable terms and conditions. If external sources of capital become limited or unavailable, our ability to make capital investments, continue our business plan, meet all of our financial obligations as they come due and maintain existing properties may be impaired.

Our ability to obtain additional capital is dependent on, among other things, a general interest in energy industry investments and, in particular, interest in our securities. If we are unable to maintain our indebtedness and financial ratios at levels acceptable to investors, or should our business prospects deteriorate, our ability to access additional capital could decrease. Additionally, from time to time, our securities may not meet the investment criteria or characteristics of a particular institutional or other investor,

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 30

including institutional investors who are not willing or able to hold securities of oil and gas companies for reasons unrelated to financial or operational performance. This may include changes to market-based factors or investor strategies, including ESG, or responsible investing criteria/rankings (for example, ESG, social impact or environmental scores), the implementation of new financial market regulations and fossil fuel divestment initiatives undertaken by governments, pension funds and/or other institutional investors. These events would adversely affect the value of our outstanding securities and existing debt and our ability to obtain new financing, and may increase our borrowing costs.

From time to time, we may enter into transactions which may be financed in whole or in part with debt or equity. The level of our indebtedness, from time to time, could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise. Additionally, from time to time, we may issue securities from treasury in order to reduce debt, complete acquisitions and/or optimize our capital structure.

***There are numerous uncertainties inherent in estimating quantities of recoverable oil and natural gas reserves, including many factors beyond our control***

The reserves estimates included in the AIF for the year ended December 31, 2025 are estimates only. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable oil and natural gas reserves and the future net revenues therefrom are based upon a number of factors and assumptions made as of the date on which the reserves estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies, historical production from the properties, initial production rates, production decline rates, the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities and estimates of future commodity prices and capital costs, all of which may vary considerably from actual results.

All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our reserves as at December 31, 2025 are estimated using forecast prices and costs as set forth under *"Statement of Reserves Data - Pricing Assumptions"* in the AIF for the year ended December 31, 2025. If we realize lower prices for crude oil, natural gas liquids and natural gas and they are substituted for the estimated price assumptions, the present value of estimated future net revenues for our reserves and net asset value would be reduced and the reduction could be significant. Our actual production, revenues, royalties, taxes and development, abandonment and operating expenditures with respect to our reserves will likely vary from such estimates, and such variances could be material.

Estimates of reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Reserve reports based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations in the previously estimated reserves and such variances could be material.

***Restrictions and/or costs associated with regulatory initiatives to combat climate change and the physical risks of climate change may have a material adverse affect on our business***

*Regulatory and Policy Initiatives*

Our exploration and production facilities and other operational activities emit GHGs. As such, GHG emissions regulation (including carbon taxes) enacted in jurisdictions where we operate will impact us. In addition, certain of our assets have a higher GHG emissions intensity than others and may be disproportionately impacted.

Negative consequences which could result from new GHG emissions regulation include, but are not limited to: increased operating costs, additional taxes, increased construction and development costs, additional monitoring and compliance costs, a requirement to redesign or retrofit current facilities, permitting delays, additional costs associated with the purchase of emission credits or allowances, the availability to use necessary third-party services and facilities that we rely on, and reduced demand for crude oil. Additionally, if GHG emissions regulation differs by region or type of production, all or part of our production could be subject to costs which are disproportionately higher than those of other producers.

The direct or indirect costs of compliance with GHG emissions regulation may have a material adverse affect on our business, financial condition, results of operations and prospects. At this time, it is not possible to predict whether compliance costs will have a material adverse affect on our financial condition, results of operations or prospects.

Although we provide for the necessary amounts in our annual capital budget to fund our currently estimated obligations, there can be no assurance that we will be able to satisfy our actual future obligations associated with GHG emissions from such funds. For more information on the evolution and status of climate change and related environmental legislation, see "*Industry Conditions - Climate Change Regulation and Litigation*" in the AIF for the year ended December 31, 2025.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 31

*Physical Risk*

Climate change has been linked to extreme weather conditions. Extreme hot and cold weather, heavy snowfall, heavy rain fall, hurricanes, drought and wildfires may restrict our ability to access our properties, cause operational difficulties including damage to machinery and facilities. Extreme weather also increases the risk of personnel injury as a result of dangerous working conditions. Certain assets are located where they are exposed to forest fires, floods, heavy rains, hurricanes, drought and other extreme weather conditions which can lead to significant downtime, damage to such assets and/or increased costs of construction and maintenance. Moreover, extreme weather conditions may lead to disruptions in our ability to transport produced oil and natural gas as well as goods and services in our supply chain.

***An energy transition that lessens demand for petroleum products may have an adverse affect on our business***

A transition away from the use of petroleum products, which may include conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and renewable energy, could reduce demand for oil and natural gas. Certain jurisdictions have implemented policies or incentives to decrease the use of fossil fuels and encourage the use of renewable fuel alternatives, which may lessen demand for petroleum products and put downward pressure on commodity prices. In addition, advancements in energy efficient products have a similar effect on the demand for oil and gas products. The Company cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Company's business and financial condition by decreasing its cash flow from operating activities and the value of its assets.

***Failure to retain or replace our leadership and key personnel may have an adverse affect on our business***

Our success is dependent upon our management, our leadership capabilities and the quality and competency of our talent. Contributions of the existing management team to the immediate and near-term operations of the Company are likely to be of central importance. In addition, certain of the Company's current employees may have significant institutional knowledge that must be transferred to other employees prior to their departure from the workforce. If we are unable to retain key personnel and critical talent or to attract and retain new talent with the necessary leadership, professional and technical competencies, it could have a material adverse effect on our financial condition, results of operations and prospects.

***Income tax laws or other laws or government incentive programs or regulations relating to our industry may in the future be changed or interpreted in a manner that adversely affects us and our Shareholders***

Income tax laws and government incentive programs relating to the oil and gas industry may change in a manner that adversely affects our financial condition, results of operations and prospects.

In addition, tax authorities having jurisdiction over us or our Shareholders may disagree with the manner in which we calculate our income for tax purposes or could change their administrative practices to our detriment or the detriment of our Shareholders. We file all required income tax returns and believe that we are in full compliance with the applicable tax legislation. However, such returns are subject to audit and reassessment by the applicable taxation authority. At present, the Canadian tax authorities have reassessed the returns of certain of our subsidiaries. For further details, see "Legal Proceedings and Regulatory Actions" in the AIF for the year ended December 31, 2025. Any such reassessment may have an impact on current and future taxes payable. We believe appropriate provisions for current and deferred income taxes have been made in our consolidated financial statements; however, it is difficult to predict the outcome of audit findings by tax authorities or their final adjudication by the courts. These findings may increase the amount of our tax liabilities and adversely affect our business, financial condition and results of operations.

