40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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 December 31, 2023 Commission File Number 001-36258

CRESCENT POINT ENERGY CORP.

(Exact name of Registrant as specified in its charter)

Alberta	1311	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)

Suite 2000, 585-8th Avenue S.W.

Calgary, Alberta

T2P 1G1

(403) 693-0020

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

CT Corporation System

28 Liberty Street

New York, NY 10005

(212) 894-8940

(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	CPG	New York Stock Exchange

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

None

(Title of Class)

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

None

(Title of Class)

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

    ☒ Annual Information Form                    ☒ 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:

    619,929,490 Common Shares (as at December 31, 2023).

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 ☒    No ☐

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 ☒    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).

☐

The annual report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, the Registrant’s Registration Statement under the Securities Act of 1933, as amended: Form F-10 (File No. 333-275312), Form S-8 (File No. 333-226210) and Form F-3D (File No. 333-205592)

EXPLANATORY NOTE

Crescent Point Energy Corp. (the “Registrant” or “we”) is a Canadian issuer eligible to file its annual report pursuant to Section 13 of Exchange Act, on Form 40-F pursuant to the multi-jurisdictional disclosure system of the Exchange Act. We are a “foreign private issuer” as defined in Rule 3b-4 under the Exchange Act. Accordingly, our equity securities are exempt from Sections 14(a), 14(b), 14(c), 14(f) and 16 of the Exchange Act pursuant to Rule 3a12-3.

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 40-F and the exhibits attached hereto contain or incorporate by reference “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Please see “Special Notes to Reader” in the Annual Information Form of the Registrant for the year ended December 31, 2023, filed as Exhibit 99.1 to this Annual Report on Form 40-F for a discussion of risks, uncertainties, and assumptions that could cause actual results, performance or achievements to differ materially from those expressed in, or implied by, these forward-looking statements. We believe the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. These forward-looking statements are based on the beliefs, expectations and opinions of management on the date the statements are made. We do not assume any obligation to update forward-looking statements, except as required by applicable securities laws, if circumstances or management’s beliefs, expectations or opinions should change.

PRINCIPAL DOCUMENTS

The following documents are filed as part of this Annual Report on Form 40-F:

A.Annual Information Form

For the Registrant’s Annual Information Form for the fiscal year ended December 31, 2023, 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 fiscal year ended December 31, 2023, including the report of its Independent Auditor (PCAOB ID 271) 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 fiscal year ended December 31, 2023, see Exhibit 99.3 of this Annual Report on Form 40-F.

D.Supplementary Information

For the Registrant’s Supplementary Information about Extractive Activities - Oil and Gas (unaudited) for the fiscal year ended December 31, 2023, see Exhibit 99.10 of this Annual Report on Form 40-F.

DISCLOSURE CONTROLS AND PROCEDURES

A.Certifications

The required disclosure is included in Exhibits 99.4, 99.5, 99.6 and 99.7 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, 2023, an internal evaluation was conducted under the supervision of and with the participation of the Registrant’s management, including the President and 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 Securities and Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of the Registrant’s disclosure controls and procedures were effective in ensuring that the information required to be disclosed in the reports that the Registrant files with or submits to the Securities and Exchange Commission (the “Commission”) is recorded, processed, summarized and reported, within the required time periods.

It should be noted that while the President and 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

The required disclosure is included in the “Management’s Report” that accompanies the Registrant’s Audited Consolidated Financial Statements for the fiscal year ended December 31, 2023, filed as Exhibit 99.2 to this Annual Report on Form 40-F.

D.Attestation of Report of Independent Auditor

The attestation report of PricewaterhouseCoopers LLP is included in the Independent Auditor’s Report that accompanies the Registrant’s Audited Consolidated Financial Statements for the fiscal year ended December 31, 2023, 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, 2023, 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.

NOTICES PURSUANT TO REGULATION BTR 

None.

AUDIT COMMITTEE FINANCIAL EXPERT

The Registrant’s Board of Directors has determined that Mr. M. Jackson and Ms. M. Wight are “audit committee financial experts” (as that term is defined in paragraph 8(b) of General Instruction B to Form 40-F) serving on its audit committee and are “independent” (as defined by the New York Stock Exchange corporate governance rules applicable to foreign private issuers).

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 https://crescentpointenergy.com/corporate-responsibility/esg-policies.

In the past fiscal year, the Registrant has not granted any waiver, including an implicit waiver, from any provision of its Code of Ethics.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The required disclosure is included under the heading “External Auditor Services Fees” in the Registrant’s Annual Information Form for the year ended December 31, 2023, filed as Exhibit 99.1 to this Annual Report on Form 40-F, and is incorporated herein by reference.

PRE-APPROVAL POLICIES AND PROCEDURES

The information required is included under the heading “Relationship and External Auditors” in Appendix A - Audit Committee - Terms of Reference of the Registrant’s Annual Information Form for the fiscal year ended December 31, 2023, incorporated by reference as Exhibit 99.1 to this Annual Report on Form 40-F.

HOURS EXPENDED ON AUDIT ATTRIBUTED TO PERSONS OTHER THAN THE PRINCIPAL ACCOUNTANT’S EMPLOYEES

Not Applicable.

RECOVERY OF ERRONEOUSLY AWARDED COMPENSATION

The Registrant has adopted a compensation recovery policy (referred to as the “Executive Compensation Clawback Policy”) as required by NYSE listing standards and pursuant to Rule 10D-1 of the Exchange Act. The Executive Compensation Clawback Policy is filed as Exhibit 97 to this Form 40-F. At no time during or after the fiscal year ended December 31, 2023 (as of the date of this Annual Report), was the Registrant required to prepare an accounting restatement that required recovery of erroneously awarded compensation pursuant to the Executive Compensation Clawback Policy and, as of December 31, 2023, there was no outstanding balance of erroneously awarded compensation to be recovered from the application of the Executive Compensation Clawback Policy to a prior restatement.

OFF-BALANCE SHEET ARRANGEMENTS

The Registrant does not have any commitments or obligations, including contingent obligations, arising from arrangements with unconsolidated entities or persons (which are not otherwise discussed in the Registrant's Management's Discussion and Analysis for the fiscal year ended December 31, 2023, filed as Exhibit 99.3 to this annual report on Form 40-F), that have or are reasonably likely to have a material current or future effect on its financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, cash requirements or capital resources.

DISCLOSURE OF CONTRACTUAL OBLIGATIONS

The required disclosure is included under the heading “Contractual Obligations and Commitments” in the Registrant’s Management’s Discussion and Analysis of the operating and financial results for the year ended December 31, 2023, filed as Exhibit 99.3 to this Annual Report on Form 40-F.

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 Mr. M. Jackson, Mr. F. Langlois, Mr. M. Stadnyk and Ms. M. Wight all of whom, in the opinion of the directors, are independent (as determined under Rule 10A-3 of the Exchange Act.)

Please refer to the Company’s AIF attached as Exhibit 99.1 to this annual report on Form 40-F for details in connection with each of these members and their qualifications.

The members of the Audit Committee do not have fixed terms and are appointed and replaced from time to time by resolution of the directors.

The Audit Committee meets with the CEO, CFO and the Company’s independent auditors to review and inquire into matters affecting financial reporting, the system of internal accounting and financial controls, as well as audit procedures and audit plans. The Audit Committee also recommends to the Board of Directors which independent registered public auditing firm should be appointed by the Company. In addition, the Audit Committee reviews and recommends to the Board of Directors for approval the annual financial statements and the Management’s Discussion and Analysis of Financial Condition and Results of Operations, and undertakes other activities required by exchanges on which the Company’s securities are listed and by regulatory authorities to which the Company is held responsible.

The full text of the Audit Committee Terms of Reference is disclosed in the Company’s AIF, attached hereto as Exhibit 99.1, and is incorporated by reference in this annual report on Form 40-F.

NYSE STATEMENT OF CORPORATE GOVERNANCE DIFFERENCES

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 https://crescentpointenergy.com/corporate-responsibility/tsx-supplemental-material. Except as disclosed on our website, we are in compliance with the NYSE corporate governance standards in all significant respects.

MINE SAFETY DISCLOSURE

Pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, issuers that are operators, or that have a subsidiary that is an operator, of a coal or other mine in the United States are required to disclose in their periodic reports filed with the SEC information regarding specified health and safety violations, orders and citations, related assessments and legal actions, and mining-related fatalities under the regulation of the Federal Mine Safety and Health Review Administration under the Federal Mine Safety and Health Act of 1977. During the fiscal year ended December 31, 2023, we were not subject to any of the specified violations, orders, citations or other legal actions under the Federal Mine Safety and Health Act of 1977.

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

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 in relation to which the obligation to file an annual report on Form 40-F arises or transactions in said securities.

DISCLOSURE PURSUANT TO SECTION 13(r) OF THE EXCHANGE ACT

In accordance with Section 13(r) of the Exchange Act, the Registrant is required to include certain disclosures in its periodic reports if it or any of its affiliates knowingly engaged in certain specified activities during the period covered by the report. Neither the Registrant nor is affiliates have knowingly engaged in any transaction or dealing reportable under Section 13(r) of the Exchange Act during the year ended December 31, 2023.

CONSENT TO SERVICE OF PROCESS

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.

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.

Date: February 29, 2024	Crescent Point Energy Corp.
	By:	/s/ Ken Lamont
	Name: Title:	Ken Lamont Chief Financial Officer

Form 40-F Table of Contents

Exhibit No.	Document
97	Clawback Policy
99.1	Annual Information Form of the Registrant for the fiscal year ended December 31, 2023.
99.2	Audited Consolidated Financial Statements of the Registrant for the year ended December 31, 2023 together with the Report of Independent Registered Public Accounting Firm thereon.
99.3	Management’s Discussion and Analysis of the operating and financial results of the Registrant for the year ended December 31, 2023.
99.4	Certification of Chief Executive Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
99.5	Certification of Chief Financial Officer under Section 302 of the Sarbanes-Oxley Act of 2002.
99.6	Certification of Chief Executive Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
99.7	Certification of Chief Financial Officer under Section 906 of the Sarbanes-Oxley Act of 2002.
99.8	Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm
99.9	Consent of McDaniel & Associates Consultants Ltd., Independent Engineers
99.10	Supplemental Disclosures about Extractive Activities - Oil and Gas (unaudited)
101	Interactive Data File
104	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

EX-97

Exhibit 97

Clawback Policy

INTRODUCTION

POLICY

The purpose of this Crescent Point Energy Corp. (the “Company”) Clawback Policy (this “Policy”) is to enable the Company to recover Erroneously Awarded Compensation in the event that the Company is required to prepare an Accounting Restatement. This Policy is intended to comply with all laws, government regulations, orders or stock exchange listing requirements applicable to the Company, including, but not limited to, the requirements set forth in Section 303A.14 of the NYSE Listed Company Manual (collectively, “Applicable Law” and shall be construed and interpreted in accordance with such intent. Unless otherwise defined in this Policy, capitalized terms shall have the meaning ascribed to such terms in Section 7.

Administration

This Policy shall be administered by the Human Resource and Compensation Committee (the “Committee”) of the Board unless the Board determines to administer this Policy itself. The Committee has full and final authority to make all determinations under this Policy, in each case to the extent permitted under Applicable Law and in compliance with (or pursuant to an exemption from the application of) Applicable Law, including Section 409A of the Code. All determinations and decisions made by the Committee pursuant to the provisions of this Policy shall be final, conclusive and binding on all persons, including the Company, its affiliates, its shareholders and Executive Officers. Any action or inaction by the Committee with respect to an Executive Officer under this Policy in no way limits the Committee’s actions or decisions not to act with respect to any other Executive Officer under this Policy or under any similar policy, agreement or arrangement, nor shall any such action or inaction serve as a waiver of any rights the Company may have against any Executive Officer other than as set forth in this Policy.

Application

This Policy applies to all Incentive-Based Compensation received by a person: (a) after beginning service as an Executive Officer; (b) who served as an Executive Officer at any time during the performance period for such Incentive-Based Compensation; (c) while the Company had a class of securities listed on a the Toronto Stock Exchange, the NYSE, or any other national securities exchange or a national securities association; and (d) during the three completed fiscal years immediately preceding the Accounting Restatement Date. This Policy also applies to the compensation, in addition to Incentive-Based Compensation, referred to in Section 11 for the purposes thereof. In addition to such last three completed fiscal years, the preceding clause (d) includes any transition period that results from a change in the Company’s fiscal year within or immediately following such three completed fiscal years; provided, however, that a transition period between the last day of the Company’s previous fiscal year end and the first day of its new fiscal year that comprises a period of nine to twelve months shall be deemed a completed fiscal year. For purposes of this Section 3, Incentive-Based Compensation is deemed received in the Company’s fiscal period during which the Financial Reporting Measure specified in the Incentive-Based Compensation award is attained, even if the payment or grant of the Incentive-Based Compensation occurs after the end of that period. For the avoidance of doubt, Incentive-Based Compensation that is subject to both a Financial Reporting Measure vesting condition and a service-based vesting condition shall be considered received when the relevant Financial Reporting Measure is achieved, even if the Incentive-Based Compensation continues to be subject to the service-based vesting condition.

Recovery Requirement

In the event of an Accounting Restatement, the Company must recover, reasonably promptly, Erroneously Awarded Compensation, in amounts determined pursuant to this Policy. The Company’s obligation to recover Erroneously Awarded Compensation is not dependent on if or when the Company files restated financial statements. Recovery under this Policy with respect to an Executive Officer shall not require the finding of any misconduct by such Executive Officer or such Executive Officer being found responsible for the accounting error leading to an Accounting Restatement. In the event of an Accounting Restatement, the Company shall satisfy the Company’s obligations under this Policy to recover any amount owed from any applicable Executive Officer by exercising its sole and absolute discretion in how to accomplish such recovery, to the extent permitted under Applicable Law and in compliance with (or pursuant to an exemption from the application of) Applicable Law, including Section 409A of the Code. The Company’s recovery obligation pursuant to this Section 4 shall not apply to the extent that the Committee, or in the absence of the Committee, a majority of the independent directors serving on the Board, determines that such recovery would be impracticable and:

a.The direct expense paid to a third party to assist in enforcing this Policy would exceed the amount to be recovered. Before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation based on expense of enforcement, the Company must make a reasonable attempt to recover such Erroneously Awarded Compensation, document such reasonable attempt(s) to recover, and provide that documentation to the Stock Exchange;

b.Recovery would violate the laws of Alberta or the laws of Canada applicable therein, where that law was adopted prior to November 28, 2022. Before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation based on violation of such law, the Company must obtain an opinion of Canadian counsel, acceptable to the Stock Exchange, that recovery would result in such a violation, and must provide such opinion to the Stock Exchange; or

c.Recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the registrant, to fail to meet the requirements of Applicable Law, including Section 401(a)(13) or Section 411(a) of the Code.

Prohibition on Indemnification and Insurance Reimbursement

The Company is prohibited from indemnifying any Executive Officer or former Executive Officer against the loss of Erroneously Awarded Compensation. Further, the Company is prohibited from paying or reimbursing an Executive Officer for purchasing insurance to cover any such loss.

Required Policy Related Filings

The Company shall file all disclosures with respect to this Policy in accordance with the requirements of the provincial and U.S. federal securities laws, including disclosures required by U.S. Securities and Exchange Commission filings.

Definitions

a.“Accounting Restatement” means an accounting restatement due to the material noncompliance of the Company with any financial reporting requirement under the securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements, or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period.

b.“Accounting Restatement Date” means the earlier to occur of: (i) the date the Board, a committee of the Board, or the officer or officers of the Company authorized to take such action if the Board action is not required, concludes, or reasonably should have concluded, that the Company is required to prepare an Accounting Restatement; and (ii) the date a court, regulator, or other legally authorized body directs the Company to prepare an Accounting Restatement.

c.“Board” means the board of directors of the Company.

d.“Code” means the U.S. Internal Revenue Code of 1986, as amended. Any reference to a section of the Code or regulation thereunder includes such section or regulation, any valid regulation or other official guidance promulgated under such section, and any comparable provision of any future legislation or regulation amending, supplementing, or superseding such section or regulation.

e.“Erroneously Awarded Compensation” means, in the event of an Accounting Restatement, the amount of Incentive-Based Compensation previously received that exceeds the amount of Incentive-Based Compensation that otherwise would have been received had it been determined based on the restated amounts in such Accounting Restatement, and must be computed without regard to any taxes paid by the relevant Executive Officer; provided, however, that for Incentive-Based Compensation based on stock price or total stockholder return, where the amount of Erroneously Awarded Compensation is not subject to mathematical recalculation directly from the information in an Accounting Restatement: (i) the amount of Erroneously Awarded Compensation must be based on a reasonable estimate of the effect of the Accounting Restatement on the stock price or total stockholder return upon which the Incentive-Based Compensation was received; and (ii) the Company must maintain documentation of the determination of that reasonable estimate and provide such documentation to the Stock Exchange.

f.“Executive Officer” means the Company’s president, principal financial officer, principal accounting officer (or if there is no such accounting officer, the controller), any vice-president of the Company in charge of a principal business unit, division, or function (such as sales, administration, or finance), any other officer who performs a policy-making function, or any other person who performs similar policy-making functions for the Company. An executive officer of the Company’s parent or subsidiary is deemed an “Executive Officer” if the executive officer performs such policy making functions for the Company.

g.“Financial Reporting Measure” means any measure that is determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements, and any measure that is derived wholly or in part from such measure; provided, however, that a Financial Reporting Measure is not required to be presented within the Company’s financial statements or included in a filing with the U.S. Securities and Exchange Commission to qualify as a “Financial Reporting Measure.” For purposes of this Policy, “Financial Reporting Measure” includes, but is not limited to, stock price and total stockholder return.

h.“Incentive-Based Compensation” means any compensation that is granted, earned, or vested based wholly or in part upon the attainment of a Financial Reporting Measure.

i.“Stock Exchange” means the U.S. national stock exchange on which the Company’s Common Shares are listed (e.g., NYSE).

Acknowledgement

Each Executive Officer shall acknowledge and confirm annually that such Executive Officer agrees to be bound by, and to comply with, the terms and conditions of this Policy.

Severability

The provisions in this Policy are intended to be applied to the fullest extent of the law, such provision shall be applied to the maximum extent permitted, and shall automatically be deemed amended in a manner consistent with its objectives to the extent necessary to conform to any limitations required under applicable law.

Amendment, Termination

The Board may amend this Policy from time to time in its sole and absolute discretion and shall amend this Policy as it deems necessary to reflect Applicable Law, or to comply with (or maintain an exemption from the application of) Applicable Law, including Section 409A of the Code. The Board may terminate this Policy at any time.

Other Recovery Obligations, General Rights

To the extent that the application of this Policy would provide for recovery of Incentive-Based Compensation that the Company recovers pursuant to Section 304 of the Sarbanes-Oxley Act or other recovery obligations, the amount the relevant Executive Officer has already reimbursed the Company will be credited to the required recovery under this Policy. This Policy shall not limit the rights of the Company to take any other actions or pursue other remedies that the Company may deem appropriate under the circumstances and under Applicable Law, in each case to the extent permitted under Applicable Law and in compliance with (or pursuant to an exemption from the application of) Applicable Law, including Section 409A of the Code. For greater certainty, any Incentive-Based Compensation, or any other compensation, paid or payable to an employee, contractor or member of the Board pursuant to any agreement or arrangement with the Company (including under the Company’s existing Restricted Share Unit Plan, Deferred Share Unit Plan, Performance Share Unit Plan, Employee Share Value Plan or Stock Option Plan) which is subject to recovery under Applicable Law, will be subject to such deductions and clawback (recovery) as may be required to be made pursuant to Applicable Law (or any policy of the Company adopted pursuant to Applicable Law). Nothing contained in this Policy shall limit the Company’s ability to seek recoupment, in appropriate circumstances (including circumstances beyond the scope of this Policy) and as permitted by Applicable Law, of any amounts from any individual, in each case to the extent permitted under Applicable Law, including in compliance with (or pursuant to an exemption from the application of) Section 409A of the Code.

Conduct Detrimental to the Company

In addition, if the Board determines, acting reasonably, that an employee, contractor or member of the Board has engaged in conduct that is sufficiently detrimental to the Company, either during or after the cessation of such person’s employment with, or service to, the Company, the Board may, at its sole election, terminate any Incentive-Based Compensation payable to such person that has not yet vested or that has not yet been paid. Detrimental conduct includes, but is not limited to, participating in transactions involving the Company and its clients which were under way, contemplated or under consideration at the time of termination, solicitation of clients or employees, disclosing confidential information, making inappropriate or defamatory comments about the Company or breaches of the material provisions of any of the Company's internal policies, including its Code of Conduct.

Successors

This Policy is binding and enforceable against all Executive Officers and their beneficiaries, heirs, executors, administrators or other legal representatives.

EX-99.1

Exhibit 99.1

CRESCENT POINT ENERGY CORP.

ANNUAL INFORMATION FORM

For the Year Ended December 31, 2023

Dated February 28, 2024

Contents

Section	Page
SPECIAL NOTES TO READER	1
GLOSSARY	5
SELECTED ABBREVIATIONS	7
CURRENCY OF INFORMATION	8
OUR ORGANIZATIONAL STRUCTURE	8
GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION	9
DESCRIPTION OF OUR BUSINESS	11
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	15
ADDITIONAL INFORMATION RESPECTING CRESCENT POINT	40
INDUSTRY CONDITIONS	50
RISK FACTORS	62
DIVIDENDS AND SHARE REPURCHASES	78
MARKET FOR SECURITIES	79
CONFLICTS OF INTEREST	81
LEGAL PROCEEDINGS	81
AUDIT COMMITTEE	81
TRANSFER AGENT AND REGISTRARS	83
AUDITOR	83
MATERIAL CONTRACTS	84
INTERESTS OF EXPERTS	84
ADDITIONAL INFORMATION	85

APPENDIX A    -    AUDIT COMMITTEE MANDATE

APPENDIX B    -    RESERVES COMMITTEE MANDATE

APPENDIX C    -    REPORTS ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

APPENDIX D    -    REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

    - 1 -

SPECIAL NOTES TO READER

Any "financial outlook" or "future oriented financial information" in this annual information form, as defined by applicable securities legislation, has been approved by management of Crescent Point (as defined herein). Such financial outlook or future oriented financial information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

This AIF (as defined herein) and other reports and filings made with the securities regulatory authorities include certain statements that constitute "forward-looking statements" within the meaning of section 27A of the Securities Act of 1933, section 21E of the Securities Exchange Act of 1934 and the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" for the purposes of Canadian securities regulation (collectively, "forward-looking statements"). All forward-looking statements are based on our beliefs and assumptions based on information available at the time the assumption was made. Crescent Point has tried to identify such forward-looking statements by use of such words as "could", "should", "can", "anticipate", "expect", "believe", "will", "may", "plan", "forecast", "intend", "projected", "sustain", "continues", "strategy", "potential", "projects", "grow", "take advantage", "estimate", "well-positioned" and similar expressions, but these words are not the exclusive means of identifying such statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Crescent Point believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. These statements speak only as of the date of this AIF or, if applicable, as of the date specified in this AIF.

In particular, this AIF contains forward-looking statements pertaining, among other things, to the following:

•corporate strategy and anticipated financial and operational performance;

•forecast prices and the expected impact of commodity price fluctuations on cash available to pay dividends and return capital to shareholders;

•return of capital framework that targets the return of 60% of Crescent Point's excess cash flow;

•hedging strategy, including expected outcomes, and the approach to managing physical delivery contracts;

•risk mitigation strategy and the expected outcomes;

•the potential impact of competition and our working relationships with industry partners and joint operators on Crescent Point's business;

•business prospects;

•the performance characteristics of Crescent Point's oil and natural gas properties, including but not limited to oil and natural gas production levels;

•anticipated future cash flows and oil and natural gas production levels;

•projected returns and exploration potential of our assets;

•the potential of Crescent Point's plays;

•future development plans, including focus areas;

•forecast costs and expenses associated with Crescent Point's business, including capital expenditure programs and how they will be funded;

•leverage objectives;

•corporate and asset acquisitions and dispositions;

•work commitments and drilling programs;

•expected location inventory development timing;

•expected production breakdown by area on a Proved and Proved plus Probable production basis;

•expected development time frame of the Proved and Proved plus Probable locations;

•the quantity of oil and natural gas reserves;

•projections of commodity prices and costs;

•Crescent Point's decline mitigation efforts;

•future enhanced oil recovery and waterflood programs;

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•the possible impacts of curtailment on Crescent Point;

•the impacts of the Redwater decision and other legal decisions;

•expected decommissioning, abandonment, remediation and reclamation costs;

•Crescent Point's tax horizon;

•the impact of the Canada-United States-Mexico Agreement;

•expected trends in environmental regulation, including the anticipated impact the trends may have on operations and compliance costs;

•the impact, and projected long-term impacts, of the pricing of carbon and greenhouse gases;

•payment of dividends, including special dividends, and the repurchase of Common Shares (as defined herein) by Crescent Point, including pursuant to its normal course issuer bid;

•supply and demand for oil and natural gas;

•the actions of OPEC+;

•expectations of legal and regulatory changes and implementations and change in governmental and regulatory bodies;

•expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development;

•treatment under governmental regulatory regimes, including royalty regimes applicable to natural resources;

•stock option intentions;

•the impacts of the wars in Ukraine and the Middle East;

•the impacts of pandemics;

•the risks and impacts of droughts and wildfires; and

•risks related to the regulatory, social and market efforts to address climate change.

By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements, including those material risks discussed in our Management's Discussion and Analysis for the year ended December 31, 2023, under the headings "Risk Factors" and "Forward-Looking Information" and as disclosed in this AIF. The material assumptions and factors in making forward-looking statements are disclosed in the Management's Discussion and Analysis for the year ended December 31, 2023, under the headings "Overview", "Development Capital Expenditures", "Commodity Derivatives", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Risk Factors", "Changes in Accounting Policies" and "Guidance".

This information contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, certain of which are beyond Crescent Point's control. Such risks and uncertainties include, but are not limited to: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations, pipeline restrictions and blowouts; the impacts of the wars in Ukraine and the Middle East; the actions of OPEC+; the risk of carrying out operations with minimal environmental impact; industry conditions, including changes in laws and regulations, the adoption of new environmental laws and regulations, and changes in how environmental laws and regulations are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs and of dispositions and monetization; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; the impacts of pandemics, drought and wildfires; fluctuations in foreign exchange and interest rates; stock market volatility; failure to realize the anticipated benefits of acquisitions and dispositions; general economic, market and business conditions; inflation; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; tax laws and changes thereto, crown royalty rates and incentive programs relating to the oil and gas industry; and other factors, many of which are outside the control of Crescent Point, including those listed under "Risk Factors" in this AIF. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as each of these are interdependent and Crescent Point's future course of action depends on management's assessment of all information available at the relevant time.

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Statements relating to "reserves" and "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided herein.

There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and natural gas liquids reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. In general, estimates of economically recoverable crude oil, natural gas and natural gas liquids reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, natural gas liquids and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. Crescent Point's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. In addition, the discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value; and the estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Crescent Point's actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking estimates and if such actual results, performance or achievements transpire or occur, or if any of them do so, there can be no certainty as to what benefits, if any, Crescent Point will derive therefrom.

Barrels of oil equivalent ("boe") 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.

Netback received is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses. Netback received excludes realized commodity derivative gains and losses. Netback received is used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis. Netback received is equivalent to "operating netback" referenced in the MD&A. The calculation of netback received is shown in the Production History section of this AIF.

The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for the year.

Additional information on these and other factors that could affect Crescent Point's operations or financial results are included in Crescent Point's reports on file with Canadian and U.S. securities regulatory authorities (including our Annual Report on Form 40-F and Management's Discussion and Analysis). Readers are cautioned not to place undue reliance on the forward-looking information, which is given as of the date it is expressed in this AIF or otherwise. We do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required pursuant to applicable law. All subsequent forward-looking statements, whether written or oral, attributable to Crescent Point or persons acting on the Corporation's behalf are expressly qualified in their entirety by these cautionary statements.

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Currency Presentation

All references to "dollars" and "$" are to the currency of Canada, unless otherwise indicated. The daily rate of exchange on December 31, 2023, as reported by the Bank of Canada for the conversion of Canadian dollars into United States dollars was Cdn.$1.00 equals U.S.$0.7561 and for the conversion of United States dollars into Canadian dollars was U.S.$1.00 equals Cdn.$1.3226. The following table sets forth, for 2023 and 2022, the high, low and average of the daily exchange rates for that year, each for one U.S. dollar expressed in Canadian dollars as reported by the Bank of Canada.

	Year ended December 31, 2023 (Cdn$/Usd)	Year ended December 31, 2022 (Cdn$/Usd)
High	0.7617	0.8031
Low	0.7207	0.7217
Average	0.7410	0.7692

Presentation of our Reserve and Resource Information

Current SEC reporting requirements permit oil and gas companies to disclose Probable reserves (as defined herein), in addition to the required disclosure of Proved reserves. Under current SEC requirements, net quantities of reserves are required to be disclosed, which requires disclosure on an after-royalties basis and does not include reserves relating to the interests of others. For a description of these and additional differences between Canadian and U.S. standards of reporting reserves, see "Risk Factors — 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".

New York Stock Exchange

As a Canadian corporation listed on the NYSE (as defined herein), 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.crescentpointenergy.com, we are in compliance with the NYSE corporate governance standards.

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GLOSSARY

In this AIF, the capitalized terms set forth below have the following meanings:

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

"AER" means the Alberta Energy Regulator.

"Alberta EPA" means the Alberta Ministry of Environment and Protected Areas.

"AIF" means this annual information form of the Corporation dated February 28, 2024 for the year ended December 31, 2023.

"Board" or "Board of Directors" means the board of directors of the Corporation.

"Common Shares" means common shares in the capital of the Corporation.

"Conversion Arrangement" means the plan of arrangement under Section 193 of the ABCA, completed on July 2, 2009 pursuant to which the Trust effectively converted from an income trust to a corporate structure.

"CPEUS" means Crescent Point Energy U.S. Corp.

"CPHL" means Crescent Point Holdings Ltd.

"CPUSH" means Crescent Point U.S. Holdings Corp.

"Crescent Point" or the "Corporation" means Crescent Point Energy Corp., formerly Wild River Resources Ltd., a corporation amalgamated under the ABCA and, where applicable, includes its subsidiaries and affiliates.

"DRIP" means the Premium DividendTM and Dividend Reinvestment Plan of the Corporation.

"DSU Plan" means the Deferred Share Unit Plan of the Corporation.

"ESVP" means the Employee Share Value Plan of the Corporation.

"Greenhouse Gases" or "GHGs" means any or all of, including but not limited to, carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulphur hexafluoride (SF6).

"HEI" means Hammerhead Energy Inc.

"HRULC" means Hammerhead Resources ULC.

"IFRS" means the standards and interpretations adopted by the International Accounting Standards Board, as amended from time to time.

"McDaniel" means McDaniel & Associates Consultants Ltd.

"MD&A" means the management's discussion and analysis of financial condition and results of operations of the Corporation for the year ended December 31, 2023.

"NCIB" means normal course issuer bid.

"NI 51-101" means "National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities".

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"NYSE" means the New York Stock Exchange.

"OPEC+" means the Organization of the Petroleum Exporting Countries and cooperating oil-exporting nations.

"Partnership" means Crescent Point Resources Partnership, a general partnership formed under the laws of the Province of Alberta, having CPHL and the Corporation as partners.

"PSU Plan" means the Performance Share Unit Plan of the Corporation.

"Restricted Share Bonus Plan" means the Restricted Share Bonus Plan of the Corporation.

"SDP" means the Share Dividend Plan of the Corporation.

"SEC" means the U.S. Securities and Exchange Commission.

"Shareholders" means the holders from time to time of Common Shares.

"Stock Option Plan" means the Stock Option Plan of the Corporation.

"Tax Act" means the Income Tax Act (Canada), R.S.C. 1985, c. 1 (5th Supp.), and the regulations promulgated thereunder, each as amended from time to time.

"Trust" means Crescent Point Energy Trust, an unincorporated open ended investment trust governed by the laws of the Province of Alberta that was dissolved pursuant to the Conversion Arrangement.

"Trust Units" means the trust units of the Trust.

"TSX" means the Toronto Stock Exchange.

"U.S." means the United States of America.

"Unitholders" means holders of Trust Units.

For additional definitions used in this AIF, please see "Statement of Reserves Data and Other Oil and Gas Information - Notes and Definitions".

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SELECTED ABBREVIATIONS

In this AIF, the abbreviations set forth below have the following meanings:

Oil and Natural Gas Liquids		Natural Gas
bbl	barrel	Mcf	thousand cubic feet
bbls	barrels	Mcf/d	thousand cubic feet per day
bbls/d	barrels per day	Mcfe	thousand cubic feet of gas equivalent converting one barrel of oil to 6 Mcf of natural gas equivalent
Mbbls	thousand barrels
NGLs	natural gas liquids
		MMcf	million cubic feet
		MMcf/d	million cubic feet per day
		MMBTU	million British Thermal Units
		MMBTU/d	million British Thermal Units per day

Other
AECO	the natural gas storage facility located at Suffield, Alberta
boe or BOE	barrels of oil equivalent 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	barrel of oil equivalent per day
m³	cubic metres
M$	thousand dollars
Mboe	thousand barrels of oil equivalent
MMboe	million barrels of oil equivalent
MM$	million dollars
NYMEX	New York Mercantile Exchange natural gas price
tCO2e/boe	tonnes of carbon dioxide equivalent per barrel of oil equivalent
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for crude oil of standard grade

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CURRENCY OF INFORMATION

The information set out in this AIF is stated as at December 31, 2023, unless otherwise indicated. Capitalized terms used but not defined in the text are defined in the Glossary.

OUR ORGANIZATIONAL STRUCTURE

The Corporation

Crescent Point Energy Corp. ("Crescent Point" or the "Corporation" and, together with its direct and indirect subsidiaries and partnerships, where appropriate, "we", "our" or "us") is the corporation resulting from the January 1, 2024 amalgamation of Crescent Point and HRULC under the ABCA following Crescent Point's acquisition of HEI and its subsidiary, HRULC. The Corporation is the successor to Crescent Point Energy Ltd. which was founded in 2001, and to the Trust, following the completion of the "conversion" of the Trust from an income trust to a corporate structure in accordance with the Conversion Agreement.

The head and principal office of the Corporation is located at Suite 2000, 585 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1 and its registered office is located at Suite 3700, 400 – 3rd Avenue S.W., Calgary, Alberta, T2P 4H2.

The Corporation is a conventional oil and gas producer with assets strategically focused in properties comprised of high quality, long life, operated, light and medium crude oil, natural gas liquids and natural gas reserves in Western Canada. We make regular cash dividends to Shareholders from our net cash flow.

Partnership

The Partnership is a general partnership governed by the laws of the Province of Alberta. As set forth in the diagram below under "Organizational Structure of the Corporation", the partners of the Partnership are CPHL and the Corporation.

The existing business of the Corporation is carried on through the Partnership and through CPEUS. The Partnership holds all the Corporation's Canadian operating assets and CPEUS holds all of the Corporation’s U.S. assets.

CPHL

CPHL is a wholly-owned subsidiary of the Corporation. CPHL is a partner of the Partnership.

CPEUS

CPEUS is a wholly-owned indirect subsidiary of the Corporation.

Relationships

The following table provides the name, the percentage of voting securities owned by the Corporation and the jurisdiction of incorporation, continuance or formation of the Corporation's material subsidiaries as at the date hereof.

	Percentage of Voting Securities (Directly or Indirectly)	Jurisdiction of Incorporation/Formation
CPHL	100%	Alberta
Partnership	100%	Alberta
CPEUS	100%	Delaware

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Organizational Structure of the Corporation

The following diagram describes the inter-corporate relationships among the Corporation and its material direct and indirect subsidiaries described above as at December 31, 2023 and current to February 28, 2024. Reference should be made to the appropriate sections of this AIF for a complete description of the structure of the Corporation.

HRULC (incorporated in Alberta) was a wholly owned subsidiary of Crescent Point on December 31, 2023, and amalgamated with Crescent Point on January 1, 2024.

GENERAL DEVELOPMENT OF THE BUSINESS OF THE CORPORATION

History

The following is a description of the general development of the business of Crescent Point over the past three years.

2021

On February 17, 2021, the Corporation entered into an agreement with Shell Canada Energy (Shell), an affiliate of Royal Dutch Shell plc (formerly, Royal Dutch Shell plc), to acquire Shell’s Kaybob Duvernay assets in Alberta for $900 million. The total consideration consisted of $700 million in cash and 50 million Common Shares. The acquisition closed in April 2021.

On March 5, 2021, the Corporation announced the approval by the TSX of its notice to implement a NCIB (the "2021 NCIB") to purchase, for cancellation, 26,462,509 Common Shares, or five percent of the Corporation's public float, as at February 26, 2021. The NCIB commenced on March 9, 2021 and expired on March 8, 2022. In 2021, the Corporation purchased a total of 2,817,000 Common Shares under its NCIB program.

On June 7, 2021 the Corporation completed the disposition of certain non-core southeast Saskatchewan conventional assets, for cash proceeds of $93 million. As a result of the transaction, Crescent Point also reduced its asset retirement obligations by approximately $220 million, or nearly 25 percent of its asset retirement obligations balance as at March 31, 2021.

On September 13, 2021, the Corporation announced that it was increasing its quarterly dividend from $0.0025 per share payable every quarter to $0.03 per share payable every quarter, commencing with the fourth quarter of 2021.

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On December 6, 2021, the Corporation announced that it was increasing its quarterly dividend from $0.03 per share payable every quarter to $0.045 per share payable every quarter, commencing with the first quarter of 2022.

CPHI, a former partner of the Partnership, was dissolved effective December 31, 2021.

2022

On March 4, 2022, the Corporation announced the approval by the TSX of its notice to implement a NCIB (the "2022 NCIB") to purchase, for cancellation, up to 57,309,975 Common Shares, or ten percent of the Corporation's public float, as at February 28, 2022. The NCIB commenced on March 9, 2022 and expired on March 8, 2023. In 2022, the Corporation purchased a total of 31,347,100 Common Shares under its NCIB programs.

On May 12, 2022, the Corporation announced that it was increasing its quarterly dividend from $0.045 per share payable every quarter to $0.065 per share payable every quarter, commencing with the second quarter of 2022.

On May 19, 2022, Mindy Wight was elected to the Board. See "Additional Information Respecting Crescent Point - Directors and Officers".

On October 26, 2022, the Corporation announced a special dividend of $0.035 per share payable on November 14, 2022.

On December 9, 2022, the Corporation announced that it was increasing its quarterly dividend from $0.065 per share payable every quarter to $0.10 per share payable every quarter, commencing with the first quarter of 2023.

2023

On January 11, 2023, Crescent Point completed the acquisition of certain Kaybob Duvernay assets in Alberta for cash consideration of $370.4 million, including closing adjustments.

On March 2, 2023, the Corporation announced a special dividend of $0.032 per share payable on March 17, 2023.

On March 7, 2023, the Corporation announced the approval by the TSX of its notice to implement a NCIB (the "2023 NCIB") to purchase, for cancellation, up to 54,605,659 Common Shares, or ten percent of the Corporation's public float, as at February 23, 2023. The NCIB commenced on March 9, 2023 and is due to expire on March 8, 2024. In 2023, the Corporation purchased a total of 34,611,900 Common Shares under its NCIB programs.

On March 28, 2023, Crescent Point entered into an agreement with Spartan Delta Corp. ("Spartan Delta") to acquire Spartan Delta's Montney assets in Alberta for cash consideration of $1.7 billion. Cash consideration was funded through the Corporation's existing credit facility. The acquisition closed on May 10, 2023.

On May 10, 2023, concurrent with the closing of the Spartan Delta acquisition, the Company entered into the Syndicated Liquidity Facility (as defined below) with ten banks that matures on May 10, 2025.

On July 26, 2023, the Corporation announced a special dividend of $0.035 per share payable on August 15, 2023.

On August 24, 2023, Crescent Point and CPEUS entered into an agreement with a private operator to sell substantially all its North Dakota assets for US$432.7 million including closing adjustments and US$60.0 million of deferred consideration. The acquisition closed on October 24, 2023. Following completion of the acquisition, Crescent Point ceased to hold any operating assets in the United States.

On November 2, 2023, the Corporation announced a special dividend of $0.02 per share payable on November 22, 2023.

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On November 6, 2023, Crescent Point announced that it entered into an arrangement agreement to acquire, by a statutory arrangement, HEI, and its subsidiary, HRULC, for total consideration of approximately $2.52 billion (the "Hammerhead Acquisition"). The consideration included $1.54 billion in cash, the issuance of 53.2 million Common Shares and $480.2 million of net debt.

On November 6, 2023, Crescent Point announced that it entered into an agreement with a syndicate of underwriters co-led by BMO Capital Markets and RBC Capital Markets (collectively the "Underwriters") under which the Underwriters agreed to purchase, on a bought deal basis 48,550,000 Common Shares at $10.30 per common share for aggregate gross proceeds of approximately $500 million (the "Offering"). The Offering closed on November 10, 2023.

On December 21, 2023, Crescent Point completed the Hammerhead Acquisition.

On December 21, 2023, concurrent with the closing of the Hammerhead Acquisition, the Company entered into the Term Loan (as defined below) with twelve banks that matures on November 26, 2026.

On December 31, 2023, HEI was wound-up into the Corporation.

CPUSH, a wholly-owned direct subsidiary of the Corporation was dissolved effective December 31, 2023.

2024

On January 1, 2024, HRULC was amalgamated with Crescent Point.

On January 26, 2024, the Corporation completed the disposition of its Southern Alberta assets for total consideration of approximately $38.1 million, including interim closing adjustments. Total consideration includes $25.0 million of deferred consideration receivable. Due to significant decommissioning liabilities associated with these assets, this transaction reduces the Company's decommissioning liability balance by $92.4 million.

DESCRIPTION OF OUR BUSINESS

General

The Corporation is an oil and gas exploration, development and production company. The Corporation is a conventional oil and gas producer with assets strategically focused in properties comprised of high quality, long life, operated, light and medium crude oil, natural gas liquids and natural gas reserves in Western Canada. The primary assets of the Corporation are currently its interest in the Partnership and shares in CPHL.

The crude oil and natural gas properties and related assets generating income for the benefit of the Corporation are located in the provinces of Saskatchewan and Alberta. The properties and assets consist of producing crude oil, natural gas liquids and natural gas reserves and Proved plus Probable (as defined herein) crude oil, natural gas liquids and natural gas reserves not yet on production, and land holdings.

We pay regular cash dividends to Shareholders from our net cash flow in accordance with our dividend policy. Our primary sources of cash flow are distributions from the Partnership. During the year ended December 31, 2023, dividends declared to shareholders, including both base dividends and special dividends, were $0.387 per Common Share. See "Dividends".

Strategy

Our strategy is to deliver lasting market-leading value to our stakeholders as a trusted, ethical and environmentally responsible source for energy. We will maintain a resilient, balanced and sustainable portfolio, and apply our agile, diverse, learning mindset to optimize all aspects of our business.

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We strive to enhance shareholder returns by cost effectively developing a focused asset base in a responsible and sustainable manner. The Corporation employs a disciplined capital allocation framework centered around returns and balance sheet strength, in order to create value for shareholders through a combination of significant return of capital, returns-based growth and balance sheet strength.

We strategically develop our properties through detailed technical analysis including reservoir characteristics, petroleum initially in place, recovery factors and the applicability of enhanced recovery techniques. Our development strategies include, multi-stage fracture stimulation of horizontal wells, infill and step-out wells, re-completion of existing wells along with the application of secondary and enhanced oil recovery techniques, including waterflood programs.

Risk Management and Marketing

Factors outside our control impact, to varying degrees, the prices we receive for production. These include, but are not limited to:

(a)    world market forces, including world supply and consumption levels and the ability of OPEC+ and others to set and maintain production levels and prices for crude oil;

(b)    political conditions, including the risk of hostilities in the Middle East, South America, Eastern Europe and other regions throughout the world;

(c)    availability, proximity and capacity of take-away alternatives, including oil and gas gathering systems, pipelines, processing facilities, railcars and railcar loading facilities;

(d)    increases or decreases in crude oil differentials and their implications for prices received by us;

(e)    the impact of changes in the exchange rate between Canadian and U.S. dollars on prices received by us for our crude oil and natural gas;

(f)    North American market forces, most notably shifts in the balance between supply and demand for crude oil and natural gas and the implications for the prices of crude oil and natural gas;

(g)    global and domestic economic and weather conditions and changes in demand as a result of outbreaks, pandemics, such as the COVID-19 health emergency, or other health emergencies;

(h)    price and availability of alternative energy sources;

(i)    the effect of energy conservation measures and government regulations; and

(j)    U.S. and Canada tax policy.

Fluctuations in commodity prices, differentials and foreign exchange and interest rates, among other factors, are outside of our control and yet can have a significant impact on the level of cash we have available for return of capital to our shareholders, including payment of dividends and the acquisition of Common Shares.

To mitigate a portion of these risks, we actively initiate, manage and disclose the effects of our hedging activities. Our strategy for crude oil and natural gas production is to hedge up to 65%, or as otherwise approved by the Board of Directors, of our net of royalty production up to a rolling three and a half year basis, at the discretion of management. The Corporation also uses a combination of financial derivatives and fixed-differential physical contracts to hedge price differentials. For oil differential hedging, Crescent Point's risk management program allows for hedging a forward profile of up to three and a half years, and up to 35% net of royalty production. For gas differential hedging, Crescent Point's risk management program allows for hedging a forward profile of up to three and a half years, and up to 50% net of royalty production. All hedging activities are governed by our Risk Management and Counterparty Credit Policy and are regularly reviewed by the Board of Directors.

As part of our risk management program, benchmark oil prices are hedged using financial WTI-based instruments transacted in Canadian and U.S. dollars, benchmark natural gas prices are hedged using financial AECO and NYMEX based instruments transacted in Canadian and U.S. dollars, respectively. Total financial oil and gas hedges in 2023 amounted to approximately 27% of annual production, net of royalties, consisting of approximately 28% of annual liquids production and approximately 25% of annual natural gas production, net of royalties. The Corporation recorded a realized derivative gain on crude oil, NGL and natural gas hedge contracts of $15.5 million in 2023.

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Crescent Point also enters into physical delivery and derivative WTI price differential contracts which manage the spread between US$ WTI and various stream prices on a portion of its production. The Corporation manages physical delivery contracts on a month-to-month spot and term contract basis. From January to December 2023, approximately 5,000 bbls/d of liquids production was contracted with fixed price differentials off WTI. Crescent Point also enters into derivative NYMEX price differential contracts which manage the spread between US$ NYMEX and AECO-based pricing on a portion of its natural gas production. From January to December 2023, the Company had approximately 27,700 MMBTU/d of natural gas financial derivatives with fixed price differentials off NYMEX.

Refer to the annual financial statements for our commitments under all hedging agreements as at December 31, 2023.

In addition to hedging benchmark crude oil and natural gas prices with financial instruments, we also have the ability to mitigate crude oil basis risk by delivering a portion of our crude oil production into diversified refinery markets using rail transportation when it is economically beneficial to do so. Crescent Point operates two railcar loading facilities, serving its key producing areas of southeast Saskatchewan and southwest Saskatchewan. Crude oil and NGL volumes loaded at these facilities are sold at the loading facilities and our buyers are responsible for providing railcars and managing transportation logistics from that point until delivery.

We mitigate credit risk by having a well-diversified marketing portfolio for our commodity sales. Credit risk associated with the Corporation's product sales and with the Corporation's financial hedging portfolio is managed by Crescent Point's Risk Management Committee and is governed by a board-approved Risk Management and Counterparty Credit Policy that is reviewed annually by the Board of Directors. The Policy requires annual credit reviews of all trade counterparties. Credit limits are required to be set for all trade counterparties, which are based on either a fixed dollar amount which is set annually, at a minimum, or a percentage of the Corporation's portfolio calculated monthly. Crescent Point utilizes a diversified approach in both its physical sales portfolio and its financial hedging portfolio. The physical sales portfolio consists of 82 purchasers and its financial hedging portfolio consists of 12 counterparties. The Corporation's portfolio of counterparty exposures is monitored on a monthly basis.

To further mitigate credit risk associated with its physical sales portfolio, Crescent Point may obtain financial assurances such as parental guarantees, prepayments, letters of credit and third party credit insurance. Including these assurances, approximately 98% of the Corporation's oil and gas sales are with entities considered investment grade.