***We may participate in larger projects and may have more concentrated risk in certain areas of our operations***

We have a variety of exploration, development and construction projects underway at any given time. Project delays may result in delayed revenue receipts and cost overruns may result in projects being uneconomic. Our ability to complete projects is dependent on general business, community relationships and market conditions as well as other factors beyond our control, including the availability of skilled labour and manpower, the availability and proximity of pipeline capacity and rail terminals, weather, environmental and regulatory matters, ability to access lands, availability of drilling and other equipment and supplies, and availability of processing capacity.

***We could experience adverse impacts associated with a high concentration of activity and tighter drilling spacing***

We are subject to drilling, completion and operating risks, including our ability to efficiently execute large-scale project development, as we could experience delays, curtailments and other adverse impacts associated with a high concentration of activity and tighter drilling spacing. A higher concentration of activity and tighter drilling spacing may increase the frequency of operational shut-ins and unintentional communication with other adjacent wells and reduce the total recoverable reserves from the reservoir.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 32

***Our financial performance is significantly affected by the cost of developing and operating our assets***

Our development and operating costs are affected by a number of factors including, but not limited to: price inflation, increased costs due to tariffs, access to skilled and unskilled labour, availability of equipment, scheduling delays, trucking and fuel costs, failure to maintain quality construction standards, the cost of new technologies and supply chain disruptions. Labour costs, natural gas, electricity, water, diluent and chemicals are examples of some of the operating and other costs that are susceptible to significant fluctuation. Increases to development and operating costs could have a material adverse effect on our financial condition, results of operations or prospects.

***Our information technology systems are subject to certain risks***

We utilize and have become increasingly dependent upon a number of information technology systems for the administration and management of our business and are subject to a variety of information technology and system risks as a part of our normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Company's information technology systems by third parties or insiders. If our ability to access and use these systems is interrupted and cannot be quickly and easily restored then such event could have a material adverse effect on us. Furthermore, although the Company has security measures and controls in line with industry-accepted standards in place to mitigate these risks, a breach of its security measures disruption of critical information technology services, and/or a loss of information could occur and result in a loss of material and confidential information and reputation, breach of privacy laws, and/or disruption to business activities. The significance of any such event is difficult to quantify but may in certain circumstances be material and could have a material adverse effect on the Company's business, financial condition, results of operations or our reputation, and any damages may not be adequately covered by the Company's current insurance coverage. In addition, our vendors, suppliers and other businesses partners may separately suffer disruptions as a result of such security breaks which may directly or indirectly affect our business activities.

The Company's IT systems may incorporate artificial intelligence ("AI"), and development of these capabilities is ongoing. AI introduces risks and unintended consequences that could affect adoption and business operations. Algorithms and training methods may be flawed, and reliance on AI without adequate safeguards can lead to inaccurate outcomes or operational vulnerabilities.

AI also poses data privacy, cyber-security, and intellectual property risks. Improper use may result in unauthorized disclosure of sensitive information or outputs that infringe copyrights, patents, or privacy rights. As legal and regulatory frameworks for AI remain uncertain, future compliance obligations could impose significant costs or limit the Company's ability to integrate AI tools.

***Adverse results from litigation may have an adverse affect on our business and reputation***

In the normal course of our operations, we currently are and from time to time in the future may become involved in, be named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions. In addition, we retained liability for certain legal proceedings related to our prior ownership of assets located in the U.S. Potential litigation may develop in relation to personal injuries, including resulting from exposure to hazardous substances, property damage, property taxes, land and access rights, and environmental issues, including claims relating to contamination or natural resource damages and contract disputes.

The Company establishes legal provisions for known and potential claims for which payment is probable and can be reliably estimated. The Company also has comprehensive liability insurance coverage; however such insurance does not cover all risks to which we might be exposed and in other cases, may only partially cover losses incurred by the Company. The outcome with respect to outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to us and could have a material adverse effect on our assets, liabilities, business, financial condition and results of operations. Furthermore, even if we prevail in any such legal proceedings, the proceedings could be costly and time-consuming and may divert the attention of management and key personnel from business operations, which could have an adverse effect on our financial condition. For further details, see "*Legal Proceedings and Regulatory Actions*" in the AIF for the year ended December 31, 2025.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 33

***Current or future controls, legislation or regulations applicable to the oil and gas industry could adversely affect us***

*Operations*

The oil and gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, completion operations, including the use of hydraulic fracturing, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government. All such controls, regulations and legislation are subject to revocation, amendment or administrative change, some of which have historically been material and in some cases materially adverse. The exercise of discretion by governmental authorities under existing controls, legislation or regulations, the implementation of new controls, legislation or regulations or the modification of existing controls, legislation or regulations affecting the oil and gas industry could reduce demand for crude oil and natural gas, increase our costs, or delay or restrict our operations, all of which would have a material adverse effect on our financial condition, results of operations or prospects. See "*Industry Conditions*" in the AIF for the year ended December 31, 2025.

*Environment*

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state, provincial and local laws and regulations. Environmental legislation provides for, among other things, the initiation and approval of new oil and natural gas projects, and restrictions and prohibitions on the spill, release or emission of various substances produced in association with oil and natural gas industry operations. In addition, such legislation sets out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well and facility sites. New environmental legislation at the federal, state, and provincial levels may increase uncertainty among oil and natural gas industry participants as the new laws are implemented, and the effects of the new rules and standards are felt in the oil and natural gas industry. See "*Industry Conditions*" in the AIF for the year ended December 31, 2025.

Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liabilities and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. Although the Company believes that it is in material compliance with current applicable environmental legislation, no assurance can be given that environmental compliance requirements will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

*The Company may have to pay certain costs associated with abandonment and reclamation*

The Company will need to comply with the terms and conditions of environmental and regulatory approvals and all legislation regarding the abandonment of its projects and reclamation of the project lands at the end of their economic life, which may result in substantial abandonment and reclamation costs. Any failure to comply with the terms and conditions of the Company's approvals and legislation may result in the imposition of fines and penalties, which may be material. Generally, abandonment and reclamation costs are substantial. The Company records a provision for abandonment and reclamation costs in its consolidated financial statements, this provision requires significant judgment and reflects the Company's best estimate of the costs to complete the required abandonment and reclamation work. Actual results may be significantly different than the estimated amounts.