Revenue Sources

Our crude oil and natural gas volumes are sold in Alberta, Saskatchewan, British Columbia and the United States. During 2023, approximately 48% of our liquids volumes were sold in Saskatchewan, 37% in Alberta, 14% in the U.S. and less than 1% in British Columbia. Approximately 82% of our natural gas volumes were sold in Alberta, 11% in Saskatchewan, 6% in the United States and less than 1% in British Columbia.

For 2023, our commodity production mix was approximately 40% tight oil, 26% NGLs, 22% shale gas, 8% light and medium oil, 3% heavy oil and 1% conventional natural gas.

The following table summarizes our revenue sources by product before hedging and royalties:

For Year Ended	Light and Medium Crude Oil	Heavy Crude Oil	Tight Oil	NGLs(1)	Shale Gas	Conventional Natural Gas
2023	10.5%	2.6%	55.9%	24.9%	5.8%	0.3%
2022	13.2%	3.2%	51.1%	24.9%	7.1%	0.5%
2021	15.4%	3.4%	55.8%	19.6%	5.3%	0.5%

Notes:

(1)    Within our NGL mix, approximately 80% of our 2023 revenue came from condensate sales (2022 - 75%, 2021 - 56%).

    - 14 -    

Competition

We actively compete for reserve acquisitions, exploration leases, licenses and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial resources than we do. Our competitors include major integrated oil and natural gas companies, numerous other independent oil and natural gas entities and individual producers and operators. Similarly, we face a competitive market when we attempt to divest of non-core assets.

Certain of our customers and potential customers are themselves exploring for crude oil and natural gas, and the results of such exploration efforts could affect our ability to sell or supply crude oil or natural gas to these customers in the future. Our ability to successfully bid on and acquire additional property rights, divest property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers is dependent upon developing and maintaining close working relationships with our industry partners and joint operators, our ability to select and evaluate suitable properties, and our ability to consummate transactions in a highly competitive environment.

Seasonal Factors

The production of crude oil and natural gas is dependent on access to areas where development of reserves is to be conducted. Seasonal weather variations, including freeze-up and break-up, affect access in certain circumstances.

Personnel

As of December 31, 2023, the Corporation had 777 permanent employees: 394 employees at the head office in Calgary and 383 field employees.

    - 15 -    

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Disclosure of Reserves Data

In accordance with NI 51-101, the reserves data of the Corporation set forth below (the "Reserves Data") is based upon evaluations conducted by McDaniel with an effective date of December 31, 2023 (the "Crescent Point Reserve Report"). The tables below are a combined summary of our crude oil, natural gas liquids, and natural gas reserves and the net present value of future net revenue attributable to such reserves as evaluated in the Crescent Point Reserve Report based on December 31, 2023 forecast price and cost assumptions using the average of three Independent Reserve Evaluators (McDaniel, GLJ Ltd. and Sproule Associates Ltd.). McDaniel evaluated the Corporation's total Proved plus Probable reserves and total Proved plus Probable value discounted at 10% and evaluated all of the Corporation's properties to prepare the Crescent Point Reserve Report. The tables below summarize the data contained in the Crescent Point Reserve Report. Subsequent to December 31, 2023, the Company disposed of its Southern Alberta assets.

The net present value of future net revenue attributable to our reserves is stated without provision for interest costs, and general and administrative costs, but after providing for estimated royalties, production costs, capital taxes, development costs, other income, future capital expenditures, projected carbon emission costs, and well and location abandonment costs. The reserve assessments also include costs associated with wells that have not been assessed values in the reserve reports and facilities and gathering systems associated with the ongoing production for the Corporation. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to our reserves estimated by McDaniel represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of our crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

The Corporation continuously monitors and reviews legislation concerning greenhouse gas emissions and the impact on operations. Legislation adopted in 2019 has allowed Crescent Point to reduce anticipated negative financial impacts from the production of oil and gas products through the Output-Based Performance Standard ("OBPS") program in Saskatchewan and the Technology Innovation and Emission Reduction ("TIER") program in Alberta. The carbon emission costs related to government programs are fully integrated into the operating costs and capital unit costs in the reserve evaluation.

The Crescent Point Reserve Report includes the abandonment, decommissioning, and reclamation costs for both the active and inactive locations, including all non-producing and suspended wells, facilities and pipelines. The incremental liabilities from the inactive locations on the total Proved plus Probable reserves is estimated at $235 million of value discounted at 10%. The total impact in the Crescent Point Reserve Report from the combined active and inactive liabilities on total Proved plus Probable reserves is estimated at $328 million of value discounted at 10%. Subsequent to December 31, 2023, the Corporation closed a disposition of certain non-core assets in South Alberta, which carried combined active and inactive liabilities, estimated at $54 million, discounted at 10%.

The Crescent Point Reserve Report is based on certain factual data supplied by Crescent Point as well as McDaniel's opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to Crescent Point's petroleum properties and contracts were supplied by the Corporation to McDaniel, and were accepted without any further investigation. McDaniel accepted this data as presented and neither title searches nor field inspections were conducted.

    - 16 -    

Reserves Data – Forecast Prices and Costs

Summary of Oil and Gas Reserves(1)

	Light and Medium Crude Oil		Heavy Crude Oil		Tight Oil		Natural Gas Liquids		Shale Gas		Conventional Natural Gas		Total
Reserves Category	Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (Mbbls)	Company Net (Mbbls)	Company Gross (MMcf)	Company Net (MMcf)	Company Gross (MMcf)	Company Net (MMcf)	Company Gross (Mboe)	Company Net (Mboe)
Proved Developed Producing
Canada	37,020	33,181	17,173	14,417	131,979	118,448	82,447	69,988	636,829	584,298	38,074	34,551	381,103	339,176
United States	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Total	37,020	33,181	17,173	14,417	131,979	118,448	82,447	69,988	636,829	584,298	38,074	34,551	381,103	339,176
Proved Developed Non-Producing
Canada	252	244	2,260	2,089	587	539	149	134	1,603	1,510	64	54	3,527	3,267
United States	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Total	252	244	2,260	2,089	587	539	149	134	1,603	1,510	64	54	3,527	3,267
Proved Undeveloped
Canada	9,551	8,892	1,729	1,582	106,423	91,180	107,124	90,233	949,769	860,513	3,013	2,834	383,624	335,779
United States	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Total	9,551	8,892	1,729	1,582	106,423	91,180	107,124	90,233	949,769	860,513	3,013	2,834	383,624	335,779
Total Proved
Canada	46,823	42,318	21,163	18,088	238,989	210,168	189,720	160,355	1,588,202	1,446,322	41,151	37,440	768,254	678,222
United States	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Total	46,823	42,318	21,163	18,088	238,989	210,168	189,720	160,355	1,588,202	1,446,322	41,151	37,440	768,254	678,222
Total Probable
Canada	33,119	29,445	6,677	5,671	142,434	119,830	93,735	73,064	917,729	805,980	24,721	22,440	433,040	366,080
United States	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Total	33,119	29,445	6,677	5,671	142,434	119,830	93,735	73,064	917,729	805,980	24,721	22,440	433,040	366,080
Total Proved Plus Probable
Canada	79,942	71,763	27,840	23,760	381,422	329,998	283,455	233,418	2,505,931	2,252,302	65,872	59,879	1,201,294	1,044,302
United States	—	—	—	—	—	—	—	—	—	—	—	—	—	—
Total	79,942	71,763	27,840	23,760	381,422	329,998	283,455	233,418	2,505,931	2,252,302	65,872	59,879	1,201,294	1,044,302

Note:

(1)    Numbers may not add due to rounding.

    - 17 -    

Net Present Value of Future Net Revenue of Oil and Gas Reserves(1)

	Before Income Taxes Discounted at (%/year)						After Income Taxes Discounted at (%/year)
Reserves Category	0% (MM$)	5% (MM$)	8% (MM$)	10% (MM$)	15% (MM$)	20% (MM$)	0% (MM$)	5% (MM$)	8% (MM$)	10% (MM$)	15% (MM$)	20% (MM$)
Proved Developed Producing
Canada	10,035	8,130	7,266	6,792	5,868	5,201	8,195	6,719	6,035	5,659	4,928	4,401
United States	—	—	—	—	—	—	—	—	—	—	—	—
Total	10,035	8,130	7,266	6,792	5,868	5,201	8,195	6,719	6,035	5,659	4,928	4,401
Proved Developed Non-Producing
Canada	129	88	74	66	53	44	114	77	64	58	46	38
United States	—	—	—	—	—	—	—	—	—	—	—	—
Total	129	88	74	66	53	44	114	77	64	58	46	38
Proved Undeveloped
Canada	7,889	5,490	4,490	3,950	2,913	2,185	7,193	5,045	4,145	3,657	2,721	2,062
United States	—	—	—	—	—	—	—	—	—	—	—	—
Total	7,889	5,490	4,490	3,950	2,913	2,185	7,193	5,045	4,145	3,657	2,721	2,062
Total Proved
Canada	18,053	13,709	11,830	10,808	8,834	7,430	15,503	11,841	10,244	9,374	7,695	6,501
United States	—	—	—	—	—	—	—	—	—	—	—	—
Total	18,053	13,709	11,830	10,808	8,834	7,430	15,503	11,841	10,244	9,374	7,695	6,501
Total Probable
Canada	13,413	7,925	6,103	5,216	3,693	2,755	10,265	5,964	4,552	3,868	2,703	1,992
United States	—	—	—	—	—	—	—	—	—	—	—	—
Total	13,413	7,925	6,103	5,216	3,693	2,755	10,265	5,964	4,552	3,868	2,703	1,992
Total Proved Plus Probable
Canada	31,466	21,634	17,933	16,024	12,527	10,185	25,768	17,805	14,795	13,242	10,397	8,493
United States	—	—	—	—	—	—	—	—	—	—	—	—
Total	31,466	21,634	17,933	16,024	12,527	10,185	25,768	17,805	14,795	13,242	10,397	8,493

Note:

(1)    Numbers may not add due to rounding.

    - 18 -    

Additional Information Concerning Future Net Revenue – (Undiscounted)(1)

Reserves Category	Revenue (MM$)	Royalties & Burdens(2) (MM$)	Operating Costs (MM$)	Development Costs (MM$)	Abandonment and Reclamation Costs(3) (MM$)	Future Net Revenue Before Income Taxes (MM$)	Income Tax (MM$)	Future Net Revenue After Income Taxes (MM$)
Proved
Canada	50,928	6,700	18,098	6,356	1,721	18,053	2,551	15,503
United States	—	—	—	—	—	—	—	—
Total	50,928	6,700	18,098	6,356	1,721	18,053	2,551	15,503
Proved Plus Probable
Canada	82,849	12,059	27,739	9,665	1,921	31,466	5,698	25,768
United States	—	—	—	—	—	—	—	—
Total	82,849	12,059	27,739	9,665	1,921	31,466	5,698	25,768

Notes:

(1)    Numbers may not add due to rounding.

(2)    Saskatchewan Capital Resource Surcharge has been included under the royalties and burdens column.

(3)    In accordance with the Canadian Oil and Gas Evaluation Handbook, abandonment and reclamation costs include: (i) entities with associated reserves included in the Crescent Point Reserve Report, the undiscounted abandonment and reclamation costs associated with these amounts are $931 million and $1.13 billion for Proved and Proved plus Probable, respectively; and (ii) non-reserve entities that include wells with no reserves assigned, suspended wells, pipeline, and facilities, the undiscounted abandonment and reclamation costs associated with these are estimated at $789 million.

Future Net Revenue by Production Type(1)

	Future Net Revenue Before Income Taxes(2) (Discounted at 10% per year)	Percentage	Unit Value
	(MM$)	(%)	($/boe)	($/Mcfe)
Proved
CANADA
Light and Medium Crude Oil(3)	911	8.4	18.44	3.07
Heavy Crude Oil(3)	351	3.2	19.29	3.21
Tight Oil(5)	6,276	58.1	14.74	2.46
Shale Gas(6)	3,227	29.9	18.01	3.00
Conventional Natural Gas(4)	44	0.4	7.54	1.26
Total Canada	10,808	100	15.94	2.66
UNITED STATES
Light and Medium Crude Oil(3)	—	—	—	—
Heavy Crude Oil(3)	—	—	—	—
Tight Oil(5)	—	—	—	—
Shale Gas(4)(6)	—	—	—	—
Conventional Natural Gas(4)	—	—	—	—
Total United States	—	—	—	—
TOTAL
Light and Medium Crude Oil(3)	911	8.4	18.44	3.07
Heavy Crude Oil(3)	351	3.2	19.29	3.21
Tight Oil(5)	6,276	58.1	14.74	2.46
Shale Gas(4)(6)	3,227	29.9	18.01	3.00
Conventional Natural Gas(4)	44	0.4	7.54	1.26
Total Proved	10,808	100	15.94	2.66

Notes:

(1)    Numbers may not add due to rounding.

(2)    Other company revenue and costs not related to a specific production type have been allocated proportionately to production types. Unit values are based on Company Net Reserves.

(3)    Including solution gas and other by-products.

(4)    Including by-products, but excluding solution gas.

(5)    Including solution gas (categorized as "Shale Gas") and other by-products.

(6)    Shale Gas includes the majority of Natural Gas Liquids.

    - 19 -    

	Future Net Revenue Before Income Taxes(2) (Discounted at 10% per year)	Percentage	Unit Value
	(MM$)	(%)	($/boe)	($/Mcfe)
Proved Plus Probable
CANADA
Light and Medium Crude Oil(3)	1,474	9.2	17.02	2.84
Heavy Crude Oil(3)	438	2.7	18.32	3.05
Tight Oil(5)	9,661	60.3	14.67	2.44
Shale Gas(6)	4,400	27.5	16.44	2.74
Conventional Natural Gas(4)	51	0.3	6.99	1.16
Total Canada	16,024	100	15.34	2.56
UNITED STATES
Light and Medium Crude Oil(3)	—	—	—	—
Heavy Crude Oil(3)	—	—	—	—
Tight Oil(5)	—	—	—	—
Shale Gas(4)(6)	—	—	—	—
Conventional Natural Gas(4)	—	—	—	—
Total United States	—	—	—	—
TOTAL
Light and Medium Crude Oil(3)	1,474	9.2	17.02	2.84
Heavy Crude Oil(3)	438	2.7	18.32	3.05
Tight Oil(5)	9,661	60.3	14.67	2.44
Shale Gas(4)(6)	4,400	27.5	16.44	2.74
Conventional Natural Gas(4)	51	0.3	6.99	1.16
Total Proved Plus Probable	16,024	100	15.34	2.56

Notes:

(1)    Numbers may not add due to rounding.

(2)    Other company revenue and costs not related to a specific production type have been allocated proportionately to production types. Unit values are based on Company Net Reserves.

(3)    Including solution gas and other by-products.

(4)    Including by-products, but excluding solution gas.

(5)    Including solution gas (categorized as "Shale Gas") and other by-products.

(6)    Shale Gas includes the majority of Natural Gas Liquids.

Notes and Definitions

In the tables set forth above in "Disclosure of Reserves Data" and elsewhere in this AIF, the following notes and other definitions are applicable.

Reserve Categories

The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of Proved and Probable reserves have been established in accordance with NI 51-101 to reflect the level of these uncertainties and to provide an indication of the probability of recovery.

The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.

(a)    "Reserves" are estimated remaining economic quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on (a) analysis of drilling, geological, geophysical, and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

    - 20 -    

(b)    "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.

(c)    "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.

(d)    "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.

(e)    "Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., 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 category (proved, probable, possible) to which they are assigned. In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

(f)    "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.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve 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:

•at least a 90% probability that the quantities actually recovered will equal or exceed the estimated Proved reserves; and

•at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated Proved plus Probable reserves.

A quantitative 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.

Additional Definitions

The following terms, used in the preparation of the Crescent Point Reserve Report and this AIF, have the following meanings:

(a)    "associated gas" means the gas cap overlying a crude oil accumulation in a reservoir.

(b)    "crude oil" or "oil" means a mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain small amounts of sulphur and other non-hydrocarbons, that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. It does not include liquids obtained from the processing of natural gas.

    - 21 -    

(c)    "development costs" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)    gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;

(ii)    drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and the wellhead assembly;

(iii)    acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds measuring devices and production storage, natural gas cycling and processing plants, and central utility and waste disposal system; and

(iv)    provide improved recovery systems.

(d)    "development well" means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

(e)    "exploration costs" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as "prospecting costs") and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)    costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as "geological and geophysical costs");

(ii)    costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defense, and the maintenance of land and lease records;

(iii)    dry hole contributions and bottom hole contributions;

(iv)    costs of drilling and equipping exploratory wells; and

(v)    costs of drilling exploratory type stratigraphic test wells.

(f)    "exploratory well" means a well that is not a development well, a service well or a development type stratigraphic test well.

(g)    "field" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to denote localized geological features, in contrast to broader terms such as "basin", "trend", "province", "play" or "area of interest".

    - 22 -    

(h)    "future prices and costs" means future prices and costs that are:

(i)    generally accepted as being a reasonable outlook of the future; and

(ii)    if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Corporation 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 (i).

(i)    "future income tax expenses" means future income tax expenses estimated (generally, year-by-year):

(i)    making appropriate allocations of estimated unclaimed costs and losses carried forward for tax purposes, between oil and gas activities and other business activities;

(ii)    without deducting estimated future costs that are not deductible in computing taxable income;

(iii)    taking into account estimated tax credits and allowances (for example, royalty tax credits); and

(iv)    applying to the future pre-tax net cash flows relating to the Corporation's oil and gas activities the appropriate year end statutory tax rates, taking into account future tax rates already legislated.

(j)    "future net revenue" means the estimated net amount to be received with respect to the anticipated development and production of reserves (including synthetic oil, coal bed methane and other non-conventional reserves) estimated using future prices and costs.

(k)    "gross" means:

(i)    in relation to the Corporation's interest in production or reserves, its "company gross reserves", which are its working interest (operated or non-operated) share before deduction of royalties and without including any royalty interests of the Corporation;

(ii)    in relation to wells, the total number of wells in which the Corporation has an interest; and

(iii)    in relation to properties, the total area of properties in which the Corporation has an interest.

(l)    "natural gas" means a naturally occurring mixture of hydrocarbon gases and other gases.

(m)    "natural gas liquids" means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.

(n)    "net" means:

(i)    in relation to the Corporation's interest in production or reserves, its working interest (operated or non-operated) share after deduction of royalty obligations, plus its royalty interests in production or reserves;

(ii)    in relation to the Corporation's interest in wells, the number of wells obtained by aggregating the Corporation's working interest in each of its gross wells; and

(iii)    in relation to the Corporation's interest in a property, the total area in which the Corporation has an interest multiplied by the working interest owned by the Corporation.

    - 23 -    

(o)    "non-associated gas" means an accumulation of natural gas in a reservoir where there is no crude oil.

(p)    "operating costs" or "production costs" means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities as well as other costs of operating and maintaining those wells and related equipment and facilities.

(q)    "production" means recovering, gathering, treating, field or plant processing (for example, processing gas to extract natural gas liquids) and field storage of oil and gas.

(r)    "property" includes:

(i)    fee ownership or a lease, concession, agreement, permit, license or other interest representing the right to extract oil or gas subject to such terms as may be imposed by the conveyance of that interest;

(ii)    royalty interests, production payments payable in oil or gas, and other non-operated interests in properties operated by others; and

(iii)    an agreement with a foreign government or authority under which the Corporation participates in the operation of properties or otherwise serves as "producer" of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer).

A property does not include supply agreements, or contracts that represent a right to purchase, rather than extract, oil or gas.

(s)    "property acquisition costs" means costs incurred to acquire a property (directly by purchase or lease, or indirectly by acquiring another corporate entity with an interest in the property), including:

(i)    costs of lease bonuses and options to purchase or lease a property;

(ii)    the portion of the costs applicable to hydrocarbons when land including rights to hydrocarbons is purchased in fee; and

(iii)    brokers' fees, recording and registration fees, legal costs and other costs incurred in acquiring properties.

(t)    "proved property" means a property or part of a property to which reserves have been specifically attributed.

(u)    "reservoir" means a subsurface rock unit that contains an accumulation of petroleum.

(v)    "service well" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for combustion.

(w)    "solution gas" means natural gas dissolved in crude oil.

(x)    "stratigraphic test well" means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon production. They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) "exploratory type" if not drilled into a proved property; or (ii) "development type", if drilled into a proved property. Development type stratigraphic wells are also referred to as "evaluation wells".

    - 24 -    

(y)    "support equipment and facilities" means equipment and facilities used in oil and gas activities, including seismic equipment, drilling equipment, construction and grading equipment, vehicles, repair shops, warehouses, supply points, camps, and division, district or field offices.

(z)    "unproved property" means a property or part of a property to which no reserves have been specifically attributed.

(aa)    "well abandonment and reclamation costs" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system and remediating and reclaiming the site to original conditions. They do not include costs of abandoning the gathering system.

Pricing Assumptions – Forecast Prices and Costs

The average of the three independent reserve evaluator price decks (McDaniel, GLJ Ltd. and Sproule Associates Ltd.) resulted in the following pricing, exchange rate and inflation rate assumptions as of December 31, 2023 in estimating our reserves data using forecast prices and costs.

Year	Crude Oil		Conventional Natural Gas		NGLs
	WTI at Cushing Oklahoma ($US/bbl)	Edmonton ($Cdn/bbl)	Henry Hub NYMEX ($US/MMBTU)	AECO/NIT Spot ($Cdn/MMBTU)	Pentane Plus Edmonton ($Cdn/bbl)	Butane Edmonton ($Cdn/bbl)	Propane Edmonton ($Cdn/bbl)	Operating Cost Inflation Rate (%/yr)	Capital Cost Inflation Rate (%/yr)	Exchange Rate ($US/$Cdn)
Forecast
2024	73.67	92.91	2.75	2.20	96.79	47.69	29.65	0.00%	0.00%	0.752
2025	74.98	95.04	3.64	3.37	98.75	48.83	35.13	2.00%	2.00%	0.752
2026	76.14	96.07	4.02	4.05	100.71	49.36	35.43	2.00%	2.00%	0.755
2027	77.66	97.99	4.10	4.13	102.72	50.35	36.14	2.00%	2.00%	0.755
2028	79.22	99.95	4.18	4.21	104.78	51.35	36.86	2.00%	2.00%	0.755
2029	80.80	101.94	4.27	4.30	106.87	52.38	37.60	2.00%	2.00%	0.755
2030	82.42	103.98	4.35	4.38	109.01	53.43	38.35	2.00%	2.00%	0.755
2031	84.06	106.06	4.44	4.47	111.19	54.50	39.12	2.00%	2.00%	0.755
2032	85.74	108.18	4.53	4.56	113.41	55.58	39.90	2.00%	2.00%	0.755
2033	87.46	110.35	4.62	4.65	115.67	56.70	40.70	2.00%	2.00%	0.755
2034	89.21	112.56	4.71	4.74	117.98	57.83	41.51	2.00%	2.00%	0.755
2035+	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	+2%/yr	2.00%	2.00%	0.755

    - 25 -    

Reconciliations of Changes in Reserves(1)

The following table sets forth a reconciliation of the Corporation's working interest reserves by total Proved, total Probable and total Proved plus Probable reserves as at December 31, 2023, against such reserves as at December 31, 2022, based on forecast price and cost assumptions.

CANADA	Light and Medium Crude Oil (Mbbls)			Heavy Crude Oil (Mbbls)			Tight Oil (Mbbls)			Natural Gas Liquids (Mbbls)
Factors	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
December 31, 2022	49,197	36,550	85,747	23,039	7,230	30,268	138,419	75,590	214,009	135,264	44,562	179,827
Discoveries	—	—	—	—	—	—	—	—	—	—	—	—
Extensions and Improved Recovery (2)	388	(149)	239	—	—	—	4,922	(228)	4,694	17,384	29,323	46,707
Technical Revisions (3)	1,643	(3,370)	(1,727)	(675)	(580)	(1,255)	2,183	(4,415)	(2,232)	(4,919)	(5,213)	(10,132)
Acquisitions (4)	126	22	148	—	—	—	111,332	74,357	185,689	55,257	25,209	80,466
Dispositions (5)	(376)	(190)	(565)	—	—	—	(859)	(3,102)	(3,961)	(120)	(300)	(420)
Economic Factors (6)	468	255	723	193	27	220	1,161	232	1,393	305	153	458
Production (7)	(4,623)	—	(4,623)	(1,394)	—	(1,394)	(18,169)	—	(18,169)	(13,451)	—	(13,451)
December 31, 2023	46,823	33,119	79,942	21,163	6,677	27,840	238,989	142,434	381,422	189,720	93,735	283,455

CANADA	Shale Gas (Natural Gas) (MMcf)			Conventional Natural Gas (Natural Gas) (MMcf)			Total BOE (Mboe)
Factors	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
December 31, 2022	486,076	149,035	635,111	39,279	23,599	62,877	433,478	192,705	626,182
Discoveries	—	—	—	—	—	—	—	—	—
Extensions and Improved Recovery (2)	78,189	197,826	276,015	158	(157)	—	35,751	61,891	97,643
Technical Revisions (3)	15,063	(5,454)	9,609	4,034	58	4,092	1,415	(14,477)	(13,062)
Acquisitions (4)	1,082,973	581,238	1,664,211	2,684	927	3,610	347,657	196,616	544,273
Dispositions (5)	(2,077)	(5,247)	(7,324)	(176)	(38)	(215)	(1,730)	(4,473)	(6,203)
Economic Factors (6)	1,165	331	1,497	(899)	333	(566)	2,172	778	2,949
Production (7)	(73,188)	—	(73,188)	(3,928)	—	(3,928)	(50,489)	—	(50,489)
December 31, 2023	1,588,202	917,729	2,505,931	41,151	24,721	65,872	768,254	433,040	1,201,294

UNITED STATES	Light and Medium Crude Oil(Mbbls)			Heavy Crude Oil (Mbbls)			Tight Oil (Mbbls)			Natural Gas Liquids (Mbbls)
Factors	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
December 31, 2022	—	—	—	—	—	—	31,238	25,788	57,026	11,218	8,330	19,548
Discoveries	—	—	—	—	—	—	—	—	—	—	—	—
Extensions and Improved Recovery	—	—	—	—	—	—	2,060	(1,289)	772	634	(373)	261
Technical Revisions (3)	—	—	—	—	—	—	—	—	—	—	—	—
Acquisitions	—	—	—	—	—	—	—	—	—	—	—	—
Dispositions	—	—	—	—	—	—	(28,142)	(24,499)	(52,641)	(10,142)	(7,957)	(18,099)
Economic Factors (6)	—	—	—	—	—	—	—	—	—	—	—	—
Production (7)	—	—	—	—	—	—	(5,156)	—	(5,156)	(1,709)	—	(1,709)
December 31, 2023	—	—	—	—	—	—	—	—	—	—	—	—

    - 26 -    

UNITED STATES	Shale Gas (Natural Gas) (MMcf)			Conventional Natural Gas (Natural Gas) (MMcf)			Total BOE (Mboe)
Factors	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
December 31, 2022	35,611	26,445	62,056	—	—	—	48,391	38,525	86,916
Discoveries	—	—	—	—	—	—	—	—	—
Extensions and Improved Recovery	1,810	(1,065)	746	—	—	—	2,996	(1,839)	1,157
Technical Revisions (3)	—	—	—	—	—	—	—	—	—
Acquisitions	—	—	—	—	—	—	—	—	—
Dispositions	(32,439)	(25,380)	(57,819)	—	—	—	(43,690)	(36,686)	(80,377)
Economic Factors (6)	—	—	—	—	—	—	—	—	—
Production (7)	(4,983)	—	(4,983)				(7,696)	—	(7,696)
December 31, 2023	—	—	—	—	—	—	—	—	—

TOTAL	Light and Medium Crude Oil(Mbbls)			Heavy Crude Oil (Mbbls)			Tight Oil (Mbbls)			Natural Gas Liquids (Mbbls)
Factors	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
December 31, 2022	49,197	36,550	85,747	23,039	7,230	30,268	169,657	101,378	271,034	146,482	52,892	199,374
Discoveries	—	—	—	—	—	—	—	—	—	—	—	—
Extensions and Improved Recovery (2)	388	(149)	239	—	—	—	6,982	(1,517)	5,465	18,017	28,950	46,968
Technical Revisions (3)	1,643	(3,370)	(1,727)	(675)	(580)	(1,255)	2,183	(4,415)	(2,232)	(4,919)	(5,213)	(10,132)
Acquisitions (4)	126	22	148	—	—	—	111,332	74,357	185,689	55,257	25,209	80,466
Dispositions (5)	(376)	(190)	(565)	—	—	—	(29,001)	(27,601)	(56,602)	(10,262)	(8,257)	(18,519)
Economic Factors (6)	468	255	723	193	27	220	1,161	232	1,393	305	153	458
Production (7)	(4,623)	—	(4,623)	(1,394)	—	(1,394)	(23,326)	—	(23,326)	(15,160)	—	(15,160)
December 31, 2023	46,823	33,119	79,942	21,163	6,677	27,840	238,989	142,434	381,422	189,720	93,735	283,455

    - 27 -    

TOTAL	Shale Gas(Natural Gas) (MMcf)			Conventional Natural Gas (Natural Gas) (MMcf)			Total BOE (Mboe)
Factors	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
December 31, 2022	521,688	175,480	697,167	39,279	23,599	62,877	481,868	231,230	713,098
Discoveries	—	—	—	—	—	—	—	—	—
Extensions and Improved Recovery (2)	80,000	196,761	276,761	158	(157)	—	38,747	60,052	98,799
Technical Revisions (3)	15,063	(5,454)	9,609	4,034	58	4,092	1,415	(14,477)	(13,062)
Acquisitions (4)	1,082,973	581,238	1,664,211	2,684	927	3,610	347,657	196,616	544,273
Dispositions (5)	(34,516)	(30,627)	(65,143)	(176)	(38)	(215)	(45,420)	(41,159)	(86,579)
Economic Factors (6)	1,165	331	1,497	(899)	333	(566)	2,172	778	2,949
Production (7)	(78,170)	—	(78,170)	(3,928)	—	(3,928)	(58,185)	—	(58,185)
December 31, 2023	1,588,202	917,729	2,505,931	41,151	24,721	65,872	768,254	433,040	1,201,294

Notes:

(1)    Numbers may not add due to rounding.

(2)    The Corporation's Canadian development strategy focused on development of its Kaybob Duvernay and newly acquired Alberta Montney assets, along with low risk, infill and development, primarily in the Viewfield Bakken and Shaunavon resource plays. The Corporation continues its decline mitigation efforts through implementation of waterflood development within its Saskatchewan assets. The majority of the extensions in 2023 were in the Kaybob Duvernay asset.

(3)    The Corporation realized minor negative revisions primarily due to increased operating expenses, as a result of inflationary pressures on costs. Overall, total revisions made up a minor portion of the year-over-year changes.

(4)    During the year, the Corporation closed on several material acquisitions:

i) Certain Duvernay assets in the Kaybob Duvernay area, which closed on January 11, 2023.

ii) Certain Montney assets, within the Corporation's newly formed Montney DU, which closed on May 10, 2023.

iii) Corporate acquisition of Hammerhead Energy Inc., including Montney assets offsetting the earlier acquisition, which closed on December 21, 2023.

(5)    The Corporation completed dispositions of non-core assets including portions of its East Shale Basin Duvernay asset, as well as the complete disposition of its North Dakota assets in the United States.

(6)    Increases in reserves are due to slight increases in long term forecast commodity prices, determined by prior year end reserves calculated on current year end price forecasts.

(7)    The Corporation produced an average of 138,326 boe per day in Canada and 21,085 boe per day in the United States for a total of 159,411 boe per day.

Undeveloped Reserves

The following discussion generally describes the basis on which we attribute Proved and Probable undeveloped reserves. Our near-term plans for developing our undeveloped reserves are described in the section "Major Oil and Gas Properties".

Proved Undeveloped Reserves

Proved Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. These reserves represent a high degree of certainty to be recoverable, and mostly relate to planned infill drilling and proximal offset locations to current producing entities.

The Corporation has extensive Proved development opportunities that are prioritized based on a disciplined set of criteria including, but not limited to, time for payout, rate of return, maturity of land tenure, reserve booking opportunities, proximity to transportation and marketing, as well as anticipated production rates. With this extensive portfolio of opportunities, it would be unrealistic, both from a cash flow as well as a physical ability, to completely execute on the entire portfolio of booked opportunities within two years, however, approximately 39% of the development spending occurs within this time frame.

The development of these reserves have been based on current and planned capital activity levels, with no material deferrals of development opportunities beyond these normal budgetary constraints. The majority of these reserves are planned to be developed within a three year time frame, which represents approximately 56% of the net undeveloped location count, as well as 62% of the net total future development capital. These development activities are directed mostly to the Corporation's core focus areas of the Montney, Kaybob Duvernay, Viewfield Bakken and Shaunavon resource plays. The current market environment has resulted in long term sustainability. When combined with an extensive location inventory, this results in an extended time period for full development.

    - 28 -    

The following table provides the timing of the initial reserve assignments for the Corporation's gross Proved Undeveloped reserves.

Timing of Initial Proved Undeveloped Reserve Assignment

	Light & Medium Crude Oil (Mbbl)		Heavy Crude Oil (Mbbl)		Tight Oil (Mbbl)		Natural Gas Liquids (Mbbl)		Shale Gas (MMcf)		Conventional Natural Gas (MMcf)		Oil Equivalent (Mboe)
	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End
2021	4,784	14,353	404	1,677	8,960	61,755	44,358	57,577	137,175	183,576	987	3,468	81,533	166,536
2022	1,108	10,757	—	1,731	167	48,806	25,624	69,253	117,568	235,901	528	3,491	46,581	170,446
2023	21	9,551	—	1,729	74,385	106,423	51,082	107,124	737,162	949,769	—	3,013	248,349	383,624

Note:

(1)    "First attributed" refers to reserves first attributed at year-end to corresponding fiscal year.

Probable Undeveloped Reserves

Probable Undeveloped reserves are generally those reserves tested or indicated by analogy to be productive, and lands contiguous to production. These reserves represent quantities that are less certain to be recovered than Proved reserves.

In the reserve evaluation, development of these reserves is balanced across a five to seven year time-frame to closely match the aggregate internal development schedule and represent a practicable development program. A large portion of these reserves are planned to be developed within a three year time frame, representing approximately 41% of the net undeveloped location count, as well as 45% of the total net future development costs. The current market environment has resulted in long term sustainability. When combined with extensive location inventory, this results in an extended full development time period.

This broader distribution of development activities continues to focus on the Corporation's core areas, while reclassifying current Probable locations to Proved locations during the early years of development. These development activities are directed mostly to the Corporation's core focus areas of the Montney, Kaybob Duvernay, Viewfield Bakken and Shaunavon resource plays.

The following table provides the timing of the initial reserve assignments for the Corporation's Probable Undeveloped reserves.

Timing of Initial Probable Undeveloped Reserves Assignment

	Light & Medium Crude Oil (Mbbl)		Heavy Crude Oil (Mbbl)		Tight Oil (Mbbl)		Natural Gas Liquids (Mbbl)		Shale Gas (MMcf)		Conventional Natural Gas (MMcf)		Oil Equivalent (Mboe)
	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End	First Attributed(1)	Total at Year-End
2021	1,190	24,862	693	1,447	1,466	66,758	9,084	27,067	26,750	80,377	640	14,767	16,998	135,991
2022	470	23,332	—	1,481	57	60,050	6,384	29,544	29,397	91,012	236	14,877	11,849	132,055
2023	8	22,131	—	1,481	66,300	100,756	50,021	70,098	687,435	752,281	—	14,694	230,901	322,295

Note:

(1)    "First attributed" refers to reserves first attributed at year end of the corresponding fiscal year.

Significant Factors or Uncertainties Affecting Reserves Data

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. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. Our reserves are evaluated by McDaniel, an independent engineering firm. Different reserve engineers may make different estimates of reserve quantities based on the same data.

    - 29 -    

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, prices, economic conditions and governmental regulations.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions and judgments, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from numerous factors including, but not limited to, additional development activity, evolving production history, continual reassessment of the viability of production under varying economic conditions, changes in forecast prices, and reservoir performance. Such revisions can be substantial and can be either positive or negative.

Future Development Costs

The table below sets out the development costs deducted in the estimation of future net revenue attributable to total Proved reserves and total Proved plus Probable reserves (using forecast prices and costs).

Company Annual Capital Expenditures (MM$)
	Canada (2)		United States (3)		Total (1)
Year	Total Proved	Total Proved Plus Probable	Total Proved	Total Proved Plus Probable	Total Proved	Total Proved Plus Probable
2024	1,233	1,372	—	—	1,233	1,372
2025	1,240	1,437	—	—	1,240	1,437
2026	1,462	1,585	—	—	1,462	1,585
2027	1,429	1,738	—	—	1,429	1,738
2028	888	1,708	—	—	888	1,708
2029	26	1,095	—	—	26	1,095
2030	11	603	—	—	11	603
2031	12	19	—	—	12	19
2032	13	19	—	—	13	19
2033	9	9	—	—	9	9
2034	7	9	—	—	7	9
2035	6	9	—	—	6	9
Subtotal	6,336	9,603	—	—	6,336	9,603
Remainder	21	62	—	—	21	62
Total	6,356	9,665	—	—	6,356	9,665
10% Discounted	5,076	7,196	—	—	5,076	7,196

Notes:

(1)    Numbers may not add due to rounding.

(2)    Due to the nature of the resource style plays that Crescent Point is focused on, with large contiguous blocks of land, a large number of Proved as well as Proved plus Probable locations have been booked. The scheduling of locations in the reserve report have a similar drilling timing as the Corporation's long-term development plan, with development drilling scheduled to occur within a five year period for Proved reserves, extending up to seven year for Probable reserves.

We estimate that our internally generated cash flow will be sufficient to fund the future development costs ("FDC") disclosed above. In addition, we have access to debt financing through our bank credit facilities and through debt capital markets, if available on terms acceptable to us.

    - 30 -    

Major Oil and Gas Properties

The following is a description of the major oil and natural gas producing properties in which Crescent Point has an interest and that are material to the Corporation's operations and activities. All of the Corporation's assets are located onshore within North America. The Corporation holds no interests in any plants, facilities or installations that are significant beyond normal oil and gas operating practices. Unless otherwise noted, reserve amounts are Company Gross, based on escalating cost and price assumptions as evaluated in the Crescent Point Reserve Report as at December 31, 2023.

Alberta Montney Area

In 2023, the Corporation acquired Montney assets from Spartan Delta and also acquired HEI. The Corporation's Montney production is a combination of tight oil, natural gas, and natural gas liquids, weighted approximately 57% to oil and natural gas liquids. The Corporation is developing the play using pad based multi-staged fractured horizontal wells. In 2023, Crescent Point's production from the Montney averaged approximately 25,000 boe per day.

In the Montney, the Corporation spent $219 million, representing 19% of its 2023 capital program, drilling 18 (17.8 net) horizontal wells.

At year-end 2023, the Corporation's total Proved plus Probable reserves in the Montney were 499.6 MMboe, with 410 (383.3 net) drilling locations booked, representing approximately 42% of the Corporation's total Proved plus Probable reserves. It is expected the total Proved as well as the total Proved plus Probable locations will be developed within seven years.

As at December 31, 2023, Crescent Point has allocated approximately 45% of the Corporation's 2024 capital budget to developing the Montney resources play in Alberta.

Kaybob Duvernay Area

The Corporation's Kaybob Duvernay production is a combination of natural gas liquids, weighted towards condensate, and natural gas, weighted approximately 58% to natural gas liquids. The Corporation is developing the play using multi-staged fractured horizontal wells. In 2023, Crescent Point's production averaged approximately 44,500 boe per day. In 2023, the Corporation expanded its Kaybob Duvernay assets by acquiring assets from Paramount Resources Ltd.

In Kaybob Duvernay, the Corporation spent $303 million, representing 26% of its 2023 capital program, drilling 22 (22.0 net) horizontal wells.

At year-end 2023, the Corporation's total Proved plus Probable reserves in Kaybob Duvernay were 313.3 MMboe, with 213 (213.0 net) drilling locations booked, representing approximately 26% of the Corporation's total Proved plus Probable reserves. It is expected the total Proved as well as the total Proved plus Probable locations will be developed within six years.

As of December 31, 2023, Crescent Point has allocated approximately 35% of the Corporation's 2024 capital budget to developing the Duvernay resource play in Kaybob Duvernay.

Viewfield Area

In the Viewfield resource area, located in southeastern Saskatchewan, the Corporation has development in the Bakken resource play, as well as conventional plays including the Frobisher and Midale. In 2023, Crescent Point's production averaged approximately 29,300 boe per day in the area. The majority of the production is from the Bakken resource which is a high-quality light oil and exploited using multi-stage fractured horizontal wells. The core area of the Bakken resource has mostly been unitized, which has allowed for the implementation of various waterflood projects.

Crescent Point spent $169 million, representing approximately 14% of its 2023 capital development program, in the Viewfield area including drilling 62 (60.7 net) additional oil wells. The Corporation also continued to focus on waterflood development expansion.

    - 31 -    

At year-end 2023, the Corporation's total Proved plus Probable reserves in the Viewfield area were 172.7 MMboe, with 593 (555.0 net) locations booked to these reserves. This represents approximately 14% of the Corporation's total Proved plus Probable reserves. Crescent Point expects to fully develop this location inventory within five years for Proved reserves, extending to six years for Probable reserves.

As of December 31, 2023, Crescent Point has allocated approximately 9% of the Corporation's 2024 capital budget to development of the Viewfield area, focused on the Bakken resource play and conventional Frobisher and Midale drilling, as well as additional waterflood development.

Shaunavon Area

In the Shaunavon resource area, located in southwest Saskatchewan, the Corporation has development occurring in the Upper and Lower Shaunavon resource zones, as well as conventional Upper Shaunavon pools, all of which are medium quality oil. The Corporation has developed tight oil Upper and Lower resource plays using multi-stage fracture stimulated horizontal wells. In 2023, Crescent Point's production averaged approximately 18,700 boe per day.

Crescent Point spent $134 million, representing approximately 11% of its 2023 capital development program, in the Shaunavon area including drilling 40 (38.2 net) additional wells. The Corporation has also continued to focus on waterflood expansion and has continued its enhanced oil recovery project in a conventional Upper Shaunavon pool.

As of year-end 2023, the Corporation's total Proved plus Probable reserves in the Shaunavon area were 97.1 MMboe, with 475 (461.5 net) locations booked to these reserves. This represents approximately 8% of the Corporation's total Proved plus Probable reserves. Crescent Point expects to fully develop this location inventory within five years for Proved reserves, extending to seven years for Probable reserves.

As of December 31, 2023, Crescent Point has allocated approximately 7% of the Corporation's 2024 capital budget to development of the Shaunavon area, focused on both Upper and Lower Shaunavon drilling, as well as continued expansion of waterflood and polymer enhanced oil recovery projects.

Oil and Gas Wells

Producing Wells
Area	Oil		Gas
	Gross	Net	Gross	Net
CANADA
Saskatchewan	5,274	4,702	55	17
Alberta	614	565	523	453
British Columbia	—	—	—	—
TOTAL CANADA	5,888	5,267	578	470
U.S.
North Dakota	—	—	—	—
TOTAL U.S.	—	—	—	—
Total	5,888	5,267	578	470

    - 32 -    

Non-Producing Wells
Area	Oil		Gas
	Gross	Net	Gross	Net
CANADA
Saskatchewan	3,157	2,629	333	91
Alberta	459	349	312	239
British Columbia	—	—	—	—
TOTAL CANADA	3,616	2,978	645	330
U.S.
North Dakota	—	—	—	—
TOTAL U.S.	—	—	—	—
Total	3,616	2,978	645	330

Notes:

(1)    Gross and net producing and non-producing oil and gas counts include both reserve assigned and non-reserve assigned wells.

(2)    Active injection wells are reflected in the non-producing well count.

All of the Corporation's oil and gas wells are onshore. The Corporation's non-producing wells are generally situated within defined developed areas and include recent drills awaiting final preparation prior to being placed on production; existing wells that may be waiting on improved economic conditions to restart; wells currently in use for observation or monitoring; wells awaiting recompletion in secondary zones or as injectors; or wells scheduled for abandonment. These non-producing entities include wells with reserve assignments as well as currently non-booked wells, which will have various terms of being non-producing from recent to longer-term.

Developed non-producing reserves represent only 0.5% of the Corporation's total Proved reserve category, and 0.3% of the total Proved plus Probable reserve category. The Corporation's wells in the developed non-producing category exist across most of the Corporation's areas and mostly represent wells awaiting final preparation for production, plus those awaiting well reactivation.

Properties With No Attributed Reserves

The following table summarizes the gross and net acres of unproved properties in which we have an interest and also the number of net acres for which our rights to develop or exploit will, absent further action, expire within one year.

	December 31, 2023
	Gross Acres	Net Acres	Net Acres Expiring Within One Year
CANADA
Alberta	676,722	601,318	44,273
Saskatchewan	577,471	548,854	51,117
Manitoba	2,475	2,475	—
British Columbia	—	—	—
Total	1,256,668	1,152,647	95,390
U.S.
North Dakota	—	—	—
Total	—	—	—
Total	1,256,668	1,152,647	95,390

The Corporation has no material drilling commitments relating to unproved properties.

    - 33 -    

Drilling Activity

The following table summarizes the gross and net exploration and development wells we participated in during the year ended December 31, 2023, in each of Canada and the United States.

	Development Wells		Exploration Wells (2)		Total Wells
	Gross	Net	Gross	Net	Gross	Net
CANADA
Oil wells	125	122	—	—	125	122
Natural Gas wells (3)	22	22	—	—	22	22
Service wells	3	3	—	—	3	3
Stratigraphic test	—	—	4	4	4	4
Dry Holes	—	—	—	—	—	—
Total (1)	150	147	4	4	154	151

	Development Wells		Exploration Wells (2)		Total Wells
	Gross	Net	Gross	Net	Gross	Net
U.S.
Oil wells	24	23	—	—	24	23
Natural Gas wells	—	—	—	—	—	—
Service wells	2	2	—	—	2	2
Stratigraphic Test	—	—	—	—	—	—
Dry Holes	—	—	—	—	—	—
Total (1)	26	25	—	—	26	25

Notes:

(1)    Numbers may not add due to rounding.

(2)    Exploration wells in this grouping are based on the well license classification at the time of drilling.

(3) Kaybob Duvernay wells where the primary product is condensate.

For details on important exploration and development activities during 2023, see "Statement of Reserves Data and Other Oil and Gas Information – Major Oil and Gas Properties".

The Corporation has no work commitments for its proved properties (including drilling commitments) in Canada or the U.S. for the next three years.

Tax Horizon

Crescent Point had tax pools of approximately $8.3 billion at December 31, 2023, which are deductible against future taxable income. Based on this tax pool balance and forecast cash flows using December 31, 2023 forecast prices from the average of three Independent Reserve Evaluators (McDaniel, GLJ Ltd. and Sproule Associates Ltd.), with the Corporation's development capital plans, Crescent Point does not expect to be taxable until 2026. Crescent Point is subject to other taxes, such as payroll taxes, property taxes, carbon taxes, sales taxes and foreign withholding taxes as part of its ongoing business.

Costs Incurred(1)

The following table summarizes our property acquisition costs, exploration costs and development costs for the year ended December 31, 2023. Our total capital costs were approximately $5,148.5 million in 2023.

($ millions)	Acquisition Costs (2)
	Proved Properties	Unproved Properties	Exploration Costs	Development Costs
Canada	4,074.4	515.2	26.6	849.5
U.S.	0.1	—	0.1	296.2
Total	4,074.5	515.2	26.7	1,145.7

Notes:

(1)    Costs incurred exclude capitalized administration.

(2)    Excludes disposition proceeds of $611.7 million and $1.9 million for proved and unproved properties, respectively.

    - 34 -    

Production Estimates

The following table discloses the gross volume of production for each product type estimated by McDaniel for 2024 in the estimates of future net revenue with forecast pricing from Proved reserves disclosed above under the heading "Reserves Data – Forecast Prices and Costs".