*Foreign Investment and Competition Act Legislation*

In addition to regulatory requirements mentioned above, our business and financial condition could be influenced by federal legislation affecting, in particular, foreign investment, through legislation such as the *Competition Act* (Canada) and the *Investment Canada Act* (Canada).

***New regulations on hydraulic fracturing may lead to operational delays, increased costs and/or decreased production volumes***

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate the production of oil and natural gas. Specifically, hydraulic fracturing enables the production of commercial quantities of oil and natural gas from reservoirs that were previously unproductive. Hydraulic fracturing has featured prominently in recent political, media and activist commentary on the subject of water usage, induced seismicity events and environmental damage. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs, third party or governmental claims, and could increase the Company's costs of compliance and doing business as well as delay the development of oil and natural gas resources from shale formations, which are not commercial without the use of

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 34

hydraulic fracturing, or could effectively prevent the development of crude oil and natural gas. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

***Regulations regarding the disposal of fluids used in the Company's operations may increase its costs of compliance or subject it to regulatory penalties or litigation***

The safe disposal of hydraulic fracturing fluids (including the additives) and water recovered from oil and natural gas wells is subject to ongoing regulatory review by the federal, provincial and state governments, including its effect on fresh water supplies and the ability of such water to be recycled, amongst other things. While it is difficult to predict the impact of any regulations that may be enacted in response to such review, the implementation of stricter regulations may increase the Company's costs of compliance.

***Acquiring, developing and exploring for oil and natural gas involves many physical hazards. We have not insured and cannot fully insure against all risks related to our operations***

Our crude oil and natural gas operations are subject to all of the risks normally incidental to the: (i) storing, transporting, processing, refining and marketing of crude oil, natural gas and other related products; (ii) drilling and completion of crude oil and natural gas wells; including horizontal multi-well pad developments; and (iii) operation and development of crude oil and natural gas properties, including, but not limited to: encountering unexpected formations or pressures, premature declines of reservoir pressure or productivity, blowouts, fires, explosions, equipment failures and other accidents, gaseous leaks, uncontrollable or unauthorized flows of crude oil, natural gas or well fluids, migration of harmful substances, oil spills, corrosion, adverse weather conditions, pollution, acts of vandalism, theft and terrorism and other adverse risks to the environment.

If any of the foregoing risks were to materialize, we could sustain material losses as a result of injury or loss of life, damage to, or destruction of, property, natural resources or equipment, including the costs of repair or replacement, pollution or other environmental harm, interruptions to our ongoing operations, including the reduction or shutting-in of existing production, regulatory investigations and administrative, civil and criminal penalties, and limitation or suspension of current or future operations.

Although we maintain insurance in accordance with customary industry practice, we are not fully insured against all of these risks nor are all such risks insurable and in certain circumstances we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. In addition, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect on our business, financial condition, results of operations and prospects.

***Our thermal heavy oil projects face additional risks compared to conventional oil and gas production***

Our thermal heavy oil projects are capital intensive projects which rely on specialized production technologies. Certain current technologies for the recovery of heavy oil, such as CSS and SAGD, are energy intensive, requiring significant consumption of natural gas and other fuels in the production of steam that is used in the recovery process. The amount of steam required in the production process varies and therefore impacts costs. The performance of the reservoir can also affect the timing and levels of production using new technologies. A large increase in recovery costs could cause certain projects that rely on CSS, SAGD or other new technologies to become uneconomic, which could have an adverse effect on our financial condition and our reserves. There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies cannot be assured.

Project economics and our earnings may be reduced if increases in operating costs are incurred. Factors which could affect operating costs include, without limitation: the costs imposed by GHG emissions regulations, labour costs, the cost of catalysts and chemicals, the cost of natural gas and electricity, water handling and availability, power outages, produced sand causing issues of erosion, hot spots and corrosion, reliability of facilities, maintenance costs, the cost to transport sales products and the cost to dispose of certain by-products.

***We may be unable to compete successfully with other organizations in the oil and natural gas industry, or obtain required vendor services to compete***

The oil and natural gas industry is highly competitive in all of its phases. The Company competes with numerous other entities in the exploration for, and the development, production and marketing of, oil and natural gas, as well as for capital, acquisitions of reserves and/or resources, undeveloped lands, skilled/qualified labour, access to drilling rigs, service rigs and other equipment and materials such as drilling rigs, hydraulic fracturing pumping equipment and related skilled personnel, access to processing facilities, pipeline and refining capacity, as well as many other services, and in many other respects, with a substantial number of other organizations, many of which may have greater technical and financial resources than the Company. As a result, such competition can significantly increase costs and some of the Company's competitors may have greater opportunities and be able to access, services or vendors that the Company is not able to access, thereby limiting its ability to compete.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 35

***Our Credit Facilities may not provide sufficient liquidity and a failure to renew our Credit Facilities at maturity could adversely affect our financial condition***

Our Credit Facilities and any replacement credit facilities may not provide sufficient liquidity. The amounts available under our Credit Facilities may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms, if at all. There can be no assurance that the amount of our Credit Facilities will be adequate for our future financial obligations, including future capital expenditures, or that we will be able to obtain additional funds. In the event we are unable to refinance our debt obligations, it may impact our ability to fund ongoing operations. In the event that the Credit Facilities are not extended prior to maturity, indebtedness under the Credit Facilities will be repayable at that time. There is also a risk that the Credit Facilities will not be renewed for the same amount or on the same terms. See "*Description of Capital Structure*" in the AIF for the year ended December 31, 2025.

***Expansion into New Activities***

Our operations and the expertise of our management are currently focused primarily on oil and natural gas production, exploration and development in the Provinces of Alberta and Saskatchewan. In the future, we may acquire or move into new industry related activities or new geographical areas and may acquire different energy-related assets. As a result, we may face unexpected risks or, alternatively, our exposure to one or more existing risk factors may be significantly increased, which may in turn result in our future operational and financial conditions being adversely affected.

***Indigenous Land and Rights Claims***

Opposition by Indigenous groups to the conduct of the Company's operations, development or exploratory activities in any of the jurisdictions in which the Company conducts business may negatively impact it in terms of public perception, diversion of management's time and resources, and legal and other advisory expenses, and could adversely impact the Company's progress and ability to explore and develop properties.