	Light and Medium Crude Oil	Heavy Crude Oil	Tight Oil	NGLs	Shale Gas	Conventional Natural Gas	Total
	(bbls/d)	(bbls/d)	(bbls/d)	(bbls/d)	(Mcf/d)	(Mcf/d)	(boe/d)
CANADA
Alberta	3,010	—	34,031	39,753	366,653	7,541	139,160
Southwest Saskatchewan	2,656	3,753	11,765	317	9,496	552	20,167
Southeast Saskatchewan	6,783	—	21,189	6,231	12,519	1,820	36,593
Total CANADA(1)	12,449	3,753	66,985	46,302	388,668	9,913	195,919
U.S.
North Dakota	—	—	—	—	—	—	—
Total U.S.(1)	—	—	—	—	—	—	—
Total Corporate(1)	12,449	3,753	66,985	46,302	388,668	9,913	195,919

Note:

(1)    Numbers may not add due to rounding.

In 2024, production in the Montney in Alberta is estimated at 87,151 boe per day (comprised of 34,031 bbl/d Tight Oil; 11 bbl/d Light & Medium Oil; 10,249 bbl/d NGLs; 256,669 Mcf/d Shale Gas; and 496 Mcf/d Conventional Natural Gas). Production in the Kaybob Duvernay area of Alberta is estimated at 46,737 boe per day (comprised of 28,365 bbl/d NGLs; 109,984 Mcf/d Shale Gas; and 251 Mcf/d Conventional Natural Gas). Condensate is estimated to make up 45% of 2024 total production from Kaybob Duvernay. The Montney and Kaybob Duvernay areas make up 44% and 24% of the Corporation's Proved production estimate in the Crescent Point Reserve Report, respectively. Remaining areas each account for a smaller portion of the Corporation's production estimates for 2024.

The following table discloses, for each product type, the gross volume of production estimated by McDaniel for 2024 in the estimates of future net revenue with forecast pricing from Proved plus Probable reserves disclosed above under the heading "Reserves Data – Forecast Prices and Costs".

Region	Light and Medium Crude Oil	Heavy Crude Oil	Tight Oil	NGLs	Shale Gas	Conventional Natural Gas	Total
	(bbls/d)	(bbls/d)	(bbls/d)	(bbls/d)	(Mcf/d)	(Mcf/d)	(boe/d)
CANADA
Alberta	3,132	—	38,160	41,920	392,626	7,994	149,982
Southwest Saskatchewan	2,809	3,864	12,954	340	10,197	579	21,763
Southeast Saskatchewan	7,251	—	22,718	6,594	13,206	1,993	39,096
Total CANADA(1)	13,192	3,864	73,832	48,853	416,029	10,567	210,841
U.S.
North Dakota	—	—	—	—	—	—	—
Total U.S.(1)	—	—	—	—	—	—	—
Total Corporate(1)	13,192	3,864	73,832	48,853	416,029	10,567	210,841

Note:

(1)    Numbers may not add due to rounding.

In 2024, production in the Montney in Alberta is estimated at 95,906 boe per day (comprised of 38,160 bbl/d Tight Oil; 11 bbl/d Light & Medium Oil; 11,138 bbl/d NGLs; 279,081 Mcf/d Shale Gas; and 507 Mcf/d Conventional Natural Gas). Production in the Kaybob Duvernay area of Alberta is estimated at 48,585 boe per day (comprised of 29,590 bbl/d NGLs; 113,545 Mcf/d Shale Gas; and 424 Mcf/d Conventional Natural Gas). Condensate is estimated to make up 46% of 2024 total production from Kaybob Duvernay. The Montney and Kaybob Duvernay areas make up 45% and 23% of the Corporation's Proved plus Probable production estimate in the Crescent Point Reserve Report, respectively. Remaining areas each account for a smaller portion of the Corporation's production estimates for 2024.

    - 35 -    

Production History

The following tables disclose, on a quarterly and annual basis for the year ended December 31, 2023, our share of average daily production volume (prior to deducting royalties), and the prices received, royalties, production costs and transportation costs incurred and netbacks received on a per unit of volume basis for each product type.

Average Daily Production Volume(1)

	Three Months Ended				Year Ended
	March 31, 2023	June 30, 2023	Sept. 30, 2023	Dec. 31, 2023	2023
CANADA
Light and Medium Crude Oil (bbls/d)	12,879	13,188	12,405	12,198	12,665
Heavy Crude Oil (bbls/d)	4,010	3,857	3,617	3,795	3,818
Tight Oil (bbls/d)	39,464	48,151	54,605	56,657	49,779
NGLs (bbls/d)	35,401	34,108	38,316	39,517	36,851
Shale Gas (Mcf/d)	147,458	184,105	232,235	236,926	200,514
Conventional Natural Gas (Mcf/d)	10,233	8,859	12,542	11,380	10,761
Total (boe/d)	118,036	131,465	149,739	153,551	138,326
U.S.
Light and Medium Crude Oil (bbls/d)	—	—	—	—	—
Heavy Crude Oil (bbls/d)	—	—	—	—	—
Tight Oil (bbls/d)	13,720	15,662	21,277	5,855	14,127
NGLs (bbls/d)	5,191	5,291	6,412	1,856	4,683
Shale Gas (Mcf/d)	14,001	15,676	18,917	6,039	13,651
Conventional Natural Gas (Mcf/d)	—	—	—	—	—
Total (boe/d)	21,245	23,566	30,842	8,718	21,085
TOTAL
Light and Medium Crude Oil (bbls/d)	12,879	13,188	12,405	12,198	12,665
Heavy Crude Oil (bbls/d)	4,010	3,857	3,617	3,795	3,818
Tight Oil (bbls/d)	53,184	63,813	75,882	62,512	63,906
NGLs (bbls/d) (2)	40,592	39,399	44,728	41,373	41,534
Shale Gas (Mcf/d)	161,459	199,781	251,152	242,965	214,165
Conventional Natural Gas (Mcf/d)	10,233	8,859	12,542	11,380	10,761
Total (boe/d)	139,280	155,031	180,581	162,269	159,411

Notes:

(1)    Numbers may not add due to rounding.

(2)    For the year ended December 31, 2023, the Company's average condensate production was 22,517 bbl/s, which is included in NGLs production.

    - 36 -    

Prices Received, Royalties, Production Costs and Transportation Costs Incurred – Light and Medium Crude Oil

	Three Months Ended				Year Ended
($ per bbl)	March 31, 2023	June 30, 2023	Sept. 30, 2023	Dec. 31, 2023	2023
CANADA
Prices Received	88.35	89.45	95.42	100.09	93.23
Royalties	(15.49)	(15.10)	(16.83)	(18.39)	(16.42)
Production Costs(1)	(24.41)	(23.39)	(22.61)	(24.12)	(23.63)
Transportation Costs(1)	(0.70)	(1.24)	(1.39)	(1.34)	(1.17)
Netback Received	47.75	49.72	54.59	56.24	52.01
U.S.
Prices Received	—	—	—	—	—
Royalties	—	—	—	—	—
Production Costs(1)	—	—	—	—	—
Transportation Costs(1)	—	—	—	—	—
Netback Received	—	—	—	—	—
TOTAL
Prices Received	88.35	89.45	95.42	100.09	93.23
Royalties	(15.49)	(15.10)	(16.83)	(18.39)	(16.42)
Production Costs(1)	(24.41)	(23.39)	(22.61)	(24.12)	(23.63)
Transportation Costs(1)	(0.70)	(1.24)	(1.39)	(1.34)	(1.17)
Netback Received	47.75	49.72	54.59	56.24	52.01

Note:

(1)    Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.

Prices Received, Royalties, Production Costs and Transportation Costs Incurred – Heavy Crude Oil

	Three Months Ended				Year Ended
($ per bbl)	March 31, 2023	June 30, 2023	Sept. 30, 2023	Dec. 31, 2023	2023
CANADA
Prices Received	66.80	72.89	91.59	74.48	76.19
Royalties	(14.87)	(18.37)	(22.14)	(17.23)	(18.08)
Production Costs(1)	(18.46)	(19.06)	(21.70)	(17.95)	(19.26)
Transportation Costs(1)	(2.35)	(2.41)	(2.40)	(2.40)	(2.39)
Netback Received	31.12	33.05	45.35	36.90	36.46
U.S.
Prices Received	—	—	—	—	—
Royalties	—	—	—	—	—
Production Costs(1)	—	—	—	—	—
Transportation Costs(1)	—	—	—	—	—
Netback Received	—	—	—	—	—
TOTAL
Prices Received	66.80	72.89	91.59	74.48	76.19
Royalties	(14.87)	(18.37)	(22.14)	(17.23)	(18.08)
Production Costs(1)	(18.46)	(19.06)	(21.70)	(17.95)	(19.26)
Transportation Costs(1)	(2.35)	(2.41)	(2.40)	(2.40)	(2.39)
Netback Received	31.12	33.05	45.35	36.90	36.46

Note:

(1)    Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.

    - 37 -    

Prices Received, Royalties, Production Costs and Transportation Costs Incurred – Tight Oil

	Three Months Ended				Year Ended
($ per bbl)	March 31, 2023	June 30, 2023	Sept. 30, 2023	Dec. 31, 2023	2023
CANADA
Prices Received	91.04	91.05	107.80	92.57	96.12
Royalties	(8.96)	(9.32)	(10.03)	(9.97)	(9.63)
Production Costs(1)	(25.16)	(23.81)	(25.54)	(22.31)	(24.12)
Transportation Costs(1)	(5.07)	(4.70)	(5.11)	(5.45)	(5.10)
Netback Received	51.85	53.22	67.12	54.84	57.27
U.S.
Prices Received	103.98	99.72	111.29	115.07	106.74
Royalties	(28.46)	(26.72)	(29.62)	(30.37)	(28.62)
Production Costs(1)	(15.94)	(12.95)	(13.14)	(13.84)	(13.83)
Transportation Costs(1)	(1.85)	(2.38)	(2.08)	(1.68)	(2.07)
Netback Received	57.73	57.67	66.45	69.18	62.22
TOTAL
Prices Received	94.38	93.18	108.78	94.68	98.46
Royalties	(13.99)	(13.59)	(15.52)	(11.88)	(13.83)
Production Costs(1)	(22.78)	(21.14)	(22.07)	(21.51)	(21.85)
Transportation Costs(1)	(4.24)	(4.13)	(4.26)	(5.10)	(4.43)
Netback Received	53.37	54.32	66.93	56.19	58.35

Note:

(1)    Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.

Prices Received, Royalties, Production Costs and Transportation Costs Incurred – NGLs

	Three Months Ended				Year Ended
($ per bbl)	March 31, 2023	June 30, 2023	Sept. 30, 2023	Dec. 31, 2023	2023
CANADA
Prices Received	79.37	67.95	72.10	71.86	72.80
Royalties	(9.49)	(7.93)	(7.44)	(8.90)	(8.43)
Production Costs(1)	(11.12)	(11.14)	(11.77)	(11.88)	(11.50)
Transportation Costs(1)	(2.27)	(3.41)	(2.70)	(3.41)	(2.95)
Netback Received	56.49	45.47	50.19	47.67	49.92
U.S.
Prices Received	35.55	24.06	26.14	18.46	27.05
Royalties	(4.63)	(2.40)	(3.28)	3.18	(2.75)
Production Costs(1)	(5.47)	(3.00)	(3.08)	(2.33)	(3.63)
Transportation Costs(1)	(0.48)	(0.54)	(0.46)	(0.43)	(0.49)
Netback Received	24.97	18.12	19.32	18.88	20.18
TOTAL
Prices Received	73.77	62.71	66.88	70.99	67.64
Royalties	(8.87)	(7.18)	(6.85)	(8.35)	(7.79)
Production Costs(1)	(10.40)	(10.05)	(10.52)	(11.45)	(10.61)
Transportation Costs(1)	(2.04)	(3.03)	(2.38)	(3.27)	(2.68)
Netback Received	52.46	42.45	47.13	47.92	46.56

Note:

(1)    Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.

    - 38 -    

Prices Received, Royalties, Production Costs and Transportation Costs Incurred – Shale Gas

	Three Months Ended				Year Ended
($ per Mcf)	March 31, 2023	June 30, 2023	Sept. 30, 2023	Dec. 31, 2023	2023
CANADA
Prices Received	4.15	2.78	2.84	2.84	3.06
Royalties(2)	(0.07)	0.29	0.14	0.19	0.15
Production Costs(1)	(0.65)	(0.52)	(0.51)	(0.51)	(0.54)
Transportation Costs(1)	(0.42)	(0.36)	(0.37)	(0.58)	(0.44)
Netback Received	3.01	2.19	2.10	1.94	2.23
U.S.
Prices Received	5.22	3.12	2.68	1.08	3.27
Royalties	(0.92)	(0.70)	(0.71)	(0.42)	(0.73)
Production Costs(1)	(0.80)	(0.39)	(0.33)	(0.14)	(0.45)
Transportation Costs(1)	(0.18)	(0.17)	(0.13)	(0.13)	(0.16)
Netback Received	3.32	1.86	1.51	0.39	1.93
TOTAL
Prices Received	4.25	2.81	2.82	2.79	3.07
Royalties(2)	(0.15)	0.21	0.08	0.18	0.10
Production Costs(1)	(0.67)	(0.51)	(0.49)	(0.50)	(0.53)
Transportation Costs(1)	(0.40)	(0.34)	(0.35)	(0.57)	(0.42)
Netback Received	3.03	2.17	2.06	1.90	2.22

Notes:

(1)    Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.

(2)    In Canada, royalties include the impact of the gas cost allowance.

Prices Received, Royalties, Production Costs and Transportation Costs Incurred – Conventional Natural Gas

	Three Months Ended				Year Ended
($ per Mcf)	March 31, 2023	June 30, 2023	Sept. 30, 2023	Dec. 31, 2023	2023
CANADA
Prices Received	4.49	2.81	2.62	2.67	3.11
Royalties(2)	0.32	1.70	0.57	0.68	0.77
Production Costs(1)	(0.71)	(0.53)	(0.47)	(0.48)	(0.54)
Transportation Costs(1)	(0.36)	(0.34)	(0.23)	(0.25)	(0.29)
Netback Received	3.74	3.64	2.49	2.62	3.05
U.S.
Prices Received	—	—	—	—	—
Royalties	—	—	—	—	—
Production Costs(1)	—	—	—	—	—
Transportation Costs(1)	—	—	—	—	—
Netback Received	—	—	—	—	—
TOTAL
Prices Received	4.49	2.81	2.62	2.67	3.11
Royalties(2)	0.32	1.70	0.57	0.68	0.77
Production Costs(1)	(0.71)	(0.53)	(0.47)	(0.48)	(0.54)
Transportation Costs(1)	(0.36)	(0.34)	(0.23)	(0.25)	(0.29)
Netback Received	3.74	3.64	2.49	2.62	3.05

Notes:

(1)    Production costs and transportation costs consist of direct costs incurred to operate both oil and gas wells. Costs are allocated between all product types based on a number of assumptions.

(2)    In Canada, royalties include the impact of the gas cost allowance.

    - 39 -    

Production Volume by Field

The following table discloses for each important field, and in total, our production volumes for the year ended December 31, 2023 for each product type.

Region	Light and Medium Crude Oil	Heavy Crude Oil	Tight Oil	NGLs	Shale Gas	Conventional Natural Gas	Total
	(bbls/d)	(bbls/d)	(bbls/d)	(bbls/d)	(Mcf/d)	(Mcf/d)	(boe/d)
CANADA
Kaybob Duvernay	—	—	6	25,712	112,430	307	44,508
Viewfield	3,787	—	18,344	5,258	10,278	1,112	29,287
Montney	4	—	11,466	2,779	64,132	361	24,998
Shaunavon	2,357	—	14,171	361	10,535	356	18,704
Flat Lake	3,418	—	5,090	1,482	2,274	1,095	10,552
Other Canada (2)	3,099	3,818	702	1,259	865	7,530	10,277
Total CANADA(1)	12,665	3,818	49,779	36,851	200,514	10,761	138,326
U.S.
North Dakota	—	—	14,127	4,683	13,651	—	21,085
Total U.S.(1)	—	—	14,127	4,683	13,651	—	21,085
Total(1)	12,665	3,818	63,906	41,534	214,165	10,761	159,411

Notes:

(1)    Numbers may not add due to rounding.

(2)    Includes all remaining assets in Canada.

    - 40 -    

ADDITIONAL INFORMATION RESPECTING CRESCENT POINT

Directors and Officers

Crescent Point has a board of directors currently consisting of nine individuals. The directors are elected by Shareholders and hold office until the next annual meeting of the Corporation.

The name, municipality of residence and principal occupation during the last five years of each of the directors and executive officers of the Corporation are as follows:

Name and Municipality of Residence	Position Held with the Corporation	Date First Elected or Appointed as Director
Craig Bryksa (4) Calgary, Alberta	President, Chief Executive Officer and Director	2018
Kenneth R. Lamont Calgary, Alberta	Chief Financial Officer	Not applicable
Ryan Gritzfeldt Calgary, Alberta	Chief Operating Officer	Not applicable
Mark G. Eade Calgary, Alberta	Senior Vice President, General Counsel and Corporate Secretary	Not applicable
Garret Holt Calgary, Alberta	Senior Vice President, Strategy and Planning	Not applicable
Michael Politeski Calgary, Alberta	Senior Vice President, Finance and Treasurer	Not applicable
Shelly Witwer Calgary, Alberta	Senior Vice President, Business Development	Not applicable
Justin Foraie Calgary, Alberta	Vice President, Operations and Marketing	Not applicable
Barbara Munroe (6) Calgary, Alberta	Director and Chair of the Board	2016
James E. Craddock(2) (3) (5)Whitney, Texas	Director	2019
John P. Dielwart (3) (4) Calgary, Alberta	Director	2019
Mike Jackson (1) (5)Calgary, Alberta	Director	2016
Jennifer F. Koury (2) (5) Calgary, Alberta	Director	2019
Francois Langlois (1) (3) (4) Calgary, Alberta	Director	2018
Myron M. Stadnyk (1) (2) (4) Calgary, Alberta	Director	2020
Mindy Wight (1) (2) Prince George, British Columbia	Director	2022

Notes:

(1)    Member of the Audit Committee.

(2)    Member of the Human Resources and Compensation Committee.

(3)    Member of the Reserves Committee.

(4)    Member of the Environmental, Safety and Sustainability Committee.

(5)    Member of Corporate Governance and Nominating Committee.

(6)    Chair of the Board serves in an ex officio capacity on each Committee.

As at February 16, 2024, the directors and executive officers as a group beneficially owned, directly or indirectly, or exercised control or direction over 3,045,632 Common Shares, representing approximately 0.5% of the issued and outstanding Common Shares. Including restricted shares and options, ownership increased to 0.9% on a fully diluted basis.

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Craig Bryksa, President, Chief Executive Officer and Director

Craig Bryksa is the President, Chief Executive Officer and a Director of Crescent Point, roles he has held since September 2018. Prior to his current position, Mr. Bryksa was Vice President, Engineering West and has held a number of senior management roles with Crescent Point since joining the Corporation in 2006, directly overseeing the development and operations of each of Crescent Point's core assets.

Mr. Bryksa is the past Chair of the Board of Governors at the Canadian Association of Petroleum Producers ("CAPP"). He has significant experience as a professional engineer in the oil and gas industry, working with companies such as Enerplus Resources Fund and McDaniel & Associates Consultants. Mr. Bryksa is a member of the Association of Professional Engineers and Geoscientists of Alberta ("APEGA") and Association of Professional Engineers and Geoscientists of Saskatchewan ("APEGS"). He holds a Bachelor of Applied Science degree in petroleum engineering from the University of Regina.

Ken Lamont, Chief Financial Officer

Ken Lamont is the Chief Financial Officer of Crescent Point, a role he has held since January 2016. Prior to that, he was Vice President, Finance and Treasurer for Crescent Point. Mr. Lamont has worked in the oil and gas industry since 2001, having held a variety of roles with companies such as Shelter Bay Energy Inc., Direct Energy Marketing Ltd. and Shell Trading Gas and Power Canada Ltd. Prior to 2001, he was a Senior Manager at PricewaterhouseCoopers LLP.

Mr. Lamont holds a Bachelor of Commerce degree (with distinction) from the University of Alberta, is a Chartered Professional Accountant and holds the ICD.D designation. He is a member of the Chartered Professional Accountants of Alberta and a member of the Institute of Corporate Directors.

Ryan Gritzfeldt, Chief Operating Officer

Ryan Gritzfeldt is the Chief Operating Officer of Crescent Point, a role he has held since 2018. Prior to that, he was Vice President, Marketing and Innovation and Vice President, Engineering and Business Development East for Crescent Point from 2010 until 2018. Mr. Gritzfeldt has worked in the oil and gas industry since 1998, having held a variety of roles with companies such as Shelter Bay Energy Inc. and Talisman Energy Inc. in addition to Crescent Point.

Mr. Gritzfeldt is a member of APEGA and APEGS. He holds a Bachelor of Applied Science degree (with great distinction) in industrial systems engineering from the University of Regina.

Mark Eade, Senior Vice President, General Counsel and Corporate Secretary

Mark Eade is the Senior Vice President, General Counsel and Corporate Secretary at Crescent Point. Mr. Eade has served as Corporate Secretary since 2004 and was formerly Vice President, General Counsel and Corporate Secretary. Prior to being named Vice President at Crescent Point in September 2015, he was a partner with Norton Rose Fulbright Canada LLP from August 2011 to August 2015. Prior thereto, Mr. Eade was a partner at McCarthy Tétrault LLP. Mr. Eade has over 30 years of experience in corporate governance, securities and mergers and acquisitions law and has represented clients in a number of significant acquisitions and public offerings.

Mr. Eade holds a Bachelor of Commerce degree (with honors) and a LL.B. degree from the University of Saskatchewan and was called to the Alberta bar in 1994. He is a member of the Law Society of Alberta and the Canadian Bar Association.

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Garret Holt, Senior Vice President, Strategy and Planning

Garret Holt is Crescent Point's Senior Vice President, Strategy and Planning, and has been on the company's executive team since 2019. Mr. Holt has over 30 years of experience in the oil and gas industry. Most recently, he was an Executive Director in Energy Investment Banking with JPMorgan. Prior to that, Mr. Holt held senior executive positions with Wapiti Energy, LLC as Chief Operating Officer and Fairways E&P, LLC as Senior Vice President of Exploration and Production.

He graduated from the University of Tulsa with a Bachelor of Science, Petroleum Engineering (Magna Cum Laude) and is a Registered Professional Engineer.

Michael Politeski, Senior Vice President, Finance and Treasurer

Michael Politeski is the Senior Vice President, Finance and Treasurer. He has held an executive role with the Corporation since joining Crescent Point in March 2015. Mr. Politeski has worked in the oil and gas industry since 2003 in various areas, including treasury and debt capital markets, tax, risk management and insurance, corporate reporting, operational accounting and supply chain management. Prior to joining Crescent Point, Mr. Politeski was the Treasurer and Corporate Controller of Enerplus Corporation and held various management roles with Halliburton Canada and KPMG LLP.

Mr. Politeski is a Chartered Professional Accountant and holds a Bachelor of Commerce degree (with distinction) from the University of Saskatchewan. He is a member of the Institute of Chartered Professional Accountants of Alberta.

Shelly Witwer, Senior Vice President, Business Development

Shelly Witwer is Crescent Point's Senior Vice President, Business Development. Since joining the Corporation in 2007, she has held a number of senior management roles, including Vice President, Land and Vice President, Business Development. Ms. Witwer has significant experience in land and business development roles, having worked for companies such as BP Energy, Burlington Resources and Bear Ridge Resources.

Ms. Witwer is a member of the Canadian Association of Petroleum Landmen and the Petroleum Acquisition and Divestment Association. She holds a Bachelor of Commerce degree and a Bachelor of Arts degree in Energy Economics from the University of Calgary.

Justin Foraie, Vice President, Operations and Marketing

Justin Foraie is Crescent Point's Vice President, Operations and Marketing. Mr. Foraie has been with the Corporation since 2009 and has held engineering roles of increasing responsibility, primarily focused on developing the Corporation's United States properties, where he previously served as Vice President, U.S. Operations for CPEUS. Prior to joining Crescent Point, Mr. Foraie worked for Talisman Energy, Inc..

Mr. Foraie has a Bachelor of Applied Science degree in Petroleum Systems Engineering from the University of Regina and is a graduate of the Stanford Graduate School of Business LEAD program. Mr. Foraie became a Registered Professional Engineer in 2008 and is a member of APEGA and Saskatchewan APEGS.

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Barbara Munroe, Chair of the Board

Ms. Barbara Munroe was admitted to the Law Society of Alberta in 1991 and brings over 30 years of legal experience and industry diversification to the Board. Prior to retiring in March 2019, Ms. Munroe served as Executive Vice President, Corporate Services and General Counsel for WestJet Airlines, a position she held since November 2016. Ms. Munroe joined WestJet in November 2011 as Vice President & General Counsel and was promoted to Senior Vice President, Corporate Services & General Counsel in June 2015. She was the Assistant General Counsel, Upstream at Imperial Oil Ltd. from 2008 to 2011 and the Senior Vice President, Legal/IP & General Counsel, Corporate Secretary for SMART Technologies Inc. from 2000 to 2008. Ms. Munroe additionally serves as a Director of ENMAX Corporation, as well as a trustee of the Alberta Cancer Foundation.

Ms. Munroe holds the ICD.D designation and is a member of the Institute of Corporate Directors. She holds a Bachelor of Commerce, Finance degree and a Bachelor of Law degree, both from the University of Calgary. As Chair of the Board, Ms. Munroe serves on each committee in an ex officio capacity.

James E. Craddock, Director

Mr. James E. Craddock is a seasoned upstream executive who possesses broad-based technical knowledge with over 30 years of experience. He served on Noble Energy Inc.'s Board of Directors since its merger with Rosetta Resources Inc. from 2015 to 2020 and served as the Chairman, Chief Executive Officer and President of Rosetta from 2013 to 2015. Previously, he was the Executive Director and Chief Operating Officer for BPI Industries Inc. and held several positions of increasing responsibility over a 20-year career at Burlington Resources Inc. Mr. Craddock additionally serves as director of Amplify Energy Corp. and Callon Petroleum Company.

Mr. Craddock holds a Bachelor of Science in Mechanical Engineering from Texas A&M University and previously served on the Boards of Templar Energy and the Texas Railroad Commission's Eagle Ford Task Force.

John P. Dielwart, Director

Mr. John P. Dielwart brings a wealth of experience and knowledge to Crescent Point's Board, developed through his varied 40-year career in the oil and gas sector. Most notably, Mr. Dielwart is a founding member of ARC Resources Ltd., holding the position of Chief Executive Officer from 2001 to 2013. He is also a Partner in ARC Financial Corp., sitting on its Investment and Governance committees where he provides leadership support on various complex issues, including internal governance and investment decision-making. Mr. Dielwart is also Chairman of the Board of TransAlta Corporation. Prior to joining ARC in 1996, Mr. Dielwart spent 12 years with a major Calgary based oil and natural gas engineering consulting firm, as Senior Vice-President and a Director, where he gained extensive technical knowledge of oil and natural gas properties in Western Canada.

Mr. Dielwart has a Bachelor of Science in Civil Engineering with Distinction from the University of Calgary. He is a professional engineer, holds the ICD.D designation granted by the Institute of Corporate Directors and has served two three-year terms as a Governor of CAPP, including 18 months as Chair.

Mike Jackson, Director

Mr. Mike Jackson worked in the banking industry from 1984 to 2016 and brings more than 30 years of financial experience in corporate and investment banking. Most recently, he was Managing Director - Investment Banking, Scotiabank Global Banking and Markets, with a focus on the oil and gas industry from 2008 until his retirement in 2016. Prior to that, Mr. Jackson held several senior management roles at Scotiabank, including Managing Director, Oil & Gas Industry Head & Calgary Office Head from 1999 to 2007 and Vice President & Office Head, Corporate Banking Calgary from 1997 to 1999.

Mr. Jackson holds a Bachelor of Science degree and a Master of Business Administration, both from Dalhousie University. Additionally, Mr. Jackson completed the Executive Management Program at Queen's University and holds the ICD.D designation granted by the Institute of Corporate Directors.

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Jennifer F. Koury, Director

Ms. Jennifer F. Koury has over 35 years of professional experience, holding various senior executive positions with BHP Biliton from 2011 to 2017. Part of her responsibilities included the development of BHP Billiton's total rewards program for executives and employees of the Petroleum World-Wide Business. Prior to that, she was Vice President of Corporate Services for Enerplus Corp. from 2006 to 2011 and also held senior management positions with Imperial Oil/Exxon Mobil.

Ms. Koury serves as the Vice-Chair of the Board for the Calgary Zoo, Director for Board Ready Women and Director for Bird Construction. She holds a Bachelor of Commerce degree from the University of Alberta and the ICD.D designation granted by the Institute of Corporate Directors.

François Langlois, Director

Mr. Langlois is an oil and gas executive who brings over 35 years of domestic and international experience to the Crescent Point Board, most recently from his role as Senior Vice President, Exploration & Production with Suncor Energy Inc., where he was responsible for the financial and operating performance of the group from 2011 until his retirement in 2016. Prior thereto, he was Vice President, Unconventional Gas from 2009 to 2010 and held various roles with Petro-Canada from 1982 to 2009, most recently as Vice President, Western Canada Production & North American Exploration.

Mr. Langlois holds a Bachelor of Geological Engineering from Laval University (Quebec City) and the ICD.D designation granted by the Institute of Corporate Directors.

Myron M. Stadnyk, Director

Mr. Myron M. Stadnyk has over 35 years of oil and gas experience and is the former President and CEO of ARC Resources Ltd., retiring in 2020. During his tenure as CEO, and prior to that as COO, Mr. Stadnyk played a pivotal role in ARC’s transformation from a Royalty trust to a leading Canadian producer. His extensive career also includes working for a major oil and gas company in both domestic and international operations.

Mr. Stadnyk earned a Bachelor of Science in Mechanical Engineering from the University of Saskatchewan and is a graduate of the Harvard Business School Advanced Management Program. He holds an ICD.D designation and is a member of APEGA.

Mr. Stadnyk formerly held a position on the Board of Directors at PrairieSky Royalty Ltd. and served as a Governor for CAPP for over a decade. Currently, Mr. Stadnyk is a board member of Vermilion Energy Inc. and serves on the Board of Trustees for the University of Saskatchewan Engineering Advancement Trust.

Mindy Wight, Director

Ms. Mindy Wight brings over 15 years of tax and financial expertise from her current role of Chief Executive Officer for the Nch'kay Development Corporation. She previously held the role of Chief Financial Officer, as well as holding the role as Treasurer of the Board of Directors.

Prior to joining Nch'kay Development Corporation in November 2021, Ms. Wight held progressive tax roles at MNP LLP from 2016 to 2021 and most recently was a partner and National Leader of Indigenous Tax Services for the firm. Ms. Wight has also worked for two of the Big Four National accounting firms, the Chartered Accounting School of Business and the Canada Revenue Agency since graduating from the University of Northern British Columbia with a Bachelor of Commerce Degree, Accounting in 2007. Ms. Wight also possesses Chartered Professional Accountant, Chartered Accountant, and Certified Aboriginal Financial Manager designations.

Ms. Wight has historically held Board positions as the Chair of the Board of Directors and Chair of the Finance and Audit Committee for the Nch'kay Development Corporation and was an Advisory Committee Member of the Budget and Financial Committee to the Squamish Nation.

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Bankruptcies and Cease Trade Orders

No director, executive officer or shareholder holding a sufficient number of securities to affect materially the control of the Corporation is, as of the date of this AIF, or has been, within the last 10 years, been a director or executive officer of any company (including the Corporation) that, while such person was acting in that capacity, was the subject of a cease trade or similar order or an order that denied the Corporation access to any statutory exemption for a period of more than 30 consecutive days or was declared a bankrupt or made a voluntary assignment in bankruptcy, made a proposal under any legislation relating to bankruptcy or been 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 that person, except for Mr. Dielwart, who was a director of Denbury Resources Inc. when it entered into Chapter 11 proceedings in the United States on July 30, 2020. Denbury Resources Inc. subsequently emerged from Chapter 11 proceedings on September 18, 2020 and Mr. Dielwart resigned as a director of Denbury Resources Inc. at that time.

Penalties or Sanctions

No director, executive officer or shareholder holding a sufficient number of securities to affect materially the control of the Corporation, within the last 10 years, has been subject to any penalties or sanctions imposed by a court or securities regulatory authority relating to trading in securities, promotion or management of a publicly traded issuer or theft or fraud.

Personal Bankruptcies

No director, executive officer or shareholder holding a sufficient number of securities to affect materially the control of the Corporation, or a personal holding company of any such persons, has, within the 10 years preceding the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or being 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 individual.

Share Capital

The Corporation is authorized to issue an unlimited number of Common Shares.

Common Shares

Each Common Share entitles its holder to receive notice of and to attend all meetings of the Shareholders of the Corporation and to one vote at such meetings. The holders of Common Shares are, at the discretion of the Board of Directors and subject to applicable legal restrictions, entitled to receive any dividends declared by the Board of Directors. The holders of Common Shares are entitled to share equally in any distribution of the assets of the Corporation upon the liquidation, dissolution, bankruptcy or winding up of the Corporation or other distribution of its assets among its Shareholders for the purpose of winding up its affairs. Such participation is subject to the rights, privileges, restrictions and conditions attaching to any other shares having priority over the Common Shares.

Premium DividendTM and Dividend Reinvestment Plan

The DRIP was in effect from 2010 until August 2015, when it was suspended.

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Under the Corporation's DRIP, eligible Shareholders may, at their option, reinvest their cash dividends to purchase additional Common Shares at 95% of the average market price (as defined in the DRIP) of a Common Share on the applicable distribution date. The DRIP also provides an alternative where eligible Shareholders may elect, under the premium dividend component, to receive a premium cash distribution equal to 102% of the reinvested cash dividends that such Shareholders would have otherwise been entitled to receive on the applicable dividend date. Generally, no commissions, service charges or brokerage fees will be payable by Shareholders who participate in the DRIP. We have reserved the right to determine how much new equity is available under the Plan on any particular distribution date. Accordingly, participation in the DRIP may be pro-rated in certain circumstances.

Registered and beneficial owners of Common Shares who are not resident in Canada are not eligible to participate in the DRIP.

Share Dividend Plan

The SDP was in effect from May 9, 2014 until it was suspended on August 12, 2015.

Under the terms of the SDP, eligible Shareholders may, at their option, elect to receive dividends declared on Common Shares as share dividends rather than cash dividends, where such share dividends are declared by the Board of Directors, to be payable in either cash or Common Shares at the election of the Shareholder. Share dividends are satisfied through the issuance of new Common Shares equal to the amount obtained by dividing the dollar amount of the dividend per Common Share by 95% of the average market price (as defined in the SDP) on the TSX. Generally, no commissions, service charges or brokerage fees will be payable by Shareholders who participate in the SDP. Under the SDP, we have reserved the right to determine how much new equity is available under the SDP on any particular distribution date. Accordingly, participation in the SDP may be pro-rated in certain circumstances.

Unlike the dividend reinvestment component of the DRIP, which gives only Shareholders resident in Canada the option to reinvest cash dividends into Common Shares at a 5% discount to market prices, the SDP provides all Shareholders with the option to receive dividends in the form of Common Shares at a 5% discount to current market prices.

Restricted Share Bonus Plan

Under the terms of the Corporation's Restricted Share Bonus Plan, any director, officer or employee of the Corporation who, in each case, in the opinion of the Board of Directors, hold an appropriate position with the Corporation to warrant participation in the Restricted Share Bonus Plan (collectively, the "RSBPParticipants") may be granted restricted shares ("Restricted Shares") which vest over time and, upon vesting, can be redeemed by the holder for cash or Common Shares at the option of the Corporation. The Restricted Share Bonus Plan is administered by the Board of Directors. Under the Restricted Share Bonus Plan at December 31, 2023 the Corporation is authorized to issue up to 9,774,533 Common Shares, of which the Corporation had 1,380,685 Restricted Shares outstanding at December 31, 2023.

The Restricted Shares vest on terms up to three years from the grant date as determined by the Board of Directors. Upon redemption, the Corporation will be required to pay to the RSBP Participant the fair market value of the redeemed Restricted Shares, based on the weighted average of the prices at which the Common Shares traded on the TSX for the five trading days immediately preceding the redemption date, plus any accrued but unpaid dividend amounts in respect of such Restricted Shares (the "Payout Amount"). The Payout Amount may be satisfied by the Corporation making a cash payment, the Corporation purchasing Common Shares in the market and delivering such Common Shares to the RSBP Participant or by issuing Common Shares from treasury.

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DSU Plan

In 2012, the Corporation established a deferred share unit plan (the "DSU Plan") to enhance its ability to attract and retain key personnel (namely, selected officers and employees and non-employee directors) and reward significant performance achievements. Under the terms of the DSU Plan, Designated Employees and Directors (as defined in the DSU Plan), who, in the opinion of the Board of Directors, warrant participation in the DSU Plan (the "Participants"), may be granted deferred share units ("Units"). As at the date hereof, only non-employee directors have been granted DSUs.

Participants that are directors must elect to receive Units in lieu of a cash retainer prior to the year in which the retainer will be earned, unless they are elected or appointed part way through a year, in which case they must elect within 30 days of being elected or appointed to receive Units for that year. Participants that are Designated Employees must elect to receive Units in lieu of all or a portion of their annual bonus entitlement or profit share for the year within 30 days after such Designated Employee has been notified by the Corporation of such individual's bonus entitlement or profit share for such year.

The Corporation establishes an account for each Participant and all Units are credited to the applicable account as of the award date. The number of Units to be credited to an account is determined by dividing the dollar amount elected by the Participant by the five day weighted average closing price of the Common Shares on the TSX immediately prior to the award date. On the last day of each fiscal quarter of the Corporation or as soon as possible thereafter, the Corporation determines whether any dividend has been paid on Common Shares during such fiscal quarter and, if so, the rate thereof per Common Share (the "Dividend Rate") and, within 10 business days of the applicable fiscal month end, the Corporation credits each applicable account with an additional number of Units equal to (i) the number of Units in the applicable account on the record date for such dividend multiplied by (ii) the Dividend Rate. All Units vest immediately upon being credited to a Participant's account.

A Participant is not entitled to any payment of any amount in respect of Units until such Participant ceases to be an employee or director of the Corporation, as the case may be, for any reason whatsoever. Upon the Participant ceasing to be an employee or director of the Corporation, the Participant is entitled to receive a lump sum cash payment, net of applicable withholding taxes, equal to the product of (i) the number of Units in such Participant's account on the date the Participant ceased to be an employee or director and (ii) the five day weighted average closing price of the Common Shares on the TSX immediately prior to such date, unless the redemption event occurs during a black out period, in which case the amount of such payment will be calculated with reference to the five day weighted average closing price of the Common Shares on the TSX on the fifth business day following the end of such black out period. The Corporation will make such lump sum cash payment by the end of the calendar year following the year in which the Participant ceased to be an employee or director.

On March 10, 2015, the Board amended the DSU Plan to include provisions that govern citizens and residents in conformity with Section 409A of the U.S. Internal Revenue Code. This amendment was made to clarify and explicitly disclose certain tax consequences associated with participation in the DSU Plan by eligible U.S. citizens and U.S. residents.

The Corporation had 1,728,423 DSUs outstanding at December 31, 2023.

PSU Plan

In 2017, the Corporation adopted the PSU Plan, which is administered by the Board of Directors. The purposes of the PSU Plan are: (i) to promote alignment of interests between participants in the PSU Plan and Shareholders by providing the participants with an opportunity to participate in an increase in the equity value of the Corporation, taking into account the performance of the Corporation relative to its peers and targets established by the Board; (ii) to provide participants in the PSU Plan with compensation reflective of their responsibility, commitment and risk accompanying their role over the long-term; and (iii) to provide a retention incentive to participants in the PSU Plan over the long-term. Under the terms of the PSU Plan, the Compensation Committee may designate employees of the Corporation or its affiliates who are eligible to receive performance share units ("PSUs"). PSUs are notional grants of share-based compensation units that entitle the holder to a cash payment upon redemption of the PSU.

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Unlike Restricted Shares, PSUs do not automatically vest over time. Instead, vesting is dependent on the achievement of various corporate performance metrics over a three year performance period.

The vested number of PSUs relating to a given performance period are paid out in cash based on the volume weighted average trading price of the Common Shares on the TSX over the five business days subsequent to the end of the performance period for the applicable PSUs, plus the dividends paid during the applicable performance period. For PSUs that were granted in 2023 or later, the vested number of PSUs relating to a given performance period are paid out in cash based on the volume weighted average trading price of the Common Shares on the TSX over the five business days subsequent to the end of the performance period for the applicable PSUs. Dividends paid during the applicable performance period are reinvested in additional PSUs, which vest on the vest date of the original grant.

Based on underlying units prior to any effect of the performance multiplier, the Corporation had 1,623,248 PSUs outstanding at December 31, 2023.

Stock Option Plan

The Corporation has made no stock option ("Options") grants since 2021 and does not intend to grant Options in the future.

The Corporation adopted the Stock Option Plan in early 2018, with the purpose of rewarding those persons who promote the growth and success of the Corporation and assisting the Corporation in attracting, motivating and retaining personnel. The Stock Option Plan was approved by the Shareholders at the Corporation's annual meeting of shareholders on May 4, 2018 and amended to reduce the maximum number of Common Shares issuable under the Stock Option Plan at the Corporation's annual meeting of shareholders on May 14, 2020.

Pursuant to the terms of the Stock Option Plan, a maximum of 10,000,000 Common Shares may be issuable upon the exercise of Options granted under the Stock Option Plan (subject to adjustment for any subdivision or consolidation of the Common Shares). As at December 31, 2023, there were 3,224,260 Options to purchase Common Shares outstanding. Additionally, the number of Common Shares issuable to insiders of the Corporation (as defined in the Company Manual of the TSX) in any one year period, or at any time when combined with Common Shares issued or issuable under any of the Corporation's other security-based compensation plans, may not exceed 10% of the issued and outstanding Common Shares, and no one insider (or associates of that insider, as defined in the Company Manual of the TSX) may be issued more than 5% of the issued and outstanding Common Shares in any one year period. Non-employee directors are not entitled to participate in the Stock Option Plan. No Options shall be granted to any participant if the total number of Common Shares issuable to or on behalf of such participant under the Stock Option Plan, together with any Common Shares reserved for issuance to such participant under any other share compensation or incentive mechanism of the Corporation (which includes RSUs issued under the Restricted Share Bonus Plan) would exceed 5% of the aggregate issued and outstanding Common Shares.

The Board of Directors administer the Stock Option Plan, and will from time to time designate officers and employees of the Corporation who are entitled to participate in the Stock Option Plan, and determine the number and exercise price of Options to be granted to such participants. Non-employee directors are prohibited from participating in the Stock Option Plan. Under the Stock Option Plan, the exercise price of Options is determined by the Board of Directors at the time of grant, but will not be less than permitted by the applicable rules and policies of the TSX. Subject to the vesting provisions of the Stock Option Plan, Options may be: (i) exercised by paying the Corporation the exercise price in exchange for Common Shares; (ii) surrendered to the Corporation in exchange for a cash payment representing the aggregate difference between the market price of the Common Shares and the exercise price of the Options surrendered; or (iii) surrendered to the Corporation in exchange for a number of Common Shares equivalent in value (based on the market price) to the aggregate difference between market price of the Common Shares and the exercise price of the Options surrendered.

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Unless the Board of Directors determine otherwise, Options granted pursuant to the Stock Option Plan will have a term of seven years, subject to early expiry in accordance with the change in control and other provisions of the Stock Option Plan. All Options are granted pursuant to stock option agreements executed at the time of grant by the Corporation and the grantee.

Employee Share Value Plan

In early 2020, the Corporation adopted an Employee Share Value Plan ("ESVP") for certain employees in lieu of grants that would have previously been made under the Restricted Share Bonus Plan. Under the terms of the ESVP, any employee of the Corporation who, in each case, in the opinion of the Board of Directors, holds an appropriate position with the Corporation to warrant participation in the ESVP (collectively, the "ESVPParticipants") may be granted rights ("Awards") which vest over time and, upon vesting, entitle the participant to receive a cash payment for each Award equal to the five day weighted average trading price on the TSX of the Common Shares immediately preceding the vesting date plus an amount equal to the aggregate amount paid by the Corporation in dividends per Common Share from the grant date of an Award to and including the vesting date (collectively, the "Payout Value"). ESVP Participants do not have any right to receive Common Shares in respect of vested Awards.

Awards vest as to 33 1/3% on each of the first, second and third anniversaries of the grant date as determined by the Board of Directors. Upon vesting of an Award, the Corporation is required to pay to an ESVP Participant the Payout Value within 15 business days of vesting and, in all cases, prior to December 31 of the year of vesting.

The Employee Share Value Plan is administered by the Board of Directors. At December 31, 2023, there were 2,660,066 awards outstanding.

Long-Term Debt - Bank Debt

At December 31, 2023, the Company had combined revolving facilities (the “Credit Facilities”) of $2.76 billion and a $750.0 million syndicated term loan (the “Term Loan”).

The revolving Credit Facilities include a $2.26 billion syndicated unsecured credit facility (the “Syndicated Credit Facility”) with eleven banks and a $100 million unsecured operating credit facility with one Canadian chartered bank (the "Bi-Lateral Credit Facility"), both with a current maturity date of November 26, 2026. On May 10, 2023, concurrent with the closing of the Alberta Montney acquisition, Crescent Point entered into an additional $400.0 million syndicated unsecured revolving credit facility (the “Syndicated Liquidity Credit Facility”) with ten banks that matures on May 10, 2025.

The Syndicated Credit Facility and the Bi-Lateral Credit Facility's interest rate is based on either Canadian prime rate, U.S. base rate, Secured Overnight Financing Rate or bankers' acceptance rates at the Corporation's option subject to certain basis point or stamping fee adjustments ranging from 0.25% to 3.15%, depending on the Corporation's senior debt to earnings before interest, taxes, depreciation and amortization, adjusted for certain non-cash items ("adjusted EBITDA") ratio. The Syndicated Liquidity Credit Facility’s adjustments for its interest rate is subject to certain basis point or stamping fee adjustments ranging from 0.45% to 4.00%. The Credit Facilities are guaranteed by certain restricted subsidiaries currently being CPEUS, CPHL and the Partnership. Various borrowing options are available under the Credit Facilities, including Canadian prime rate-based advances, U.S. base rate-based advances, Secured Overnight Financing Rate loans and bankers' acceptance loans. The Syndicated Credit Facility and Bi-Lateral Credit Facility constitute revolving credit facilities and are extendible annually. The Credit Facilities contain standard commercial covenants for facilities of this nature. Distributions to Shareholders and share repurchases are not permitted if the Corporation is in default of the Credit Facilities or if the making of such distribution would cause an event of default. The Corporation does not have a borrowing base restriction respecting its Credit Facilities.

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On December 21, 2023, concurrent with the closing of the Hammerhead Acquisition, the Company entered into the Term Loan with twelve banks that matures on November 26, 2026 and is repayable at any time with no penalty, provided that prepayments using the proceeds of advances under the Credit Facilities may only be made if no less than 15% of total commitments thereunder will remain undrawn on a pro forma basis after giving effective to any and all such prepayments. The Term Loan interest rate is based on either the Canadian prime rate or Canadian Overnight Repo Rate Average at the Corporation's option subject to certain basis points adjustments ranging from 2.00% to 3.00%. The Term Loan is guaranteed by certain restricted subsidiaries currently being CPEUS, CPHL and the Partnership. The Term Loan has financial covenants similar to those of the Credit Facilities described above and includes certain mandatory repayment provisions with cash proceeds received from future issuances of equity securities, debt securities and proceeds received from property dispositions.

At December 31, 2023, the Corporation had approximately $2.72 billion drawn under its Credit Facilities and Term Loan.

Long-Term Debt - Senior Guaranteed Notes

At December 31, 2023, the Corporation had approximately $883.4 million of senior guaranteed notes (the “Senior Guaranteed Notes") outstanding of which $380.0 million become due within one year excluding the value of underlying cross currency swaps. The Senior Guaranteed Notes are unsecured and rank pari passu with the Corporation’s Credit Facilities and carry a bullet repayment on maturity. The Senior Guaranteed Notes have financial covenants similar to those of the Credit Facilities described above. Concurrent with the issuance of US$517.0 million Senior Guaranteed Notes, the Corporation entered into cross currency swaps to hedge its foreign exchange exposure, fixing a notional amount of $606.9 million for the purpose of interest and principal repayments.

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations imposed by various levels of government. It is not expected that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and gas entities of similar size. All current legislation is a matter of public record, and we are unable to predict what additional legislation or amendments may be enacted.

Pricing and Marketing - Oil

In Canada, producers of oil negotiate sales contracts directly with oil purchasers. Oil prices are primarily based on worldwide and North American supply and demand. The specific price paid depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products and the supply/demand balance.