Indigenous peoples have claimed Indigenous rights and title in portions of Western Canada. We are not aware that any claims have been made in respect of our properties and assets. However, if a claim arose and was successful, such claim may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, the process of addressing such claims, regardless of the outcome, is expensive and time consuming and could result in delays in the construction of infrastructure systems and facilities which could have a material adverse effect on our business and financial results.

***Public perception and its influence on the regulatory regime***

Concern over the impact of oil and gas development on the environment and climate change has received considerable attention in the media and recent public commentary, and the social value proposition of resource development is being challenged. Additionally, certain pipeline leaks, rail car derailments, major weather events and induced seismicity events have gained media, environmental and other stakeholder attention. Future laws and regulation may be impacted by such incidents, which could have a material adverse effect on our financial condition, results of operations or prospects.

***We are subject to risk of default by the counterparties to our contracts and our counterparties may deem us to be a default risk***

We are subject to the risk that counterparties to our risk management contracts, marketing arrangements and operating agreements and other suppliers of products and services may default on their obligations under such agreements or arrangements, including as a result of liquidity requirements or insolvency. Furthermore, low oil and natural gas prices increase the risk of bad debts related to our joint venture and industry partners. A failure by such counterparties to make payments or perform their operational or other obligations to us may adversely affect our results of operations, cash flow from operating activities and financial position. Conversely, our counterparties may deem us to be at risk of defaulting on our contractual obligations. These counterparties may require that we provide additional credit assurances by prepaying anticipated expenses or posting letters of credit, which would decrease our available liquidity and increase our costs.

***Geopolitical risk and conflicts in or around major oil and gas producing nations can significantly impact commodity prices and, therefore the financial condition of the oil and gas industry***

Existing or future conflicts in major oil and gas producing nations and the international response may have potential wide-ranging consequences for global market volatility and economic conditions, including affecting crude oil and natural gas prices. Financial and trade sanctions that may be imposed against countries involved in such conflicts may have continued far-reaching effects on the global economy, energy and commodity prices. The short-, medium- and long-term implications of any such conflicts is difficult to predict with any degree of certainty. Depending on the extent, duration, and severity of such conflict(s), it may have the effect of heightening many of the other risks described herein, including, without limitation, risks relating to global market volatility and economic conditions; cybersecurity threats; crude oil and natural gas prices; inflationary pressures, interest rates and costs of

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 36

capital; change in trade relations and policies, including the potential for tariffs; and supply chains and cost-effective and timely transportation.

***Our hedging activities may negatively impact our income and our financial condition***

In response to fluctuations in commodity prices, foreign exchange and interest rates, we may utilize various derivative financial instruments and physical sales contracts to manage our exposure under a hedging program. The terms of these arrangements may limit the benefit to us of favourable changes in these factors, including receiving less than the market price for our production, and for certain assets will result in us paying royalties at a reference price which is higher than the hedged price. We may also suffer financial loss due to hedging arrangements if we are unable to produce oil or natural gas to fulfill our delivery obligations. There is also increased exposure to counterparty credit risk. To the extent that our current hedging agreements are beneficial to us, these benefits will only be realized for the period and for the commodity quantities in those contracts. In addition, there is no certainty that we will be able to obtain additional hedges at prices that have an equivalent benefit to us, which may adversely impact our revenues in future periods. For more information about our commodity hedging program, see *"Description of our Business - Marketing Arrangements and Forward Contracts"* in the AIF for the year ended December 31, 2025.

***Failure to comply with the covenants in the agreements governing our debt could adversely affect our financial condition***

We are required to comply with the covenants in our Credit Facilities and the 2032 Notes. If we fail to comply with such covenants, are unable to repay or refinance amounts owned at maturity or pay the debt service charges or otherwise commit an event of default, such as bankruptcy, it could result in the seizure and/or sale of our assets by our creditors. The proceeds from any sale of our assets would be applied to satisfy amounts owed to the secured creditors and then unsecured creditors. Only after the proceeds of that sale were applied towards our debt would the remainder, if any, be available for the benefit of our Shareholders.

***Conflicts of interest may arise between the Company and its directors and officers***

Circumstances may arise where directors and officers of the Company are directors or officers of other companies involved in the oil and gas industry which are in competition to, or otherwise in conflict with, the interests of the Company. Directors are required to abstain from voting on matters when they are in conflict. Employees, including officers, are not permitted to partake in activities that do not support the best interests of the Company. Where employee conflicts exist, they are to be provided in writing to our Human Resources Department, which discloses all conflicts to Chief Legal Officer. See "*Directors and Officers – Conflicts*" in the AIF for the year ended December 31, 2025 and the Company's Code of Business Conduct and Ethics at *www.baytexenergy.com*.

**Risks Related to Ownership of our Securities**

***Changes in market-based factors may adversely affect the trading price of the Common Shares***

The market price of our Common Shares is sensitive to a variety of market-based factors including, but not limited to, commodity prices, interest rates, foreign exchange rates, the decision of certain indices to include our Common Shares and the comparability of the Common Shares to other securities. Any changes in these market-based factors may adversely affect the trading price of the Common Shares.

***Forward-Looking Information rely upon assumptions which may not prove correct***

Shareholders and prospective investors are cautioned not to place undue reliance on our forward-looking information. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking information or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate.

Additional information on the risks, assumption and uncertainties are found under the heading "*Special Notes to Reader – Forward-Looking Statements*" in the AIF for the year ended December 31, 2025.

***Dividends on the Company's Common Shares and Common Share repurchases are variable***

The future acquisition by the Company of Common Shares pursuant to a share buyback (including through its NCIB) and the payment of dividends, if any, and the level thereof is uncertain. Any decision to acquire Common Shares pursuant to a share buyback or to pay dividends 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, commodity prices, 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 the Company under applicable corporate law. In the future, there can be no assurance of the number of Common Shares that the Company will acquire pursuant to a share buyback and there can be no assurance that dividends will be paid or, if paid the amount of such dividends.