Oil exports from Canada may be made pursuant to an export contract with a term not exceeding one year in the case of light crude oil, and not exceeding two years in the case of heavy crude oil, provided that an order approving any such export has been obtained from the Canada Energy Regulator (the "CER"). Any 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 CER and the issue of such a license requires the approval of the Governor in Council.

In the United States, transportation of crude oil is subject to rate and access regulation. The Federal Energy Regulatory Commission (the "FERC") regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act of 1887 (the "ICA"). In general, such pipeline rates must be cost-based. The FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service. Such rates and terms and conditions may not be discriminatory or preferential. A pipeline may also file cost-of-service based rates if rate indexing will be insufficient to allow the pipeline to recover its costs. Intrastate crude oil pipeline transportation rates may be subject to regulation by state regulatory commissions. The basis for intrastate pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state.

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On December 18, 2015, the U.S. Congress passed, and the President signed, legislation into law which repealed the 40-year old ban on exports of crude oil produced in the United States. Accordingly, most exports of domestically-produced crude oil may be made without an export license. Only exports to embargoed or sanctioned countries continue to require authorization from the U.S. Department of Commerce.

Pricing and Marketing - Natural Gas

In Canada, the price of natural gas sold intra-provincially or to the United States is determined by negotiation between buyers and sellers. In the United States, the price of inter-state or international sales is determined by negotiation between buyers and sellers based upon factors normally considered in the industry such as distance from well to pipeline, pressure, and quality. Natural gas exported from Canada is subject to regulation by the CER and the Government of Canada, and in the United States is regulated principally by the FERC and the United States Department of Energy (the "DOE"). The FERC, which has the authority under the Natural Gas Act of 1938 (the "NGA") to regulate prices, terms and conditions for the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to FERC regulation, except interstate pipelines, to resell natural gas at market prices. In addition, under the provisions of the Energy Policy Act of 2005, the NGA was amended to prohibit market manipulation in connection with the purchase or sale of natural gas and the FERC established regulations to increase natural gas pricing transparency by requiring certain market participants to report their gas sales transactions annually to the FERC. Facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Although FERC has set forth a general test to determine whether facilities are exempt from FERC jurisdiction as "gathering" facilities, FERC's determinations as to the classification of facilities are performed on a case-by-case basis and FERC has the authority to reclassify facilities previously thought to be non-jurisdictional. The FERC regulates interstate natural gas transportation rates and service conditions under the NGA and the Natural Gas Policy Act of 1978 (the "NGPA"), which affects the marketing of natural gas, as well as revenues we may receive for sales of our natural gas. Intrastate natural gas transportation service is also subject to regulation by state regulatory agencies.

In both Canada and the United States, exporters are free to negotiate prices and other terms with purchasers, provided that the export contract meets certain criteria prescribed by the CER and the Government of Canada or, in relation to United States exports, restrictions on export licenses imposed by the DOE. Natural gas may not be exported from Canada without a license or order from the CER or imported into the United States or exported from the United States without a license from the DOE. Licenses to export or import natural gas may include various terms and conditions with respect to duration, quantity, tolerance levels, points of exportation or importation, environmental requirements, among other factors and, in Canada, for export, may be obtained for a period that does not exceed 40 years. In Canada the approval of the Minister of Natural Resources and the Governor in Council is currently required prior to the issuance of a license to export natural gas. Alternatively, natural gas may be exported from Canada pursuant to an order from the CER. Orders may be obtained for a period of two years or less or for a period greater than two years but less than 20 years, where the quantity is not more than 30,000 m3/day. Orders do not require the approval of the Governor in Council or the Minister of Natural Resources. Any person who imports oil or gas into Canada must provide prescribed information in the prescribed form and manner to the CER, but does not require a license. In the United States, the DOE regulates the exportation and importation of natural gas, including liquefied natural gas. U.S. law provides for very limited regulation of exports to and imports from any country that has entered into a free trade agreement with the United States that provides for national treatment of trade in natural gas, however, the DOE's regulation of imports and exports from and to countries without such free trade agreements is more comprehensive. The FERC also regulates the construction and operation of import and export facilities.

The Canada-United States-Mexico Agreement and The North American Free Trade Agreement

On July 1, 2020, the Canada-United States-Mexico Agreement ("CUSMA") came into force replacing the North American Free Trade Agreement ("NAFTA").

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Relevant to the energy industry, CUSMA does not contain the proportionality rules found in NAFTA's Article 605 whereby Canada remained free to restrict exports to the U.S. or Mexico provided that such export restrictions did not: (i) reduce the proportion of the energy resource exported relative to the total supply of that energy resource in Canada as compared to the proportion prevailing in the most recent 36-month period; (ii) impose an export price higher than the domestic price; and (iii) disrupt normal channels of supply.

CUSMA also eliminated certain tariffs on some diluents used to transport heavy oil from Canada to the U.S.

There has been little to no effect on Canada's energy industry by the ratification of CUSMA and Crescent Point has experienced little to no change to its operations or marketing activities as a result of the ratification of CUSMA.

Royalties and Incentives

In addition to federal regulation, each province has legislation with respect to oil and gas activities, governing matters such as land tenure, royalties, production rates, environmental protection and other matters. In all Canadian jurisdictions where we operate, producers of oil and natural gas are required to pay annual rental payments in respect of Crown leases and royalties and freehold production taxes in respect of oil and natural gas produced from Crown and freehold lands, respectively. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity and depth, geographical location, field discovery date and the type or quality of the petroleum product produced.

From time to time, the governments of Canada, Alberta and Saskatchewan have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced production projects. Such programs are generally introduced when commodity prices are low, and are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. These programs reduce the amount of Crown royalties otherwise payable.

Alberta

In terms of oil or natural gas production from Crown lands, royalties are payable to the Province of Alberta. In respect of freehold lands, royalties are payable to the mineral owner and taxes are payable to the Province of Alberta. The Government of Alberta's approach to the royalty and tax regime is regularly reviewed for compliance with the purpose of the regimes to ensure that Albertans are receiving a fair share from energy development through royalties, taxes and fees.

On January 1, 2017, Alberta adopted a new, modernized Alberta royalty framework (the "Modernized Framework") that applies to all wells drilled after December 31, 2016. The previous royalty framework (the "Old Framework") continues to apply to wells drilled prior to January 1, 2017 for a period of ten years ending on December 31, 2026. After the expiry of this ten-year period, these older wells will become subject to the Modernized Framework.

The Modernized Framework applies to all hydrocarbons other than oil sands, which remain subject to their pre-existing royalty regime. Royalties on production from non-oil sands wells under the Modernized Framework are determined on a "revenue-minus-costs" basis with the cost component based on a Drilling and Completion Cost Allowance formula for each well, depending on its vertical depth and horizontal length. The formula is based on the industry's average drilling and completion costs as determined by the AER on an annual basis.

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Producers pay a flat royalty rate of 5% of gross revenue from each well that is subject to the Modernized Framework until the well reaches payout. Payout for a well is the point at which cumulative gross revenues from the well equals the Drilling and Completion Cost Allowance for the well set by the AER. After payout, producers pay an increased post-payout royalty on revenues determined by reference to the then current commodity prices of the various hydrocarbons. Similar to the Old Framework, the post-payout royalty rate under the Modernized Framework varies with commodity prices. Once production in a mature well drops below a threshold level where the rate of production is too low to sustain the full royalty burden, its royalty rate is adjusted downward as the mature well's production declines.

As the Modernized Framework uses deemed drilling and completion costs in calculating the royalty and not the actual drilling and completion costs incurred by a producer, low cost producers benefit if their well costs are lower than the Drilling and Completion Cost Allowance and, accordingly, they continue to pay the lower 5% royalty rate for a period of time after their wells achieve actual payout.

The Old Framework is applicable to all conventional oil and natural gas wells drilled prior to January 1, 2017 and bitumen production. Subject to certain available incentives, effective from the January 2011 production month, royalty rates for conventional oil production under the Old Framework range from a base rate of zero to a cap of 40%.

The Old Framework also includes a natural gas royalty formula, which formula provides for a reduction based on the measured depth of the well below 2,000 metres deep, as well as the acid gas content of the produced gas. Subject to certain available incentives, effective from the January 2011 production month, royalty rates for natural gas production under the Old Framework range from a base rate of 5% to a cap of 36%.

Under the Old Framework, the royalty rate applicable to natural gas liquids is a flat rate of 40% for pentanes and 30% for butanes and propane.

In terms of oil and natural gas production obtained from lands other than Crown lands, taxes are payable to the Province of Alberta. Approximately 19% of the mineral rights in the Province of Alberta are freehold mineral rights not owned by the Alberta Crown. The tax levied in respect of freehold oil and gas production in the Province of Alberta is calculated annually based on a rate dependent on the prescribed tax rate, the quantity of produced oil or gas, and the unit value of the produced oil or gas.

Incentive Programs

A number of incentive programs, including the Enhanced Oil Recovery Royalty Program (the "EOR Program") were created pursuant to the Old Framework.

Under the EOR Program, Alberta Energy may approve royalty reductions for qualifying enhanced oil recovery projects. Applications under the EOR Program ceased being accepted as of December 31, 2016, however, the EOR Program continues to apply to schemes previously approved thereunder, and will continue to so apply until December 31, 2026.

Under the Modernized Framework, two strategic programs were introduced with the intention of promoting expanded production potential and generating long-term returns to the Province of Alberta.

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The Enhanced Hydrocarbon Recovery Program (the "EHR Program") began January 1, 2017, and replaced the EOR Program. The EHR Program is intended to promote incremental production through enhanced recovery methods and consists of two main components. The first component targets tertiary recovery schemes which enhance recovery of hydrocarbons from an oil or gas pool by miscible flooding, immiscible flooding, solvent flooding, chemical flooding or other approved methods. The second component targets secondary recovery schemes which enhance recovery of hydrocarbons from an oil or gas pool by waterflooding, gas cycling, gas flooding, polymer flooding or other approved methods. Under both components of the program, a company pays a flat royalty of 5% on crude oil, natural gas and natural gas liquids produced from wells in an approved scheme for a limited benefit period. After the benefit period ends, wells in these schemes are subject to normal royalty rates under the Modernized Framework.

The Emerging Resources Program (the "ERP") began January 1, 2017. The ERP is intended to encourage industry to open up new oil and gas resources in higher-risk and higher-cost areas that have large resource potential. For the purposes of the ERP, a project consists of a defined geographic area, target formation, set of wells and associated infrastructure. Wells that receive program benefits pay a flat royalty rate of 5% on revenues until their combined revenue equals their combined program specific cost allowances established under the ERP, which replace the standard Drilling and Completion Cost Allowance under the Modernized Framework in respect of such wells. After achieving payout of the specific cost allowance, wells are subject to normal royalty rates under the Modernized Framework.

Saskatchewan

With respect to production obtained from provincial Crown lands in the Province of Saskatchewan, the amount payable as a royalty in respect of crude oil depends on the vintage of the oil, the type of oil, the quantity of oil produced in a month and the price of the oil. For both Crown royalty and freehold production tax purposes, crude oil is categorized by oil type as "heavy oil", "southwest designated oil" or "non-heavy oil other than southwest designated oil". Additionally, the oil in each category is subdivided according to the conventional royalty and production tax classifications as "fourth tier oil", "third tier oil", "new oil", or "old oil". The royalty reserved to the Crown depends on the categorization and classification of the oil, monthly production, and a prescribed reference price determined monthly by the Saskatchewan Ministry of Energy and Resources ("SMER").

Similarly, the amount payable as a royalty in respect of natural gas in the Province of Saskatchewan depends on the vintage of the gas, the type of gas production, the quantity of gas produced in a month, and the price of the gas. For both provincial Crown royalty and freehold production tax purposes, natural gas is categorized as either non-associated gas or associated gas, the former being gas produced from gas wells and the latter being gas produced from oil wells. Additionally, the gas is divided according to the royalty and production tax classifications as "fourth tier gas", "third tier gas", "new gas", or "old gas". The royalty reserved to the Crown depends on the categorization and classification of the natural gas, monthly production, and a reference price prescribed by the SMER. As an incentive for the production and marketing of natural gas which may otherwise have been flared, the royalty rate on associated gas is less than on non-associated natural gas.

Approximately 17% of the mineral rights in the Province of Saskatchewan are freehold mineral rights not owned by the provincial Crown. With respect to production from freehold lands, the tax levied on oil and gas production in the Province of Saskatchewan will depend on the classification of the oil or gas and the relevant Crown royalty rate.

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Incentive Programs

On October 1, 2002, a modified system of incentive volumes and maximum royalty/tax rates applicable to the initial production from qualifying oil wells and gas wells in the Province of Saskatchewan with a finished drilling date on or after October 1, 2002, was introduced. The incentive volumes are applicable to various well types and are subject to a maximum royalty rate of 2.5% and a freehold production tax rate of 0%. In addition, oil produced from Enhanced Oil Recovery ("EOR") projects that commenced operation prior to April 1, 2005 are subject to a cost sensitive royalty regime determined by prescribed formulas which include a number of variables and which differentiate between pre- and post-project payout. EOR projects that commenced operation on or after April 1, 2005 are also subject to a cost sensitive royalty regime that provides a royalty of 1% of gross EOR revenues prior to project payout and 20% of EOR operating income after project payout and a freehold production tax rate of 0% prior to payout and 8% of EOR operating income after payout. In respect of new waterflood projects, or expansions of existing waterflood projects, that have been approved by the minister and that commenced operation on or after October 1, 2002, the incremental oil produced from the project as a result of the waterflood operations qualifies for the "fourth tier oil" Crown royalty and freehold production tax rates.

In April of 2013, the SMER announced three new drilling incentives for wells drilled on or after October 1, 2002: the vertical well drilling incentive (the "VWDI"); the horizontal well drilling incentive (the "HWDI"); and the exploratory gas well drilling incentive (the "EGWDI"). The VWDI provides a royalty reduction to 2.5% and a freehold production tax rate of 0% for fixed volumes drilled from exploratory vertical oil wells and deep development vertical oil wells. Exploratory vertical oil wells are wells that meet certain prescribed criteria showing the well produces oil from an area which has not generally seen production. The incentive for exploratory vertical oil wells applies to the produced volume up to 16,000m³, depending on depth. Deep development vertical oil wells are deep or deepened wells, that are not exploratory oil wells, drilled to certain prescribed zones. The incentive for these wells applies to the produced volume up to 8,000 m³. The HWDI is very similar to the VWDI, but applies to non-exploratory horizontal wells drilled on or after October 1, 2002 and provides the incentive to produced volumes up to 16,000 m³, depending on depth. Finally, the EGWDI provides a royalty reduction of the lesser of the fourth tier gas royalty rate (between 0%-5%) or 2.5% and a 0% freehold production tax rate. The incentive applies to wells that meet certain prescribed criteria which show that the well produces gas from an area from which gas has not generally been produced. The incentive applies to the produced volume up to 25,000,000 m³.

In December 2018, the Government of Saskatchewan introduced the Waterflood Development Program (the "WDP"), which program offers repayable royalty and freehold production tax deferrals for eligible wells that have been converted to injection wells or newly drilled injection wells for the purpose of waterflooding an oil reservoir. Under the WDP, royalty and freehold production taxes can be deferred for a period of three years and can be used alongside other incentive grant programs available in Saskatchewan.

In June of 2019, the Government of Saskatchewan introduced the Saskatchewan Petroleum Innovation Incentive ("SPII"). SPII offers transferable royalty and freehold production tax credits for qualified innovation commercialization projects at a rate of 25% of eligible project costs, targeting a broad range of innovations across all segments of Saskatchewan's oil and gas industry.

On August 1, 2019 the Government of Saskatchewan introduced the Oil and Gas Processing Investment Incentive ("OGPII"). OGPII offers transferable royalty and freehold production tax credits for qualified greenfield or brownfield value-added projects at a rate of 15% of eligible project costs.

In March 2020, the Government of Saskatchewan introduced the Oil Infrastructure Investment Program ("OIIP"), which program offers transferable oil and gas royalty and freehold production tax credits for qualified projects at a rate of 20 percent of eligible project costs (with a minimum $10 million investment). OIIP is open to new or expanded oil, refined petroleum products or natural gas liquids, including transmission pipelines, feeder pipeline and pipeline terminals. As of November 4, 2021, carbon dioxide pipeline projects became eligible for OIIP, including pipeline projects to be used for transporting carbon dioxide for carbon capture and storage or for EOR projects.

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Effective April 1, 2021, Saskatchewan amended the High Water-Cut Oil Well Program, which program provides a royalty status re-assignment for qualifying high water-cut oil wells that incur an average minimum investment of $20,000 per well, made on or after April 1, 2021, to directly improve water handling capabilities and extend the producing life of the well. Such eligible wells drilled before October 1, 2002 will receive fourth tier royalties on all future incremental high water-cut oil production, and wells drilled on or after October 1, 2002 will obtain a 2 percent royalty rate reduction on all future oil production.

On April 6, 2021, the Government of Saskatchewan introduced the Associated Gas Royalty Moratorium, which is a moratorium on the collection of Crown royalty and freehold production tax on associated gas produced from wells other than gas wells, including natural gas produced from oil wells. The moratorium has been implemented as part of Saskatchewan's Methane Action Plan to assist producers in meeting regulatory obligations to reduce methane-based greenhouse gas emissions by 40-45 percent between 2020 and 2025. The moratorium applies to associated natural gas produced on or after April 1, 2021, and before April 1, 2026.

Environmental Regulation and Protection Requirements

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to international conventions and national, provincial, state, territorial and municipal laws. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases, discharges, or emissions of various substances produced or used in association with oil and gas operations, as well as requirements with respect to oilfield waste handling, storage and disposal, land reclamation, habitat and endangered species protection, and minimum setbacks of oil and gas activities from sensitive receptors.

Provincial environmental legislation in the Province of Alberta for the oil and gas industry is, for the most part, set out in the Environmental Protection and Enhancement Act, the Oil and Gas Conservation Act, the Pipeline Act, the Water Act and the Technology and Emissions Reductions Implementation Act, 2019, 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. Provincial environmental legislation in the Province of Saskatchewan is, for the most part, set out in TheEnvironmental Management and Protection Act, 2010, The Saskatchewan Environmental Code, TheOil and Gas Conservation Act, The Pipeline Act, 1998 and The Management and Reduction of Greenhouse Gases Act which regulate harmful or potentially harmful activities and substances and GHGs, any release of such substances, and remediation and abandonment obligations in Saskatchewan. Certain development activities in Saskatchewan, depending on the location and potential environmental impact, may require an environmental impact assessment under the provincial Environmental Assessment Act. Provincial environmental legislation in the Province of Manitoba is, for the most part, set out in the Environment Act and the Oil and Gas Act.

Environmental legislation also requires that wells, pipelines and facility sites be constructed, operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material, or in the suspension or revocation of necessary licenses and approvals. Crescent Point may also be subject to civil liability for damage caused by pollution. Certain environmental protection legislation may subject Crescent Point to statutory strict liability in the event of an accidental spill or discharge from a well, pipeline or facility, meaning that fault on the part of Crescent Point need not be established if such a spill or discharge is found to have occurred.

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Crescent Point estimates abandonment and reclamation costs by taking into consideration the costs associated with decommissioning, abandonment, remediation and reclamation, all adjusted according to its working interest and discounted in accordance with NI 51-101. Decommissioning liability cost estimates are based on information published by the AER with respect to the AER liability management programs in Alberta and published by SMER in Directive PNG025 Financial Security Requirements Saskatchewan. Crescent Point has procedures in place which address various matters including: spill prevention, response, notification, reporting, remediation and reclamation; environmental monitoring; government inspections; surface equipment spacing requirements; facility protection/security; vegetation management; surface water run-off/run-on management; groundwater; noise control; atmospheric emissions; wellsite reclamation; earthen pits; storage tanks; naturally occurring radioactive materials; disposal wells; suspended or shut-in wells; waste management; and communications.

Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability, 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 third parties or regulators or result in the suspension or revocation of regulatory approvals and may require Crescent Point to incur costs to remedy such a discharge in an event not covered by Crescent Point's insurance, which insurance is in line with industry practice. Furthermore, Crescent Point expects incremental future costs associated with compliance with increasingly complex environmental protection requirements with respect to GHG emissions or otherwise, some of which may require the installation of emissions monitoring and measuring devices, the verification and reporting of emissions data and additional financial expenditures to comply with GHG emissions reduction requirements.

Greenhouse Gas Emissions

Carbon Policy

In November 2015, Canada participated in the twenty first session of the Conference of the Parties of the United Nations Framework Convention on Climate Change ("COP 21") in Paris, France, the goal of which was to reach a new agreement for fighting global climate change. COP 21 resulted in the adoption of the Paris Agreement which made several recommendations, including: (i) holding the increase in the global average temperature to well below 2 °C above pre-industrial levels and pursuing efforts to limit the temperature increase to 1.5 °C above pre-industrial levels, recognizing that this would significantly reduce the risks and impacts of climate change; (ii) increasing the ability to adapt to the adverse impacts of climate change and fostering climate resilience and low greenhouse gas emissions development, in a manner that does not threaten food production; and (iii) making finance flows consistent with a pathway towards low greenhouse gas emissions and climate-resilient development. The Paris Agreement came into force on November 4, 2016.

Over the last several years, the federal government has undertaken a number of initiatives to achieve domestic GHG reductions that align with its commitments made under the Paris Agreement. These measures include regulations, codes and standards, targeted investments, incentives, tax measures and programs intended to directly and indirectly reduce GHG emissions.

On June 21, 2018, the Government of Canada brought into force a pan-Canadian approach to the pricing of GHG emissions under the Greenhouse Gas Pollution Pricing Act ("GGPPA"). The federal carbon pollution pricing system has two parts: (i) an emission reduction and trading system for large industry, known as the output-based pricing system ("OBPS"); and (ii) a regulatory charge on 21 types of fuel, commonly known as the carbon tax. Each province was given the choice to either accept the federal requirement in full; create their own carbon pricing policies that meet federal standards; or a hybrid approach. Both Saskatchewan and Alberta have opted for the hybrid approach, where they have committed to develop province specific output-based pricing systems but are subject to the federal carbon tax on fuel. The federal carbon tax is applied on a broad set of fuels at $65 per tonne of GHG emissions in 2023 and will increase to $80 per tonne in 2024 and then by $15 per tonne per year until it reaches $170 per tonne in 2030.

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The federal government also has a GHG emission reporting requirement under the Canadian Environmental Protection Act, 1999 ("CEPA") whereby facilities that emitted 10,000 tonnes or more of GHGs per year must report their emissions to Environment and Climate Change Canada. On June 21, 2022, the federal government also brought into force the Clean Fuel Regulations which set emission limits on a variety of liquid fuels, including gasoline and diesel.

On December 7, 2023, the Government of Canada published a proposed Regulatory Framework for an Oil and Gas Sector Greenhouse Gas Emissions Cap that will, if enacted, set emissions limits from upstream oil and gas facilities that will be phased in between 2026 and 2030. The proposed Regulatory Framework includes a proposed cap and trade system whereby emission allowances issued or auctioned by the federal government will be tradeable among upstream oil and gas facilities. In addition, it is proposed that facilities will be able to use both emission offset credits created under other federal or provincial emission reduction systems and payments made to a decarbonization fund to meet the emissions cap. The proposed framework would allow up to a maximum of 20% over the emissions allowance cap to be offset by credits or paying into the decarbonization fund. Draft regulations setting the emissions cap system are expected to be published in mid-2024.

In Alberta, GHGemissions are regulated under the Emissions Management and Climate Resilience Act and the TIER Regulation, which came into effect January 1, 2020. The TIER system is mandatory for large emitters, being those that emit 100,000 tonnes or more of GHGs per year, however, facilities with less than 100,000 tonnes per year can voluntarily opt into the system by aggregating two or more smaller facilities together. Registered facilities are required to reduce their emission intensity (tCO2e/boe) by 10% based on a historical benchmark. Companies may meet these required reductions through improvements to their operations; by purchasing and retiring Alberta-based emission reduction or offset credits; by contributing to the provincial TIER Compliance Fund; or by a combination of these actions. Any facility registered into the TIER system can apply to the Canadian Revenue Agency and receive an exemption from the federal fuel surcharge (carbon tax) on applicable fuel combustion and flaring. Crescent Point has two aggregate facilities registered in the TIER system.

On December 15, 2022, the Government of Alberta announced amendments to TIER which became effective on January 1, 2023, which amendments include meeting federal emission reduction requirements for 2023 through 2030, compliance flexibility and increasing the regulator stringency.

On January 1, 2019, the Government of Saskatchewan brought into force The Management and Reduction of Greenhouse Gases (Standards and Compliance) Regulations (the "MRGHGR") to regulate greenhouse gas emissions in the province. As part of the MRGHGR, the Output-Based Performance Standards ("the Saskatchewan OBPS") were developed to reduce emissions intensity associated with stationary fuel combustion by 15% by 2030, however, subsequently, effective January 1, 2023, emissions intensity associated with stationary fuel combustion and flaring were reduced by 20% by 2030. Under the Saskatchewan OBPS program operators of certain large facilities that emit 25,000 tonnes or more of GHGs per year must register. Additionally, a voluntary aggregated facility (two or more smaller facilities grouped together) can also register in the OBPS program. Operators must reduce their emissions per unit of production from their historical emissions and may meet these required reductions through improvements to their operations; by purchasing and retiring emission reduction or offset credits; by contributing to the provincial Technology Fund; or by a combination of these actions. Any facility registered in the Saskatchewan OBPS can apply to the Canadian Revenue Agency and receive an exemption from the federal fuel surcharge (carbon tax) on applicable fuel combustion. Crescent Point has large emitter and aggregate facilities registered in the Saskatchewan OBPS program.

On November 22, 2022, the Government of Saskatchewan announced amendments to the Saskatchewan OBPS to meet the requirements of the 2023-2030 national carbon pricing benchmark. Effective January 1, 2023, the regulated emissions under the Saskatchewan OBPS were expanded to include flaring and the emission intensity reduction was increased to 20%.

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Methane Policy

On June 29, 2016, Canada joined the United States and Mexico in agreeing to reduce methane emissions from the oil and gas sector by up to 45% by 2025 from 2014 levels by developing and implementing federal regulations for both existing and new sources of venting and fugitive methane emissions. Previously, on March 10, 2016, Canada and the United States committed to take action on methane emissions through federal regulations as expeditiously as possible. The United States has since cancelled their participation in this initiative.

On January 1, 2020, the Canadian federal government implemented the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector).

The federal regulations that apply to methane in the upstream oil and gas sector aim to control methane emissions and also reduce the amount of volatile organic compounds released into the air. These regulations apply generally to facilities that handle significant volumes of gas (facilities that produce or receive a combined volume of 60,000 m3 of hydrocarbon gas or greater annually in any of the past five years). The regulations outline regulatory requirements for fugitive equipment leaks, venting from well completions, and compressors, which came into force on January 1, 2020, and requirements for facility production venting restrictions and venting limits for pneumatic equipment, which come into force on January 1, 2023.

Operators of upstream oil and gas facilities are required to: implement a leak detection and repair program to stop natural gas leaks three times per year on facilities that produce or receive a combined volume of 60,000 m3 of hydrocarbon gas or greater annually; complete annual measurements of emissions from natural gas compressor vents to ensure emissions are under the applicable limit; and eliminate venting from well completions involving hydraulic fracturing.

Beginning in 2023, operators of upstream oil and gas facilities were required to: meet a venting limit of 15,000 m3 of gas per year at facilities that produce and/or receive more than 60,000 m3 of gas per year, and limit venting from pneumatic devices to a maximum threshold.

All upstream oil and gas facilities to which the federal regulations apply are required to register and to keep records in order to demonstrate compliance with the proposed regulations. Facility operators are also required to submit reports at the request of the federal Minister of Environment.

On October 11, 2021, the Canadian federal government announced its support for the Global Methane Pledge, which aims to reduce global methane emissions by 30 percent below 2020 levels by 2030. In support of the Global Methane Pledge, Canada announced its commitment to developing a plan to reduce methane emissions across the broader Canadian economy and to reducing oil and gas methane emissions by at least 75 percent below 2012 levels by 2030, and that these goals will be achieved through an approach that will include regulation.

In September 2022, the Government of Canada released Canada's Methane Strategy with the aim of reducing domestic methane emissions, including a new target of reducing absolute methane emissions from the oil and gas sector by 75% by 2030 relative to 2012. In November 2022, the Government of Canada released a Proposed Regulatory Framework for Reducing Oil and Gas Methane Emissions to Achieve 2030 Target. The proposed changes will expand the scope of the existing regulations to apply to a wider set of sources, including all facilities handling natural gas, increasing the scope and frequency of inspection programs, requiring certain non-emitting equipment when feasible, prohibiting flaring at oil sites, limiting venting of methane and requiring fugitive methane emissions management plans.

On December 16, 2023, the Government of Canada published draft Regulations Amending the Regulations Respecting the Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sectors) for public consultation. The proposed amendments would prohibit flaring and venting, other than to avoid serious risk to human health or safety, at new facilities starting in 2027 and at all facilities in 2030. Alternatively, a facility may install continuous monitoring systems to detect for methane emissions, and then take mandating mitigation measures within set time lines. Further, with respect to fugitive emissions, the proposed regulations distinguish between facilities more likely to emit methane from facilities less likely to emit methane.

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Facilities more likely to emit methane must be inspected quarterly while facilities less likely to emit methane must be inspected annually. Mandatory repair timelines are included in the proposed Regulations upon the detection of an emission. Finally, new equipment standards are mandatory efficiency requirements are proposed.

Currently the federal regulations do not apply in provinces which the federal government deems to have equivalent methane reduction regulations. Alberta, Saskatchewan and British Columbia have each reached equivalency agreements with the federal government and currently operators in these provinces are subject to only the provincial methane reduction requirements.

In Alberta, design specifications have been put in place by the AER for oil and gas wells, pipelines and facilities as well as standards for key equipment and operational best practices. Fugitive emission standards are also included in the regulatory requirements and will raise current standards for performance, monitoring, measurement and reporting. The AER has published directives requiring methane emission reductions.

On January 1, 2019, the Government of Saskatchewan brought into force The Oil and Gas Emissions Management Regulations to reduce methane emissions from upstream oil and gas companies with emissions of more than 50,000 tonnes of GHGs per year from oil facilities. Every company subject to the regulation must ensure GHG emissions from flaring and venting are below provincial limits or pay an administrative penalty if they fail to do so.

Crescent Point's operations are subject to costs being incurred to comply with carbon taxes, GHG emission reduction requirements, including methane emission reductions, and to preform necessary monitoring, measurement, verification and reporting of GHG emissions.

Crescent Point anticipates current and future environmental legislation will require reductions in emissions from its operations and result in increased capital and operational expenditures. Further changes in environmental legislation could occur, which may result in stricter standards and enforcement, larger fines and liability and increased capital expenditures and operating costs, which could have a material adverse effect on our financial condition and results of operations.

We are committed to meeting our responsibilities to protect the environment wherever we operate and anticipate making increased expenditures as a result of the increasingly stringent laws relating to the protection of the environment. Our internal procedures are designed to ensure that the environmental aspects of new developments are taken into account prior to proceeding.

Abandonment and Reclamation Costs

As at December 31, 2023, Crescent Point owned approximately 14,493 gross (12,041.4 net) producing, non-producing and abandoned wells for which abandonment and/or reclamation costs are expected to be incurred. During 2023, Crescent Point spent approximately $45.4 million on well abandonment and environmental reclamation activities, of which $5.4 million was received from government grant programs. In 2024, Crescent Point expects to carry out abandonment and reclamation operations that will total approximately $40.0 million. Crescent Point has estimated the net present value (discounted at approximately 3.02% per annum) of its total decommissioning liability (wells and facilities) to be approximately $738.8 million as at December 31, 2023, including liabilities associated with assets held for sale, based on estimated undiscounted and uninflated cash flows of approximately $1.03 billion.

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On July 30, 2020, the Government of Alberta announced a new liability management program that overhauls and modernizes the previous liability management program, known as the Liability Management Ratio ("LMR") which uses a licensee's ratio of deemed asset value to deemed liability value to determine the risk that the licensee poses to the Orphan Well Association and to determine if a security deposit is required to mitigate that risk. The LMR was replaced by Directive 088: Licensee Life-Cycle Management ("LLCM"), which directive was released and became effective on December 1, 2021. Unlike the LMR, which measures two metrics to determine a licensee's risk, the LLCM assesses more than 30 additional metrics, such as the licensee's financial capability, previous closure activity, operational performance and regulatory compliance. Additionally, the new liability framework includes an Inactive Inventory Reduction Program which introduced annual mandatory liability reduction spending targets for each licensee. The new framework also includes the development of a program to address legacy sites that were abandoned, remediated or reclaimed before current requirements were introduced. In September 2022, the AER introduced the Closure Nomination Program as part of LLCM. This program allows for specific, direct stakeholders to nominate inactive sites for abandonment and/or reclamation.

Like the Alberta Government, the Government of Saskatchewan also announced enhancements to its Liability Management Program framework in 2020. This framework includes using licensee-specific data to better reflect the actual deemed asset and liability values, which is expected to improve the accuracy of License Liability Ratings; an Inactive Liability Reduction Program that requires an annual spending target on closure activities; completing the Proportional Risk Transfer model that will assess security deposit requirements for license transfers with a high amount of inactive infrastructure; and addressing regulatory gaps related to new entrants and the acceptable forms of security deposits. To support these new initiatives, the Government of Saskatchewan has enacted TheFinancial Security and Site Closure Regulation, which came into force on January 1, 2023.

Health, Safety and Environment

The health and safety of employees, contractors, visitors and the public, as well as the protection of the environment, is of the utmost importance to Crescent Point. The Corporation endeavors to conduct its operations in a manner that will minimize both adverse environmental effects and consequences of emergency situations by:

•Complying with all applicable government regulations and standards;

•Operating in a manner consistent with industry codes, practices and guidelines;

•Ensuring prompt and effective response and repair to emergency situations and environmental incidents;

•Providing training to ensure compliance with Crescent Point's Operations Management System;

•Careful planning, good judgment and prudent monitoring of the Corporation's activities;

•Communicating openly with all stakeholders regarding our activities; and

•Amending Crescent Point's policies and procedures, as may be required from time to time.

Crescent Point believes that it is in material compliance with environmental legislation in the jurisdictions in which it operates at this time. Crescent Point's practice is to do all that it reasonably can to ensure that it remains in material compliance with applicable environmental protection legislation. Crescent Point also believes that it is reasonably likely that the trend towards stricter standards in environmental regulation will continue. Crescent Point is committed to meeting its responsibilities to protect the environment wherever it operates and will take such steps as required to ensure compliance with environmental legislation. Crescent Point anticipates increased capital and operating expenditures as a result of increasingly stringent laws relating to the protection of the environment. No assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, the development or exploration activities, or otherwise adversely affect Crescent Point's financial condition, capital expenditures, results of operations, competitive position or prospects.

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RISK FACTORS

Each of the risks described below should be carefully considered, together with all of the other information contained herein, before making an investment decision with respect to our Common Shares. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially and adversely affected, and you could lose all or part of your investment.

Risks Relating to Our Business

Our estimated Proved and Proved plus Probable reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

The reserve and recovery information contained in the Crescent Point Reserve Report are only estimates and the actual production and ultimate reserves from our properties may be greater or less than the estimates prepared by McDaniel. Ultimately, actual reserves attributable to our properties will vary from estimates, and those variations may be material. The reserve figures contained herein are only estimates. The estimation of reserves is an inherently complex process requiring significant judgment. A number of factors are considered and a number of assumptions are made when estimating reserves. These factors and assumptions include, among others:

•historical production in the area compared with production rates from similar producing areas;

•future commodity prices, production and development costs, royalties and capital expenditures;

•initial production rates;

•production decline rates;

•ultimate recovery of reserves;

•success of future development activities;

•marketability of production;

•availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities;

•effects of government regulation; and

•other government levies that may be imposed over the producing life of reserves.

Reserve estimates are based on the relevant factors, assumptions and prices on the date the relevant evaluations were prepared. These estimates are expected to be revised upward or downward over time, as additional information such as reservoir performance becomes available, or as economic conditions change. See "Special Notes to Reader". Many of these factors are subject to change and are beyond our control. If these factors, assumptions and prices prove to be inaccurate, actual results may vary materially from reserve estimates and such variations may affect the market price of our Common Shares and return of capital (which, for purposes of this AIF, includes dividends and share repurchases) to Shareholders.

The amount of oil and natural gas that we can produce and sell is subject to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems.

Our business depends in part upon the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities and rail loading facilities and railcars. Canadian federal and provincial, as well as U.S. federal, state and local, regulation of oil and gas production, processing and transportation, tax and energy policies, general economic conditions, changes in supply and demand and changes in pipeline ownership or operation could adversely affect our ability to produce or market oil and natural gas. If market factors change and inhibit the marketing of our production, overall production or realized prices may decline, which may affect the market price of our Common Shares and reduce our return of capital to our Shareholders.

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Our future performance depends on our ability to acquire additional natural gas and oil reserves that are economically recoverable.

If we are unable to acquire additional reserves, the value of our Common Shares and our return of capital to Shareholders may decline. We add to our oil and natural gas reserves primarily through development, exploitation and acquisitions including those with large resource potential. As a result, future oil and natural gas reserves are highly dependent on our success in exploiting existing properties and acquiring additional reserves. We cannot guarantee that we will be successful in developing additional reserves or acquiring additional reserves on terms that meet our investment objectives. Without these reserve additions, our reserves will deplete and, as a consequence, either production from, or the average reserve life of, our properties may decline. Either decline may result in a reduction in the value of our Common Shares and in a reduction in cash available for return of capital to Shareholders.

The properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the acquired properties or obtain protection from sellers against such liabilities.

The properties we acquire may not produce as expected, may be in an unexpected condition and we may be subject to increased costs and liabilities, including environmental liabilities. Although we review properties prior to acquisition in a manner consistent with industry practices, such reviews are not always capable of identifying all potential adverse conditions. Furthermore, we may not be able to subject the preparation of reserve estimates for acquired properties to the same internal controls we have for the preparation of reserve estimates for our existing properties. Generally, it is not feasible to review in depth every individual property involved in each acquisition. We focus our review efforts on the higher-value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties and preparation of reserve reports in accordance with our internal controls may not necessarily reveal existing or potential problems or permit us to become sufficiently familiar with the properties to fully assess their condition, any deficiencies, and development potential.

Failure to realize anticipated benefits of prior acquisitions and dispositions may have a material adverse effect on our business.

The Corporation has completed a number of acquisitions and dispositions in order to strengthen its position in the oil and natural gas industry and to create the opportunity to realize certain benefits, including, among other things, potential cost savings. In order to achieve the benefits of these and future acquisitions, the Corporation is dependent upon its ability to successfully consolidate functions and integrate operations, procedures and personnel in a timely and efficient manner and to realize the anticipated growth opportunities and synergies from combining the acquired assets and operations with those of the Corporation. The integration of acquired assets and operations requires the dedication of management effort, time and resources, which may divert management's focus and resources from other strategic opportunities and from operational matters during this process. The integration process may result in the disruption of ongoing business and customer relationships that may adversely affect the Corporation's ability to achieve the anticipated benefits of such prior acquisitions. Dispositions may fail to provide anticipated benefits as the employment of capital received from any such dispositions will be subject to the risks the Corporation faces. Such capital may fail to deliver a return commensurate or greater than the return formerly garnered from the disposed assets.

Increases in costs could adversely affect our business, financial condition and results of operations.

An increase in costs could have a material adverse effect on our results of operations and financial condition and, therefore, could reduce our ability to pay down debt, reduce dividends to Shareholders as well as affect the market price of the Common Shares.

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Current and future inflationary effects may be driven by, among other things, supply chain disruptions and governmental stimulus or fiscal policies, and geopolitical instability, including the ongoing conflict between the Ukraine and Russia and in the Middle East. Continuing increases in inflation could increase our costs of labor and other costs related to our business, which could have an adverse impact on our business, financial position, results of operations and cash flows.

Higher operating and capital costs for our underlying properties will directly decrease the amount of cash flow received by the Corporation and, therefore, may reduce return of capital to our Shareholders.

The conflicts in Ukraine and the Middle East and related price volatility and geopolitical instability could negatively impact our business.

In late February 2022, Russia launched significant military action against Ukraine and in October 2023, Israel declared war and mobilized troops to the Gaza Strip. The conflicts and other events causing geopolitical instability, have caused, and could intensify, volatility in natural gas, oil and NGL prices, and the extent and duration of the military actions, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time. There is evidence that recent volatility in crude oil prices is partially due to the impact of geopolitical instability, including the conflict between Russia and Ukraine and in the Middle East, on the global commodity and financial markets, and in response to economic and trade sanctions that certain countries have imposed on Russia. Any such volatility and disruptions may also magnify the impact of other risks described in this "Risk Factors" section.

The operation of a portion of our properties is largely dependent on the ability of third party operators.

Some of our properties are not operated by us and, therefore, results of operations may be adversely affected by the failure of third-party operators, which could affect the market price of our Common Shares and return of capital to Shareholders.

The continuing production from a property, and to some extent the marketing of that production, is dependent upon the ability of the operators of those properties. At December 31, 2023, approximately 9% of our daily production was from properties operated by third parties. To the extent a third-party operator fails to perform its functions efficiently or becomes insolvent, our revenue may be reduced. Third party operators also make estimates of future capital expenditures more difficult.

Further, the operating agreements which govern the properties not operated by us typically require the operator to conduct operations in a good and "workmanlike" manner. These operating agreements generally provide, however, that the operator has no liability to the other non-operated working interest owners for losses sustained or liabilities incurred, except for liabilities that may result from gross negligence or willful misconduct.

Delays in business operations could adversely affect our income and financial condition.

Delays in business operations could adversely affect return of capital to Shareholders, our income, our financial condition and the market price of our Common Shares. In addition to the usual delays in payment by purchasers of oil and natural gas to the operators of our properties, and the delays of those operators in remitting payment to us, payments between any of these parties may also be delayed by:

•restrictions imposed by lenders;

•delays in the sale or delivery of products;

•delays in the connection of wells to a gathering system;

•restrictions due to limited pipeline, railcar, trucking or refinery capacity;

•extreme weather events, including severe cold, wildfires and floods, which may damage or destroy infrastructure;

•droughts, which may impact the availability and usage of water;

•blowouts or other accidents;

•public health crises, epidemics or pandemics, including the effects of, and response to, COVID-19;

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•blockades and social unrest;

•accounting delays;

•adjustments for prior periods;

•recovery by the operator of expenses incurred in the operation of the properties;

•the establishment by the operator of reserves for these expenses; or

•delays in receiving government approvals and licenses.

Any of these or other delays in our business operations could reduce our income, the amount of cash available for return of capital to Shareholders in a given period, our financial condition and could expose us to additional third party credit risks.

Failure of third parties to meet their contractual obligations to us may have a material adverse effect on our financial condition.

Although the Corporation monitors the credit worthiness of third parties it contracts with and manages its exposures through a formal Risk Management and Counterparty Credit Policy, there can be no assurance that the Corporation will not experience a loss for non-performance by any counterparty with whom it has a commercial relationship. Such events may have material adverse consequences on the business of the Corporation and may limit the timing or amount of return of capital to Shareholders and could affect the market price of our Common Shares.

Our debt level and the covenants in the agreements governing our debt could negatively impact our financial condition, ability to return capital to shareholders, results of operations, cash flows and business prospects.

We may, from time to time, finance a significant portion of our operations through debt. Our indebtedness may limit the timing or amount of capital returns to Shareholders, and could affect the market price of our Common Shares and our return of capital to Shareholders.

The payments of interest and principal, and other costs, expenses and disbursements to our lenders reduces amounts available for return to Shareholders. Variations in interest rates and scheduled principal repayments could result in significant changes to the amount of the cash flow required to be applied to the debt before payment of any amounts to the Shareholders. The agreements governing our long-term debt provide that, if we are in default or fail to comply with certain covenants, we must repay the indebtedness at an accelerated rate, and the ability to return capital to Shareholders may be restricted. Additionally, the Term Loan has certain mandatory repayment provisions applicable to cash proceeds received from future issuances of equity securities, debt securities and proceeds received from property dispositions that may limit our ability to pay dividends or return capital to shareholders. Significant reductions to cash flow or increases in drawn amounts under the Credit Facilities may result in the Corporation breaching its debt covenants under the agreements governing its debt. If a breach occurs, there is a risk that the Corporation may not be able to negotiate covenant relief with one or more of its debt counterparties. Failure to comply with debt covenants or negotiate relief may result in its indebtedness under the Credit Facilities, Term Loan or Senior Guaranteed Notes becoming immediately due and payable, which may have a material adverse effect on the Corporation’s operations and financial condition.

Increased costs of capital could adversely affect our business.

Our business and operating results could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows and place us at a competitive disadvantage. Disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could have a material adverse effect on the Corporation's operations and financial condition.

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Pandemics could adversely affect the Corporation's financial condition, operations and results from operations.

A pandemic and the actions taken in response, could result in a similar contraction in the global economy as experienced in response to COVID-19. Another pandemic could cause periods of unprecedented disruption in the oil and gas industry and negatively impacted the demand for, and pricing of, energy products, including crude oil, NGLs and natural gas produced by the Corporation. A consequence of this disruption is that the oil and gas industry could again experience a period of market contraction. Furthermore, the oil and gas industry could experience an increased risk of counterparty bankruptcy and insolvency.

In response to a pandemic, the Corporation may need to implement additional health and safety protocols within its Calgary office and field operations and may be required to make adjustments to its health and safety protocols.

There were many variables and uncertainties associated with COVID-19 that could return with the onset of another pandemic. For example, during and following the COVID-19 pandemic, inflation has been driven by many factors, including disruptions to local and global supply chain and transportation services. Additionally, pandemics, including COVID-19 and its variants, have the potential to directly affect the health of our employees. Inflation, disruptions to supply chain and transportation services and employee health have the potential to disrupt or impact the Corporation's operations, projects and financial condition. The extent of the impact of a pandemic on our operational and financial performance will depend on future developments, the pandemic's severity, government actions to contain the disease or mitigate its impact and the effectiveness of treatments and vaccines, all of which are highly uncertain and cannot be predicted with certainty at this time.

Our existing Credit Facilities and any replacement credit facilities may not provide sufficient liquidity.

Our current Credit Facilities and any replacement credit facilities may not provide sufficient liquidity. The amounts available under our existing Credit Facilities may not be sufficient for future operations, or we may not be able to obtain additional financing on economic terms attractive to us, if at all. The interest charged on our Credit Facilities is calculated based on a sliding scale ratio of the Corporation's senior debt to adjusted EBITDA ratio. Repayment of all outstanding amounts under the Credit Facilities may be demanded on relatively short notice if an event of default occurs and is continuing. If this occurs, we may need to obtain alternate financing. Any failure to obtain suitable replacement financing may have a material adverse effect on our business, and return of capital to Shareholders may be materially reduced.

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

Dividends may be reduced or eliminated in the sole discretion of the Board of Directors. For example, dividends may be reduced or eliminated during periods in which we make capital expenditures or debt repayments using cash flow, which could also affect the market price of our Common Shares. To the extent that we use cash flow to finance acquisitions, development costs and other significant expenditures, the net cash flow the Corporation receives that is available for dividends to Shareholders, or to repurchase Common Shares will be reduced. Furthermore, the availability of net cash flow is dependent upon commodity prices which are variable. Hence, the timing and amount of capital expenditures and the variability of commodity prices, may affect the amount of net cash flow received by the Corporation and, as a consequence, the amount of cash available to distribute to Shareholders or to repurchase Common Shares. Therefore, dividends or share buybacks may be reduced, or even eliminated, at times when significant capital or other expenditures are made, or when commodity prices vary.

The Board of Directors has the discretion to determine the extent to which cash flow from Crescent Point will be allocated to the payment of debt service charges as well as the repayment of outstanding debt, including under the Credit Facilities, the Term Loan and Senior Guarantee Notes. As a consequence, the amount of funds used to pay debt service charges or reduce debt will reduce the amount of cash available for dividends to Shareholders or to repurchase Common Shares during those periods in which funds are so retained.

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We have been historically reliant on external sources of capital, which may dilute Shareholders' ownership interests.

There may be future dilution to our Shareholders. One of our objectives is to continually add to our reserves through development, and where warranted, through acquisitions. Since we pay a dividend, our success in growth from development and acquisitions may, in part, depend on our ability to raise capital from time to time by selling additional Common Shares. Shareholders will suffer dilution as a result of these offerings if, for example, the cash flow, production or reserves from the acquired assets do not reflect the additional number of Common Shares issued to develop or acquire assets. Shareholders may also suffer dilution in connection with future issuances of Common Shares to effect acquisitions.