------

Baytex Energy Corp.<br>2025 MD&A&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; 37

***The Company could lose its status as a "foreign private issuer" in the United States***

The Company is required to assess its "foreign private issuer" ("FPI") status under U.S. securities laws on an annual basis at the end of its second quarter. While the Company currently qualifies as an FPI, it could lose its FPI status in the future. If the Company were to lose its status as an FPI it would be required to fully comply with both U.S. and Canadian securities and accounting requirements applicable to domestic issuers in each country. In addition, if the Company loses its FPI status, it would be required to report as a U.S. domestic issuer and be subject to other U.S. securities laws applicable to U.S. domestic issuers. The regulatory and compliance costs to the Company under U.S. securities laws as a U.S. domestic issuer may be significantly greater than the costs the Company incurs as a foreign private issuer. For example, as a U.S. domestic issuer, the Company would be required to file periodic reports and registration statements with the SEC on U.S. domestic issuer forms, which are more detailed and extensive in certain respects than the forms available to the Company as a foreign private issuer. The Company would also be required to report its oil and gas reserves and production information in accordance with applicable U.S. disclosure requirements. Such conversion and modifications would involve additional costs and may restrict the Company's access to capital markets for a period of time until it has satisfied SEC reporting requirements. In addition, the Company may lose its ability to rely upon exemptions from certain corporate governance requirements on U.S. stock exchanges that are available to FPIs, which could also increase its costs.

**Certain Risks for United States and other non-resident Shareholders**

***The ability of investors resident in the United States to enforce civil remedies is limited***

We are a corporation incorporated under the laws of the Province of Alberta, Canada, our principal office is located in Calgary, Alberta and a substantial portion of our assets are located outside the United States. Most of our directors and officers and the representatives of the experts who provide services to us (such as our auditors and our independent qualified reserves evaluators), and all or a substantial portion of their assets are located outside the United States. As a result, it may be difficult for investors in the United States to effect service of process within the United States upon such directors, officers and representatives of experts who are not residents of the United States or to enforce against them judgments of the United States courts based upon civil liability under the United States federal securities laws or the securities laws of any state within the United States. There is doubt as to the enforceability in Canada against us or any of our directors, officers or representatives of experts who are not residents of the United States, in original actions or in actions for enforcement of judgments of United States courts of liabilities based solely upon the United States federal securities laws or securities laws of any state within the United States.

***Canadian and United States practices differ in reporting reserves and production and our estimates may not be comparable to those of companies in the United States***

We report our production and reserves quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.

We incorporate additional information with respect to production and reserves which is either not required to be included or prohibited under rules of the SEC and practices in the United States. We follow the Canadian practice of reporting gross production and reserve volumes (before deduction of Crown and other royalties). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves, whereas the SEC rules require that a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, be utilized.

We have included in the AIF for the year ended December 31, 2025 estimates of proved reserves and proved plus probable reserves. Probable reserves have a lower certainty of recovery than proved reserves. The SEC requires oil and gas issuers in their filings with the SEC to disclose only proved reserves but permits the optional disclosure of probable reserves. The SEC definitions of proved reserves and probable reserves are different than NI 51-101; therefore, proved, probable and proved plus probable reserves disclosed in the AIF for the year ended December 31, 2025 may not be comparable to United States standards.

As a consequence of the foregoing, our reserves estimates and production volumes in the AIF for the year ended December 31, 2025 may not be comparable to those made by companies utilizing United States reporting and disclosure standards.

***There is additional taxation applicable to non-residents***

Tax legislation in Canada may impose withholding or other taxes on the cash dividends, stock dividends or other property transferred by us to non-resident shareholders. These taxes may be reduced pursuant to tax treaties between Canada and the non-resident shareholder's jurisdiction of residence. Evidence of eligibility for a reduced withholding rate must be filed by the non-resident shareholder in prescribed form with their broker (or in the case of registered shareholders, with the transfer agent). In addition, the country in which the non-resident shareholder is resident may impose additional taxes on such dividends. Any of these taxes may change from time to time.

## Exhibit 99.4

**Baytex Energy Corp.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**

**Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)**

**December 31, 2025**

**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, 2024 and 2025 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, 2025 were as follows:

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Canada** | **Canada** | **Canada** | **Canada** | **Canada** | **United States** | **United States** | **United States** | **United States** |
| | **Crude Oil**<br>(mbbl) | **NGL**<br>(mbbl) | **Bitumen**<br>(mbbl) | **Natural<br>Gas**<br>(mmcf) | **Total**<br>(mboe) | **Crude Oil**<br>(mbbl) | **NGL**<br>(mbbl) | **Natural<br>Gas**<br>(mmcf) | **Total**<br>(mboe) |
| **Net Proved Reserves** |  |  |  |  |  |  |  |  |  |
| December 31, 2023 | 72915 | 8642 | 3480 | 85177 | 99232 | 111406 | 46378 | 200974 | 191280 |
| &nbsp;&nbsp;&nbsp;Revisions of previous estimates | 3307 | (89) |  | (6648) | 2109 | 4127 | (5771) | (25394) | (5876) |
| &nbsp;&nbsp;&nbsp;Improved recovery |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Purchases of minerals in place | 349 |  |  |  | 349 |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Extensions and discoveries | 21078 | 5640 |  | 25695 | 31001 | 13772 | 16643 | 57236 | 39954 |
| &nbsp;&nbsp;&nbsp;Production | (16372) | (930) | (769) | (13908) | (20389) | (14998) | (5253) | (28134) | (24941) |
| &nbsp;&nbsp;&nbsp;Sales of minerals in place | (143) | (5) | (2711) | (24) | (2862) | (130) | (47) | (267) | (221) |
| December 31, 2024 | 81133 | 13257 |  | 90292 | 109439 | 114176 | 51951 | 204414 | 200196 |
| &nbsp;&nbsp;&nbsp;Revisions of previous estimates | 2490 | 1284 |  | 6758 | 4901 |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Improved recovery |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Purchases of minerals in place |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Extensions and discoveries | 20384 | 7684 |  | 33424 | 33639 | 768 | 301 | 1480 | 1316 |
| &nbsp;&nbsp;&nbsp;Production | (16876) | (1189) |  | (14717) | (20519) | (13298) | (4592) | (25020) | (22060) |
| &nbsp;&nbsp;&nbsp;Sales of minerals in place | (435) | (17) |  | (545) | (543) | (101646) | (47660) | (180874) | (179452) |
| December 31, 2025 | 86696 | 21019 |  | 115212 | 126917 |  |  |  |  |