Indigenous claims could have an adverse effect on us and our operations.

The economic impact on us of claims of indigenous title or rights is unknown. Indigenous people have claimed indigenous title and rights to a substantial portion of western Canada. We are unable to assess the effect, if any, that any such claim would have on our business and operations. Protests that affect transportation and other infrastructure in Canada, may have a negative impact on the Corporation's ability to sell its products.

Hedging limits participation in commodity price increases and increases counterparty credit risk exposure.

We periodically enter into hedging activities with respect to a portion of our production to manage our exposure to oil and gas price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts.

We may incur losses as a result of title defects in the properties in which we invest.

Unforeseen title defects may result in a loss of entitlement to production and reserves. Although we conduct title reviews in accordance with industry practice prior to any purchase of resource assets, such reviews do not guarantee that an unforeseen defect in the chain of title will not arise and defeat our title to the purchased assets. If such a defect were to occur, our entitlement to the production from such purchased assets could be jeopardized and, as a result, return of capital to Shareholders may be reduced.

Our information assets and critical infrastructure may be subject to cyber security risks.

The Corporation is subject to a variety of information technology and system risks as a part of its 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. Although the Corporation has security measures and controls in place that are designed to mitigate these risks, a breach of its security measures 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 a disruption to its 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 and results of operations.

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Crescent Point relies heavily on information technology, such as computer hardware and software systems, in order to properly operate its business. In the event the Corporation is unable to regularly deploy software and hardware, effectively upgrade systems and network infrastructure, and take other steps to maintain or improve the efficiency and efficacy of systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of data. In addition, information systems could be damaged or interrupted by natural disasters, force majeure events, telecommunications failures, power loss, acts of war or terrorism, computer viruses, malicious code, physical or electronic security breaches, intentional or inadvertent user misuse or error, or similar events or disruptions. Any of these or other events could cause interruptions, delays, loss of critical or sensitive data or similar effects, which could have a material adverse impact on the protection of intellectual property, and confidential and proprietary information, and on Crescent Point's business, financial condition, results of operations and cash flows.

We depend upon our management team and our operations require us to attract and retain experienced technical personnel.

Shareholders are entirely dependent on our management with respect to the acquisition of oil and gas properties and assets, the development and acquisition of additional reserves and the management and administration of all matters relating to our oil and natural gas properties. The loss of the services of key individuals who currently comprise the management team could have a detrimental effect on the Corporation. .

We operate only in western Canada and expansion outside of these areas may increase our risk exposure.

If we expand our operations beyond oil and natural gas production in western Canada, we may face new challenges and risks. If we were to be unsuccessful in managing these challenges and risks, our results of operations and financial condition could be adversely affected, which could affect the market price of our Common Shares and return of capital to Shareholders.

Our operations and expertise are currently deployed on conventional oil and gas production and development in the Western Canadian Sedimentary Basin. In the future, we may acquire oil and gas properties outside this geographic area. In addition, we could acquire other energy related assets, such as oil and natural gas processing plants or pipelines. Expansion of our activities into new areas may present challenges and risks that we have not faced in the past. If we do not manage these challenges and risks successfully, our results of operations and financial condition could be adversely affected.

We may be the subject of litigation.

From time to time, the Corporation may be the subject of litigation. Claims under such litigation may be material. The types of claims the Corporation may face include, without limitation, claims for breach of contract, environmental damage, negligence, product liability, tax, patent infringement and employment matters. The outcome of any such litigation is not certain, but may materially impact Crescent Point's financial condition or results of operations. Crescent Point may also be subject to adverse publicity related to such claims, regardless whether Crescent Point is ultimately found responsible. In addition, the Corporation may be required to incur significant expenses or devote significant resources defending any such litigation.

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The Corporation relies on surface and groundwater licenses, which, if rescinded or the conditions of which are amended, could disrupt its business and have a material adverse effect on its business, financial condition, results of operations and prospects.

The Corporation relies on access to both surface and groundwater, which is obtained under government licenses, to provide the substantial quantities of water required for certain of its operations. The licenses to withdraw water may be rescinded and additional conditions may be added to these licenses. Further, the Corporation may have to pay increased fees for the use of water in the future and any such fees may be uneconomic. Finally, new projects or the expansion of existing projects may be dependent on securing licenses for additional water withdrawal, and these licenses may be granted on terms not favorable to the Corporation, or at all, and such additional water may not be available to divert under such licenses. Any prolonged droughts in our operating areas could result in the Corporation's surface and groundwater licenses being subject to additional conditions or rescission. The Corporation's inability to secure surface and groundwater licenses in the future and any amendment to or rescission of, its current licenses may disrupt its business and have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects.

Wildfire Risk

Wildfires may restrict the Corporation's ability to access and operate its properties and cause operational difficulties, including damage to equipment and infrastructure. Wildfires also increase the risk of personnel injury as a result of dangerous working conditions. Certain of the Corporation's assets are located near forests and a wildfire may lead to significant downtime and/or damage to the Corporation's assets or cause disruptions to the production and transport of its products or the delivery of goods and services in its supply chain.

Restrictions on operational activities intended to protect certain species of wildlife may adversely affect the Corporation's ability to conduct drilling and other operational activities in some of the areas where it operates.

Oil, condensate and other NGLs and natural gas operations in the Corporation's operating areas can be adversely affected by seasonal or permanent restrictions on construction, drilling and well completions activities designed to protect various wildlife. Seasonal restrictions may limit the Corporation's ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling and completions activities are allowed. These constraints and the resulting shortages or high costs could delay the Corporation's operations and materially increase the Corporation's operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit development in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species as threatened or endangered in areas where the Corporation operates could cause the Corporation to incur increased costs arising from species protection measures or could result in limitations on the Corporation's exploration and production activities that could have an adverse impact on the Corporation's ability to develop and produce its reserves.

Risks Relating to the Oil and Gas Industry

Oil and natural gas prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Lower commodity prices may reduce the amount of oil and natural gas that we can produce economically. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Depressed prices in the future would have a negative impact on our future financial results and could result in impairment charges.

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Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:

•the levels and location of oil and natural gas supply and demand and expectations regarding supply and demand, both domestically and abroad;

•the level of consumer product demand;

•extreme weather events, such as severe cold, wildfires and floods;

•political conditions, social unrest, sanctions, hostilities or war in, or relating to, oil and natural gas producing regions, including the Middle East, Africa, Eastern Europe (including the conflict between Ukraine and Russia) and South America;

•the ability of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree to and maintain oil price and production controls;

•the price level and quantity of foreign imports;

•actions of governmental authorities;

•the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for oil and natural gas;

•blockades of transportation infrastructure and civil unrest;

•inventory storage levels;

•the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation;

•conservation and environmental protection efforts;

•the price, availability and acceptance of alternative energy sources;

•technological advances affecting energy usage and consumption and energy supply;

•speculation by investors in oil and natural gas;

•public health crises, epidemics or pandemics, including the impacts of and response to COVID-19;

•weather conditions;

•variations between product prices at sales points and applicable index prices; and

•overall domestic and worldwide economic conditions, including the value of the U.S. dollar relative to Canadian and other major currencies.

These factors and the volatile nature of the energy markets make it extremely difficult to predict with any certainty the future prices of crude oil and natural gas. If crude oil and natural gas prices remain significantly depressed for a sustained period of time, the lower prices may adversely affect our ability to make planned expenditures, raise additional capital, meet our financial obligations or provide return of capital to shareholders through dividends or share repurchases.

Variations in interest rates, foreign exchange rates, and inflation could adversely affect our financial condition.

There is a risk that interest rates will continue to increase in response to inflation in Canada and the United States. An increase in interest rates could result in a significant increase in the amount we pay to service debt, while rising inflation could cause us to incur additional expense and, either or both, could have an adverse effect on our financial condition, results of operations and future growth, potentially resulting in a decrease in a decrease in the return of capital to Shareholders and/or the market price of the Common Shares.

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Fluctuations in foreign currency exchange rates could adversely affect our business, and could affect the market price of our Common Shares and return of capital to Shareholders. The price that we receive for a majority of our oil and natural gas is based on U.S. dollar denominated benchmarks and, therefore, the price that we receive in Canadian dollars is affected by the exchange rate between the two currencies. A material increase in the value of the Canadian dollar relative to the U.S. dollar may negatively impact net production revenue by decreasing the Canadian dollars received for a given U.S. dollar price. Conversely, a material decease in Canadian versus U.S. dollar values would reduce the Corporation's ability to develop the U.S. asset base. Each of these situations may negatively impact future dividends and the future value of the Corporation's reserves as determined by independent evaluators. We could be subject to unfavorable exchange rate changes to the extent of our investment in U.S. subsidiaries and to the extent that we have engaged, or in the future engage, in risk management activities related to foreign exchange rates, through entry into forward foreign exchange contracts or otherwise.

Competition in the oil and gas industry is intense, which may adversely affect our ability to compete.

The oil and natural gas industry is highly competitive. We compete for capital, acquisitions of reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to processing facilities, pipeline and refining capacity and in many other respects with a substantial number of other organizations, many of which may have greater technical and financial resources than we do. Some of these organizations not only explore for, develop and produce oil and natural gas but also carry on refining operations and market oil and other products on a worldwide basis. As a result of these complementary activities, some of our competitors may have greater and more diverse competitive resources to draw on than we do. Given the highly competitive nature of the oil and natural gas industry, this could adversely affect the market price of our Common Shares and return of capital to Shareholders.

Risks associated with the production, gathering, transportation and sale of oil and natural gas could adversely affect net income and cash flows. We may not be insured against all of the operating risks to which our business is exposed.

The industry in which we operate exposes us to potential liabilities that may not be covered by insurance. Our operations are subject to all of the risks associated with the operation and development of oil and natural gas properties, including the drilling of oil and natural gas wells, and the production and transportation of oil and natural gas. These risks include encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, cratering, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions, pollution, other environmental risks, fires, spills and explosions. A number of these risks could result in personal injury, loss of life, or environmental and other damage to our property or the property of others and reputational loss. We cannot fully protect against all of these risks, nor are all of these risks insurable. We may become liable for damages arising from these events against which we cannot insure or against which we may elect not to insure because of high premium costs or other reasons. Any costs incurred to repair these damages or pay these liabilities would reduce funds available for payment of dividends to Shareholders. Additionally, the insurance market changes over time and, in the future, we may not be able to purchase insurance for all of the risks that we are currently able to insure against.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

Crescent Point is subject to extensive and complex regulations and laws enforced by various regulatory agencies. These regulatory agencies include, in Canada, the AER, the Alberta EPA, the British Columbia Energy Regulator, the British Columbia Ministry of Environment and Climate Change Strategy, the SMER, Saskatchewan Ministry of Environment, the Canadian Energy Regulator, Environment and Climate Change Canada, Health Canada and Transport Canada. Additionally, the development or implementation of changes to land use activities, such as regional or subregional planning, may effect how we are able to use certain lands for oil and gas development. Crescent Point is also subject to regulation by other federal, provincial, state and local agencies. Regulations affect almost every aspect of Crescent Point's business and limit its ability to make and implement independent management decisions, including about business combinations, disposing of operating assets and engaging in transactions between Crescent Point and its affiliates.

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Under these laws and regulations, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that could substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our financial condition and results of operations.

Regulations and laws are subject to ongoing policy initiatives, and Crescent Point cannot predict the future course of regulations or legislation and their respective ultimate effects. Such changes could materially impact Crescent Point's business, financial position and results of operations.

For further discussion about the effect of environmental laws and regulations, see below "Our operations may incur substantial costs and liabilities to comply with environmental laws and regulations".

Our operations may incur substantial costs and liabilities to comply with environmental laws and regulations.

Many aspects of the oil and natural gas business present environmental risks and hazards, including the risk that Crescent Point may be in non-compliance with an environmental law, regulation, permit, license or other regulatory approval, possibly unintentionally or without knowledge. Such risks may expose Crescent Point to fines or penalties, suspension or revocation of regulatory permits, third party liabilities or to the requirement to remediate or carry out other actions, the costs of which could be material. The operational hazards associated with possible blowouts, accidents, oil spills, gas leaks, fires, explosions or other damage to a well, pipeline or facility may require Crescent Point to incur costs and delays to undertake corrective actions, and could result in penalties and fines and suspension or revocation of regulatory approvals or environmental or other damage for which Crescent Point could be liable. Oil and gas operations are also subject to specific operational risks which may have a material operational and financial impact on Crescent Point should they occur, such as drilling into unexpected formations or unexpected pressures, premature decline of reservoirs and water invasion into producing formations.

Crescent Point may also be subject to associated liabilities resulting from lawsuits alleging property damage or personal injury brought by private litigants related to the operation of Crescent Point's facilities or the land on which such facilities are located, regardless of whether Crescent Point leases or owns the facility, and regardless of whether such environmental conditions were created by Crescent Point, a prior owner or tenant, a third party or a neighbouring facility whose operations may have affected Crescent Point's facility or land. Such liabilities could have a material adverse effect on Crescent Point's business, financial position, operations, assets or future prospects.

Crescent Point also faces uncertainties related to future environmental laws and regulations affecting its business and operations. Existing environmental laws and regulations may be revised or interpreted more strictly, and new laws or regulations may be adopted or become applicable to Crescent Point, which may result in increased compliance costs or additional operating restrictions, each of which could reduce Crescent Point's earnings and adversely affect Crescent Point's business, financial position, operations, assets or future prospects. For example, if the Corporation did not qualify in 2023 for an exemption under the TIERS and OBPS programs in Alberta and Saskatchewan, respectively, the additional carbon compliance costs to the Corporation in Canada would have been, approximately, $66.5 million in 2023, which amount is calculated based on Scope 1 fuel combustion and flaring emissions at the applicable 2023 carbon pricing rate.

Compliance with environmental laws and regulations could materially increase our costs. We may incur substantial capital and operating costs to comply with increasingly complex laws covering the protection of the environment and human health and safety. In particular, we may be required to incur significant costs to comply with future federal GHG emissions reduction requirements or other GHG emissions regulations. See below "Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for oil and gas that we produce".

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Although we record a provision in our consolidated financial statements relating to our estimated future abandonment and reclamation obligations, we cannot guarantee that we will be able to satisfy our actual future abandonment and reclamation obligations. In addition, estimates of the costs are subject to uncertainty associated with the method, timing and extent of future decommissioning activities. Although the Corporation maintains insurance consistent with prudent industry practice, we are not fully insured against certain environmental risks, including the impacts of climate change, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms.

Accordingly, our properties may be subject to liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other reasons. It is also possible that changing regulatory requirements or emerging jurisprudence could render such insurance of less benefit to Crescent Point. Any site remediation, reclamation or abandonment costs actually incurred in the ordinary course of business in a specific period will be funded out of our reclamation budget and, if required, out of cash flow and, therefore, will reduce the amounts available for return of capital to Shareholders. Should we be unable to fully fund the cost of remedying an environmental problem, we might be required to suspend or terminate certain operations or enter into interim compliance measures pending completion of the required remedy.

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for oil and gas that we produce.

Complying with climate change legislation and regulations has increased operating costs as we pay fuel charges imposed by such legislation and have undertaken initiatives to reduce GHG emissions. Additionally, complying with methane reduction regulations applicable to our business requires Crescent Point to incur additional operating costs in order to achieve compliance.

Changes to federal legislation, as well as legislation in Alberta and Saskatchewan require the restriction or reduction of GHG emissions or emissions intensity from our current and future operations and facilities, which may lead to increased operational costs associated with emission reductions, payments to technology or decarbonization funds, payments of carbon levies, the purchase and retirement of emission reductions, allowances or offset credits, or a combination of such actions. The required GHG reductions may not be technically or economically feasible for our operations and the failure to meet such emission reduction or emission intensity reduction requirements or other compliance mechanisms may materially adversely affect our business and result in fines, penalties and the suspension of some operations. Furthermore, equipment from suppliers which can meet future emission standards may not be available on an economic basis and other compliance methods of reducing emissions or emission intensity to levels required in the future may significantly increase our operating costs or reduce output. Emission reductions, allowances or offset credits may not be available on an economic basis. Additionally, changes in technology could decrease the demand for our products.

The current state of development of ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties or domestic United States regulations. Moreover, many experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in precipitation and extreme weather events, including severe cold, wildfires, droughts and floods, which can result in damage to or destruction of infrastructure, facilities and equipment. In addition, warmer winters in some regions as a result of climate change could also decrease demand for natural gas. To the extent that such unfavorable weather conditions are realized due to climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make any estimations of future financial risk to our operations caused by these potential physical risks of climate change unreliable.

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We may be unable to meet emissions targets.

We have set internal emissions reduction targets with respect to GHG emissions. There are substantial costs and operational changes required to meet such targets, and as such, we may be unable to finance the required changes to meet our emissions targets due to lack of capital for a variety of reasons, many of which are beyond our control. Additionally, we may be unable to adequately alter our operations in such a way as to meet our emissions targets by the stated dates or at all.

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 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.

Federal, provincial and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Some of Crescent Point's operations use hydraulic fracturing, which involves the high pressure injection of fluids and sand down a well to fracture the reservoir and thereby stimulate the increased flow of oil or gas into the well bore. Hydraulic fracturing has been the subject of greater regulatory and public scrutiny and regulation in certain jurisdictions of the world, including some of the areas in which Crescent Point operates. In a limited number of areas, hydraulic fracturing has been banned pending public and scientific reviews or is subject to moratoria while regulators study the practice. Additionally, hydraulic fracturing has been found to induce seismicity, and the AER has developed monitoring and reporting requirements that companies must follow in certain areas of Alberta, and in certain cases, the AER may require that operations resulting in increased seismic activity be suspended and not resumed without AER approval. We may be required to expend additional costs to comply with future regulatory requirements with respect to hydraulic fracturing or, in the future, be unable to carry out hydraulic fracturing operations, thereby lessening the volume of oil and gas we could otherwise produce and this could have a material operational and financial impact on Crescent Point and adversely affect the market price of our Common Shares and dividends to Shareholders.

Our business and financial performance may be adversely affected by subsequent unavailability and unfavorable terms of water licenses.

Crescent Point utilizes fresh water in certain operations, including hydraulic fracturing operations, which water is obtained under licenses issued within each respective jurisdiction's regulations. If water use fees increase or a change under these licenses reduces the amount of water available for our use, production could decline or operating expenses could increase, both of which may have a material adverse effect on our business and financial performance. There can be no assurance that the licenses to withdraw water will not be rescinded, that additional conditions will not be added to these licenses or that the water licensed will be available. There is no assurance that if we require licenses or amendments to existing licenses, that these licenses or amendments will be granted on favorable terms. This may adversely affect our business, including the ability to operate our assets and execute development plans.

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The Corporation's risk and/or cost of borrowing may be adversely affected by the uncertainty resulting from the Orphan Well Association v Grant Thornton Ltd. court decision.

On January 31, 2019, the Supreme Court of Canada released its decision in Orphan Well Association v Grant Thornton Ltd. (the "Redwater decision") overturning earlier decisions of the Alberta courts to hold that receivers and trustees can no longer avoid the AER legislated authority to: impose abandonment orders against licensees, or require a licensee to pay a security deposit before approving a transfer when such a licensee is subject to formal insolvency proceedings. As a result, any financial resources of a bankrupt licensee in Alberta may first be used to satisfy outstanding abandonment and reclamation obligations in respect of its unproductive assets. Remaining amounts, if any, will then satisfy the claims of secured creditors in accordance with the Bankruptcy and Insolvency Act. As a result of the Redwater decision, the provincial regulation of environmental liabilities and associated decommissioning liability in the oil and gas industry is undergoing changes. On January 1, 2023, SMER changed how it assesses the financial ability of operators/licensees to meet their abandonment, reclamation and other regulatory obligations and on December 1, 2021, the AER brought into force the new LLCM. The impact of any such regulatory measures by a provincial or federal government on the Corporation is uncertain at this time.

Additionally, some issuers have been required by lenders to include covenants with respect to the asset recovery obligations in the agreements that govern their borrowings (including credit facilities and other debt obligations) following the Redwater decision. To date, the Corporation has not been required by its lenders to include such provisions, however, there can be no certainty that the Corporation's lenders will not require such or other covenants and contractual terms, which in turn could cause the Corporation's risk and/or cost of borrowing to increase, possibly materially.

Safety requirements involving rail transportation may adversely affect us and our Shareholders.

In response to train derailments occurring in the United States and Canada in 2013, U.S. and Canadian regulators have implemented additional rules to address the safety risks of transporting crude oil by rail.

In Canada, amendments have been made to the Transportation of Dangerous Goods Regulations which adopt a new class of tank car for flammable liquid dangerous goods service and which require all new rail tank cars destined for flammable liquid service to be built to the new specifications. Certain older tank cars used to transport crude oil have been phased out. Further, shippers of crude oil by rail now must have in place an Emergency Response Assistance Plan approved by the Minister of Transportation in order to be able to provide assistance to responders in the event of an accident. Other amendments require the consigner of a shipment of crude oil by rail to properly classify the crude oil and to certify that the classification is correct. Additionally, Transport Canada has introduced requirements for railway companies to reduce the speed of trains carrying dangerous goods such as crude oil and to implement various other safe operating practices.

In the United States, the Department of Transportation has adopted regulations for the transportation of flammable liquids, which align with the standards adopted by Canada. Among other matters, the regulations require enhanced braking systems on trains transporting flammable liquids, restricts operating speeds, requires a risk assessment-based routing analysis, and mandates procedures for more accurate classification of crude oil.

These regulations and the adoption of any other regulations that impact the testing or rail transportation of crude oil could increase our costs of doing business and limit our ability to transport and sell our crude oil at favorable prices at market centers throughout Canada and the United States, the consequences of which could have a material adverse effect on our financial condition, results of operations and cash flows.

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.

Changes in tax and other laws may adversely affect the trading price of our Common Shares and return of capital to Shareholders. Tax authorities having jurisdiction over the Corporation or the 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 Shareholders.

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The oil and gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, the provinces, the United States, and the various states, all of which should be carefully considered by investors in the oil and gas industry. All of 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 and there can be no assurance that there will not be further revocation, amendment or administrative change which will be materially adverse to our assets, reserves, financial condition or results of operations or prospects and our ability to return capital to Shareholders.

Royalty changes may adversely affect us.

Royalty frameworks, including rates and available incentive programs, may be reviewed and amended from time to time by the applicable federal, provincial, state or other governmental bodies or agencies having jurisdiction. In addition, the royalty rates applicable to the Corporation’s production of hydrocarbons may be impacted by changes in market prices for hydrocarbons, production volumes, and capital and operating costs. An increase in royalty rates would reduce the Corporation's cash flow and earnings, and could make future capital investments, or the Corporation's operations, less economic.

We are affected by seasonal weather patterns.

The level of activity in the oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities, provincial and state transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors, unexpected weather patterns, wildfires, floods and droughts may lead to declines in exploration and production activity and corresponding declines in the demand for crude oil and natural gas.

We may be adversely affected by extreme weather events.

Extreme weather events are an unpredictable risk. Wildfires can be caused by lightning, high temperatures, or by human activity and can spread because of wind and are otherwise encouraged by hot dry conditions. Floods can be caused by a high level of precipitation in a short period of time. Severe cold can cause water to freeze and expand leading to a chance that pipes can burst and valves may break. Wildfires, floods and severe cold can cause damage to or destroy infrastructure including roads, rail lines, and power transmission lines, cause damage to facilities and equipment, cause operational difficulties and access restrictions, lead to reduced operations or a cessation of operations in affected areas, and can cause supply chain disruptions affecting both our ability to market oil and gas and our ability to obtain goods and services required for our operations. Drought can lessen the availability of water required to conduct our operations. Extreme weather events could adversely affect our business and operations, however, due to the unpredictable nature of extreme weather events, it is not possible to determine how or to what extent our business or operations may be affected.

We may be subject to environmental non-governmental organization legal challenges.

Environmental non-governmental organizations have become more aggressive in pursuing legal challenges to oil and gas companies, drilling and pipeline projects. In turn, this could result in increased costs and additional operating restrictions or delays as well as the risks under "Risks Relating to Our Business - We may be Subject to Litigation."

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Investor sentiment towards fossil fuel development may not align with our business.

Investor sentiment towards fossil fuel development has been affected by a number of factors, including public perception, climate change, environmental impacts of operations, environmental damage resulting from accidental releases, responsibility for orphaned wells and Indigenous rights. As a result of these and other concerns, some institutional, retail and governmental investors have announced that they will no longer fund or invest in oil and natural gas, or are reducing their investments in the same. Some institutional investors are also requesting that issuers develop and implement robust social, environmental and governance policies and practices, which may be more stringent than those which Crescent Point already has in place. Changing investor sentiment can make capital harder to access or more expensive, and may also have an effect on the value of our assets. It is not expected that changing investor sentiment will affect our operations in a manner materially different than they would affect other oil and gas entities of similar size.

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.

Most of our directors and officers and the representatives of the experts who provide services to us (such as our auditors and our independent reserve engineers), and all or a substantial portion of our assets and the assets of such persons 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 reserve 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), however, we also follow the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves, whereas, the SEC rules require that a trailing 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-month for each month within the 12-month period to the end of the reporting period, and uninflated (constant) costs be utilized. The SEC permits, but does not require, the disclosure of reserves based on forecast prices and costs.

Reserve information contained herein include estimates of Proved and Proved plus Probable reserves. The SEC requires oil and gas issuers in their filings with the SEC to disclose only Proved reserves. The SEC permits, but does not require, the inclusion of estimates of Probable reserves in filings made with it by United States oil and gas companies. The SEC definitions of Proved reserves and Probable reserves are different than those in NI 51-101. As a consequence of the foregoing, our reserve estimates and production volumes in this AIF may not be comparable to those made by companies utilizing United States reporting and disclosure standards.

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Shareholders who are non-residents of Canada may be subject to additional taxation.

The Tax Act imposes a withholding tax at the rate of 25% on dividends paid by us to Shareholders who are non-residents of Canada, unless the rate is reduced under the provisions of a tax treaty between Canada and the non-resident Shareholder's jurisdiction of residence. These withholding tax rates may change from time to time. Where the non-resident Shareholder is a United States resident entitled to benefits under the Canada-United States Income Tax Convention, 1980 and is the beneficial owner of the dividend, the rate of Canadian withholding tax applicable to dividends is generally reduced to 15%. Shareholders who are non-residents of Canada are encouraged to consult with their tax advisors for more information concerning additional taxation that may be applicable to them.

Shareholders who are non-residents of Canada may be subject to foreign exchange risk.

Our dividends are declared in Canadian dollars and converted to foreign denominated currencies at the spot exchange rate at the time of payment. As a consequence, investors are subject to foreign exchange risk. To the extent that the Canadian dollar strengthens with respect to their currency, the amount of the dividend will be reduced when converted to their home currency.

DIVIDENDS AND SHARE REPURCHASES

The Corporation has established a dividend policy of paying regular dividends to Shareholders. An objective of the Corporation's dividend policy is to provide Shareholders with relatively stable and predictable dividends. An additional objective is to retain a portion of cash flow to fund ongoing development and optimization projects designed to enhance the sustainability of the Corporation's cash flow. Commencing in 2019, the Corporation moved to a quarterly dividend, paid on the first business day of each quarter. Dividends are paid to Shareholders of record on the 15th day of the month prior to the payment date.

Additionally, as part of its return of capital framework that targets the return of up to 60% of the Corporation's excess cash flow, the Corporation, has and, in the future, may declare special dividends. Special dividends declared and paid in 2023 were $0.087 per Share.

The amount of cash dividends to be paid on the Common Shares, if any, will be subject to the discretion of the Board of Directors and may vary depending on a variety of factors, including the price of oil and gas, the prevailing economic and competitive environment, results of operations, debt and working capital levels, the taxability of Crescent Point, Crescent Point's ability to raise capital, the amount of capital expenditures and other conditions existing from time to time. There can be no guarantee that Crescent Point will maintain its dividend policy.

Although the Corporation strives to provide Shareholders with stable and predictable cash flows, the percentage of cash flow from operations paid to Shareholders may vary according to a number of factors, including, fluctuations in resources prices, 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 of the Corporation.

The agreements governing the Credit Facilities, Term Loan and Senior Guaranteed Notes provide 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.

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

			Dividends per Common Share ($)
January 2021	–	December 2021	0.0825
January 2022	–	December 2022	0.3600
January 2023	–	December 2023	0.3870

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Normal Course Issuer Bid

On March 9, 2022, Crescent Point commenced the 2022 NCIB to purchase, for cancellation, up to 57,309,975 Common Shares, representing 10% of the Corporation's public float as at February 28, 2022. The 2022 NCIB expired on March 8, 2023. A total of 29,398,000 Common Shares were purchased under the 2022 NCIB.

On March 9, 2023, Crescent Point commenced the 2023 NCIB to purchase, for cancellation, up to 54,605,659 Common Shares, representing 10% of the Corporation's public float as at February 23, 2023. The 2023 NCIB is due to expire on March 8, 2024. As of February 16, 2024, the Corporation had purchased 30,775,500 Common Shares under the 2023 NCIB.

The objective of the 2022 NCIB and the 2023 NCIB was to return capital to Shareholders in a way that is accretive to both Shareholders and the Corporation. Purchases of Common Shares under the 2023 NCIB may be made through the facilities of the TSX or the NYSE, alternative trading systems by means of open market transactions, or by such other means as may be permitted by the TSX and applicable securities laws.

MARKET FOR SECURITIES

The outstanding Common Shares are traded on the TSX and the NYSE under the trading symbol "CPG". The following tables set forth the price range and trading volume of the Common Shares as reported by the TSX and NYSE for the periods indicated.

TSX	High ($)	Low ($)	Volume (000's)
2023
January	10.22	8.64	77,066
February	10.09	8.93	100,987
March	10.07	7.73	170,792
April	10.54	9.67	94,266
May	10.02	8.50	74,361
June	9.46	8.32	85,273
July	10.94	8.69	90,232
August	11.49	10.55	59,550
September	11.70	10.65	56,985
October	11.62	10.16	61,599
November	11.67	9.22	103,645
December	9.72	8.62	70,618
2024
January	9.48	8.51	60,207
February 1 - 16	9.22	8.16	31,225

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NYSE	High (US$)	Low (US$)	Volume (000's)
2023
January	7.67	6.39	103,313
February	7.57	6.59	121,827
March	7.40	5.59	164,215
April	7.87	7.08	85,216
May	7.40	6.26	73,222
June	7.08	6.30	76,271
July	8.29	6.50	70,229
August	8.57	7.81	62,699
September	8.59	7.90	56,839
October	8.49	7.40	77,938
November	8.53	6.70	101,748
December	7.23	6.34	92,036
2024
January	7.10	6.28	100,653
February 1 - 16	6.84	6.04	69,915

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CONFLICTS OF INTEREST

Circumstances may arise where members of the Board of Directors or officers of the Corporation are directors or officers of corporations which are in competition to the interests of the Corporation. No assurances can be given that opportunities identified by such Board members or officers will be provided to the Corporation. In accordance with the ABCA, a director or officer who is a party to a material contract or proposed material contract with the Corporation or is a director or an officer of or has a material interest in any person who is a party to a material contract or proposed material contract with the Corporation shall disclose to the Corporation the nature and extent of the director's or officer's interest. In addition, a director shall not vote on any resolution to approve a contract of the nature described except in limited circumstances. Management of the Corporation is not aware of any existing or potential material conflicts of interest between the Corporation or a subsidiary of the Corporation and a director or officer of the Corporation or any other subsidiary of the Corporation.

LEGAL PROCEEDINGS

There are no outstanding legal proceedings material to the Corporation to which we are a party or in respect of which any of our properties are subject, nor are any such proceedings known to be contemplated.

AUDIT COMMITTEE

General

The Corporation has established an Audit Committee (the "Audit Committee") comprised of four members: Mike Jackson (Chair), Francois Langlois, Myron M. Stadnyk and Mindy Wight each of whom is considered "independent" and "financially literate" within the meaning of National Instrument 52-110 – Audit Committees.

Mandate of the Audit Committee

The mandate of the Audit Committee is to assist the Board of Directors in its oversight of the integrity of the financial and related information of the Corporation and its subsidiaries and related entities, including the consolidated financial statements, internal controls and procedures for financial reporting and the processes for monitoring compliance with legal and regulatory requirements. In doing so, the Audit Committee oversees the audit efforts of our external auditors and, in that regard, is empowered to take such actions as it may deem necessary to satisfy itself that our external auditors are independent of us. It is the objective of the Audit Committee to have direct, open and frank communications throughout the year with management, other Committee chairs, the external auditors, and other key committee advisors or the Corporation's staff members, as applicable.

The Audit Committee's function is oversight. Management of the Corporation is responsible for the preparation, presentation and integrity of the consolidated financial statements of the Corporation. Management is responsible for maintaining appropriate accounting and financial reporting principles and policies as well as internal controls and procedures that provide for compliance with accounting standards and applicable laws and regulations. Additionally, the Audit Committee reviews the cyber risks facing the Corporation and any related policies for managing cyber risk, as well as the Corporation's enterprise risk management policy, processes and framework and the assessment of enterprise risk management effectiveness by internal audit.

While the Audit Committee has the responsibilities and powers set forth above, it is not the duty of the Audit Committee to plan or conduct audits or to determine whether the consolidated financial statements of the Corporation are complete and accurate and are in accordance with generally accepted accounting principles. This is the responsibility of management and the external auditors, on whom the members of the Committee are entitled to rely upon in good faith.

The Audit Committee Mandate is attached hereto as Appendix A.

    - 82 -    

Relevant Education and Experience of Audit Committee Members

The following is a brief summary of the education or experience of each member of the Audit Committee that is relevant to the performance of his or her responsibilities as a member of the Audit Committee, including any education or experience that has provided the member with an understanding of the accounting principles used by us to prepare our annual and interim consolidated financial statements.

Name of Audit Committee Member	Relevant Education and Experience
Mike Jackson	Mr. Mike Jackson worked in the banking sector from 1984 until his retirement in 2016. From 1997 to 2016, he was Managing Director in Scotiabank's Corporate & Investment Banking group focused on the oil & gas industry, including ten years heading the group. For the period 2006-2016, Mr. Jackson served as Financial Advisor to Boards/companies on M&A transactions aggregating over $28 billion. Mr. Jackson joined the Board of Crescent Point in November 2016.
	Mr. Jackson holds a Bachelor of Science degree and a Master of Business Administration, both from Dalhousie University and the ICD.D designation granted by the Institute of Corporate Directors. Additionally, Mr. Jackson completed the Executive Management Program at Queen's University.
François Langlois	Mr. Langlois is an oil and gas executive who brings over 35 years of domestic and international experience to the Crescent Point Board, most recently from his role as Senior Vice President, Exploration & Production with Suncor Energy Inc., where he was responsible for the financial and operating performance of the group from 2011 until his retirement in 2016. Prior thereto, he was Vice President, Unconventional Gas from 2009 to 2010 and held various roles with Petro-Canada from 1982 to 2009, most recently as Vice President, Western Canada Production & North American Exploration.
	Mr. Langlois holds a Bachelor Geological Engineering from Laval University (Quebec City) and the ICD.D designation granted by the Institute of Corporate Directors.
Mindy Wight	Ms. Mindy Wight brings over 15 years of tax and financial expertise in her current role of Chief Executive Officer for the Nch'kay Development Corporation, as well as holding the role as Treasurer of the Board of Directors. Prior to joining Nch'kay Development Corporation in November 2021, Ms. Wight held progressive tax roles at MNP LLP from 2016 to 2021 and most recently was a partner and National Leader of Indigenous Tax Services for the firm. Ms. Wight has also worked for two of the Big Four National accounting firms, the Chartered Accounting School of Business and the Canada Revenue Agency since graduating from the University of Northern British Columbia with a Bachelor of Commerce Degree, Accounting in 2007. Ms. Wight also possesses Chartered Professional Accountant, Chartered Accountant, and Certified Aboriginal Financial Manager designations.
	Ms. Wight has historically held Board positions as the Chair of the Board of Directors and Chair of the Finance and Audit Committee for the Nch'kay Development Corporation and was an Advisory Committee Member of the Budget and Financial Committee to the Squamish Nation.
Myron M. Stadnyk	Mr. Myron M. Stadnyk has over 35 years of oil and gas experience and is the former President and CEO of ARC Resources Ltd., retiring in 2020. During his tenure as CEO, and prior to that as COO, Mr. Stadnyk played a pivotal role in ARC's transformation from a Royalty trust to a leading Canadian producer. His extensive career also includes working for a major oil and gas company in both domestic and international operations. Mr. Stadnyk earned a Bachelor of Science in Mechanical Engineering from the University of Saskatchewan and is a graduate of the Harvard Business School Advanced Management Program. He holds an ICD.D designation and is a member of APEGA.
	Mr. Stadnyk formerly held a position on the Board of Directors at PrairieSky Royalty Ltd. and served as a Governor for CAPP for over a decade. Currently, Mr. Stadnyk is a board member of Vermilion Energy Inc. and serves on the Board of Trustees for the University of Saskatchewan Engineering Advancement Trust.

    - 83 -    

External Auditor Services Fees

For services provided to the Corporation and its subsidiaries for the years ended December 31, 2023 and 2022 PricewaterhouseCoopers LLP billed approximately $1,656,373 and $998,961, respectively, as detailed below:

	Year ended December 31
	2023		2022
PricewaterhouseCoopers
Audit fees	$	1,457,676	$	952,778
Audit-related fees	$	48,897	$	46,183
Tax fees	—		—
All other fees	$	149,800	$	—
Total	$	1,656,373	$	998,961

The Chair of the Audit Committee has the authority to pre-approve non-audit services which may be required from time to time.

Audit Fees were paid, or are payable, for professional services rendered by the auditors for the audit of the annual financial statements and reviews of the quarterly financial statements, as well as services provided in connection with statutory and regulatory filings or engagements. Audit-related fees consist of the aggregate fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the Corporation's financial statements and are not reported as Audit fees. The services in this category include participation fees levied by the Canadian Public Accountability Board. All Other Fees were for products or services provided by Crescent Point's auditors other than those described as Audit Fees and Audit-Related Fees. All services described beside the captions "Audit Fees", "Audit-Related Fees", and "All Other Fees" were approved by the Audit Committee in compliance with paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X under the U.S. Securities and Exchange Act of 1934, as amended (the "Exchange Act"). None of the fees described above were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Regulation S-X under the Exchange Act.

Audit Committee Oversight

At no time since the commencement of our most recently completed financial year, has a recommendation of the Audit Committee to nominate or compensate an external auditor not been adopted by the Board of Directors.

TRANSFER AGENT AND REGISTRARS

The transfer agent and registrar for our Common Shares is Computershare Trust Company of Canada in Calgary, Alberta.

AUDITOR

Our auditor is PricewaterhouseCoopers LLP, Chartered Professional Accountants, 3100, 111 – 5th Avenue S.W., Calgary, Alberta, T2P 5L3.

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MATERIAL CONTRACTS

Set out below is the only agreement that may be considered material to us:

•Premium Dividend and Dividend Reinvestment Plan.

See "Additional Information Respecting Crescent Point – Premium Dividend and Dividend Reinvestment Plan".

INTERESTS OF EXPERTS

Audit of the consolidated financial statements and the effectiveness of internal control over financial reporting is conducted in accordance with PCAOB standards.

The Corporation’s independent registered public accounting firm is PricewaterhouseCoopers LLP, Chartered Professional Accountants, who have issued a Report of Independent Registered Public Accounting Firm dated February 28, 2024 in respect of the Corporation’s consolidated financial statements as at December 31, 2023 and December 31, 2022 and for each of the years ended December 31 and on the effectiveness of internal control over financial reporting as at December 31, 2023. PricewaterhouseCoopers LLP has advised that they are independent with respect to the Corporation within the meaning of the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta and the rules of the US Securities and Exchange Commission (SEC) and the Public Company Accounting Oversight Board (PCAOB) on auditor independence.

Reserve estimates contained in this AIF are derived from reserve reports prepared by McDaniel. As of the date hereof, McDaniel, as a group, does not beneficially own, directly or indirectly, any Common Shares.

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ADDITIONAL INFORMATION

Additional financial information is available on SEDAR+ at www.sedarplus.com, on EDGAR at www.sec.gov/edgar and on our website at www.crescentpointenergy.com.

Additional information including directors' and officers' remuneration and indebtedness, principal holders of the Corporation's securities, options to purchase securities and securities authorized for issuance under equity compensation plans, if applicable, is contained in our information circular in respect of the annual meeting of Shareholders held on May 18, 2023, which is available on SEDAR. Additional financial information is provided in our comparative consolidated financial statements for our most recently completed financial year ended December 31, 2023 and MD&A.

For additional copies of this AIF please contact:

Crescent Point Energy Corp.

2000, 585 – 8th Avenue, S.W.

Calgary, Alberta

T2P 1G1

Attention: Investor Relations

APPENDIX A

CRESCENT POINT ENERGY CORP.

AUDIT COMMITTEE MANDATE

CORPORATE POLICIES & PROCEDURES

I.    THE BOARD OF DIRECTORS' MANDATE FOR THE AUDIT COMMITTEE

1.General

The Board of Directors (the "Board") has responsibility for the stewardship of Crescent Point Energy Corp. ("Crescent Point") and its subsidiaries or related entities (collectively referred to herein as the "Corporation"). To discharge that responsibility, the Board is obligated by the Business Corporations Act (Alberta) to supervise the management of the business and affairs of the Corporation. The Board's supervisory function involves Board oversight or monitoring of all significant aspects of the management of the Corporation's business and affairs.

Public financial reporting and disclosure by the Corporation are fundamental to the Corporation's business and affairs and to its status as a publicly listed enterprise. The objective of the Board's monitoring of the Corporation's financial reporting and disclosure is to gain reasonable assurance of the following (including, where advisable in the achievement of this objective, through appropriate consultation with senior management and the Corporation's external auditors):

(a)that the Corporation complies with all applicable laws, regulations, rules, policies and other requirement of governments, regulatory agencies and stock exchanges relating to financial reporting and disclosure;

(b)that the accounting principles, significant judgments and disclosures which underlie or are incorporated in the Corporation's consolidated financial statements are the most appropriate in the prevailing circumstances;

(c)that the Corporation's quarterly and annual consolidated financial statements and management's discussion and analysis, and the Corporation's Annual Information Forms ("AIF") are accurate within a reasonable level of materiality and present fairly the Corporation's financial position and performance in accordance with the recognition and measurement principles of International Financial Reporting Standards as issued by the International Accounting Standards Board ("IFRS"); and

(d)that appropriate information concerning the financial position and performance of the Corporation is disseminated to the public in a timely manner in accordance with corporate and securities law and with stock exchange regulations.

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The Board is of the view that monitoring the Corporation's financial reporting and disclosure policies and procedures cannot be reliably met unless the following activities (the "Fundamental Activities") are conducted effectively:

(i)the Corporation's accounting functions are performed in accordance with a system of internal financial controls designed to capture and record properly and accurately all of the Corporation's financial transactions;

(ii)the internal financial controls are regularly assessed for effectiveness and efficiency;

(iii)the Corporation's accounting functions are performed in a manner sufficient to ensure the Corporation has established and continues to maintain disclosure controls and procedures and internal control over financial reporting that meet the requirements of applicable laws, rules and regulations and allows the Chief Executive Officer and the Chief Financial Officer to certify the same;

(iv)the Corporation's quarterly and annual consolidated financial statements are properly prepared by management to comply with IFRS; and

(v)the Corporation's quarterly and annual consolidated financial statements and Management Discussion and Analysis ("MD&A") are reported on by an external auditor appointed by the shareholders of the Corporation.

To assist the Board in monitoring the Corporation's financial reporting and disclosure and to conform to applicable corporate and securities law, including National Instrument 52-110 Audit Committees ("NI 52-110") (as implemented by the Canadian Securities Administrators and as amended from time to time) the Board has established the Audit Committee (the "Committee") of the Board.

2.Role of the Committee

The role of the Committee is to assist the Board in its oversight of: (i) the integrity of the financial and related information of the Corporation, including its consolidated financial statements, the internal controls and procedures for financial reporting and the processes for monitoring compliance with legal and regulatory requirements; (ii) the Corporation's supply chain management process and procedures; (iii) the Corporation's enterprise risk management policy and framework; and (iv) the independence, qualifications and performance of the external auditor of the Corporation. Management is responsible for establishing and maintaining those controls, procedures and processes and the Committee is appointed by the Board to review and monitor them.

The Committee has the authority to conduct any review or investigation appropriate to fulfilling its responsibilities. The Committee shall have unrestricted access to personnel and information, and any resources necessary to carry out its responsibility. In this regard, the Committee may direct internal audit personnel to particular areas of examination.

3.    Composition of Committee

(a)The Committee shall be appointed annually by the Board and consist of at least three members (the "Members") from among the directors of the Corporation.

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(b)Each Member must be an independent, non-executive director, free from any relationship that would interfere with the exercise of the Member's independent judgement. Members shall meet the independence and experience requirements set forth in NI 52-110 and of the regulatory bodies to which the Corporation is subject. Each Member shall be "financially literate", which means under NI 52-110 having the ability to read and understand a set of financial statements that present a breadth and level of complexity of finance and accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Corporation's financial statements at the time of the Member's appointment to the Committee. At least one Member shall have accounting or related financial management expertise and qualify as an "audit committee financial expert" or similar designation in accordance with the requirements of the regulatory bodies to which the Corporation is subject.

(c)Committee members may not, other than in their respective capacities as members of the Committee, the Board or any other committee of the Board, accept directly or indirectly any consulting, advisory or other compensatory fee from the Corporation or any subsidiary of the Corporation, or be an "affiliated person" (as such term is defined in the United States Securities Exchange Act of 1934, as amended, and the rules, if any, adopted by the U.S. Securities and Exchange Commission thereunder) of the Corporation or any subsidiary of the Corporation. For greater certainty, directors' fees and fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the Corporation that are not contingent on continued service should be the only compensation a Committee member receives from the Corporation.

(d)At least one member shall have experience in the oil and gas industry.

(e)Committee members shall not simultaneously serve on the audit committees of more than two other public companies, unless the Board first determines that such simultaneous service will not impair the ability of the relevant members to effectively serve on the Committee, and required public disclosure is made.

(f)The Board shall designate the Chair of the Committee.

(g)The Chair of the Board shall be an ex officio member of the Committee and shall be entitled to attend all meetings of the Committee.

(h)In the event of either: (i) a vacancy arising in the Committee that reduces the size of the Committee to fewer than three members; or (ii) the loss of independence of any Member, the Committee will fill the vacancy or replace the Member that has lost independence, as applicable, within six weeks or by the following annual shareholders' meeting if sooner.

4.    Reliance on Experts

In contributing to the Committee discharging its duties under this Mandate, each Member of the Committee shall be entitled to rely in good faith upon:

(a)consolidated financial statements of the Corporation represented to the Member by an officer of the Corporation or in a written report of the external auditors to present fairly the financial position of the Corporation in accordance with IFRS; and

(b)any report of a lawyer, accountant, engineer, appraiser or other person whose profession lends credibility to a statement made by any such person.

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5.Limitations on The Committee's Duties

In contributing to the Committee discharging its duties under this Mandate, each Member shall be obliged only to exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. Nothing in this Mandate is intended, or may be construed, to impose on any Member a standard of care or diligence that is in any way more onerous or extensive than the standard to which all Board members are subject. The essence of the Committee's duties is monitoring and reviewing to gain reasonable assurance (but not to ensure) that the Fundamental Activities are being conducted effectively, that the objectives of the Corporation's financial reporting are being met and to enable the Committee to report thereon to the Board.

II.    AUDIT COMMITTEE MANDATE

This Mandate outlines how the Committee will satisfy the requirements set forth by the Board in its mandate.

1.Operating Principles

The Committee shall fulfill its responsibilities within the context of the following principles.

Committee Values

The Committee expects the management of the Corporation to operate in compliance with corporate policies; to comply with laws and regulations governing the Corporation; and to maintain strong financial reporting and control processes.

Communications

The Committee and its Members expect to have direct, open and frank communications throughout the year with management, other Committee Chairs, the external auditors, and other key Committee advisors or Company staff members as applicable.

Delegation

The Committee may delegate, from time to time, to any person or committee of persons any of the Committee's responsibilities that may be lawfully delegated.

Annual Audit Committee Plan

The Committee, in consultation with management and the external auditors, shall develop an annual Audit Committee plan responsive to the Committee's responsibilities as set out in this Mandate. In addition, the Committee, in consultation with management and the external auditors, shall develop and participate in a process for review of important financial topics that have the potential to impact the Corporation's financial disclosure.

The plan will be focused primarily on the annual and interim consolidated financial statements and MD&A of the Corporation; however, the Committee may at its sole discretion, or the discretion of the Board, review such other matters as may be necessary to satisfy the requirements of this Mandate.

Committee Expectations and Information Needs

The Committee shall communicate its expectations to management and the external auditors with respect to the nature, timing and extent of its information needs. The Committee expects that written materials will be received from management and the external auditors at a reasonable time in advance of meeting dates.

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Access to Independent Advisors

To assist the Committee in discharging its responsibilities, the Committee may at its discretion, in addition to the external auditors, at the expense of the Corporation, retain one or more persons, firms or corporations having special expertise.

Reporting to the Board, Shareholders and Others

The Committee, through its Chair, shall report after each Committee meeting to the Board at the Board's next regular meeting. In addition, the Committee shall prepare a report to shareholders or others, concerning the Committee's activities in the discharge of its responsibilities, when and as required by applicable laws, rules, policies or regulations.

Evaluation

The Committee will conduct and present to the Board an annual evaluation of the performance of the Committee and the adequacy of this Mandate and recommend any proposed changes to the Board for approval.

Access to the Committee

Representatives of the Auditor and management of the Corporation shall have access to the Committee each in absence of the other.

The External Auditors

The Committee expects that, in discharging their responsibilities to the shareholders, the external auditors shall be accountable to the Board through the Committee. The external auditors shall report all material issues or potentially material issues, either specific to the Corporation or to the financial reporting environment in general, to the Committee.

No Alteration

No alteration to the roles and responsibilities of the Committee shall be effective without the approval of the Board.

2.Operating Procedures

Meetings

The Committee shall meet at least four times annually, or more frequently as circumstances dictate. Meetings shall be held at the call of the Chair, upon the request of two (2) Members or at the request of the external auditors.

Quorum

A quorum shall be a majority of the Members.

Notice of Meeting

Notice of the time and place of every meeting shall be given in writing by any means of transmitted or recorded communication, including email or other electronic means that produces a written copy, to each Member of the Committee at least 24 hours prior to the time fixed for such meeting; provided however, that a Member may in any manner waive a notice of the meeting. Attendance of a Member at a meeting constitutes waiver of notice of the meeting, except where a Member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called.

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Meeting Agenda

Committee meeting agendas shall be the responsibility of the Chair of the Committee in consultation with other Members, senior management and the external auditors.

Procedure, Records and Reporting

Subject to any statute or the articles and by-laws of the Corporation, the Committee shall fix its own procedures at meetings, keep records of its proceedings and report to the Board when the Committee may deem appropriate (but not later than the next regularly scheduled meeting of the Board).

In Camera Meetings

At the discretion of the Committee, the Members shall meet in private session with the external auditors and with management only.

Referral to the Board

Any matter the Committee does not unanimously approve will be referred to the Board for consideration.

Secretary

Unless the Committee otherwise specifies, the Corporate Secretary (or the Associate General Counsel or other person authorized by the Corporate Secretary and acceptable to the Chair of the Committee) of the Corporation shall act as Secretary of all meetings of the Committee.

Acting Chair

In the absence of the Chair of the Committee, the Members shall appoint an acting Chair.

Minutes

A copy of the minutes of each meeting of the Committee shall be provided to each Member and to each director of the Corporation in a timely fashion.

Attendance at Meetings

The Chief Executive Officer, the Chief Financial Officer, the Senior Vice President, Finance and Treasurer and the internal audit staff are expected to be available to attend the Committee's meetings or portions thereof, and the Chief Executive Officer is entitled to attend all meetings of the Committee.

The Committee may, by specific invitation, have other resource persons in attendance.

The Committee shall have the right to determine who shall, and who shall not, be present at any time during a meeting of the Committee.

Directors, who are not members of the Committee, may attend Committee meetings, on an ad hoc basis, upon prior consultation and approval by the Committee Chair or by a majority of the members of the Committee.

3.    Specific Responsibilities and Duties

To fulfill its responsibilities and duties, the Committee shall:

    - 7 -    

Financial Information and Reporting

(a)Review, prior to public release, the Corporation's annual and quarterly consolidated financial statements with management and the external auditors to gain reasonable assurance that the statements are accurate within reasonable levels of materiality, complete, represent fairly the Corporation's financial position and performance and are in accordance with IFRS and report thereon to the Board before such consolidated financial statements are approved by the Board;

(b)Receive from the external auditors reports on their review of the annual and quarterly consolidated financial statements;

(c)Receive from management a copy of the representation letter provided to the external auditors and receive from management any additional representations required by the Committee;

(d)Review, prior to public release, all news releases issued by the Corporation with respect to the Corporation's annual and quarterly consolidated financial statements; and

(e)Review, prior to public release, prospectuses, material change disclosures of a financial nature, management discussion and analysis, AIF and similar disclosure documents to be issued by the Corporation.

Accounting Policies

(a)Review with management and the external auditors the appropriateness of the Corporation's accounting policies, disclosures, reserves, key estimates and judgments, including changes or variations thereto;

(b)Obtain reasonable assurance that the accounting policies, disclosures, reserves, key estimates and judgments are in compliance with IFRS from management and external auditors and report thereon to the Board;

(c)Review with management and the external auditors the degree of conservatism of the Corporation's underlying accounting policies, key estimates and judgments and reserves along with quality of financial reporting; and

(d)Participate, if requested, in the resolution of disagreements between management and the external auditors.

Risk and Uncertainty

(a)Acknowledging that it is the responsibility of the Board, in consultation with management, to identify the principal business risks facing the Corporation, determine the Corporation's tolerance for risk and approve risk management policies, the Committee shall focus on financial risk and gain reasonable assurance that financial risk is being effectively managed or controlled by:

(i)reviewing with management the Corporation's tolerance for financial risks;

(ii)reviewing with management its assessment of the significant financial risks facing the Corporation;

(iii)reviewing with management the Corporation's policies and any proposed changes thereto for managing those significant financial risks; and

(iv)reviewing with management its plans, processes and programs to manage and control such risks.

(b)Review with management its assessment of the cyber risks facing the Corporation and any related policies and any proposed changes thereto for managing cyber risk;

    - 8 -    

(c)Review, at least biennially, review the enterprise risk management policy, processes and framework and the assessment of enterprise risk management effectiveness by internal audit;

(d)Annually review the report prepared in accordance with the Fighting Against Force Labour and Child Labour in Supply Chains Act on the steps the Corporation has taken during its previous financial year to prevent and reduce the risk that forced labour or child labour is used at any step in the Corporation's supply chain and recommend to the Board that the report be approved by the Board in discharging its duty under the Act;

(e)Review policies and compliance therewith that require significant actual or potential liabilities, contingent or otherwise, to be reported to the Board in a timely fashion;

(f)Review foreign currency, interest rate and commodity price risk mitigation strategies, including the use of derivative financial instruments;

(g)Review the adequacy of insurance coverages maintained by the Corporation; and

(h)Review regularly with management, the external auditors and the Corporation's legal counsel, any legal claim or other contingency, including tax assessments, that could have a material effect upon the financial position or operating results of the Corporation and the manner in which these matters have been disclosed in the consolidated financial statements.

Financial Controls and Control Deviations

(a)Review the plans of the external auditors to gain reasonable assurance that the evaluation and testing of internal financial controls is comprehensive, coordinated and cost effective;

(b)Receive regular reports from management and the external auditors on all significant deviations from IFRS or other Company internal control processes or indications which may suggest fraud and the corrective activity undertaken in respect thereto; and

(c)Institute a procedure that will permit any employee, including management employees, to bring to the attention of the Board or the Committee concerns relating to financial controls and reporting which are material in scope and which cannot be addressed, in the employee's judgment, through existing reporting structures in the Corporation.

Compliance with Laws and Regulations

(a)Receive and review regular reports from management and others (e.g. external auditors) with respect to the Corporation's compliance with laws and regulations having a material impact on the consolidated financial statements including:

(i)tax and financial reporting laws and regulations;

(ii)legal withholding requirements; and

(iii)other laws and regulations which expose directors to liability; and

(b)Review the filing status of the Corporation's tax returns and those of its subsidiaries or related entities.

    - 9 -    

Relationship and External Auditors

(a)Be directly responsible, in the Committee's capacity as a committee of the Board and subject to the rights of shareholders and applicable law, for the appointment, compensation, retention and oversight of the work of the external auditors (including resolution of disagreements between management and the external auditors regarding financial reporting) for the purpose of preparing or issuing an audit report, or performing other audit, review or attest services for the Corporation. The external auditors shall report directly to the Committee;

(b)Recommend to the Board the nomination of the external auditors;

(c)Pre-approve and recommend to the Board the remuneration and the terms of engagement of the external auditors as set forth in the Engagement Letter. The Chair of the Committee hereby has the authority to pre-approve non-audit services which may be required from time to time;

(d)Review the performance of the external auditors annually or more frequently as required;

(e)Receive annually from the external auditors an acknowledgement in writing that the shareholders, as represented by the Board and the Committee, are their primary client;

(f)Receive a report annually from the external auditors with respect to their independence, such report to include a disclosure of all engagements (and fees related thereto) for non-audit services by the Corporation;

(g)Review with the external auditors the scope of the audit, the areas of special emphasis to be addressed in the audit, and the materiality levels which the external auditors propose to employ;

(h)Meet with the external auditors at least once a year in the absence of management to determine, inter alia, that no management restrictions have been placed on the scope and extent of the audit examinations by the external auditors or the reporting of their findings to the Committee;

(i)Establish effective communication processes with management and the Corporation's external auditors to assist the Committee to monitor objectively the quality and effectiveness of the relationship among the external auditors, management and the Committee; and

(j)Establish a reporting relationship between the external auditors and the Committee such that the external auditors can bring directly to the Committee matters that, in the judgment of the external auditors, merit the Committee's attention. In particular, the external auditors will advise the Committee of any disagreements between management and the external auditors regarding financial reporting and how such disagreements were resolved.

Relationship with Internal Auditor

(a)Review the internal audit staff functions, including:

(i)the purpose, authority and organizational reporting lines;

(ii)the annual audit plan, budget and staffing; and

(iii)the appointment and compensation of any person with the responsibility for the Internal Audit; and

(b)Review, with the Chief Financial Officer, controller or others, as appropriate, the Corporation's internal system of audit controls and the results of internal audits.

    - 10 -    

Other Responsibilities and Procedures

(a)After consultation with the Chief Financial Officer, the Senior Vice President Finance and Treasurer and the external auditors, gain reasonable assurance, at least annually, of the quality and sufficiency of the Corporation's accounting and financial personnel and other resources;

(b)Investigate any matters that, in the Committee's discretion, fall within the Committee's duties;

(c)Determine the appropriate funding for payment by the Corporation of: (i) of compensation to the external auditors for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Corporation, (ii) of compensation to any advisors employed by the Committee, and (iii) of ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties; and

(d)Perform such other functions as may, from time to time, be assigned to the Committee by the Board.

III.HIRING GUIDELINES FOR INDEPENDENT AUDITOR EMPLOYEES

1.Guidelines

The Committee has adopted the following guidelines regarding the hiring of any partner, employee, reviewing tax professional or other person providing audit assurance to the external auditor of the Corporation on any aspect of its certification of the Corporation's consolidated financial statements:

(a)No senior member of the audit team that is auditing a business of the Corporation can be hired into that business or into a position to which that business reports for a period of two years after the audit; and

(b)No former partner or employee of the external auditor may be made an officer of the Corporation or any of its subsidiaries for two years following association with the external auditor:

(i)The Chief Executive Officer must approve all office hires from the external auditor; and

(ii)The Chief Financial Officer must report annually to the Committee on any hires within these guidelines during the preceding year.

2.Audit Partner Rotation

The Committee will ensure that the head audit partner assigned by the external auditor to the Corporation, as well as the audit partner charged with reviewing the audit of the Corporation, are changed at least every five years.

3.Process for Handling Complaints about Accounting Matters

The Committee will establish the following procedures for the receipt and treatment of any complaint received by the Corporation, including confidential, anonymous submissions by employees of the Corporation and by third parties, regarding accounting, internal accounting controls, auditing or other matters and create a summary of any significant investigations regarding such matters:

(a)The Corporation will publish on its website special mail and e-mail addresses and a toll-free telephone number for receiving complaints regarding accounting, internal accounting controls, auditing matters and other matters;

(b)Copies of all complaints will be sent to the Chair of the Committee and to the Chair of the Board and to the Chair of those other committees of the Board responsible for the oversight of the subject matter of the complaint;

    - 11 -    

(c)Copies of complaints relating to accounting, internal accounting controls and auditing matters received will be sent to the Members of the Committee;

(d)All complaints will be investigated by the Corporation's finance and legal departments in the normal manner, except as otherwise directed by the Committee. The Committee may request that outside advisors be retained to investigate any complaint; and

(e)The status of each complaint will be reported on a quarterly basis to the Committee and, if the Committee so directs, to the full Board.

APPENDIX B

RESERVES COMMITTEE MANDATE

CORPORATE POLICIES & PROCEDURES

PURPOSE

The Reserves Committee (the "Committee") is appointed by the Board of Directors of Crescent Point Energy Corp. (the "Board") to assist the Board in fulfilling its responsibility for the stewardship of Crescent Point Energy Corp. ("Crescent Point") and its subsidiaries or related entities (collectively referred to herein as the "Corporation"). The Committee's primary duties and responsibilities are to assume responsibility for assisting the Board in respect of the annual independent review of Crescent Point's petroleum and natural gas reserves and reporting to the Board in respect thereof, including assisting the Board in meeting its obligations under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities, (as implemented by the Canadian Securities Administrators and as amended from time to time) ("NI 51-101").

RESERVES COMMITTEE RESPONSIBILITIES AND DUTIES

The overall duties and responsibilities of the Committee shall be as follows:

(a)in conjunction with the Corporation's senior engineering management, meet with the independent evaluating engineers being considered for appointment to review their qualifications and independence to ensure the independent evaluating engineers being considered for appointment are technically qualified and competent, are independent of management and to establish the terms of their engagement;

(b)after consultation with the Corporation's senior engineering management, recommend to the Board the appointment of the independent evaluating engineers to assist the Corporation in the annual review of its petroleum and natural gas reserves;

(c)in consultation with the Corporation's senior engineering management determine the scope of the annual review of the petroleum and natural gas reserves by the independent evaluating engineers, having regard to the regulatory reporting requirements applicable to the Corporation, including those set forth in NI 51-101;

(d)review, with reasonable frequency, the Corporation's procedures for providing petroleum and natural gas reserves information to the qualified independent evaluating engineers who report on reserves data for the purposes of NI 51 - 101, and the information used by the independent evaluating engineers to enable the independent evaluating engineers to provide a report that will meet regulatory reporting requirements;

    - 2 -    

(e)in consultation with the Corporation's senior engineering management and the independent evaluating engineers:

◦determine whether any restrictions affect the ability of the independent evaluating engineers to report on reserve data without reservations; and

◦review the reserves data and the report of the independent evaluating engineers.

(f)ensure the disclosure to the public on the Corporation's petroleum and natural gas reserves is in compliance with regulatory requirements and make appropriate changes, reports or recommendations to the Board with respect to the procedures for such disclosure;

(g)review any proposal to change the independent evaluating engineers and/or resolve any differences between the independent evaluating engineers and management;

(h)meet on an annual basis with the Corporation's senior engineering management and/or the independent evaluating engineers of the Corporation to review and consider the evaluation of the Corporation's petroleum and natural gas reserves;

(i)meet separately with the independent evaluating engineers and/or senior engineering management when the Committee deems it desirable and advise the Board on the results of such meeting;

(j)coordinate meetings with the Audit Committee of the Corporation, the Corporation's senior engineering management, independent evaluating engineers and auditors as required to address matters of mutual concern in respect of the Corporation's evaluation of petroleum and natural gas reserves;

(k)review at least biennially this Committee mandate and recommend any changes to the Board; and

(l)to maintain minutes of meetings and periodically report to the Board on significant results of the foregoing activities.

COMMITTEE MEMBERS' DUTIES IN ADDITION TO THOSE OF DIRECTOR

The duties and responsibilities of a member of the Committee are in addition to those duties set out for a member of the Board.

REPORTING

The Committee shall report to the Board. The Committee shall provide the Board with a summary of all meetings held at a regularly scheduled meeting of the Board held following any Committee meetings.

COMPOSITION

The Committee will be comprised of at least three members, as determined by the Board. The Committee members shall satisfy the independence and experience requirements of applicable securities laws, rules, or guidelines, any applicable stock exchange requirements or guidelines and any other applicable regulatory rules. In particular, a majority of the members of the Committee shall be free from any relationship which could reasonably be expected to materially interfere with the member's independent judgment. Determinations as to whether a particular director satisfies the requirements for membership on the Committee shall be made by the full Board and shall be reviewed at least bi-annually.

The Chair of the Board shall be an ex officio member of the Committee and shall be entitled to attend all meetings of the Committee.

    - 3 -    

Committee members will include only duly-elected directors. Members of the Committee shall be appointed from time to time by the Board. Each member shall serve until such member's successor is appointed, unless such member resigns or is removed by the Board or such member otherwise ceases to be a director of the Corporation. If a member of the Committee ceases to be independent for reasons outside that member's reasonable control, the member shall immediately notify the Chair of the Board as to this fact and shall resign such member's position on the Committee on the earliest of (i) the appointment of such member's successor; (ii) the next annual meeting of shareholders of the Corporation; and (iii) the date that is six months from the occurrence of the event which caused the member to not be independent. The Board shall fill any vacancy if the membership of the Committee is less than three directors.

CHAIR

The Board shall appoint the Chair of the Committee or, if it does not do so, the members of the Committee may elect a Chair by a vote of a majority of the full Committee membership. The Chair shall be an independent director. If the Chair of the Committee is not present at any meeting of the Committee, one of the other members of the Committee present at the meeting shall be chosen to preside by a majority of the members of the Committee present at such meeting.

SECRETARY

The Corporate Secretary of the Corporation, the Associate General Counsel or such other person as the Corporate Secretary of the Corporation shall designate from time to time, shall be the Secretary of the Committee and shall keep minutes of the meetings of the Committee.

OPERATION OF COMMITTEE MEETINGS

The Committee shall have access to such officers and employees of the Corporation and to such information respecting the Corporation, as it considers necessary or advisable in order to perform its duties and responsibilities. The Committee has the authority to engage independent counsel and other advisors as it determines necessary to carry out its duties and to set and pay the compensation for any such counsel and advisors, such engagement to be for the Corporation's sole account and expense.

Committee meetings may, by agreement of the Chair of the Committee, be held in person, by means of teleconference or by a combination of any of the foregoing.

Meetings of the Committee shall be conducted as follows:

(1)The Committee shall meet at least two times annually at such times and at such locations as the Chair of the Committee shall determine. Any two members of the Committee may also request a meeting of the Committee.

(2)The quorum for meetings shall be a majority of the members of the Committee, present in person or by telephone or by other telecommunication device that permits all persons participating in the meeting to hear each other.

(3)The Chair shall, in consultation with management, establish the agenda for the meetings and instruct management to ensure that properly prepared agenda materials are circulated to the Committee with sufficient time for study prior to the meeting.

(4)Every question at a Committee meeting shall be decided by a majority of the votes cast.

    - 4 -    

(5)The Chief Executive Officer is expected to be available to attend the Committee's meetings or portions thereof. The Committee may, by specific invitation, have other resource persons in attendance. The Committee shall have the right to determine who shall, and who shall not, be present at any time during a meeting of the Committee, provided that the Chief Executive Officer of the Corporation is entitled to attend all meetings of the Committee. Directors, who are not members of the Committee, may attend Committee meetings on an ad hoc basis upon prior consultation and approval by the Committee Chair or by a majority of the members of the Committee.

(6)The Committee may delegate from time to time to any person or committee of persons any of the Committee's responsibilities that lawfully may be delegated.

(7)Minutes of each Committee meeting should be succinct yet comprehensive in describing substantive issues discussed by the Committee. However, they should clearly identify those items of responsibilities scheduled by the Committee for the meeting that have been discharged by the Committee and those items of responsibilities that are outstanding. Minutes of the Committee meeting shall be sent firstly to the Chair and next to all Committee members.

NOTICE OF MEETING

Notice of the time and place of each meeting may be given in writing, by electronic means, or orally to each member of the Committee at least 24 hours prior to the time fixed for such meeting.

A member may in any manner waive notice of the meeting. Attendance of a member at a meeting shall constitute waiver of notice of the meeting except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting was not lawfully called.

MISCELLANEOUS

The Committee, with unanimity, may engage outside resources if deemed advisable. Lack of unanimity requires that the matter be referred to the Nominating and Corporate Governance Committee.

Appendix C

FORM 51-101F2
REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES
EVALUATOR OR AUDITOR

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

1.    We have evaluated the Company's reserves data as at December 31, 2023. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2023, 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, 2023, and identifies the respective portions thereof that we have evaluated and reported on to the Company's Board of Directors:

			Net Present Value of Future Net Revenue $M (before income taxes, 10% discount rate)
Independent Qualified Reserves Evaluator or Auditor	Effective Date of Evaluation Report	Location of Reserves	Audited	Evaluated	Reviewed	Total
McDaniel	December 31, 2023	Canada	—	16,023,933.4	—	16,023,933.4
McDaniel	December 31, 2023	United States	—	0	—	0
		Total	—	16,023,933.4	—	16,023,933.4

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 judgements 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.

ORIGINALLY SIGNED BY

Michael J. Verney, P.Eng.

Executive Vice President

Calgary, Alberta, Canada

February 7, 2024

Appendix D

REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

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

McDaniel & Associates Consultants Ltd., an independent qualified reserves evaluator, has evaluated the Corporation's reserves data. The reports of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.

The Reserves Committee of the board of directors of the Corporation has:

(a)    reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluator;

(b)    met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and

(c)    reviewed the reserves data with management and the independent qualified reserves evaluator.

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

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

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

(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.

"Craig Bryksa"	"Ryan Gritzfeldt"
CRAIG BRYKSA President and Chief Executive Officer	RYAN GRITZFELDT Chief Operating Officer
"Francois Langlois"	"Barbara Munroe"
FRANCOIS LANGLOIS Director	BARBARA MUNROE Chair of the Board

February 28, 2024

1

EX-99.2

Exhibit 99.2

MANAGEMENT'S REPORT                                        

MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL REPORTING

The management of Crescent Point Energy Corp. is responsible for the preparation of the consolidated financial statements. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board and include certain estimates that reflect management’s best estimates and judgments. Management has determined such amounts on a reasonable basis in order to determine that the consolidated financial statements are presented fairly in all material respects.

PricewaterhouseCoopers LLP, an independent firm of chartered professional accountants, was appointed by a resolution of the Board of Directors to audit the consolidated financial statements of the Company and to provide an independent professional opinion. PricewaterhouseCoopers LLP was appointed to hold such office until the next annual meeting of the shareholders of the Company.

The Board of Directors, through its Audit Committee, has reviewed the consolidated financial statements including notes thereto with management and PricewaterhouseCoopers LLP. The members of the Audit Committee are composed of independent directors who are not employees of the Company. The Audit Committee meets regularly with management and PricewaterhouseCoopers LLP to review and approve the consolidated financial statements. The Board of Directors has approved the information contained in the consolidated financial statements based on the recommendation of the Audit Committee.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management has developed and maintains an extensive system of internal accounting controls that provide reasonable assurance that all transactions are accurately recorded, that the consolidated financial statements realistically report the Company’s operating and financial results, and that the Company’s assets are safeguarded. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Management has assessed the effectiveness of the Company's internal control over financial reporting as at December 31, 2023. The assessment was based on the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") framework in Internal Control - Integrated Framework (2013) to evaluate the design and effectiveness of internal control over financial reporting. Management concluded that this system of internal controls was effective as of December 31, 2023. The Company has effective disclosure controls and procedures to ensure timely and accurate disclosure of material information relating to the Company which complies with the requirements of Canadian securities legislation and the United States Sarbanes - Oxley Act of 2002.

PricewaterhouseCoopers LLP, an independent firm of chartered professional accountants who also audited the Company's consolidated financial statement for the year ended December 31, 2023, has audited the effectiveness of the Company's internal control over financial reporting as at December 31, 2023.

Craig Bryksa President and Chief Executive Officer	Ken Lamont Chief Financial Officer

February 28, 2024

CRESCENT POINT ENERGY CORP. 1

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Crescent Point Energy Corp.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Crescent Point Energy Corp. and its subsidiaries (together, the Company) as of December 31, 2023 and 2022, and the related consolidated statements of comprehensive income, changes in shareholders’ equity and cash flows for the years then ended, including the related notes (collectively referred to as the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and its financial performance and its cash flows for the years then ended in conformity with IFRS Accounting Standards as issued by the International Accounting Standards Board. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company’s management is responsible for these consolidated financial statements, 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 Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (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 audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements 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. 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 audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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.

CRESCENT POINT ENERGY CORP. 2

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 (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) 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.

Valuation of property, plant and equipment acquired as a part of business combinations

As described in Notes 2, 3 and 8 to the consolidated financial statements, the Company completed the acquisitions of the Kaybob Duvernay (Kaybob) assets on January 11, 2023 and the Alberta Montney (Montney) assets on May 10, 2023 for consideration of $370.4 million and $1.70 billion, respectively, and the corporate acquisition of Hammerhead Energy Inc. (Hammerhead) on December 21, 2023 for consideration of $2.04 billion. These transactions were accounted for as business combinations using the acquisition method, with identifiable assets acquired and liabilities and contingent liabilities assumed, measured at their fair values at the acquisition date. The Kaybob and Montney assets acquired included property, plant and equipment (PP&E) of $323.7 million and $1.62 billion, respectively. The Hammerhead acquisition included PP&E of $2.41 billion. Management determined the fair value of the PP&E acquired by estimating the discounted after-tax future net cash flows (valuation method). The determination of the fair value of PP&E acquired requires judgment by management in making assumptions, including estimates of reserves acquired, forecast benchmark commodity prices, production forecasts, costs and discount rates. In determining the estimates of the reserves acquired, management utilizes the services of specialists, specifically independent petroleum reservoir engineers (management’s specialists).

The principal considerations for our determination that performing procedures relating to the valuation of PP&E acquired as part of business combinations is a critical audit matter are (i) the judgment by management, including the use of management’s specialists, in developing the fair values of PP&E acquired, (ii) a high degree of auditor judgment, effort and subjectivity in performing procedures and evaluating assumptions used in developing those estimates including reserves acquired, forecast benchmark commodity prices, production forecasts, costs and discount rates, and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s determination of the fair values of the PP&E acquired and controls over the development of the assumptions used in these valuations. These procedures also included, among others, testing management’s process for determining the fair values of the PP&E acquired which included (i) evaluating the appropriateness of the valuation method used in making the estimates, (ii) testing the completeness and accuracy of underlying data used in management’s determination of the fair values and (iii) evaluating the reasonableness of assumptions used by management related to estimated reserves acquired, forecast benchmark commodity prices, production forecasts, costs and discount rates. Evaluating these assumptions involved assessing whether these assumptions used were reasonable considering the current and past performance of similar PP&E owned by the Company, external market and industry data and whether they were consistent with evidence obtained in other areas of the audit, as applicable. The work of management’s specialists was used in performing procedures to evaluate the reasonableness of the reserves acquired. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with management’s specialists was assessed. The procedures performed also included evaluating the methods and assumptions used by management’s specialists, testing the completeness and accuracy of the data used by management’s specialists, and evaluating management’s specialists’ findings. Professionals with specialized skill and knowledge were used to assist in assessing the appropriateness of the valuation method and evaluating the reasonableness of the discount rates.

The impact of estimates of proved plus probable oil and gas reserves on development and production assets

As described in Notes 2, 3 and 10 to the consolidated financial statements, the Company had a net balance of $10,679.2 million for development and production assets as of December 31, 2023, and the related depletion expense for the year ended December 31, 2023 was $1,009.3 million. Development and production assets are measured at cost less accumulated depletion and any accumulated impairment losses. Development and production assets are depleted using the unit-of-production method based on estimated proved plus probable oil and gas reserves before royalties, as determined by independent petroleum reservoir engineers. Determining the Company’s proved plus probable oil and gas reserves required the use of significant judgment and assumptions by management related to production forecasts, commodity prices, costs and related future cash flows. In determining the estimates of the proved plus probable oil and gas reserves, management utilizes the services of specialists, specifically independent petroleum reservoir engineers (management’s specialists).

CRESCENT POINT ENERGY CORP. 3

The principal considerations for our determination that performing procedures relating to the impact of estimates of proved plus probable oil and gas reserves on development and production assets is a critical audit matter are (i) the judgment by management, including the use of management’s specialists, when developing the estimates of proved plus probable oil and gas reserves, and (ii) a high degree of auditor judgment, effort and subjectivity in performing procedures and evaluating assumptions used in developing those estimates, including production forecasts, commodity prices, costs and related future cash flows.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved plus probable oil and gas reserves and the calculation of depletion expense. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved plus probable oil and gas reserves used to determine depletion expense. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with management’s specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by management’s specialists, tests of the data used by management’s specialists and an evaluation of management’s specialists’ findings. Evaluating the assumptions used by management’s specialists related to production forecasts, commodity prices, costs and related future cash flows involved assessing whether the assumptions used were reasonable considering the current and past performance of the Company and whether they were consistent with industry pricing forecasts and evidence obtained in other areas of the audit, as applicable. Procedures were also performed to test the unit-of-production method used to calculate depletion expense.

/s/PricewaterhouseCoopers LLP

Chartered Professional Accountants

Calgary, Canada

February 28, 2024

We have served as the Company's auditor since 2001.

CRESCENT POINT ENERGY CORP. 4

CONSOLIDATED BALANCE SHEETS

As at December 31
(Cdn$ millions)	Notes	2023	2022
ASSETS
Cash		17.3	289.9
Accounts receivable		377.9	327.8
Prepaids and deposits		87.8	65.5
Derivative asset	27	240.7	138.9
Other current assets	5	79.2	18.7
Assets held for sale	8	247.1	148.4
Total current assets		1,050.0	989.2
Derivative asset	27	14.3	96.4
Other long-term assets	6	7.4	6.4
Exploration and evaluation	7, 8	607.0	104.2
Property, plant and equipment	8, 10	10,718.3	7,729.4
Right-of-use asset	14	102.8	78.1
Goodwill	11	275.9	203.9
Deferred income tax	24	—	278.8
Total assets		12,775.7	9,486.4
LIABILITIES
Accounts payable and accrued liabilities		634.9	448.2
Dividends payable		56.8	99.4
Current portion of long-term debt	13	380.0	538.7
Derivative liability	27	51.4	8.7
Other current liabilities	12	118.0	115.6
Liabilities associated with assets held for sale	8	132.4	28.4
Total current liabilities		1,373.5	1,239.0
Long-term debt	13	3,186.3	902.8
Derivative liability	27	3.8	—
Other long-term liabilities	15	31.0	40.8
Lease liability	14	104.2	99.2
Decommissioning liability	8, 16	566.4	633.9
Deferred income tax	24	643.0	77.3
Total liabilities		5,908.2	2,993.0
SHAREHOLDERS’ EQUITY
Shareholders’ capital	17	17,052.7	16,419.3
Contributed surplus		17.4	17.1
Deficit	18	(10,202.5)	(10,563.3)
Accumulated other comprehensive income		(0.1)	620.3
Total shareholders' equity		6,867.5	6,493.4
Total liabilities and shareholders' equity		12,775.7	9,486.4

Commitments (Note 29)

Subsequent Events (Note 33)

See accompanying notes to the consolidated financial statements.

Approved on behalf of the Board of Directors:

Barbara Munroe Chair of the Board	Mike Jackson Director

CRESCENT POINT ENERGY CORP. 5

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

For the years ended December 31
(Cdn$ millions, except per share amounts)	Notes	2023	2022 Revised (1)
REVENUE AND OTHER INCOME
Oil and gas sales	32	3,499.0	3,847.0
Purchased product sales		66.2	100.8
Royalties		(375.3)	(435.5)
Oil and gas revenue		3,189.9	3,512.3
Commodity derivative gains (losses)	20, 27	163.8	(473.4)
Other income	21	13.4	59.0
		3,367.1	3,097.9
EXPENSES
Operating		770.5	628.2
Purchased product		68.6	102.9
Transportation		174.3	131.0
General and administrative	8	126.5	78.4
Interest	22	129.4	63.6
Foreign exchange (gain) loss	23	(10.0)	18.8
Share-based compensation	25	38.7	38.8
Depletion, depreciation and amortization	7, 10, 14	894.7	807.2
Impairment (impairment reversal)	10	93.8	(357.3)
Accretion and financing	14, 16	27.5	24.5
		2,314.0	1,536.1
Net income before tax from continuing operations		1,053.1	1,561.8
Tax expense (recovery)
Current	24	(0.7)	—
Deferred	24	254.4	415.1
Net income from continuing operations		799.4	1,146.7
Net income (loss) from discontinued operations	9	(229.1)	336.7
Net income		570.3	1,483.4
Other comprehensive income
Items that may be subsequently reclassified to profit or loss
Foreign currency translation of foreign operations		1.3	90.7
Reclassification of cumulative foreign currency translation of discontinued foreign operations	9	(621.7)	—
Comprehensive income (loss)		(50.1)	1,574.1
Net income (loss) per share	26
Continuing operations - basic		1.47	2.03
Discontinued operations - basic		(0.42)	0.59
Net income per share - basic		1.05	2.62
Continuing operations - diluted		1.46	2.01
Discontinued operations - diluted		(0.42)	0.59
Net income per share - diluted		1.04	2.60

(1)Comparative period revised to reflect current period presentation. See Note 9 - "Discontinued Operations" for additional information.

See accompanying notes to the consolidated financial statements.

CRESCENT POINT ENERGY CORP. 6

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

(Cdn$ millions, except per share amounts)	Notes	Shareholders’ capital	Contributed surplus	Deficit	Accumulated other comprehensive income	Total shareholders’ equity
December 31, 2021		16,706.9	17.5	(11,848.7)	529.6	5,405.3
Redemption of restricted shares		5.2	(5.2)	2.6		2.6
Common shares repurchased for cancellation		(294.2)				(294.2)
Share-based compensation			6.2			6.2
Stock options exercised		1.4	(1.4)			—
Net income				1,483.4		1,483.4
Dividends declared ($0.360 per share)				(200.6)		(200.6)
Foreign currency translation adjustment					90.7	90.7
December 31, 2022		16,419.3	17.1	(10,563.3)	620.3	6,493.4
Issued for cash	17	500.1				500.1
Issued on capital acquisition	8, 17	493.0				493.0
Redemption of restricted shares	17	4.9	(4.9)	2.4		2.4
Common shares repurchased for cancellation	17	(349.9)				(349.9)
Share issue costs, net of tax	17	(15.4)				(15.4)
Share-based compensation	25		5.8			5.8
Stock options exercised	25	0.7	(0.6)			0.1
Net income				570.3		570.3
Dividends declared ($0.387 per share)				(211.9)		(211.9)
Foreign currency translation adjustment					1.3	1.3
Reclassification of cumulative foreign currency translation of discontinued foreign operations	9				(621.7)	(621.7)
December 31, 2023		17,052.7	17.4	(10,202.5)	(0.1)	6,867.5

See accompanying notes to the consolidated financial statements.

CRESCENT POINT ENERGY CORP. 7

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31
(Cdn$ millions)	Notes	2023	2022
CASH PROVIDED BY (USED IN):
OPERATING ACTIVITIES
Net income		570.3	1,483.4
Items not affecting cash
Other (income) loss	21	4.2	(49.0)
Deferred tax expense	24	533.0	387.9
Share-based compensation		5.7	6.0
Depletion, depreciation and amortization	7, 10, 14	1,065.0	951.7
Impairment (impairment reversal)	10	822.2	(428.6)
Accretion	16	22.7	19.2
Unrealized (gains) losses on derivatives	27	56.9	(171.0)
Translation of US dollar long-term debt	23	(16.8)	91.5
Reclassification of cumulative foreign currency translation of discontinued foreign operations	9	(621.7)	—
Translation of US dollar derivatives	27	0.9	—
Realized gain on cross currency swap maturity	23	(151.8)	(63.8)
Decommissioning expenditures	16	(40.0)	(20.1)
Change in non-cash working capital	31	(54.9)	(15.0)
		2,195.7	2,192.2
INVESTING ACTIVITIES
Development capital and other expenditures	7, 10	(1,220.5)	(1,027.4)
Capital acquisitions, net of cash acquired	8	(3,616.2)	(90.7)
Capital dispositions	8	604.5	283.6
Other long-term assets	6	(0.8)	—
Change in non-cash working capital	31	(4.2)	(26.1)
		(4,237.2)	(860.6)
FINANCING ACTIVITIES
Issue of shares, net of issue costs		479.7	—
Common shares repurchased for cancellation	17	(349.9)	(294.2)
Increase (decrease) in bank debt, net	31	2,675.1	(338.5)
Repayment of senior guaranteed notes and acquired long-term debt	31	(897.9)	(281.8)
Realized gain on cross currency swap maturity	23	151.8	63.8
Payments on principal portion of lease liability	14, 31	(20.8)	(20.4)
Dividends declared	31	(211.9)	(200.6)
Change in non-cash working capital	31	(57.2)	15.7
		1,768.9	(1,056.0)
Impact of foreign currency on cash balances		—	0.8
INCREASE (DECREASE) IN CASH		(272.6)	276.4
CASH AT BEGINNING OF YEAR		289.9	13.5
CASH AT END OF YEAR		17.3	289.9

See accompanying notes to the consolidated financial statements.

Supplementary Information:

Cash taxes paid	(0.1)	—
Cash interest paid	(118.1)	(68.0)

CRESCENT POINT ENERGY CORP. 8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS    

December 31, 2023 and 2022

1.STRUCTURE OF THE BUSINESS

The principal undertaking of Crescent Point Energy Corp. (the “Company” or “Crescent Point”) is to carry on the business of acquiring, developing and holding interests in petroleum and natural gas properties and assets related thereto through a general partnership and wholly owned subsidiaries.

Crescent Point is the ultimate parent and is amalgamated in Alberta, Canada under the Alberta Business Corporations Act. The address of the principal place of business is 2000, 585 - 8th Ave S.W., Calgary, Alberta, Canada, T2P 1G1.

These annual consolidated financial statements were approved and authorized for issue by the Company's Board of Directors on February 28, 2024.

2.BASIS OF PREPARATION

a)Preparation

These consolidated financial statements are presented under IFRS Accounting Standards as issued by the International Accounting Standards Board. The policies applied in these consolidated financial statements are based on IFRS Accounting Standards issued and outstanding as of February 28, 2024, the date the Board of Directors approved the statements.

The Company’s presentation currency is Canadian dollars and all amounts reported are Canadian dollars unless noted otherwise. References to “US$” and "US dollars" are to United States ("U.S.") dollars. Crescent Point's Canadian operations are presented herein as continuing operations. The Company's U.S. operations have been classified and presented as discontinued operations. See Note 9 - "Discontinued Operations" for additional information.

b)Basis of measurement, functional and presentation currency

The Company’s presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period end exchange rates for assets and liabilities and at the average rate over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in other comprehensive income as cumulative translation adjustments.

c)Use of estimates and judgments

The preparation of consolidated financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future years affected.

The Company also faces uncertainties related to future environmental laws and climate-related regulations, which could affect the Company's financial position and future earnings. This transition to a lower-carbon society, as well as the physical impacts of climate change, could result in increased operating costs and reduced demand for oil and gas products. As a result, this could change a number of variables and assumptions used to determine the estimated recoverable amounts of the Company's oil and gas assets. The unpredictable nature, timing and extent of climate-related initiatives presents various risks and uncertainties, including to management's judgements, estimates and assumptions that affect the application of accounting policies. Significant estimates and judgments made by management in the preparation of these consolidated financial statements are outlined below.

Oil and gas activities

Reserves estimates, although not reported as part of the Company’s consolidated financial statements, can have a significant effect on net income, assets and liabilities as a result of their impact on depletion, depreciation and amortization (“DD&A”), decommissioning liability, deferred taxes, asset impairments and impairment reversals, and business combinations. Independent petroleum reservoir engineers perform evaluations of the Company’s oil and gas reserves on an annual basis. The estimation of reserves is an inherently complex process requiring significant judgment. Estimates of economically recoverable oil and gas reserves are based upon a number of variables and assumptions such as production forecasts, commodity prices, costs and related future cash flows, all of which may vary considerably from actual results. These estimates are expected to be revised upward or downward over time, as additional information such as reservoir performance becomes available, or as economic conditions change.

For purposes of impairment testing, property, plant and equipment (“PP&E”) is aggregated into cash-generating units (“CGUs”), based on separately identifiable and largely independent cash inflows. The determination of the Company’s CGUs is subject to judgment. Factors considered in the classification of CGUs include the integration between assets, shared infrastructure, the existence of common sales points, geography, geologic structure and the manner in which management monitors and makes decisions regarding operations.

The determination of technical feasibility and commercial viability, based on the presence of reserves and which results in the transfer of assets from exploration and evaluation ("E&E") to PP&E, is subject to judgment.

CRESCENT POINT ENERGY CORP. 9

Decommissioning liability

Upon retirement of its oil and gas assets, the Company anticipates incurring substantial costs associated with decommissioning. Estimates of these costs are subject to uncertainty associated with the method, timing and extent of future decommissioning activities. The liability, the related asset and the expense are impacted by estimates with respect to the cost and timing of decommissioning.

Business combinations

Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of PP&E and E&E assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, production forecasts, costs and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill. Future net earnings can be affected as a result of changes in future DD&A, asset impairment or goodwill impairment.

Fair value measurement

The estimated fair value of derivative instruments resulting in derivative assets and liabilities, by their very nature, are subject to measurement uncertainty. Estimates included in the determination of the fair value of derivative instruments include forward benchmark prices, discount rates, share price, forward foreign exchange rates and forward interest rates.

Joint control

Judgment is required to determine when the Company has joint control over an arrangement, which requires an assessment of the capital and operating activities of the projects it undertakes with partners and when the decisions in relation to those activities require unanimous consent.

Share-based compensation

Compensation costs recorded pursuant to share-based compensation plans are subject to estimated fair values, forfeiture rates and the future attainment of performance criteria.

Income taxes

Tax regulations and legislation and the interpretations thereof are subject to change. In addition, deferred income tax assets and liabilities recognize the extent that temporary differences will be receivable and payable in future periods. The calculation of the asset and liability involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, expected cash flows from estimated proved plus probable reserves and the application of tax laws. Changes in tax regulations and legislation and the other assumptions listed are subject to measurement uncertainty.

3.MATERIAL ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently by the Company and its subsidiaries for all periods presented in these annual consolidated financial statements.

a)Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries and any reference to the “Company” throughout these consolidated financial statements refers to the Company and its subsidiaries. All transactions between the Company and its subsidiaries have been eliminated.

The Company conducts some of its oil and gas production activities through jointly controlled operations and the financial statements reflect only the Company's proportionate interest in such activities. Joint control exists for contractual arrangements governing the Company's assets whereby the Company has less than 100 percent working interest, all the partners have control of the arrangement collectively, and share the associated risks. The Company does not have any joint arrangements that are material to the Company or that are structured through joint venture arrangements.

b)Property, Plant and Equipment

Items of PP&E, which primarily consist of oil and gas development and production assets, are measured at cost less accumulated depletion, depreciation and any accumulated impairment losses or impairment reversals. Development and production assets are accumulated into CGUs and account for the cost of developing the commercial reserves and initiating production.

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PP&E are recognized as development and production assets only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in net income as incurred. Capitalized development and production assets generally represent costs incurred in developing reserves and initiating or enhancing production from such reserves. The carrying amount of any sold component is derecognized.

CRESCENT POINT ENERGY CORP. 10

Depletion and Depreciation

Development and production assets are depleted using the unit-of-production method based on estimated proved plus probable oil and gas reserves before royalties, as determined by independent petroleum reservoir engineers. Natural gas reserves and production are converted to equivalent barrels of oil based upon the relative energy content (6:1). The depletion base includes capitalized costs, plus future costs to be incurred in developing proved plus probable oil and gas reserves.

Corporate assets are depreciated on a straight line basis over the estimated useful lives of the related assets, ranging from 5 to 16 years.

Impairment

The carrying amounts of PP&E, which takes into account the discounted abandonment and reclamation costs on proved plus probable undeveloped oil and gas reserves, are grouped into CGUs and reviewed quarterly for indicators of impairment. Indicators are events or changes in circumstances that indicate the carrying amount may not be recoverable. If indicators of impairment exist, the recoverable amount of the CGU is estimated. If the carrying amount of the CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income.

Assets are grouped into CGUs based on the integration between assets, shared infrastructure, the existence of common sales points, geography, geological structure and the manner in which management monitors and makes decisions regarding operations. Estimates of future cash flows used in the calculation of the recoverable amount are based on reserve evaluation reports prepared by independent petroleum reservoir engineers. The recoverable amount is the higher of fair value less costs of disposal and the value-in-use. Fair value less costs of disposal is derived by estimating the discounted after-tax future net cash flows from proved plus probable oil and gas reserves. Discounted future net cash flows are based on forecasted commodity prices and costs over the expected economic life of the reserves and discounted using market-based rates to reflect a market participant’s view of the risks associated with the assets. Value-in-use is assessed using the expected future cash flows from proved plus probable oil and gas reserves discounted at a pre-tax rate. The fair value less costs of disposal and value in use estimates are categorized as Level 3 according to the IFRS 13 fair value hierarchy.

Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined, net of depletion, had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net income.

c)Exploration and Evaluation

Exploration and evaluation assets are comprised of the accumulated expenditures incurred in an area where technical feasibility and commercial viability has not yet been determined. Exploration and evaluation assets include undeveloped land and any drilling costs thereon.

Technical feasibility and commercial viability are considered to be determinable when reserves are discovered. Upon determination of reserves, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to PP&E.

Costs incurred prior to acquiring the legal rights to explore an area are expensed as incurred.

Amortization

Undeveloped land classified as E&E assets is amortized by major area over the average primary lease term and recognized in net income. Drilling costs classified as E&E assets are not amortized, but are subject to impairment.

Impairment

Exploration and evaluation assets are reviewed quarterly for indicators of impairment and upon reclassification from E&E assets to PP&E. Exploration and evaluation assets are tested for impairment at the operating segment level by combining E&E assets with PP&E. The recoverable amount is the greater of fair value less costs of disposal or value-in-use. Fair value less costs of disposal is derived by estimating the discounted after-tax future net cash flows from proved plus probable oil and gas reserves, plus the fair market value of undeveloped land. Value-in-use is assessed using the expected future cash flows from proved plus probable oil and gas reserves discounted at a pre-tax rate.

Impairments of E&E assets are reversed when there has been a subsequent increase in the recoverable amount, but only to the extent of what the carrying amount would have been, net of amortization, had no impairment been recognized.

d)Decommissioning Liability

The Company recognizes the present value of a decommissioning liability in the period in which it is incurred. The obligation is recorded as a liability on a discounted basis using the relevant risk free rate, with a corresponding increase to the carrying amount of the related asset. Over time, the liabilities are accreted for the change in their present value and the capitalized costs are depleted on a unit-of-production basis over the life of the underlying proved plus probable oil and gas reserves. Accretion expense is recognized in net income. Revisions to the discount rate, estimated timing or amount of future cash flows would also result in an increase or decrease to the decommissioning liability and related asset.

CRESCENT POINT ENERGY CORP. 11

e)Goodwill

The Company records goodwill relating to business combinations when the purchase price exceeds the fair value of the net identifiable assets and liabilities of the acquired business. The goodwill balance is assessed for impairment annually or as events occur that could result in impairment. Goodwill is tested for impairment at an operating segment level by combining the carrying amounts of PP&E, E&E assets and goodwill and comparing this to the recoverable amount. Any excess of the carrying amount over the recoverable amount is the impairment amount. The recoverable amount estimates is categorized as Level 3 according to the IFRS 13 fair value hierarchy. Impairment charges, which are not tax affected, are recognized in net income. Goodwill is reported at cost less any accumulated impairment. Goodwill impairments are not reversed.

f)Share-based Compensation

Restricted shares granted under the Restricted Share Bonus Plan are accounted for at fair value and vest on terms up to three years from the grant date determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of shares on the date of grant. Forfeitures are estimated at the grant date and recognized when they occur. The expense is recognized over the service period, with a corresponding increase to contributed surplus. The Company capitalizes the portion of share-based compensation directly attributable to development activities, with a corresponding decrease to share-based compensation expense. At the time the restricted shares vest, the issuance of shares is recorded as an increase to shareholders’ capital and a corresponding decrease to contributed surplus.