---

------

**Baytex Energy Corp.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**

**Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)**

**December 31, 2025**

---

| | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Canada** | **Canada** | **Canada** | **Canada** | **Canada** | **United States** | **United States** | **United States** | **United States** |
| | **Crude Oil**<br>(mbbl) | **NGL**<br>(mbbl) | **Bitumen**<br>(mbbl) | **Natural<br>Gas**<br>(mmcf) | **Total**<br>(mboe) | **Crude Oil**<br>(mbbl) | **NGL**<br>(mbbl) | **Natural<br>Gas**<br>(mmcf) | **Total**<br>(mboe) |
| **Net Proved Developed Reserves** |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;December 31, 2023 | 39600 | 3000 | 1564 | 52779 | 52961 | 54893 | 27460 | 114346 | 101410 |
| &nbsp;&nbsp;&nbsp;December 31, 2024 | 42651 | 3646 |  | 44168 | 53659 | 55057 | 25526 | 104228 | 97954 |
| &nbsp;&nbsp;&nbsp;December 31, 2025 | 45155 | 5870 |  | 51427 | 59597 |  |  |  |  |
| **Net Proved Undeveloped Reserves** |  |  |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;December 31, 2023 | 33314 | 5641 | 1916 | 32398 | 46271 | 56513 | 18918 | 86628 | 89869 |
| &nbsp;&nbsp;&nbsp;December 31, 2024 | 38482 | 9611 |  | 46124 | 55780 | 59119 | 26425 | 100186 | 102242 |
| &nbsp;&nbsp;&nbsp;December 31, 2025 | 41541 | 15149 |  | 63785 | 67320 |  |  |  |  |

---

---

| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Total** | **Total** | **Total** | **Total** | **Total** |
| | **Crude Oil**<br>(mbbl) | **NGL**<br>(mbbl) | **Bitumen**<br>(mbbl) | **Natural<br>Gas**<br>(mmcf) | **Total**<br>(mboe) |
| **Net Proved Reserves** |  |  |  |  |  |
| December 31, 2023 | 184321 | 55019 | 3480 | 286151 | 290512 |
| &nbsp;&nbsp;&nbsp;Revisions of previous estimates | 7434 | (5860) |  | (32043) | (3767) |
| &nbsp;&nbsp;&nbsp;Improved recovery |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Purchases of minerals in place | 349 |  |  |  | 349 |
| &nbsp;&nbsp;&nbsp;Extensions and discoveries | 34850 | 22283 |  | 82931 | 70955 |
| &nbsp;&nbsp;&nbsp;Production | (31370) | (6184) | (769) | (42042) | (45330) |
| &nbsp;&nbsp;&nbsp;Sales of minerals in place | (273) | (52) | (2711) | (291) | (3084) |
| December 31, 2024 | 195309 | 65208 |  | 294707 | 309635 |
| &nbsp;&nbsp;&nbsp;Revisions of previous estimates | 2490 | 1284 |  | 6758 | 4901 |
| &nbsp;&nbsp;&nbsp;Improved recovery |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Purchases of minerals in place |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Extensions and discoveries | 21152 | 7985 |  | 34904 | 34955 |
| &nbsp;&nbsp;&nbsp;Production | (30174) | (5781) |  | (39738) | (42579) |
| &nbsp;&nbsp;&nbsp;Sales of minerals in place | (102081) | (47677) |  | (181418) | (179994) |
| December 31, 2025 | 86696 | 21019 |  | 115212 | 126917 |
| **Net Proved Developed Reserves** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;December 31, 2023 | 94493 | 30461 | 1564 | 167125 | 154372 |
| &nbsp;&nbsp;&nbsp;December 31, 2024 | 97708 | 29172 |  | 148397 | 151612 |
| &nbsp;&nbsp;&nbsp;December 31, 2025 | 45155 | 5870 |  | 51427 | 59597 |
| **Net Proved Undeveloped Reserves** |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;December 31, 2023 | 89827 | 24559 | 1916 | 119026 | 136140 |
| &nbsp;&nbsp;&nbsp;December 31, 2024 | 97601 | 36036 |  | 146310 | 158022 |
| &nbsp;&nbsp;&nbsp;December 31, 2025 | 41541 | 15149 |  | 63785 | 67320 |

---

*Revisions of Previous Estimates*

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.

In 2025, the Company realized total proved revisions of positive 4,901 mboe, all in Canada. These revisions consisted of: (i) negative revisions of 1,349 mboe due to a decrease in YE 2025 constant pricing as compared to YE 2024 (Edmonton Light decreased to $86.73/bbl from $98.01/bbl, WCS decreased to $75.89/bbl from $83.79/bbl, AECO increased to $1.95/MMBtu from $1.46/MMBtu), (ii) positive revisions of 6,841 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 591 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.

------

**Baytex Energy Corp.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**

**Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)**

**December 31, 2025**

*Purchases of Minerals in Place*

In 2024, the Company acquired 349 mboe of oil reserves in the Peace River region in Canada.

*Extensions and Discoveries*

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.

In 2025, the Company added 34,955 mboe of net proved reserves. These additions consisted of 33,639 mboe in Canada due to extension drilling and future offset additions being added to our development plan, and 1,316 mboe in the U.S. due to production from drilling and re-fracs of previously unbooked wells.

*Sales of Minerals in Place*

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.

In 2025, the Company divested 179,452 mboe from the U.S. which was its entire Eagle Ford position. The Company also divested 543 mboe of non-core Canadian properties, primarily from the Conventional, Peace River, and Viking business units.

**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 2025 and 2024.

---

| | | |
|:---|:---|:---|
| | **Commodity Pricing** | **Commodity Pricing** |
| | **2025** | **2024** |
| WTI crude (US$/bbl) | 66.01 | 76.32 |
| Edmonton Light crude (Cdn$/bbl) | 86.73 | 98.01 |
| Western Canadian Select crude (WCS) <sup>(1)</sup> (Cdn$/bbl) | 75.89 | 83.79 |
| AECO spot (Cdn$/mmbtu) | 1.95 | 1.46 |
| Henry Hub (US$/mmbtu) | 3.42 | 2.07 |
| Exchange rate (US$/Cdn$) | 0.71 | 0.73 |

---

*(1) &nbsp;&nbsp;&nbsp;&nbsp;Price used in the preparation of heavy oil and bitumen reserves in Canada.*

------

**Baytex Energy Corp.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**

**Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)**

**December 31, 2025**

The standardized measure of discounted future net cash flows relating to net proved petroleum and natural gas reserves are as follows:

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Canada** | **Canada** | **United States** | **United States** | **Total** <sup>(2)</sup> | **Total** <sup>(2)</sup> |
|<br>*(thousands of Canadian dollars)* | **2025** | **2024** | **2025** | **2024** | **2025** | **2024** |
| Future cash inflows | $7146124 | $7147647 | $— | $13674283 | $7146124 | $20821930 |
| Future production costs | (3154836) | (2923863) |  | (4916987) | (3154836) | (7840850) |
| Future development costs <sup>(1)</sup> | (1966034) | (1812936) |  | (3647866) | (1966034) | (5460802) |
| Future income taxes | (161266) | (248023) |  | (270193) | (161266) | (518216) |
| Future net cash flows <sup>(2)</sup> | 1863988 | 2162825 |  | 4839237 | 1863988 | 7002062 |
| Deduct: <br>10% annual discount factor | (520880) | (637681) |  | (1841656) | (520880) | (2479337) |
| Standardized measure <sup>(2)</sup> | $1343108 | $1525144 | $— | $2997581 | $1343108 | $4522725 |

---

*(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.*

**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, 2025<br>(thousands of Canadian dollars) | **Canada** | **United States** | **Total** <sup>(1)</sup> |
| Balance, beginning of year | $1525144 | $2997581 | $4522725 |
| Sales, net of production costs | (911508) | (1087795) | (1999303) |
| Net change in prices and production costs related to future production | (441317) | (805468) | (1246784) |
| Changes in previously estimated future development costs incurred during the period | (350964) |  | (350964) |
| Development costs incurred during the period | 547422 | 657719 | 1205141 |
| Extensions, discoveries and improved recovery, net of related costs | 606676 | 56360 | 663037 |
| Revisions of previous quantity estimates | 157623 |  | 157623 |
| Sales of reserves in place | (6071) | (2225959) | (2232029) |
| Purchases of reserves in place |  |  |  |
| Accretion of discount | 169643 | 311567 | 481209 |
| Net change in income taxes | 46460 | 95994 | 142454 |
| Balance, end of year <sup>(1)</sup> | $1343108 | $— | $1343108 |

---

---

| | | | |
|:---|:---|:---|:---|
| As at December 31, 2024<br>(thousands of Canadian dollars) | **Canada** | **United States** | **Total** <sup>(1)</sup> |
| Balance, beginning of year | $1528648 | $3124635 | $4653283 |
| Sales, net of production costs | (1012829) | (1398148) | (2410977) |
| Net change in prices and production costs related to future production | 22156 | (223919) | (201763) |
| Changes in previously estimated future development costs incurred during the period | (371601) | 131114 | (240487) |
| Development costs incurred during the period | 489486 | 767147 | 1256633 |
| Extensions, discoveries and improved recovery, net of related costs | 740619 | 523606 | 1264225 |
| Revisions of previous quantity estimates | 32389 | (180663) | (148274) |
| Sales of reserves in place | (15376) | (4170) | (19546) |
| Purchases of reserves in place | 6230 |  | 6230 |
| Accretion of discount | 164123 | 320224 | 484347 |
| Net change in income taxes | (58702) | (62246) | (120947) |
| Balance, end of year <sup>(1)</sup> | $1525144 | $2997581 | $4522725 |

---

*(1)The data in the table may not add due to rounding.*

------

**Baytex Energy Corp.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**

**Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)**

**December 31, 2025**

**Capitalized Costs Relating to Petroleum and Natural Gas Producing Activities**

---

| | | | |
|:---|:---|:---|:---|
| As at December 31, 2025<br>(thousands of Canadian dollars) | **Canada** | **United States** | **Total** |
| Proved properties | $7362582 | $— | $7362582 |
| Unproved properties | 133585 |  | 133585 |
| Total capital costs | 7496167 |  | 7496167 |
| Accumulated depletion and impairment | (5444147) |  | (5444147) |
| Net capitalized costs | $2052020 | $— | $2052020 |

---

---

| | | | |
|:---|:---|:---|:---|
| As at December 31, 2024<br>(thousands of Canadian dollars) | **Canada** | **United States** | **Total** |
| Proved properties | $6885991 | $10557353 | $17443344 |
| Unproved properties | 124355 |  | 124355 |
| Total capital costs | 7010346 | 10557353 | 17567699 |
| Accumulated depletion and impairment | (4865976) | (5656200) | (10522176) |
| Net capitalized costs | $2144370 | $4901153 | $7045523 |

---

**Costs Incurred in Petroleum and Natural Gas Property Acquisition, Exploration and Development Activities**

---

| | | | |
|:---|:---|:---|:---|
| As at December 31, 2025<br>(thousands of Canadian dollars) | **Canada** | **United States** | **Total** |
| Property acquisition costs |  |  |  |
| &nbsp;&nbsp;&nbsp;Proved properties | $279 | $1867 | $2146 |
| &nbsp;&nbsp;&nbsp;Unproved properties | 29872 |  | 29872 |
| Development costs <sup>(1)</sup> | 547422 | 657719 | 1205141 |
| Exploration costs <sup>(2)</sup> | 930 |  | 930 |
| Total | $578503 | $659586 | $1238089 |

---

---

| | | | |
|:---|:---|:---|:---|
| As at December 31, 2024<br>(thousands of Canadian dollars) | **Canada** | **United States** | **Total** |
| Property acquisition costs |  |  |  |
| &nbsp;&nbsp;&nbsp;Proved properties | $9534 | $3526 | $13060 |
| &nbsp;&nbsp;&nbsp;Unproved properties | 39355 |  | 39355 |
| Development costs <sup>(1)</sup> | 489486 | 767147 | 1256633 |
| Exploration costs <sup>(2)</sup> |  |  |  |
| Total | $538375 | $770673 | $1309048 |

---

*(1) &nbsp;&nbsp;&nbsp;&nbsp;Development and facilities capital expenditures.* 

*(2) &nbsp;&nbsp;&nbsp;&nbsp;Cost of geological and geophysical capital expenditures and drilling costs for exploratory wells.* 

------

**Baytex Energy Corp.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;**

**Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)**

**December 31, 2025**

**Results of Operations for Producing Activities**

---

| | | | |
|:---|:---|:---|:---|
| For year ended December 31, 2025<br>(thousands of Canadian dollars except per boe amounts) | **Canada** | **United States** | **Total** |
| Petroleum and natural gas revenues, net of royalties | $1480815 | $1380219 | $2861034 |
| Less: |  |  |  |
| Operating costs, production and mineral taxes | 334317 | 292424 | 626741 |
| Transportation and blending expense | 318687 | 45683 | 364370 |
| Exploration and evaluation | 5534 |  | 5534 |
| Depletion and impairment | 628041 | 775123 | 1403164 |
| Operating income | 194236 | 266989 | 461225 |
| Income tax expense | 46927 | 57643 | 104570 |
| Results of operations <sup>(1)</sup> | $147309 | $209346 | $356655 |