Employee Share Value Plan ("ESVP") awards are accounted for at fair value and vest on terms of up to three years from the grant date as determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of the ESVP awards on the date of grant and subsequently adjusted to reflect the fair value at each period end. The expense is recognized over the service period, with a corresponding increase to long-term compensation liability. ESVP awards are settled in cash upon vesting based on the prevailing Crescent Point share price and the aggregate amount of dividends paid from the grant date.

Performance share units ("PSUs") are accounted for at fair value and vest on terms of up to three years from the grant date as determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of the PSUs on the date of the grant and subsequently adjusted to reflect the fair value at each period end. Market performance conditions are factored into the fair value and the best estimate of non-market performance conditions is used to determine an estimate of the number of units that will vest. Fair value is based on the expected cash payment per PSU and the expected number of PSUs to vest, calculated from multipliers based on internal and external performance metrics. The expense is recognized over the service period, with a corresponding increase to long-term compensation liability. PSUs are settled in cash upon vesting based on the prevailing Crescent Point share price, performance multiplier, and factors in the aggregate amount of dividends paid over the vesting term.

Deferred share units (“DSUs”) are accounted for at fair value. Share-based compensation expense is determined based on the estimated fair value of the DSUs on the date of the grant and subsequently adjusted to reflect the fair value at each period end. Fair value is based on the prevailing Crescent Point share price.

Stock options are accounted for at fair value and have a maximum term of seven years and vest on terms as determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of the stock options on the date of the grant. Upon vesting, the stock option holder may either exercise their stock options to purchase one common share per option at the exercise price or, at the Company's discretion, surrender their stock options for a cash payment in an amount equal to the aggregate positive difference, if any, between the market price and the exercise price of the number of common shares associated with the stock options surrendered. Alternatively, the stock option holder may also, at the Company's discretion, surrender their stock options for common shares having a value equivalent to the cash payment.

g)Income Taxes

The Company follows the liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the estimated effect of any differences between the accounting and tax basis of assets and liabilities, using enacted or substantively enacted income tax rates expected to apply when the deferred tax asset or liability is settled. The effect of a change in income tax rates on deferred income taxes is recognized in net income in the period in which the change occurs.

The tax expense for the period comprises current and deferred tax. Tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity. In this case, the tax is also recognized in other comprehensive income or directly in equity, respectively.

The Company is able to deduct certain settlements under its Restricted Share Bonus Plan. To the extent the tax deduction exceeds the cumulative remuneration cost for a particular restricted share grant recorded in net income, the tax benefit related to the excess is recorded directly within equity.

A deferred tax asset is recognized to the extent that it is probable that future taxable income will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized. Deferred income tax assets and liabilities are presented as non-current.

CRESCENT POINT ENERGY CORP. 12

h)Financial Instruments

The Company uses financial derivative instruments and physical delivery commodity contracts from time to time to reduce its exposure to fluctuations in commodity prices, share price, foreign exchange rates and interest rates. The Company also makes investments in companies from time to time in connection with the Company’s acquisition and divestiture activities.

Financial derivative instruments

Financial derivative instruments are included in current assets/liabilities except for those with maturities greater than 12 months after the end of the reporting period, which are classified as non-current assets/liabilities.

The Company has not designated any of its financial derivative contracts as effective accounting hedges and, accordingly, fair values its financial derivative contracts with the resulting gains and losses recorded in net income.

The fair value of a financial derivative instrument on initial recognition is normally the transaction price. Subsequent to initial recognition, the fair values are based on quoted market prices where available from active markets, otherwise fair values are estimated based on market prices at the reporting date for similar assets or liabilities with similar terms and conditions, or by discounting future payments of interest and principal at estimated interest rates that would be available to the Company at the reporting date.

Financial assets and liabilities

Financial assets and liabilities are measured at fair value on initial recognition. For non-equity instruments, measurement in subsequent periods depends on the classification of the financial asset or liability as “fair value through profit or loss” or “amortized cost”.

Financial assets and liabilities classified as fair value through profit or loss are subsequently carried at fair value, with changes recognized in net income.

Financial assets and liabilities classified as amortized cost are subsequently carried at amortized cost using the effective interest rate method.

Currently, the Company classifies all non-equity financial instruments which are not financial derivative instruments as amortized cost.

At each reporting date, the Company assesses whether there is objective evidence that a financial asset carried at amortized cost is impaired. If such evidence exists, the Company recognizes an impairment loss in net income. Impairment losses are reversed in subsequent periods if the impairment loss decrease can be related objectively to an event occurring after the impairment was recognized.

For investments in equity instruments, the subsequent measurement is dependent on the Company’s election to classify such instruments as fair value through profit or loss or fair value through other comprehensive income. Currently, the Company classifies all investments in equity instruments as fair value through profit or loss, whereby the Company recognizes movements in the fair value of the investment (adjusted for dividends) in net income. If the fair value through other comprehensive income classification is selected, the Company would recognize any dividends from the investment in net income and would recognize fair value re-measurements of the investment in other comprehensive income.

Impairment of financial assets

Impairment losses are recognized using an expected credit loss model. The Company has adopted the simplified expected credit loss model for its accounts receivable, which permits the use of the lifetime expected loss provision.

To measure the expected credit losses, accounts receivable have been grouped based on shared credit risk characteristics and days past due. The Company uses judgment in making these assumptions and selecting the inputs into the expected loss calculation based on past history, existing market conditions and forward looking estimates at the end of each reporting period.

i)Business Combinations

Business combinations are accounted for using the acquisition method. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured at their fair values at the acquisition date. The acquisition is measured as the fair value of the acquired assets by estimating the discounted after-tax future net cash flows, the fair value of equity instruments issued and the fair value of liabilities incurred or assumed at the acquisition date. The excess of the cost of the acquisition over the fair value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of the acquisition is less than the fair value of the net assets acquired, the difference is recognized immediately in net income. Transaction costs associated with business combinations are expensed as incurred.

CRESCENT POINT ENERGY CORP. 13

j)Foreign Currency Translation

Foreign operations

The Company has operations in the U.S. transacted via U.S. subsidiaries. The assets and liabilities of foreign operations are translated to Canadian dollars at exchange rates in effect at the balance sheet date. The income and expenses of foreign operations are translated to Canadian dollars using average exchange rates for the period. The resulting unrealized gain or loss is included in other comprehensive income. The unrealized gain or loss is subsequently reclassified to profit and loss upon discontinuation of the foreign operations.

Foreign transactions

Transactions in foreign currencies not incurred by the Company’s U.S. subsidiaries are translated to Canadian dollars at exchange rates in effect at the transaction dates. Foreign currency assets and liabilities are translated to Canadian dollars at exchange rates in effect at the balance sheet date and income and expenses are translated to Canadian dollars using average exchange rates for the period. Both realized and unrealized gains and losses resulting from the settlement or restatement of foreign currency transactions are included in net income.

k)Revenue Recognition

The Company’s major revenue sources are comprised of sales from the production of crude oil and condensate, natural gas liquids ("NGLs") and natural gas. Revenue is recognized when control of the product transfers to the customer and the collection is reasonably probable, generally upon delivery of the product. Sales of crude oil and condensate, NGLs and natural gas production are based on variable pricing as the transaction prices are based on benchmark commodity prices and other variable factors, including quality differentials and location.

Each contract is 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, revenue is recognized on a gross basis. Where the Company acts as agent, revenue is recognized on a net basis.

l)Cash and Cash Equivalents

Cash and cash equivalents include short-term investments with original maturities of three months or less.

m)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. At the commencement date, the lease liability is recognized at the present value of the future lease payments and discounted using the interest rate implicit in the lease or the Company's incremental borrowing rate. A corresponding right-of-use ("ROU") asset will be recognized at the amount of the lease liability, adjusted for any lease incentives received and initial direct costs incurred. Over the term of the lease, financing expense is recognized on the lease liability using the effective interest rate method and charged to net income, lease payments are applied against the lease liability and depreciation on the ROU asset is recorded by class of underlying asset.

The lease term is the non-cancellable period of a lease and includes periods covered by an optional lease extension option if reasonably certain the Company will exercise the option to extend. Conversely, periods covered by an option to terminate are included if the Company does not expect to end the lease during that time frame. Leases with a term of less than twelve months or leases for underlying low value assets are recognized as an expense in net income on a straight-line basis over the lease term.

A lease modification will be accounted for as a separate lease if it materially changes the scope of the lease. For a modification that is not a separate lease, on the effective date of the lease modification, the Company will remeasure the lease liability and corresponding ROU asset using the interest rate implicit in the lease or the Company's incremental borrowing rate. Any variance between the remeasured ROU asset and lease liability will be recognized as a gain or loss in net income to reflect the change in scope.

The Company also acts as an intermediate lessor for office space sub-leased to other companies. As a lessor, the Company will evaluate whether a lease is a finance or operating lease. Leases where the Company transfers substantially all the risks and rewards of ownership are classified as finance leases. Conversely, leases where the risks and rewards of ownership are retained by the Company are operating leases. The head lease between the Company and the building, and the sub-lease between the Company and tenants, are accounted for separately. The lease classification of the sub-lease is based upon the head lease and not the underlying asset.

n)Earnings Per Share

Basic earnings per share (“EPS”) is calculated by dividing the net income for the period attributable to equity owners of the Company by the weighted average number of common shares outstanding during the period.

Diluted EPS is calculated by adjusting the weighted average number of common shares outstanding for dilutive instruments. The number of shares included with respect to dilutive instruments, being restricted shares issued under the Company’s Restricted Share Bonus Plan and stock options under the Company's Stock Option Plan, is computed using the treasury stock method. The treasury stock method assumes that the deemed proceeds related to unrecognized share-based compensation are used to repurchase shares at the average market price during the period.

CRESCENT POINT ENERGY CORP. 14

o)Government Grants

The Company may receive government grants which provide immediate financial assistance as compensation for costs or expenditures to be incurred. Government grants are accounted for when there is reasonable assurance that conditions attached to the grants are met and that the grants will be received. The Company recognizes government grants in net income on a systematic basis and in line with recognition of the expense that the grants are intended to compensate.

p)Assets Held for Sale

PP&E and E&E assets are classified as held for sale if it is highly probable their carrying amounts will be recovered through a capital disposition rather than through future operating cash flows. Before PP&E and E&E assets are classified as held for sale, they are assessed for indicators of impairment or reversal of previously recorded impairments and are measured at the lower of their carrying amount and fair value less costs of disposal. Any impairment charges or reversals are recognized in net income. Assets held for sale are classified as current assets and are not subject to DD&A. Decommissioning liabilities associated with assets held for sale are classified as current liabilities.

4.CHANGES IN ACCOUNTING POLICIES

Income Taxes

IAS 12 Income Taxes was amended in May 2021 by the International Accounting Standards Board which requires companies, on initial recognition, to recognize deferred tax on transactions that result in equal amounts of taxable and deductible temporary differences. The Company adopted the amendment in 2023 and the adoption did not have an impact on the Company's consolidated financial statements.

New accounting standards and amendments not yet adopted

Income Taxes

IAS 12 Income Taxes was amended in May 2023 by the International Accounting Standards Board to provide guidance on current and deferred taxes arising from Pillar Two model rules published by the Organisation for Economic Co-operation and Development. The adoption of this amendment is not expected to have an impact on the Company's consolidated financial statements.

Presentation of Financial Statements

IAS 1 Presentation of Financial Statements was amended in January 2020 by the International Accounting Standards Board to clarify the presentation requirements of liabilities as either current or non-current within the statement of financial position. This amendment is effective for fiscal years beginning on or after January 1, 2024. The adoption of this amendment is not expected to have an impact on the Company's consolidated financial statements.

5.OTHER CURRENT ASSETS

($ millions)	2023	2022
Deferred consideration receivable	79.2	—
Deposit on acquisition	—	18.7
Other current assets	79.2	18.7

At December 31, 2023, deferred consideration receivable relates to US$60.0 million deferred consideration from the disposition of the Company's North Dakota assets, which will be settled in two equal installments due June 2024 and December 2024. See Note 8 - "Capital Acquisitions and Dispositions" for additional information.

6.OTHER LONG-TERM ASSETS

At December 31, 2023, other long-term assets relates to investment tax credits of $7.2 million (December 31, 2022 - $6.4 million) and other investments of $0.2 million (December 31, 2022 - nil).

CRESCENT POINT ENERGY CORP. 15

7.EXPLORATION AND EVALUATION ASSETS

($ millions)	2023	2022
Exploration and evaluation assets at cost	1,578.6	1,453.4
Accumulated amortization	(971.6)	(1,349.2)
Net carrying amount	607.0	104.2
Reconciliation of movements during the year
Cost, beginning of year	1,453.4	1,613.3
Accumulated amortization, beginning of year	(1,349.2)	(1,564.5)
Net carrying amount, beginning of year	104.2	48.8
Net carrying amount, beginning of year	104.2	48.8
Acquisitions through business combinations	515.2	28.0
Additions	224.8	134.2
Dispositions	(1.9)	(10.9)
Transfers to property, plant and equipment	(204.3)	(80.8)
Amortization	(30.9)	(15.2)
Foreign exchange	(0.1)	0.1
Net carrying amount, end of year	607.0	104.2

Impairment test of exploration and evaluation assets

There were no indicators of impairment at December 31, 2023 or December 31, 2022.

8.CAPITAL ACQUISITIONS AND DISPOSITIONS

In the year ended December 31, 2023, the Company incurred $48.5 million (year ended December 31, 2022 - $5.1 million) of total transaction costs related to acquisitions through business combinations and dispositions. In the year ended December 31, 2023, $39.8 million (year ended December 31, 2022 - $4.6 million) related to continuing operations that were recorded as general and administrative expenses.

a) Corporate acquisition

Hammerhead Energy Inc.

On December 21, 2023, Crescent Point completed the acquisition, by way of statutory arrangement, of all issued and outstanding common shares of Hammerhead Energy Inc. ("Hammerhead"), a public oil and liquids-rich Alberta Montney producer, which was accounted for as a business combination. Total consideration was $2.04 billion, consisting of $1.54 billion in cash and the issuance of 53.2 million common shares. Long-term debt acquired of $363.8 million was repaid on December 21, 2023.

Oil and gas sales of $24.7 million and oil and gas sales less royalties, transportation and operating expenses of $14.8 million are attributable to the Hammerhead acquisition from the date of acquisition to December 31, 2023. Had the acquisition occurred on January 1, 2023, estimated oil and gas sales of $833.3 million and oil and gas sales less royalties, transportation and operating expenses of $527.6 million would have been recognized for the period ended December 31, 2023. This pro-forma information is not necessarily indicative of the results should the acquisition have actually occurred on January 1, 2023.

b) Major property acquisitions and dispositions

Kaybob Duvernay acquisition

On January 11, 2023, the Company closed the acquisition of certain Kaybob Duvernay assets in Alberta for total consideration of $370.4 million, which was accounted for as a business combination.

Oil and gas sales of $56.4 million and oil and gas sales less royalties, transportation and operating expenses of $37.0 million are attributable to the Kaybob Duvernay acquisition from the date of acquisition to December 31, 2023. Had the acquisition occurred on January 1, 2023, estimated oil and gas sales of $58.8 million and oil and gas sales less royalties, transportation and operating expenses of $38.7 million would have been recognized for the period ended December 31, 2023. This pro-forma information is not necessarily indicative of the results should the acquisition have actually occurred on January 1, 2023.

CRESCENT POINT ENERGY CORP. 16

Alberta Montney acquisition

On May 10, 2023, the Company closed the acquisition of Montney assets in Alberta for total consideration of $1.70 billion, which was accounted for as a business combination.

Oil and gas sales of $505.1 million and oil and gas sales less royalties, transportation and operating expenses of $329.4 million are attributable to the Alberta Montney acquisition from the date of acquisition to December 31, 2023. Had the acquisition occurred on January 1, 2023, estimated oil and gas sales of $755.7 million and oil and gas sales less royalties, transportation and operating expenses of $512.6 million would have been recognized for the period ended December 31, 2023. This pro-forma information is not necessarily indicative of the results should the acquisition have actually occurred on January 1, 2023.

North Dakota disposition

On October 24, 2023, the Company completed the disposition of its producing North Dakota assets for total consideration of $585.8 million, including interim closing adjustments and working capital items. Total consideration consisted of $504.6 million (US$372.7 million) in cash and $81.2 million (US$60.0 million) in deferred consideration receivable. See Note 5 - "Other Current Assets" and Note 9 - "Discontinued Operations" for additional information.

c) Minor property acquisitions and dispositions

In the year ended December 31, 2023, the Company completed minor property acquisitions and dispositions for net consideration received of $17.3 million. These assets had a net carrying value of $17.2 million, resulting in a gain of $0.1 million.

The following table summarizes the Company's capital acquisitions and dispositions:

($ millions)	Hammerhead Acquisition (1) (2)	Kaybob Duvernay Acquisition	Alberta Montney Acquisition	North Dakota Disposition (3) (4)	Other minor dispositions, net
Cash	(1,544.0)	(370.4)	(1,700.4)	504.6	17.3
Common shares	(493.0)	—	—	—	—
Deferred consideration receivable	—	—	—	81.2	—
Consideration (paid) received	(2,037.0)	(370.4)	(1,700.4)	585.8	17.3
Working capital	(116.7)	—	—	9.1	—
Derivative asset	12.3	—	—	—	—
Other long-term assets	—	—	0.1	—	—
Exploration and evaluation	354.8	52.1	108.3	(1.8)	(0.1)
Property, plant and equipment	2,406.6	323.7	1,616.6	(635.2)	(20.8)
Right-of-use asset	4.3	—	—	(1.0)	—
Goodwill	72.6	—	—	—	(0.6)
Long-term debt	(363.8)	—	—	—	—
Decommissioning liability	(9.9)	(5.4)	(24.6)	13.7	4.3
Derivative liability	(0.3)	—	—	19.0	—
Lease liability	(4.3)	—	—	1.1	—
Deferred income tax liability	(318.6)	—	—	—	—
Fair value of net assets acquired (Carrying value of net assets disposed)	2,037.0	370.4	1,700.4	(595.1)	(17.2)
Gain (loss) on capital dispositions	—	—	—	(9.3)	0.1

(1)Total net assets acquired excludes $696.6 million of commitments relating to transportation, $156.7 million related to gas processing and $4.8 million related to operating.

(2)Working capital includes $115.4 million of accounts receivable, $7.6 million of prepaids and deposits, and $239.7 million of accounts payable and accrued liabilities.

(3)Working capital includes $9.1 million of accounts payable and accrued liabilities.

(4)See Note 5 - "Other Current Assets" for additional information on deferred consideration receivable.

CRESCENT POINT ENERGY CORP. 17

d) Assets held for sale

At December 31, 2023, certain non-core assets in the Company's Alberta CGU remain held for sale. Upon classification, assets held for sale were recorded at the lesser of their carrying value and recoverable amount. The Company completed the disposition of its Southern Alberta assets in January 2024. See Note 33 - "Subsequent Events" for additional information.

($ millions)	2023	2022
Assets held for sale - PP&E	247.1	148.4
Liabilities held for sale - Decommissioning liability	(132.4)	(28.4)

For additional information on the Company's assets and liabilities held for sale see Note 10 - "Property, Plant and Equipment" and Note 16 - "Decommissioning Liability", respectively.

9.DISCONTINUED OPERATIONS

On October 24, 2023, the Company completed the disposition of the assets in its Northern U.S. CGU. The Northern U.S. CGU represents a geographical area of the Company's operations, therefore, its results have been classified as a discontinued operation in accordance with IFRS 5 Non-current Assets Held for Sale and Discontinued Operations. See Note 8 - "Capital Acquisitions and Dispositions" for additional information. Upon disposition of the Company's U.S. operations, the cumulative foreign currency translation recognized in accumulated other comprehensive income was reclassified from shareholders' equity to profit or loss. As a result, the Company recognized a foreign exchange gain of $621.7 million in the year ended December 31, 2023.

In the year ended December 31, 2023, the Company derecognized its U.S. tax pools as a result of the completed North Dakota asset sale.

a) Results from discontinued operations

The following table summarizes the Company's financial results from discontinued operations:

For the years ended December 31
(Cdn$ millions)	2023	2022
REVENUE AND OTHER INCOME
Oil and gas sales	612.9	646.1
Royalties	(155.9)	(165.4)
Oil and gas revenue	457.0	480.7
Commodity derivative losses	(23.4)	—
Other loss	(2.2)	(0.2)
	431.4	480.5
EXPENSES
Operating	80.0	84.9
Transportation	12.2	8.8
General and administrative	12.7	3.4
Foreign exchange gain	(621.7)	—
Share-based compensation	(0.4)	0.3
Depletion, depreciation and amortization	170.3	144.5
Impairment (impairment reversal)	728.4	(71.3)
Accretion and financing	0.4	0.4
	381.9	171.0
Net income before tax from discontinued operations	49.5	309.5
Tax expense (recovery)
Current	—	—
Deferred	278.6	(27.2)
Net income (loss) from discontinued operations	(229.1)	336.7

CRESCENT POINT ENERGY CORP. 18

b) Cash flows from discontinued operations

The following table summarizes cash flows from discontinued operations reported in the consolidated statements of cash flows:

For the years ended December 31
(Cdn$ millions)	2023	2022
Cash provided by (used in) discontinued operations
Operating activities	399.0	363.5
Investing activities	177.3	(252.3)
Increase in cash from discontinued operations	576.3	111.2

CRESCENT POINT ENERGY CORP. 19

10.PROPERTY, PLANT AND EQUIPMENT

($ millions)	2023	2022
Development and production assets	24,580.6	22,340.0
Corporate assets	132.1	126.2
Property, plant and equipment at cost	24,712.7	22,466.2
Accumulated depletion, depreciation and impairment	(13,994.4)	(14,736.8)
Net carrying amount	10,718.3	7,729.4
Reconciliation of movements during the year
Development and production assets
Cost, beginning of year	22,340.0	23,402.9
Accumulated depletion and impairment, beginning of year	(14,651.8)	(15,762.6)
Net carrying amount, beginning of year	7,688.2	7,640.3
Net carrying amount, beginning of year	7,688.2	7,640.3
Acquisitions through business combinations	4,348.6	66.0
Additions	1,025.8	741.9
Dispositions	(657.7)	(285.8)
Transfers from exploration and evaluation assets	204.3	80.8
Reclassified as assets held for sale	(98.7)	(148.4)
Depletion	(1,009.3)	(911.4)
Impairment reversal (impairment)	(822.2)	428.6
Foreign exchange	0.2	76.2
Net carrying amount, end of year	10,679.2	7,688.2
Cost, end of year	24,580.6	22,340.0
Accumulated depletion and impairment, end of year	(13,901.4)	(14,651.8)
Net carrying amount, end of year	10,679.2	7,688.2
Corporate assets
Cost, beginning of year	126.2	123.2
Accumulated depreciation, beginning of year	(85.0)	(76.2)
Net carrying amount, beginning of year	41.2	47.0
Net carrying amount, beginning of year	41.2	47.0
Additions	5.9	2.6
Depreciation	(8.0)	(8.5)
Foreign exchange	—	0.1
Net carrying amount, end of year	39.1	41.2
Cost, end of year	132.1	126.2
Accumulated depreciation, end of year	(93.0)	(85.0)
Net carrying amount, end of year	39.1	41.2

At December 31, 2023, future development costs of $9.08 billion (December 31, 2022 - $5.16 billion) were included in costs subject to depletion.

Direct general and administrative costs capitalized by the Company during the year ended December 31, 2023 were $42.4 million (year ended December 31, 2022 - $49.7 million), including $5.7 million of share-based compensation costs (year ended December 31, 2022 - $14.7 million).

CRESCENT POINT ENERGY CORP. 20

Impairment test of property, plant and equipment

The following table summarizes the total impairment (impairment reversal) on the consolidated statements of comprehensive income:

($ millions)	2023	2022 (1)
Impairment reversal	—	(1,469.6)
Impairment	—	985.0
Impairment on assets held for sale	93.8	127.3
Impairment (impairment reversal)	93.8	(357.3)

(1)Comparative period revised to reflect current period presentation.

Assets Held for Sale

At December 31, 2022, the Company classified certain non-core assets in its Alberta CGU as held for sale. Immediately prior to classifying the assets as held for sale, the Company conducted a review of the assets' recoverable amounts and recorded an impairment loss of $71.3 million on PP&E as a component of net impairment reversal in 2022. At December 31, 2023, these assets remained as held for sale. An additional impairment loss of $42.2 million was recorded in the fourth quarter of 2023. The recoverable amount was determined based on the assets' fair value less costs of disposal and based on expected consideration.

At September 30, 2023, the Company classified additional non-core assets in its Alberta CGU as assets held for sale. Immediately prior to classifying the assets as held for sale, the Company conducted a review of the assets' recoverable amounts and recorded an impairment loss of $45.4 million on PP&E. An additional impairment loss of $6.2 million related to these assets was recorded in the fourth quarter of 2023. The recoverable amount was determined based on the assets' fair value less costs of disposal and based on expected consideration. The assets were sold in January 2024. See Note 33 - "Subsequent Events" for additional information.

Q4 2023 Impairment Assessment

At December 31, 2023, there were no indicators of impairment or impairment reversal.

Q4 2022 Impairment

At December 31, 2022, there were no indicators of impairment or impairment reversal in the Alberta and Northern U.S. CGUs.

At December 31, 2022, the Company identified indicators that its Southeast Saskatchewan and Southwest Saskatchewan CGUs might be impaired. Increases in forecast costs and the reallocation of forecast capital spending from Saskatchewan to other CGUs were considered indicators of impairment. As a result, a test for impairment was conducted and the Company prepared estimates of future cash flows to determine the recoverable amount of the respective assets.

The following table outlines the forecast benchmark commodity prices and the exchange rate used in the impairment calculation of PP&E at December 31, 2022:

	2023 (1)	2024	2025	2026	2027	2028	2029	2030	2031	2032	2033 (3)
WTI ($US/bbl) (2)	80.33	78.50	76.95	77.61	79.16	80.74	82.36	84.00	85.69	87.40	89.15
Exchange Rate ($US/$Cdn)	0.745	0.765	0.768	0.772	0.775	0.775	0.775	0.775	0.775	0.775	0.775
WTI ($Cdn/bbl)	107.83	102.61	100.20	100.53	102.14	104.18	106.27	108.39	110.57	112.77	115.03
AECO ($Cdn/mmbtu) (2)	4.23	4.40	4.21	4.27	4.34	4.43	4.51	4.60	4.69	4.79	4.88

(1)Effective January 1, 2023.

(2)The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, distance to market and other factors in performing the impairment tests.

(3)Forecast benchmark commodity prices are assumed to increase by 2.0% in each year after 2033 to the end of the reserve life. Exchange rates are assumed to be constant at 0.775.

The following table summarizes the impairment expense for the year ended December 31, 2022 by CGU:

CGU ($ millions, except %)	Operating segment	Recoverable amount	Discount rate		Impairment	Impairment,  net of tax
Southeast Saskatchewan	Canada	2,868.3	15.00	%	564.5	424.4
Southwest Saskatchewan	Canada	1,356.6	15.00	%	420.5	316.1
Total impairment		4,224.9			985.0	740.5

CRESCENT POINT ENERGY CORP. 21

The following sensitivities show the resulting impact on income before tax of the changes in discount rate, forecast benchmark commodity price estimates and forecast operating cost estimates at December 31, 2022, with all other variables held constant:

CGU	Discount Rate		Commodity Prices		Operating Costs
($ millions)	Increase 1%	Decrease 1%	Increase 5%	Decrease 5%	Increase 5%	Decrease 5%
Southeast Saskatchewan	(167.8)	185.2	349.4	(348.3)	(117.7)	118.7
Southwest Saskatchewan	(88.0)	97.3	185.6	(185.3)	(64.8)	65.0
Increase (decrease)	(255.8)	282.5	535.0	(533.6)	(182.5)	183.7

Q1 2022 Impairment Reversal

At March 31, 2022, the significant increase in forecast benchmark commodity prices and the increase in the Company's market capitalization since the last impairment test at June 30, 2021, were indicators of impairment reversal.

The following table outlines the forecast benchmark commodity prices and the exchange rate used in the impairment calculation of PP&E at March 31, 2022:

	2022 (1)	2023	2024	2025	2026	2027	2028	2029	2030	2031	2032 (3)
WTI ($US/bbl) (2)	94.17	84.05	75.38	74.41	75.90	77.42	78.97	80.55	82.16	83.80	85.48
Exchange Rate ($US/$Cdn)	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800
WTI ($Cdn/bbl)	117.71	105.06	94.23	93.01	94.88	96.78	98.71	100.69	102.70	104.75	106.85
AECO ($Cdn/mmbtu) (2)	5.18	4.18	3.38	3.34	3.41	3.48	3.54	3.61	3.69	3.76	3.84

(1)Effective April 1, 2022.

(2)The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, distance to market and other factors in performing the impairment tests.

(3)Forecast benchmark commodity prices are assumed to increase by 2.0% in each year after 2032 to the end of the reserve life. Exchange rates are assumed to be constant at 0.800.

The following table summarizes the impairment reversal for the three months ended March 31, 2022 by CGU:

CGU ($ millions, except %)	Operating segment	Recoverable amount	Discount rate		Impairment reversal	Impairment reversal, net of tax
Southeast Saskatchewan	Canada	3,413.8	15.00	%	806.0	605.3
Southwest Saskatchewan	Canada	1,715.0	15.00	%	419.4	315.0
Alberta	Canada	2,567.1	15.00	%	244.2	183.4
Total impairment reversal		7,695.9			1,469.6	1,103.7

The following sensitivities show the resulting impact on income before tax of the changes in discount rate and forecast benchmark commodity price estimates at March 31, 2022, with all other variables held constant:

CGU	Discount Rate		Commodity Prices
($ millions)	Increase 1%	Decrease 1%	Increase 5%	Decrease 5%
Southeast Saskatchewan	(186.2)	204.8	367.6	(366.6)
Southwest Saskatchewan	(95.0)	104.6	201.1	(201.1)
Alberta	—	—	—	—
Increase (decrease)	(281.2)	309.4	568.7	(567.7)

11.GOODWILL

($ millions)	2023	2022
Goodwill, beginning of year	203.9	211.5
Hammerhead acquisition	72.6	—
Saskatchewan Viking asset disposition	—	(6.8)
Other dispositions	(0.6)	(0.8)
Goodwill, end of year	275.9	203.9

In the year ended December 31, 2023, the Company recognized $72.6 million of goodwill associated with the Hammerhead acquisition, primarily due to the deferred tax liability. See Note 8 - "Capital Acquisitions and Dispositions" for additional information. Goodwill has been assigned to the Canadian operating segment.

CRESCENT POINT ENERGY CORP. 22

Impairment test of goodwill

The impairment tests of goodwill compared the recoverable amount of the Company's PP&E and E&E to the carrying amount of the combined PP&E, E&E and goodwill at December 31, 2023 and December 31, 2022. The recoverable amount of the Company's PP&E and E&E was estimated using independent reserve evaluator forecast benchmark commodity prices, proved plus probable oil and gas reserve estimates and management's estimate of the fair market value of undeveloped land. As a result of these tests, the Company concluded that the estimated recoverable amounts exceeded the carrying amounts and no impairments were recorded.

The following table outlines the forecast benchmark commodity prices and the exchange rate used in the impairment calculation of goodwill at December 31, 2023:

	2024 (1)	2025	2026	2027	2028	2029	2030	2031	2032	2033	2034 (3)
WTI ($US/bbl) (2)	73.67	74.98	76.14	77.66	79.22	80.80	82.42	84.06	85.74	87.46	89.21
Exchange Rate ($US/$Cdn)	0.752	0.752	0.755	0.755	0.755	0.755	0.755	0.755	0.755	0.755	0.755
WTI ($Cdn/bbl)	97.97	99.71	100.85	102.86	104.93	107.02	109.17	111.34	113.56	115.84	118.16
AECO ($Cdn/mmbtu) (2)	2.20	3.37	4.05	4.13	4.21	4.30	4.38	4.47	4.56	4.65	4.74

(1)Effective January 1, 2024.

(2)The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, distance to market and other factors in performing the impairment tests.

(3)Forecast benchmark commodity prices are assumed to increase by 2.0% in each year after 2034 to the end of the reserve life. Exchange rates are assumed to be constant at 0.755.

12.OTHER CURRENT LIABILITIES

($ millions)	2023	2022
Long-term compensation liability	37.5	49.1
Lease liability	40.5	24.9
Decommissioning liability	40.0	41.6
Other current liabilities	118.0	115.6

13.LONG-TERM DEBT

($ millions)	2023	2022
Revolving bank debt	1,932.9	—
Bank term loan	750.0	—
Senior guaranteed notes	883.4	1,441.5
Long-term debt	3,566.3	1,441.5
Long-term debt due within one year	380.0	538.7
Long-term debt due beyond one year	3,186.3	902.8

Bank debt

Revolving bank debt

At December 31, 2023, the Company had combined facilities of $2.76 billion. This includes a $2.26 billion syndicated unsecured credit facility with eleven banks and a $100.0 million unsecured operating credit facility with one Canadian chartered bank, both with a current maturity date of November 26, 2026. Both of these facilities constitute revolving credit facilities and are extendible annually. On May 10, 2023, concurrent with the closing of the Alberta Montney acquisition, Crescent Point entered into an additional $400.0 million syndicated unsecured revolving credit facility with ten banks that matures on May 10, 2025.

The credit facilities have covenants which restrict the Company's ratio of senior debt to adjusted EBITDA to a maximum of 3.5:1.0, the ratio of total debt to adjusted EBITDA to a maximum of 4.0:1.0 and the ratio of senior debt to capital, adjusted for certain non-cash items as noted above, to a maximum of 0.55:1.0. The Company was in compliance with all debt covenants at December 31, 2023.

The Company had letters of credit in the amount of $26.2 million outstanding at December 31, 2023 (December 31, 2022 - $1.8 million).

Bank term loan

On December 21, 2023, concurrent with the closing of the Hammerhead acquisition, the Company entered into a $750.0 million syndicated term loan with twelve banks that matures on November 26, 2026.

The term loan has financial covenants similar to those of the combined credit facilities described above.

CRESCENT POINT ENERGY CORP. 23

Senior guaranteed notes

At December 31, 2023, the Company had senior guaranteed notes of US$589.5 million and Cdn$105.0 million outstanding. The notes are unsecured and rank pari passu with the Company's bank credit facilities and carry a bullet repayment on maturity. The senior guaranteed notes have financial covenants similar to those of the combined credit facilities described above.

Concurrent with the issuance of senior guaranteed notes with total principal of US$517.0 million, the Company entered into cross currency swaps ("CCS") to manage the Company's foreign exchange risk. The CCS fix the US dollar amount of the individual tranches of notes for purposes of interest and principal repayments at a notional amount of $606.9 million. See Note 27 - "Financial Instruments and Derivatives" for additional information.

The following table summarizes the Company's senior guaranteed notes:

Principal ($ millions)	Coupon Rate		Hedged Principal (1) (Cdn$ millions)	Unhedged  Principal (2) (Cdn$ millions)	Interest Payment Dates	Maturity Date	Financial statement carrying value
							2023	2022
US$61.5	4.12	%	—	—	October 11 and April 11	April 11, 2023	—	83.2
Cdn$80.0	3.58	%	—	—	October 11 and April 11	April 11, 2023	—	80.0
Cdn$10.0	4.11	%	—	—	December 12 and June 12	June 12, 2023	—	10.0
US$270.0	3.78	%	—	—	December 12 and June 12	June 12, 2023	—	365.5
Cdn$40.0	3.85	%	40.0	—	December 20 and June 20	June 20, 2024	40.0	40.0
US$257.5	3.75	%	276.4	—	December 20 and June 20	June 20, 2024	340.0	348.5
US$82.0	4.30	%	67.9	39.6	October 11 and April 11	April 11, 2025	108.3	111.0
Cdn$65.0	3.94	%	65.0	—	October 22 and April 22	April 22, 2025	65.0	65.0
US$230.0	4.08	%	262.6	29.7	October 22 and April 22	April 22, 2025	303.7	311.3
US$20.0	4.18	%	—	26.4	October 22 and April 22	April 22, 2027	26.4	27.0
Senior guaranteed notes			711.9	95.7			883.4	1,441.5
Due within one year			316.4	—			380.0	538.7
Due beyond one year			395.5	95.7			503.4	902.8

(1)Includes underlying derivatives which fix the Company's foreign exchange exposure on its US dollar senior guaranteed notes or represents the Canadian dollar principal on Canadian dollar denominated senior guaranteed notes.

(2)Includes the principal balance translated at the period end foreign exchange rate on US dollar senior guaranteed notes that do not have underlying CCS.

14.LEASES

Right-of-use asset

($ millions)	Office (1)	Fleet Vehicles	Equipment	Total
Right-of-use asset at cost	124.8	37.2	38.6	200.6
Accumulated depreciation	(65.1)	(23.0)	(9.7)	(97.8)
Net carrying amount	59.7	14.2	28.9	102.8
Reconciliation of movements during the year
Cost, beginning of year	121.9	28.5	11.1	161.5
Accumulated depreciation, beginning of year	(55.4)	(20.4)	(7.6)	(83.4)
Net carrying amount, beginning of year	66.5	8.1	3.5	78.1
Net carrying amount, beginning of year	66.5	8.1	3.5	78.1
Acquisitions through business combinations	3.0	0.6	0.7	4.3
Additions	0.8	10.6	26.8	38.2
Dispositions	(0.1)	(0.9)	—	(1.0)
Depreciation	(10.5)	(4.2)	(2.1)	(16.8)
Net carrying amount, end of year	59.7	14.2	28.9	102.8

(1)A portion of the Company's office space is subleased. During the year ended December 31, 2023, the Company recorded sublease income of $3.7 million (year ended December 31, 2022 - $3.6 million) as a component of other income.

CRESCENT POINT ENERGY CORP. 24

Lease liability

($ millions)	2023	2022
Lease liability, beginning of year	124.1	141.4
Acquisitions through business combinations	4.3	—
Additions	38.2	3.8
Dispositions	(1.1)	—
Financing	5.2	5.7
Payments on lease liability	(26.0)	(26.1)
Other	—	(0.7)
Lease liability, end of year	144.7	124.1
Expected to be incurred within one year	40.5	24.9
Expected to be incurred beyond one year	104.2	99.2

Some leases contain variable payments that are not included within the lease liability as the payments are based on amounts determined by the lessor annually and not dependent on an index or rate. For the year ended December 31, 2023, variable lease payments of $1.7 million were included in general and administrative expenses relating to property tax payments on office leases (year ended December 31, 2022 - $1.5 million).

During the year ended December 31, 2023, the Company recorded $0.8 million in payments related to short-term leases and leases for low dollar value underlying assets in operating and general and administrative expenses (year ended December 31, 2022 - $0.8 million).

The undiscounted cash flows relating to the lease liability are as follows:

($ millions)	December 31, 2023
1 year	41.8
2 to 3 years	59.6
4 to 5 years	35.5
More than 5 years	25.2
Total (1)	162.1

(1)Includes both the principal and amounts representing interest.

15.OTHER LONG-TERM LIABILITIES

At December 31, 2023, the Company had a long-term compensation liability of $31.0 million (December 31, 2022 - $40.8 million) related to share-based compensation. See Note 25 - "Share-based Compensation" for additional information.

CRESCENT POINT ENERGY CORP. 25

16.DECOMMISSIONING LIABILITY

($ millions)	2023	2022
Decommissioning liability, beginning of year	675.5	918.8
Liabilities incurred	19.8	21.6
Liabilities acquired through capital acquisitions	40.1	3.4
Liabilities disposed through capital dispositions	(18.2)	(46.7)
Liabilities settled (1)	(45.4)	(43.1)
Revaluation of acquired decommissioning liabilities (2)	38.5	3.8
Change in estimates	(3.0)	(11.4)
Change in discount and inflation rate estimates	(19.6)	(163.0)
Accretion	22.7	19.2
Reclassified as liabilities associated with assets held for sale	(104.0)	(28.4)
Foreign exchange	—	1.3
Decommissioning liability, end of year	606.4	675.5
Expected to be incurred within one year	40.0	41.6
Expected to be incurred beyond one year	566.4	633.9

(1)Includes $5.4 million received from government grant programs during the year ended December 31, 2023 (year ended December 31, 2022 - $23.0 million).

(2)These amounts relate to the revaluation of acquired decommissioning liabilities at the end of the period using a risk-free discount rate. At the date of acquisition, acquired decommissioning liabilities are fair valued.

Upon retirement of its oil and gas assets, the Company anticipates incurring substantial costs associated with decommissioning. The total future decommissioning liability was estimated by management based on the Company’s net ownership in all wells and facilities. This includes all estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. The Company has estimated the net present value of its total decommissioning liability to be $606.4 million at December 31, 2023 (December 31, 2022 - $675.5 million) based on total estimated undiscounted and uninflated cash flows to settle the obligation of $847.7 million (December 31, 2022 - $894.9 million). These obligations are expected to be settled through 2073, with the majority expected after 2050. The estimated cash flows have been discounted using a risk-free rate of 3.02 percent and a derived inflation rate of 1.62 percent (December 31, 2022 - risk-free rate of 3.28 percent and inflation rate of 2.09 percent).

17.SHAREHOLDERS' CAPITAL

Crescent Point has an unlimited number of common shares authorized for issuance.

	2023		2022
	Number of shares	Amount ($ millions)	Number of shares	Amount ($ millions)
Common shares, beginning of year	550,888,983	16,675.8	579,484,032	16,963.4
Issued on capital acquisition	53,202,339	493.0	—	—
Issued for cash	48,550,000	500.1	—	—
Issued on redemption of restricted shares	1,436,017	4.9	1,713,730	5.2
Issued on exercise of stock options	464,051	0.7	1,038,321	1.4
Common shares repurchased for cancellation	(34,611,900)	(349.9)	(31,347,100)	(294.2)
Common shares, end of year	619,929,490	17,324.6	550,888,983	16,675.8
Cumulative share issue costs, net of tax	—	(271.9)	—	(256.5)
Total shareholders’ capital, end of year	619,929,490	17,052.7	550,888,983	16,419.3

Normal Course Issuer Bids ("NCIBs")    

On March 7, 2023, the Company announced the approval by the Toronto Stock Exchange of its notice to implement a NCIB. The NCIB allows the Company to purchase, for cancellation, up to 54,605,659 common shares, or 10 percent of the Company's public float, as at February 23, 2023. The NCIB commenced on March 9, 2023 and is due to expire on March 8, 2024. The Company's previous NCIB commenced on March 9, 2022 and expired on March 8, 2023.

During the year ended December 31, 2023, the Company purchased 34.6 million common shares for total consideration of $349.9 million under its NCIBs. The total cost paid, including commissions and fees, was recognized directly as a reduction in shareholders' equity. Under the NCIB, all common shares purchased are cancelled.

CRESCENT POINT ENERGY CORP. 26

18.DEFICIT

($ millions)	2023	2022
Accumulated earnings (deficit)	(2,130.3)	(2,700.6)
Accumulated gain on shares issued pursuant to DRIP (1) and SDP (2)	8.4	8.4
Accumulated tax effect on redemption of restricted shares	18.2	15.8
Accumulated dividends	(8,098.8)	(7,886.9)
Deficit	(10,202.5)	(10,563.3)

(1)Premium Dividend TM and Dividend Reinvestment Plan – suspended in 2015.

(2)Share Dividend Plan – suspended in 2015.

19.CAPITAL MANAGEMENT

($ millions)	2023	2022
Long-term debt (1)	3,566.3	1,441.5
Adjusted working capital (surplus) deficiency (2)	196.3	(95.1)
Unrealized foreign exchange on translation of hedged US dollar long-term debt	(24.5)	(191.7)
Net debt	3,738.1	1,154.7
Shareholders’ equity	6,867.5	6,493.4
Total capitalization	10,605.6	7,648.1

(1)Includes current portion of long-term debt.

(2)Adjusted working capital (surplus) deficiency is calculated as accounts payable and accrued liabilities, dividends payable and long-term compensation liability net of equity derivative contracts, less cash, accounts receivable, prepaids and deposits, and other current assets.

The following table reconciles cash flow from operating activities to adjusted funds flow from operations for the year ended December 31, 2023 and December 31, 2022:

($ millions)	2023	2022
Cash flow from operating activities	2,195.7	2,192.2
Changes in non-cash working capital	54.9	15.0
Transaction costs	48.5	5.1
Decommissioning expenditures	40.0	20.1
Adjusted funds flow from operations	2,339.1	2,232.4

Crescent Point's objective for managing its capital structure is to maintain a strong balance sheet and capital base to provide financial flexibility, position the Company to fund future development projects and provide returns to shareholders.

Crescent Point manages its capital structure and short-term financing requirements using a measure not defined in IFRS Accounting Standards, or standardized, the ratio of net debt to adjusted funds flow from operations. Net debt to adjusted funds flow from operations is used to measure the Company's overall debt position and to measure the strength of the Company's balance sheet and might not be comparable to similar financial measures disclosed by other issuers. Crescent Point's objective is to manage this metric to be well positioned to execute its business objectives during periods of volatile commodity prices. Crescent Point monitors this ratio and uses it as a key measure in capital allocation decisions including capital spending levels, returns to shareholders including dividends and share repurchases, and financing considerations. The Company's net debt to adjusted funds flow from operations ratio for the trailing four quarters at December 31, 2023 was 1.6 times (December 31, 2022 - 0.5 times).

Crescent Point is subject to certain financial covenants on its credit facilities and senior guaranteed notes agreements and was in compliance with all financial covenants as at December 31, 2023. See Note 13 - "Long-term Debt" for additional information regarding the Company's financial covenant requirements.

Crescent Point retains financial flexibility with liquidity on its credit facilities. The Company continuously monitors the commodity price environment and manages its counterparty exposure to mitigate credit losses and protect its balance sheet.

20.COMMODITY DERIVATIVE GAINS (LOSSES)

($ millions)	2023	2022
Realized gains (losses)	15.5	(641.8)
Unrealized gains	148.3	168.4
Commodity derivative gains (losses)	163.8	(473.4)

CRESCENT POINT ENERGY CORP. 27

21.OTHER INCOME

($ millions)	2023	2022 (1)
Gain (loss) on capital dispositions	(0.7)	26.1
Government grant for decommissioning expenditures	5.4	23.0
Sublease income	3.7	3.6
Other	5.0	6.3
Other income	13.4	59.0

(1)Comparative period revised to reflect current period presentation.

22.INTEREST EXPENSE

($ millions)	2023	2022
Interest expense on long-term debt	126.0	64.7
Unrealized (gain) loss on interest derivative contracts	3.4	(1.1)
Interest expense	129.4	63.6

23.FOREIGN EXCHANGE GAIN (LOSS)

($ millions)	2023	2022
Realized gain on CCS - principal	151.8	63.8
Translation of US dollar long-term debt	16.8	(94.3)
Unrealized gain (loss) on CCS - principal and foreign exchange swaps	(153.6)	4.4
Other	(5.0)	7.3
Foreign exchange gain (loss)	10.0	(18.8)

24.INCOME TAXES

The provision for income taxes is as follows:

($ millions)		2023	2022 (1)
Current tax:
	Canada	(0.7)	—
Current tax recovery		(0.7)	—
Deferred tax expense:
	Canada	254.4	415.1
Deferred tax expense		254.4	415.1
Income tax expense		253.7	415.1

(1)Comparative period revised to reflect current period presentation.

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:

($ millions, except percentages)	2023		2022 (1)
Net income before tax from continuing operations	1,053.1		1,561.8
Statutory income tax rate	24.58	%	24.82	%
Expected provision for income taxes	258.9		387.6
Change in corporate tax rates and tax rate variance	(5.6)		1.6
Derecognition (recognition) of deferred tax assets	0.5		(0.7)
Non-deductible capital losses (non-taxable capital gains)	0.1		(0.2)
Non-deductible disposition of goodwill	0.1		1.9
Other (2)	(0.3)		24.9
Income tax expense	253.7		415.1

(1)Comparative period revised to reflect current period presentation.

(2)For the year ended December 31, 2022, there is an expense deducted in a foreign jurisdiction for which a tax benefit is not recognized.