---

---

| | | | |
|:---|:---|:---|:---|
| For year ended December 31, 2024<br>(thousands of Canadian dollars except per boe amounts) | **Canada** | **United States** | **Total** |
| Petroleum and natural gas revenues, net of royalties | $1612841 | $1716028 | $3328869 |
| Less: |  |  |  |
| Operating costs, production and mineral taxes | 336069 | 317880 | 653949 |
| Transportation and blending expense | 348154 | 48931 | 397085 |
| Exploration and evaluation | 779 |  | 779 |
| Depletion | 473792 | 898271 | 1372063 |
| Operating income | 454047 | 450946 | 904993 |
| Income tax expense | 110697 | 97359 | 208056 |
| Results of operations <sup>(1)</sup> | $343350 | $353587 | $696937 |

---

*(1) &nbsp;&nbsp;&nbsp;&nbsp;Excludes corporate overhead and interest costs.*

## Exhibit 99.5

**Exhibit 99.5**

**CERTIFICATION PURSUANT TO RULE 13a-14(a) OR 15d-14(a) OF**

**THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO**

**SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002**

I, Eric T. Greager, certify that:

1. I have reviewed this annual report on Form 40-F of Baytex Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting; and

5. The issuer's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Dated:&nbsp;&nbsp;&nbsp;&nbsp;March 4, 2026&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;BAYTEX ENERGY CORP.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>/s/</u>*<u>Eric T. Greager</u>*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Name:&nbsp;&nbsp;&nbsp;&nbsp;Eric T. Greager

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Title: &nbsp;&nbsp;&nbsp;&nbsp;Chief Executive Officer

## Exhibit 99.6

**Exhibit 99.6**

**CERTIFICATION PURSUANT TO RULE 13a-14(a) OR 15d-14(a) OF**

**THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO**

**SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002**

I, Chad L. Kalmakoff, certify that:

1. I have reviewed this annual report on Form 40-F of Baytex Energy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting; and

5. &nbsp;&nbsp;&nbsp;&nbsp;The issuer's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Dated:&nbsp;&nbsp;&nbsp;&nbsp;March 4, 2026&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;BAYTEX ENERGY CORP.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>/s/</u> *<u>Chad L. Kalmakoff</u>*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Name:&nbsp;&nbsp;&nbsp;&nbsp;Chad L. Kalmakoff

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Title: &nbsp;&nbsp;&nbsp;&nbsp;Chief Financial Officer

## Exhibit 99.7

**Exhibit 99.7**

**CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002**

In connection with the Annual Report of Baytex Energy Corp. (the "Company") on Form 40-F for the fiscal year ended December 31, 2025, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Eric T. Greager, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.&nbsp;&nbsp;&nbsp;&nbsp;The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.&nbsp;&nbsp;&nbsp;&nbsp;The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:&nbsp;&nbsp;&nbsp;&nbsp;March 4, 2026&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;BAYTEX ENERGY CORP.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>/s/</u> *<u>Eric T. Greager</u>*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Name:&nbsp;&nbsp;&nbsp;&nbsp;Eric T. Greager

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Title: &nbsp;&nbsp;&nbsp;&nbsp;Chief Executive Officer

## Exhibit 99.8

**Exhibit 99.8**

**CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002**

In connection with the Annual Report of Baytex Energy Corp. (the "Company") on Form 40-F for the fiscal year ended December 31, 2025, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Chad L. Kalmakoff, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1.&nbsp;&nbsp;&nbsp;&nbsp;The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.&nbsp;&nbsp;&nbsp;&nbsp;The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:&nbsp;&nbsp;&nbsp;&nbsp;March 4, 2026&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;BAYTEX ENERGY CORP.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<u>/s/</u> *<u>Chad L. Kalmakoff</u>*

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Name:&nbsp;&nbsp;&nbsp;&nbsp;Chad L. Kalmakoff

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Title: &nbsp;&nbsp;&nbsp;&nbsp;Chief Financial Officer

## Exhibit 99.9

**Exhibit 99.9**

**Consent of Independent Registered Public Accounting Firm**

To the Board of Directors of Baytex Energy Corp.

We consent to the use of:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• our report dated March 4, 2026 on the consolidated financial statements of Baytex Energy Corp. (the Company) which comprise the consolidated statements of financial position as of December 31, 2025 and 2024, the related consolidated statements of income (loss) and comprehensive income (loss), changes in equity, and cash flows for the years then ended, and the related notes, and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• our report dated March 4, 2026 on the effectiveness of the Company's internal control over financial reporting as of December 31, 2025

each of which is included in the Annual Report on Form 40-F of the Company for the fiscal year ended December 31, 2025.

We also consent to the incorporation by reference of such reports in the Registration Statements (No. 333-171568 and 333-272971) on Form S-8, and No. 333-273020 on Form F-3 of the Company.

/s/ KPMG LLP

March 4, 2026

Calgary, Canada

## Exhibit 99.10

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;![image_0a.jpg](image_0a.jpg)<br>

**Exhibit 99.10**

**CONSENT OF INDEPENDENT ENGINEERS**

We refer to our report dated February 2, 2026 and effective December 31, 2025, evaluating the proved and probable petroleum and natural gas reserves attributable to Baytex Energy Corp. and its affiliates (collectively, the "Company"), which is entitled "Baytex Energy Corp., Evaluation of Petroleum Reserves, based on Forecast Prices and Costs, As of December 31, 2025" (the "Report").

We hereby consent to the references to our name in the Company's Annual Report on Form 40-F to be filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, and to the incorporation by reference in Registration Statements No. 333-171568 and No. 333-272971 on Form S-8 and Registration Statement No. 333-273020 on Form F-3 of the Company and to the use of the Report.

We also confirm that we have read the Company's Annual Information Form for the year ended December 31, 2025 dated March 4, 2026, and that we have no reason to believe that there are any misrepresentations in the information contained therein that was derived from the Report or that is within our knowledge as a result of the services we performed in connection with such Report.

Yours truly,

**MCDANIEL & ASSOCIATES CONSULTANTS LTD.**

/s/ Michael Verney

______________________________

Michael Verney, P. Eng.

Executive Vice President

Calgary, Alberta, Canada

March 4, 2026

2000, Eighth Avenue Place, East Tower, 525 – 8 Avenue SW, Calgary, AB, T2P 1G1 Tel: (403) 262-5506 www.mcdan.com

<br>