CRESCENT POINT ENERGY CORP. 28

The composition of net deferred income tax asset (liability) is as follows:

($ millions)	2023	2022
Deferred income tax assets	—	278.8
Deferred income tax liabilities	(643.0)	(77.3)
Net deferred income tax asset (liability)	(643.0)	201.5

The net deferred income tax assets (liabilities) are expected to be settled in the following periods:

($ millions)	2023	2022
Deferred income tax:
To be settled within one year	(1.7)	19.6
To be settled beyond one year	(641.3)	181.9
Deferred income tax	(643.0)	201.5

The movement in deferred income tax assets (liabilities) are as follows:

($ millions)	At January 1, 2023	(Charges) / credits due to acquisitions, discontinued operations & other	(Charged) / credited to earnings	At December 31, 2023
Deferred income tax assets:
Decommissioning liability	167.4	(1.6)	(19.2)	146.6
Income tax losses carried forward	744.6	(348.2)	(80.6)	315.8
Risk management contracts	2.1	—	11.3	13.4
Lease liabilities	30.7	0.6	3.7	35.0
Other	29.9	6.8	16.5	53.2
	974.7	(342.4)	(68.3)	564.0
Deferred income tax liabilities:
Property, plant and equipment	(743.1)	(244.2)	(139.9)	(1,127.2)
Risk management contracts	(10.8)	(2.9)	(41.3)	(55.0)
ROU asset	(19.3)	(0.6)	(4.9)	(24.8)
	(773.2)	(247.7)	(186.1)	(1,207.0)
Net deferred income tax assets (liabilities)	201.5	(590.1)	(254.4)	(643.0)

($ millions)	At January 1, 2022	Credits due to acquisitions & other	(Charged) / credited to earnings	At December 31, 2022
Deferred income tax assets:
Decommissioning liability	229.6	—	(62.2)	167.4
Income tax losses carried forward	814.2	—	(69.6)	744.6
Risk management contracts	41.1	—	(39.0)	2.1
Lease liabilities	35.3	—	(4.6)	30.7
Other	19.5	19.3	(8.9)	29.9
	1,139.7	19.3	(184.3)	974.7
Deferred income tax liabilities:
Property, plant and equipment	(533.4)	—	(209.7)	(743.1)
Risk management contracts	(13.4)	—	2.6	(10.8)
ROU asset	(22.8)	—	3.5	(19.3)
	(569.6)	—	(203.6)	(773.2)
Net deferred income tax assets (liabilities)	570.1	19.3	(387.9)	201.5

CRESCENT POINT ENERGY CORP. 29

The approximate amounts of tax pools available as at December 31, 2023 and 2022 are as follows:

($ millions)	2023	2022
Tax pools:
Canada	8,281.0	5,685.8
United States	2,319.7	3,025.2
Total	10,600.7	8,711.0

Deferred tax assets are recognized to the extent of expected utilization of tax attributes, based on estimated undiscounted future cash flows included in the Company's independent reserve report.

The above tax pools include estimated Canadian non-capital losses carried forward of $1.31 billion (December 31, 2022 - $1.36 billion) that expire in the years 2033 through 2040, and U.S. net operating losses of $2.32 billion (December 31, 2022 - $2.30 billion) of which $1.52 billion will expire in the years 2032 through 2037, while the remaining $802.2 million will not expire.

A deferred income tax asset has not been recognized for U.S. tax pools of $2.32 billion (December 31, 2022 - $507.2 million) or for other Canadian tax pools of $69.0 million (December 31, 2022 - $69.0 million) as there is not sufficient certainty regarding future utilization.

25.SHARE-BASED COMPENSATION

The following table reconciles the number of restricted shares, ESVP awards, PSUs and DSUs for the year ended December 31, 2023:

	Restricted Shares	ESVP	PSUs (1)	DSUs
Balance, beginning of year	2,244,738	5,274,478	2,713,176	1,745,879
Granted	718,566	1,626,590	888,834	231,464
Redeemed	(1,436,017)	(3,721,568)	(1,627,028)	(248,920)
Forfeited	(146,602)	(519,434)	(351,734)	—
Balance, end of year	1,380,685	2,660,066	1,623,248	1,728,423

(1)Based on underlying units before any effect of performance multipliers.

The following table reconciles the number of restricted shares, ESVP awards, PSUs and DSUs for the year ended December 31, 2022:

	Restricted Shares	ESVP	PSUs (1)	DSUs
Balance, beginning of year	3,267,717	8,329,291	3,214,620	1,556,780
Granted	710,819	1,288,598	904,469	208,693
Redeemed	(1,718,906)	(3,691,820)	(1,405,913)	(19,594)
Forfeited	(14,892)	(651,591)	—	—
Balance, end of year	2,244,738	5,274,478	2,713,176	1,745,879

(1)Based on underlying units before any effect of performance multipliers.

The following table provides summary information regarding stock options outstanding as at December 31, 2023:

	Stock options (number of units)	Weighted average exercise price ($)
Balance, beginning of year	3,889,130	4.43
Exercised	(629,013)	2.92
Forfeited	(35,857)	3.43
Balance, end of year	3,224,260	4.74

CRESCENT POINT ENERGY CORP. 30

The following table summarizes information regarding stock options outstanding as at December 31, 2023:

Range of exercise prices ($)	Number of stock options outstanding	Weighted average remaining term for stock options outstanding (years)	Weighted average exercise price per share for stock options outstanding ($)	Number of stock options exercisable	Weighted average exercise price per share for stock options exercisable ($)
1.09 - 1.65	1,541,362	3.25	1.09	505,996	1.09
1.66 - 5.16	254,950	2.27	3.94	245,820	3.99
5.17 - 9.86	438,417	3.70	6.01	177,060	7.15
9.87 - 10.06	989,531	1.02	10.06	989,531	10.06
	3,224,260	2.55	4.74	1,918,407	6.65

The following table provides summary information regarding stock options outstanding as at December 31, 2022:

	Stock options (number of units)	Weighted average exercise price ($)
Balance, beginning of year	5,839,464	4.04
Exercised	(1,446,571)	3.16
Forfeited	(398,610)	2.06
Expired	(105,153)	9.22
Balance, end of year	3,889,130	4.43

The volume weighted average trading price of the Company's common shares was $9.73 per share during the year ended December 31, 2023 (year ended December 31, 2022 - $9.52 per share).

For the year ended December 31, 2023, the Company calculated total share-based compensation of $40.4 million (year ended December 31, 2022 - $75.6 million), net of estimated forfeitures, of which $5.4 million was capitalized (year ended December 31, 2022 - $13.3 million).

At December 31, 2023, the current portion of long-term compensation liability of $37.5 million was included in other current liabilities (December 31, 2022 - $49.1 million) and $31.0 million was included in other long-term liabilities (December 31, 2022 - $40.8 million).

26.PER SHARE AMOUNTS

The following table summarizes the weighted average shares used in calculating net income (loss) per share:

	2023	2022
Weighted average shares – basic	545,644,234	566,710,644
Dilutive impact of share-based compensation	2,684,473	4,357,422
Weighted average shares – diluted	548,328,707	571,068,066

27.FINANCIAL INSTRUMENTS AND DERIVATIVES

The Company's financial assets and liabilities are comprised of cash, accounts receivable, deferred consideration receivable, derivative assets and liabilities, accounts payable and accrued liabilities, dividends payable and long-term debt.

Crescent Point's derivative assets and liabilities are transacted in active markets. The Company classifies the fair value of these transactions according to the following fair value hierarchy based on the amount of observable inputs used to value the instrument:

•Level 1 - Values are based on unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date.

•Level 2 - Values are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. Prices in Level 2 are either directly or indirectly observable as of the reporting date.

•Level 3 - Values are based on prices or valuation techniques that are not based on observable market data.

Accordingly, Crescent Point's derivative assets and liabilities are classified as Level 2. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy.

CRESCENT POINT ENERGY CORP. 31

Discussions of the fair values and risks associated with financial assets and liabilities, as well as summarized information related to derivative positions are detailed below:

a) Carrying amount and fair value of financial instruments

The fair value of cash, accounts receivable, accounts payable and accrued liabilities and dividends payable approximate their carrying amount due to the short-term nature of those instruments. The fair value of the amounts drawn on bank debt is equal to its carrying amount as the facilities and term loan bear interest at floating rates and credit spreads that are indicative of market rates. These financial instruments are classified as financial assets and liabilities at amortized cost and are reported at amortized cost.

Crescent Point's derivative assets and liabilities are transacted in active markets, classified as financial assets and liabilities at fair value through profit or loss and fair valued at each period with the resulting gain or loss recorded in net income.

The following table summarizes the carrying value of the Company's remaining financial assets and liabilities as compared to their respective fair values as at December 31, 2023:

	2023 Carrying Value	2023 Fair Value	Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs  (Level 3)
($ millions)
Financial assets
Derivatives	255.0	255.0	—	255.0	—
	255.0	255.0	—	255.0	—
Financial liabilities
Derivatives	55.2	55.2	—	55.2	—
Senior guaranteed notes (1)	883.4	853.0	—	853.0	—
	938.6	908.2	—	908.2	—

(1)The senior guaranteed notes are classified as financial liabilities at amortized cost and are reported at amortized cost. The notes denominated in US dollars are translated to Canadian dollars at the period end exchange rate. The fair value of the notes is calculated based on current interest rates and is not recorded in the financial statements.

The following table summarizes the carrying value of the Company's remaining financial assets and liabilities as compared to their respective fair values as at December 31, 2022:

	2022 Carrying Value	2022 Fair Value	Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs  (Level 3)
($ millions)
Financial assets
Derivatives	235.3	235.3	—	235.3	—
	235.3	235.3	—	235.3	—
Financial liabilities
Derivatives	8.7	8.7	—	8.7	—
Senior guaranteed notes (1)	1,441.5	1,372.9	—	1,372.9	—
	1,450.2	1,381.6	—	1,381.6	—

(1)The senior guaranteed notes are classified as financial liabilities at amortized cost and are reported at amortized cost. The notes denominated in US dollars are translated to Canadian dollars at the period end exchange rate. The fair value of the notes is calculated based on current interest rates and is not recorded in the financial statements.

Derivative assets and liabilities

Derivative assets and liabilities arise from the use of derivative contracts. Crescent Point's derivative assets and liabilities are classified as Level 2 with values based on inputs including quoted forward prices for commodities, time value and volatility factors. Accordingly, the Company's derivative financial instruments are classified as fair value through profit or loss and are reported at fair value with changes in fair value recorded in net income.

CRESCENT POINT ENERGY CORP. 32

The following table summarizes the fair value as at December 31, 2023 and the change in fair value for the year ended December 31, 2023:

($ millions)	Commodity (1)	Interest (2)	Foreign exchange (3)	Equity	Total
Derivative assets, beginning of year	14.0	6.7	175.0	30.9	226.6
Acquisitions through business combinations	12.0	—	—	—	12.0
Dispositions	19.0	—	—	—	19.0
Unrealized change in fair value	129.4	(3.4)	(153.6)	(29.3)	(56.9)
Foreign exchange	(0.9)	—	—	—	(0.9)
Derivative assets, end of year	173.5	3.3	21.4	1.6	199.8
Derivative assets, end of year	176.5	3.3	72.2	3.0	255.0
Derivative liabilities, end of year	(3.0)	—	(50.8)	(1.4)	(55.2)

(1)Includes crude oil, crude oil differentials, natural gas and natural gas differential contracts.

(2)Interest payments on CCS.

(3)Includes principal portion of CCS and foreign exchange contracts.

The following table summarizes the fair value as at December 31, 2022 and the change in fair value for the year ended December 31, 2022:

($ millions)	Commodity (1)	Interest (2)	Foreign exchange (3)	Equity	Total
Derivative assets (liabilities), beginning of year	(154.4)	5.6	170.6	33.8	55.6
Unrealized change in fair value	168.4	1.1	4.4	(2.9)	171.0
Derivative assets, end of year	14.0	6.7	175.0	30.9	226.6
Derivative assets, end of year	22.6	6.7	175.1	30.9	235.3
Derivative liabilities, end of year	(8.6)	—	(0.1)	—	(8.7)

(1)Includes crude oil, crude oil differentials, propane, natural gas and natural gas differential contracts.

(2)Interest payments on CCS.

(3)Includes principal portion of CCS and foreign exchange contracts.

Offsetting financial assets and liabilities

Financial assets and liabilities are only offset if the Company has the legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. The Company offsets derivative assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. The following table summarizes the gross asset and liability positions of the Company's financial derivatives by contract that are offset on the balance sheet as at December 31, 2023 and December 31, 2022:

	2023			2022
($ millions)	Asset	Liability	Net	Asset	Liability	Net
Gross amount	258.4	(58.6)	199.8	246.3	(19.7)	226.6
Amount offset	(3.4)	3.4	—	(11.0)	11.0	—
Net amount	255.0	(55.2)	199.8	235.3	(8.7)	226.6

b) Risks associated with financial assets and liabilities

The Company is exposed to financial risks from its financial assets and liabilities. The financial risks include market risk relating to commodity prices, interest rates, foreign exchange rates and equity price as well as credit and liquidity risk.

CRESCENT POINT ENERGY CORP. 33

Commodity price risk

The Company is exposed to commodity price risk on crude oil and condensate, NGLs and natural gas revenues. To manage a portion of this risk, the Company has entered into various derivative agreements.

The following table summarizes the unrealized gains (losses) on the Company's commodity financial derivative contracts and the resulting impact on income before tax due to fluctuations in commodity prices or differentials, with all other variables held constant:

	Impact on Income Before Tax		Impact on Income Before Tax
($ millions)	Year ended December 31, 2023		Year ended December 31, 2022
	Increase 10%	Decrease 10%	Increase 10%	Decrease 10%
Commodity price
Crude oil	(134.4)	135.5	(40.3)	38.8
Natural gas	(25.4)	25.8	(3.1)	3.2
Differential
Natural gas	15.5	(15.5)	2.6	(2.6)

Interest rate risk

The Company is exposed to interest rate risk on amounts drawn on its bank debt to the extent of changes in market interest rates. Based on the Company's floating rate debt position, as at December 31, 2023, a 1 percent increase or decrease in the interest rate on floating rate debt would amount to an impact on income before tax of $26.8 million on an annualized basis. At December 31, 2022, the Company was undrawn on its credit facilities and had no floating rate debt outstanding, therefore, no exposure to changes in market interest rates.

Foreign exchange risk

The Company is exposed to foreign exchange risk in relation to its US dollar denominated long-term debt, US dollar denominated commodity derivative contracts, investment in its U.S. subsidiary and on a portion of its commodity sales. Crescent Point utilizes foreign exchange derivatives to hedge its foreign exchange exposure on its US dollar denominated long-term debt. To reduce foreign exchange risk relating to commodity sales, the Company utilizes a combination of foreign exchange swaps and fixed price WTI crude oil contracts that settle in Canadian dollars.

The following table summarizes the resulting unrealized gains (losses) impacting income before tax due to the respective changes in the period end and applicable foreign exchange rates, with all other variables held constant:

		Impact on Income Before Tax		Impact on Income Before Tax
($ millions)	Exchange Rate	Year ended December 31, 2023		Year ended December 31, 2022
Cdn$ relative to US$		Increase 10%	Decrease 10%	Increase 10%	Decrease 10%
US dollar long-term debt	Period End	265.1	(265.1)	124.6	(124.6)
Cross currency swaps	Forward	(254.8)	254.8	(123.7)	123.7
Foreign exchange swaps	Forward	14.1	(14.1)	4.3	(4.3)

Equity price risk

The Company is exposed to equity price risk on its own share price in relation to certain share-based compensation plans detailed in Note 25 - "Share-based Compensation". The Company has entered into total return swaps to mitigate its exposure to fluctuations in its share price by fixing the future settlement cost on a portion of it's cash settled plans.

The following table summarizes the unrealized gains (losses) on the Company's equity derivative contracts and the resulting impact on income before tax due to the respective changes in the applicable share price, with all other variables held constant:

	Impact on Income Before Tax		Impact on Income Before Tax
($ millions)	Year ended December 31, 2023		Year ended December 31, 2022
Share price	Increase 50%	Decrease 50%	Increase 50%	Decrease 50%
Total return swaps	12.7	(12.7)	26.8	(26.8)

Credit risk

The Company is exposed to credit risk in relation to its physical oil and gas sales, financial counterparty and joint venture receivables. A substantial portion of the Company's accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. To mitigate credit risk associated with its physical sales portfolio, Crescent Point obtains financial assurances such as parental guarantees, letters of credit, prepayments and third party credit insurance. Including these assurances, approximately 98 percent of the Company's oil and gas sales are with entities considered investment grade.

CRESCENT POINT ENERGY CORP. 34

At December 31, 2023, approximately 4 percent (December 31, 2022 - 4 percent) of the Company's accounts receivable balance was outstanding for more than 90 days and the Company's average expected credit loss was 0.83 percent (December 31, 2022 - 0.93 percent) on a portion of the Company’s accounts receivable balance relating to joint venture receivables.

Liquidity risk

The Company manages its liquidity risk through managing its capital structure and continuously monitoring forecast cash flows and available credit under existing banking facilities as well as other potential sources of capital.

At December 31, 2023, the Company had available unused borrowing capacity on bank credit facilities of approximately $801.1 million, including $26.2 million outstanding letters of credit and cash of $17.3 million.

The timing of undiscounted cash outflows relating to the financial liabilities outstanding as at December 31, 2023, is outlined in the table below:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Accounts payable and accrued liabilities	634.9	—	—	—	634.9
Dividends payable	56.8	—	—	—	56.8
Derivative liabilities (1)	—	3.2	—	—	3.2
Senior guaranteed notes (2)	342.8	476.5	27.0	—	846.3
Bank debt (3)	236.3	3,118.8	—	—	3,355.1

(1)These amounts exclude undiscounted cash outflows pursuant to the CCS and foreign exchange swaps.

(2)These amounts include the notional principal and interest payments pursuant to the CCS related to the senior guaranteed notes, which fix the amounts due in Canadian dollars. US dollar senior guaranteed notes that do not have any underlying CCS are translated at the period end foreign exchange rate.

(3)These amounts include interest based on debt outstanding and interest rates effective as at December 31, 2023, and includes undiscounted cash outflows pursuant to the CCS related to Secured Overnight Financing Rate loans.

The timing of undiscounted cash outflows relating to the financial liabilities outstanding as at December 31, 2022, is outlined in the table below:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Accounts payable and accrued liabilities	448.2	—	—	—	448.2
Dividends payable	99.4	—	—	—	99.4
Derivative liabilities (1)	12.6	—	—	—	12.6
Senior guaranteed notes (2)	486.6	816.2	26.9	—	1,329.7

(1)These amounts exclude undiscounted cash outflows pursuant to the CCS and foreign exchange swaps.

(2)These amounts include the notional principal and interest payments pursuant to the CCS and foreign exchange swap related to the senior guaranteed notes, which fix the amounts due in Canadian dollars.

c) Derivative contracts

The following is a summary of the derivative contracts in place as at December 31, 2023:

Financial WTI Crude Oil Derivative Contracts – Canadian Dollar (1)
	Swap		Collar
Term	Volume (bbls/d)	Average Price ($/bbl)	Volumes (bbls/d)	Average Sold Call Price ($/bbl)	Average Bought Put Price ($/bbl)
January 2024 - December 2024 (2)	15,414	102.02	28,488	114.40	97.52
January 2025 - December 2025	1,513	95.13	—	—	—

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

(2)Includes 5,000 bbls/d in the first half of 2024, which can be extended at the option of the counterparty for the second half of 2024 at an average swap price of $102.68/bbl.

Financial WTI Crude Oil Derivative Contracts – US Dollar (1)
	Swap
	Volume (bbls/d)	Average Price (US$/bbl)
Term
January 2024 - March 2024	10,050	82.44

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

CRESCENT POINT ENERGY CORP. 35

Financial AECO Natural Gas Derivative Contracts – Canadian Dollar (1)
	Swap
	Volume (GJ/d)	Average Price ($/GJ)
Term
January 2024 - October 2024	31,403	3.33

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

Financial NYMEX Natural Gas Derivative Contracts – US Dollar (1)
	Swap		Collar
Term	Volume (mmbtu/d)	Average Price (US$/mmbtu)	Volume (mmbtu/d)	Average Sold Call Price (US$/mmbtu)	Average Bought Put Price (US$/mmbtu)
January 2024 - December 2024	31,027	3.44	60,000	4.21	3.14
January 2025 - December 2025	51,000	3.43	45,000	4.01	3.33

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

Financial NYMEX Natural Gas Differential Derivative Contracts – US Dollar (1)
Term	Volume (mmbtu/d)	Contract	Basis	Fixed Differential (US$/mmbtu)
January 2024 - December 2024	151,257	Basis Swap	AECO	(1.10)
January 2025 - December 2025	150,000	Basis Swap	AECO	(1.12)

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

Financial Cross Currency Derivative Contracts
Term	Contract	Receive Notional Principal (US$ millions)	Fixed Rate (US%)	Pay Notional Principal (Cdn$ millions)	Fixed Rate (Cdn%)
January 2024	Swap	783.0	7.18	1,075.6	6.69
January 2024 - March 2024	Swap	635.0	7.17	847.6	6.78
January 2024 - June 2024	Swap	257.5	3.75	276.4	4.03
January 2024 - April 2025	Swap	52.0	4.30	67.9	3.98
January 2024 - April 2025	Swap	207.5	4.08	262.6	4.13

Financial Foreign Exchange Forward Derivative Contracts
Settlement Date	Contract	Receive Currency	Receive Notional Principal ($ millions)	Pay Currency	Pay Notional Principal ($ millions)
January 2024	Swap (1)	Cdn$	64.1	US$	48.0
June 2024	Swap	Cdn$	40.5	US$	30.0
December 2024	Swap	Cdn$	40.5	US$	30.0

(1)Based on an average floating exchange rate.

Financial Equity Derivative Contracts		Notional Principal ($ millions)	Number of shares
Term	Contract
January 2024 - March 2024	Swap	11.8	1,549,947
January 2024 - March 2025	Swap	12.0	1,207,754

28.RELATED PARTY TRANSACTIONS

Compensation of key management personnel

Key management personnel of the Company include its directors and executive officers. The compensation relating to key management personnel for the year ended December 31, 2023, recorded as general and administrative expenses was $7.3 million (year ended December 31, 2022 - $6.1 million) and share-based compensation costs were $19.4 million (year ended December 31, 2022 - $24.2 million).

CRESCENT POINT ENERGY CORP. 36

29.COMMITMENTS

At December 31, 2023, the Company had contractual obligations and commitments as follows:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Operating (1)	15.8	19.7	11.5	7.9	54.9
Gas processing	115.6	193.4	147.9	280.8	737.7
Transportation	186.1	361.5	276.5	524.5	1,348.6
Total contractual commitments (2)	317.5	574.6	435.9	813.2	2,141.2

(1)Includes operating costs on the Company's office space, net of $16.7 million recoveries from subleases.

(2)Excludes contracts accounted for under IFRS 16. See Note 14 - "Leases" for additional information.

30.SIGNIFICANT SUBSIDIARIES

The Company has the following significant subsidiaries, each owned 100% directly and indirectly, at December 31, 2023:

Subsidiary Name	Country of Formation
Crescent Point Resources Partnership	Canada
Crescent Point Holdings Ltd.	Canada
Hammerhead Resources ULC	Canada
Crescent Point Energy U.S. Corp.	United States of America

CRESCENT POINT ENERGY CORP. 37

31.SUPPLEMENTAL DISCLOSURES

Comprehensive income statement presentation

The Company’s statements of comprehensive income are prepared primarily by nature of expense, with the exception of compensation expenses which are included in the operating, general and administrative and share-based compensation line items, as follows:

($ millions)	2023	2022 (1)
Operating	64.0	56.3
General and administrative	66.8	58.7
Share-based compensation	9.4	35.9
Total compensation expenses	140.2	150.9

(1)Comparative period revised to reflect current period presentation.

Cash flow statement presentation

($ millions)	2023	2022
Operating activities
Changes in non-cash working capital:
Accounts receivable	66.7	(11.3)
Prepaids and deposits	(2.2)	(13.9)
Accounts payable and accrued liabilities	(97.8)	(3.5)
Other current liabilities	(11.8)	8.6
Other long-term liabilities	(9.8)	5.1
	(54.9)	(15.0)
Investing activities
Changes in non-cash working capital:
Accounts receivable	—	0.2
Other current assets	(60.5)	(18.7)
Accounts payable and accrued liabilities	56.3	(7.6)
	(4.2)	(26.1)
Financing activities
Changes in non-cash working capital:
Prepaids and deposits	(12.6)	(44.2)
Accounts payable and accrued liabilities	(2.0)	4.0
Dividends payable	(42.6)	55.9
	(57.2)	15.7

CRESCENT POINT ENERGY CORP. 38

Supplementary financing cash flow information

The Company's reconciliation of cash flow from financing activities is outlined in the table below:

($ millions)	Dividends payable	Long-term debt (1)	Lease liability (2)
December 31, 2021	43.5	1,970.2	141.4
Changes from cash flow from financing activities:
Decrease in bank debt, net		(338.5)
Repayment of senior guaranteed notes		(281.8)
Realized gain on cross currency swap maturity		63.8
Dividends paid	(144.7)
Payments on principal portion of lease liability			(20.4)
Non-cash changes:
Dividends declared	200.6
Additions			3.8
Other			(0.7)
Foreign exchange		27.8
December 31, 2022	99.4	1,441.5	124.1
Changes from cash flow from financing activities:
Increase in bank debt, net		2,675.1
Repayment of senior guaranteed notes and acquired long-term debt		(897.9)
Realized gain on cross currency swap maturity		147.7
Dividends paid	(254.5)
Payments on principal portion of lease liability			(20.8)
Non-cash changes:
Dividends declared	211.9
Acquisitions through business combinations		363.8	4.3
Additions			38.2
Dispositions			(1.1)
Foreign exchange		(163.9)
December 31, 2023	56.8	3,566.3	144.7

(1)Includes current portion of long-term debt.

(2)Includes current portion of lease liability.

32.OIL AND GAS SALES

The following table reconciles oil and gas sales by country:

($ millions) (1)	2023	2022
Canada
Crude oil and condensate sales	3,082.5	3,319.1
NGL sales	180.2	224.8
Natural gas sales	236.3	303.1
Total Canada	3,499.0	3,847.0
U.S.
Crude oil and condensate sales	569.6	553.3
NGL sales	27.0	55.2
Natural gas sales	16.3	37.6
Total U.S. (2)	612.9	646.1
Total oil and gas sales	4,111.9	4,493.1

(1)Oil and gas sales are reported before realized derivatives.

(2)Discontinued operations.

CRESCENT POINT ENERGY CORP. 39

33.SUBSEQUENT EVENTS

Disposition of Southern Alberta Assets

On January 26, 2024, Crescent Point completed the disposition of its Southern Alberta assets for total consideration of approximately $38.1 million, including interim closing adjustments. Total consideration includes $25.0 million of deferred consideration receivable. Due to significant decommissioning liabilities associated with these assets, this transaction reduces the Company's decommissioning liability balance by $92.4 million.

CRESCENT POINT ENERGY CORP. 40

Directors Barbara Munroe, Chair (6) James Craddock (2) (3) (5) John Dielwart (3) (4) Mike Jackson (1) (5) Jennifer Koury (2) (5) Francois Langlois (1) (3) (4) Myron Stadnyk (1) (2) (4) Mindy Wight (1) (2) Craig Bryksa (4) (1) Member of the Audit Committee of the Board of Directors (2) Member of the Human Resources and Compensation Committee of the Board of Directors (3) Member of the Reserves Committee of the Board of Directors (4) Member of the Environment, Safety and Sustainability Committee of the Board of Directors (5) Member of the Corporate Governance and Nominating Committee (6) Chair of the Board serves in an ex officio capacity on each Committee Officers Craig Bryksa President and Chief Executive Officer Ken Lamont Chief Financial Officer Ryan Gritzfeldt Chief Operating Officer Mark Eade Senior Vice President, General Counsel and Corporate Secretary Garret Holt Senior Vice President, Strategy and Planning Michael Politeski Senior Vice President, Finance and Treasurer Shelly Witwer Senior Vice President, Business Development Justin Foraie Vice President, Operations and Marketing Head Office Suite 2000, 585 - 8th Avenue S.W. Calgary, Alberta T2P 1G1 Tel: (403) 693-0020 Fax: (403) 693-0070 Toll Free: (888) 693-0020 Banker The Bank of Nova Scotia Calgary, Alberta Auditor PricewaterhouseCoopers LLP Calgary, Alberta Legal Counsel Norton Rose Fulbright Canada LLP Calgary, Alberta Evaluation Engineers McDaniel & Associates Consultants Ltd. Calgary, Alberta Registrar and Transfer Agent Investors are encouraged to contact Crescent Point's Registrar and Transfer Agent for information regarding their security holdings: Computershare Trust Company of Canada 600, 530 - 8th Avenue S.W. Calgary, Alberta T2P 3S8 Tel: (403) 267-6800 Stock Exchanges Toronto Stock Exchange - TSX New York Stock Exchange - NYSE Stock Symbol CPG Investor Contacts Shant Madian Vice President, Capital Markets (403) 693-0020 Sarfraz Somani Manager, Investor Relations (403) 693-0020

CRESCENT POINT ENERGY CORP. 41

EX-99.3

Exhibit 99.3

MANAGEMENT’S DISCUSSION AND ANALYSIS

Management's discussion and analysis (“MD&A”) is dated February 28, 2024 and should be read in conjunction with the audited consolidated financial statements for the period ended December 31, 2023 for a full understanding of the financial position and results of operations of Crescent Point Energy Corp. (the “Company” or “Crescent Point”). Except as otherwise noted, the results of operations present only continuing operations. Comparative period results have been revised to reflect current period presentation.

The audited consolidated financial statements and comparative information for the year ended December 31, 2023 are presented under IFRS Accounting Standards as issued by the International Accounting Standards Board.

Structure of the Business

The principal undertaking of Crescent Point is to carry on the business of acquiring, developing and holding interests in petroleum and natural gas properties and assets related thereto through a general partnership and wholly owned subsidiaries. Amounts in this MD&A are in Canadian dollars unless noted otherwise. References to “US$” and "US dollars" are to United States (“U.S.”) dollars.

Overview

Crescent Point's 2023 results demonstrate strong operational execution, excess cash flow generation and its commitment to shareholder returns. The Company achieved strong annual financial results with adjusted funds flow from operations of $2.34 billion and adjusted net earnings from operations of $932.6 million. The Company generated $981.6 million of excess cash flow and continued to execute on its return of capital framework, returning approximately 60 percent of its excess cash flow to shareholders through share repurchases and dividends. Crescent Point repurchased 34.6 million shares for $349.9 million in the year ended December 31, 2023, accounting for a significant allocation of the return of capital.

The Company achieved its 2023 guidance with average annual production of 159,411 boe/d (guidance of 156,000 - 161,000 boe/d), annual operating expenses of $14.62/boe (guidance of $13.75 - $14.75/boe) and development capital expenditures of $1.14 billion (guidance of $1.05 - $1.15 billion) to drill 172.4 net wells.

The Company completed its strategic portfolio transformation in 2023 which materially enhanced the long-term sustainability of the business. In May 2023, the Company entered the Alberta Montney resource play by acquiring assets from Spartan Delta Corp. for total cash consideration of $1.70 billion. In December the Company acquired Hammerhead Energy Inc. ('Hammerhead") for total consideration, inclusive of net debt, of $2.52 billion. These two strategic Montney transactions added approximately 90,000 boe/day of production, along with a deep drilling inventory and significant land position in the volatile oil fairway of the play. The Company was also active on the divestment front as it closed the sale of its North Dakota assets in October 2023 for total consideration of approximately $585.8 million including interim closing adjustments. Subsequent to year end, the Company closed the disposition of its Southern Alberta assets and expects to close the sale of its Swan Hills assets in the first quarter of 2024.

The Company exited 2023 with net debt of $3.74 billion or 1.6 times net debt to adjusted funds flow from operations. The Company is focused on reducing its net debt through excess cash flow generation. To provide downside commodity price protection, the Company has hedged approximately 45 percent of its oil and liquids production and over 30 percent of its natural gas production in 2024, net of royal interest.

Crescent Point's 2024 guidance includes annual average production of 198,000 - 206,000 boe/d, development capital expenditures of $1.40 - $1.50 billion and operating expenses of $12.75 - $13.75/boe. Based on current forecast commodity prices, the Company expects to generate strong returns and excess cash flow to provide continued returns to shareholders.

Adjusted funds flow, adjusted net earnings from operations and excess cash flow are specified financial measures that do not have any standardized meaning prescribed by IFRS and, therefore, 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.

CRESCENT POINT ENERGY CORP. 1

Presentation of Continuing and Discontinued Operations

On October 24, 2023, the Company completed the disposition of its North Dakota assets in its Northern U.S. cash-generating unit ("CGU"). The Northern U.S. CGU represents a geographical area of the Company's operations, therefore, its results have been classified as a discontinued operation in accordance with IFRS 5 Non-current Assets Held for Sale and Discontinued Operations. Refer to the Discontinued Operations in this MD&A for further information. The financial results for the year ended December 31, 2023 and December 31, 2022, are presented below to reconcile continuing and discontinued operations to total results.

The following table summarizes the Company's financial results from continuing and discontinued operations for the year ended December 31, 2023 and December 31, 2022:

	December 31, 2023			December 31, 2022
($ millions)	Continuing	Discontinued	Total	Continuing (1)	Discontinued (1)	Total
REVENUE AND OTHER INCOME
Oil and gas sales	3,499.0	612.9	4,111.9	3,847.0	646.1	4,493.1
Purchased product sales	66.2	—	66.2	100.8	—	100.8
Royalties	(375.3)	(155.9)	(531.2)	(435.5)	(165.4)	(600.9)
Oil and gas revenue	3,189.9	457.0	3,646.9	3,512.3	480.7	3,993.0
Commodity derivative gains (losses)	163.8	(23.4)	140.4	(473.4)	—	(473.4)
Other income (loss)	13.4	(2.2)	11.2	59.0	(0.2)	58.8
	3,367.1	431.4	3,798.5	3,097.9	480.5	3,578.4
EXPENSES
Operating	770.5	80.0	850.5	628.2	84.9	713.1
Purchased product	68.6	—	68.6	102.9	—	102.9
Transportation	174.3	12.2	186.5	131.0	8.8	139.8
General and administrative	126.5	12.7	139.2	78.4	3.4	81.8
Interest	129.4	—	129.4	63.6	—	63.6
Foreign exchange (gain) loss	(10.0)	(621.7)	(631.7)	18.8	—	18.8
Share-based compensation	38.7	(0.4)	38.3	38.8	0.3	39.1
Depletion, depreciation and amortization	894.7	170.3	1,065.0	807.2	144.5	951.7
Impairment (impairment reversal)	93.8	728.4	822.2	(357.3)	(71.3)	(428.6)
Accretion and financing	27.5	0.4	27.9	24.5	0.4	24.9
	2,314.0	381.9	2,695.9	1,536.1	171.0	1,707.1
Net income before tax	1,053.1	49.5	1,102.6	1,561.8	309.5	1,871.3
Tax expense (recovery)
Current	(0.7)	—	(0.7)	—	—	—
Deferred	254.4	278.6	533.0	415.1	(27.2)	387.9
Net income (loss)	799.4	(229.1)	570.3	1,146.7	336.7	1,483.4

(1)Comparative period revised to reflect current period presentation.

Results of Operations

Production

	2023	2022	% Change
Crude oil and condensate (bbls/d)	88,087	79,323	11
NGLs (bbls/d)	15,026	13,079	15
Natural gas (mcf/d)	211,275	128,099	65
Production from continuing operations (boe/d)	138,326	113,752	22
Production from discontinued operations (boe/d)	21,085	18,530	14
Total average daily production (boe/d)	159,411	132,282	21
Crude oil and liquids - continuing operations (%)	75	81	(6)
Natural gas - continuing operations (%)	25	19	6
Total (%)	100	100	—

CRESCENT POINT ENERGY CORP. 2

The following is a summary of Crescent Point's production by area:

Production By Area (boe/d)	2023	2022	% Change
Alberta	75,792	44,766	69
Saskatchewan	62,534	68,986	(9)
Production from continuing operations	138,326	113,752	22
Production from discontinued operations - North Dakota	21,085	18,530	14
Total average daily production	159,411	132,282	21

Production from continuing operations averaged 138,326 boe/d during 2023 compared to 113,752 boe/d in 2022, representing an increase of 22 percent. This growth is due primarily to the acquisitions of the Alberta Montney assets in May 2023 and additional Kaybob Duvernay assets in January 2023, along with organic growth in both the Duvernay and Montney properties as a result of the Company's successful development program.

The Company's weighting to crude oil and liquids production in 2023 decreased by 6 percent. The decrease was primarily due to the aforementioned production growth in the Alberta Montney and Kaybob Duvernay, which have higher weighting of natural gas production.

Exhibit 1

Marketing and Prices

Average Selling Prices (1)	2023	2022	% Change
Crude oil and condensate ($/bbl)	95.87	114.64	(16)
NGLs ($/bbl)	32.86	47.10	(30)
Natural gas ($/mcf)	3.06	6.48	(53)
Total ($/boe)	69.30	92.66	(25)

(1)The average selling prices reported are before realized commodity derivatives and transportation.

CRESCENT POINT ENERGY CORP. 3

Benchmark Pricing	2023	2022	% Change
Crude Oil Prices
WTI crude oil (US$/bbl) (1)	77.61	94.23	(18)
WTI crude oil (Cdn$/bbl)	104.74	122.54	(15)
Crude Oil and Condensate Differentials
LSB crude oil (Cdn$/bbl) (2)	(6.79)	(4.42)	54
FOS crude oil (Cdn$/bbl) (3)	(23.39)	(21.81)	7
MSW crude oil (Cdn$/bbl) (4)	(3.64)	(1.96)	86
C5+ condensate (Cdn$/bbl) (5)	(1.44)	(0.64)	127
Natural Gas Prices
AECO daily spot natural gas (Cdn$/mcf) (6)	2.64	5.31	(50)
AECO monthly index natural gas (Cdn$/mcf)	2.92	5.56	(47)
NYMEX natural gas (US$/mmbtu) (7)	2.74	6.64	(59)
Foreign Exchange Rate
Exchange rate (US$/Cdn$)	0.741	0.769	(4)

(1)WTI refers to the West Texas Intermediate crude oil price.

(2)LSB refers to the Light Sour Blend crude oil price.

(3)FOS refers to the Fosterton crude oil price, which typically receives a premium to the Western Canadian Select price.

(4)MSW refers to Mixed Sweet Blend crude oil price.

(5)C5+ condensate refers to the Canadian C5+ condensate index.

(6)AECO refers to the Alberta Energy Company natural gas price.

(7)NYMEX refers to the New York Mercantile Exchange natural gas price.

Benchmark crude oil prices weakened in 2023 compared to 2022, primarily due to demand concerns related to the slowing global economy and rising interest rates. Supply concerns from the Russian/Ukraine conflict faded and unfavorable refinery margins in 2023 exerted additional downward pressure on crude oil demand. Despite European sanctions, Russian crude oil production remained resilient, with a greater volume of Russian barrels being sold to Asian refineries compared to 2022. The extension of OPEC+ production cuts along with an additional voluntary cut from Saudi Arabia could not provide sustained support to the oil market due to the aforementioned factors.

Natural gas prices were significantly lower than the 2022 comparative period, primarily due to warmer than usual temperatures across most of the northern hemisphere, which led to reduced demand and higher storage inventory levels. Increased production in both the U.S. and Canada provided further downward pressure on natural gas prices. The AECO daily and NYMEX benchmark prices decreased 50 percent and 59 percent in 2023, respectively, compared to 2022.

Exhibit 2

LSB and FOS crude oil differentials weakened in 2023 compared to the same periods in 2022, primarily due to crude oil releases from the Strategic Petroleum Reserve weighing on differentials in the first half of 2023, weaker refinery margins in 2023 driven by oversupply of US gasoline as well as uncertainty associated with the startup of the Trans Mountain pipeline expansion. In addition, increased Western Canadian Sedimentary Basin ("WCSB") production flowing on the Enbridge mainline resulted in shippers nominated volumes being reduced in order to meet the pipeline's uncommitted capacity for light and heavy crude.

MSW crude oil differentials weakened in 2023 compared to 2022, primarily due to weaker refinery margins driven by oversupply of U.S. gasoline and increased WCSB production.

Condensate differentials weakened in 2023 compared to 2022, primarily due to higher diluent inventories in western Canada, increased imports of C5+ to Canada from Mont Belvieu trading hub in Texas and weakness in heavy crude pricing which decreased blending demand.

CRESCENT POINT ENERGY CORP. 4

In 2023, the Company's average selling price for crude oil and condensate decreased 16 percent, primarily due to a 15 percent decrease in the Cdn$ WTI benchmark price.

Crescent Point's corporate crude oil and condensate differential relative to Cdn$ WTI in 2023 was $8.87 per bbl compared to $7.90 per bbl in 2022. The wider differential was driven by weaker LSB, FOS, MSW and C5+ differentials.

In 2023, the Company's average selling price for NGLs decreased 30 percent, primarily due to a reduction in propane and butane prices. This reduction was largely due to record high inventories in the U.S. as a result of record domestic production and the lower WTI benchmark price.

The Company's average selling price for natural gas decreased 53 percent in 2023, as a result of weaker AECO daily and NYMEX benchmark prices, primarily due to abnormally warm temperatures and high inventory levels. The Company's gas production generally trades at a slight premium to AECO pricing due to the Company selling a portion of its portfolio to U.S. Midwest markets.

Exhibit 3

Commodity Derivatives

Management of cash flow variability is an integral component of Crescent Point's business strategy. Crescent Point regularly monitors changing business and market conditions while executing its strategic risk management program. Crescent Point proactively manages the risk exposure inherent in movements in the price of crude oil, propane, natural gas, interest rates, the Company's share price and the US/Cdn dollar exchange rate through the use of derivatives with investment-grade counterparties.

The Company's crude oil and NGL derivatives are referenced to WTI and Conway C3, respectively. The Company's natural gas derivatives are referenced to NYMEX and the AECO monthly index. Crescent Point utilizes a variety of derivatives, including swaps, swaptions, collars and put options, to protect against downward commodity price movements while also providing the opportunity for some upside participation during periods of rising prices. This reduces the volatility of the selling price of crude oil, NGLs and natural gas production and provides a measure of stability to the Company's cash flow. See Note 27 – "Financial Instruments and Derivatives" in the audited consolidated financial statements for the period ended December 31, 2023 for additional information on the Company's derivatives.

CRESCENT POINT ENERGY CORP. 5

The following is a summary of the realized commodity derivative gains (losses):

($ millions, except volume amounts)	2023	2022	% Change
Average crude oil volumes hedged (bbls/d) (1)	28,955	44,229	(35)
Crude oil realized derivative loss (1)	(3.3)	(647.3)	(99)
per bbl - continuing operations	(0.10)	(22.36)	(100)
Average NGL volumes hedged (bbls/d)	—	416	(100)
NGL realized derivative loss	—	(1.1)	(100)
per bbl - continuing operations	—	(0.23)	(100)
Average natural gas volumes hedged (GJ/d) (2) (3)	40,325	31,233	29
Natural gas realized derivative gain (3)	18.8	6.6	185
per GJ - continuing operations	0.24	0.14	71
Average barrels of oil equivalent hedged (boe/d) (1) (3)	35,325	49,579	(29)
Total realized commodity derivative gains (losses) (1) (3)	15.5	(641.8)	(102)
per boe - continuing operations	0.31	(15.46)	(102)
per boe - total average daily production	0.27	(13.29)	(102)

(1)The crude oil realized derivative loss for the years ended December 31, 2023 and December 31, 2022 includes the realized derivative gains and losses on financial crude oil price differential contracts. The average crude oil volumes hedged and average barrels of oil equivalent hedged do not include the hedged volumes related to financial crude oil price differential contracts.

(2)GJ/d is defined as gigajoules per day.

(3)The natural gas derivative gain for the years ended December 31, 2023 and December 31, 2022 includes the realized derivative gains and losses on financial natural gas price differential contracts. The average natural gas volumes hedged and average barrels of oil equivalent hedged do not include the hedged volumes related to financial natural gas price differentials contracts.

The Company's realized derivative loss for crude oil was $3.3 million for the year ended December 31, 2023, compared to $647.3 million in 2022. The realized derivative loss was primarily attributable to the higher Cdn$ WTI benchmark price compared to the Company's average derivative crude oil price.

Crescent Point's realized derivative gain for natural gas was $18.8 million for the year ended December 31, 2023, compared to $6.6 million in 2022. The realized gain in 2023 is primarily the result of the lower average AECO monthly index price compared to the Company's average derivative natural gas hedge price, partially offset by losses on the Company's natural gas differential contracts as a result of the narrower AECO to NYMEX differential.

Exhibit 4

(1)The results are presented on a continuing operations basis. Comparative period results have been revised to reflect current period presentation.

The following is a summary of the Company's unrealized commodity derivative gains:

($ millions)	2023	2022	% Change
Crude oil	127.4	145.6	(13)
NGL	—	(0.1)	(100)
Natural gas	20.9	22.9	(9)
Total unrealized commodity derivative gains	148.3	168.4	(12)

CRESCENT POINT ENERGY CORP. 6

For the year ended December 31, 2023, the Company recognized a total unrealized derivative gain of $148.3 million on its commodity contracts compared to $168.4 million in 2022. The unrealized crude oil derivative gain in 2023 was primarily attributable to the decrease in the Cdn$ WTI forward benchmark prices at December 31, 2023 relative to the average derivative price on contracts entered into during the year. The unrealized gain on natural gas derivative contracts in 2023 was primarily due to weaker NYMEX and AECO monthly forward benchmark prices at December 31, 2023 compared to the Company's average hedge price, partially offset by losses from the narrower AECO differential to NYMEX.

Oil and Gas Sales

($ millions) (1)	2023	2022	% Change
Crude oil and condensate sales	3,082.5	3,319.1	(7)
NGL sales	180.2	224.8	(20)
Natural gas sales	236.3	303.1	(22)
Total oil and gas sales	3,499.0	3,847.0	(9)

(1)Oil and gas sales are reported before realized commodity derivatives.

Total oil and gas sales decreased by 9 percent in 2023 compared to 2022. The decrease is due to lower average selling prices, partially offset by higher production volumes.

Exhibit 5

(1)The results are presented on a continuing operations basis. Comparative period results have been revised to reflect current period presentation.

Royalties

($ millions, except % and per boe amounts)	2023	2022	% Change
Royalties	375.3	435.5	(14)
As a % of oil and gas sales	10.7	11.3	(0.6)
Per boe	7.43	10.49	(29)

Royalties decreased 14 percent in 2023 compared to 2022 due to lower oil and gas sales as a result of weaker pricing. Royalties as a percentage of oil and gas sales decreased in 2023 compared to 2022, primarily attributable to the addition of lower royalty rate Alberta Montney assets.

Royalties per boe decreased 29 percent in 2023 from the 2022 comparative year. This is primarily attributable to higher production in the Alberta Montney and Kaybob Duvernay areas, as well as the lower royalty rates mentioned above.

CRESCENT POINT ENERGY CORP. 7

Exhibit 6

(1)The results are presented on a continuing operations basis. Comparative period results have been revised to reflect current period presentation.

Operating Expenses

($ millions, except per boe amounts)	2023	2022	% Change
Operating expenses	770.5	628.2	23
Per boe	15.26	15.13	1

Operating expenses increased 23 percent in 2023 compared to 2022. The increase was primarily attributable to higher production as a result of the acquisitions of producing assets in the Alberta Montney and Kaybob Duvernay, which closed in May 2023 and January 2023, respectively.

Operating expenses per boe were consistent in 2023 compared to 2022. The acquisitions of producing assets with lower associated per boe operating costs offset the economy-wide inflationary pressures in 2023.

Exhibit 7

(1)The results are presented on a continuing operations basis. Comparative period results have been revised to reflect current period presentation.

Transportation Expenses

($ millions, except per boe amounts)	2023	2022	% Change
Transportation expenses	174.3	131.0	33
Per boe	3.45	3.16	9

Transportation expenses increased 33 percent in 2023 compared to 2022, primarily due to higher production as a result of the Alberta Montney and Kaybob Duvernay acquisitions. On a per boe basis, transportation expenses increased by $0.29 per boe in 2023 compared to 2022, primarily due to higher tariff rates associated with the Alberta Montney assets and access to U.S. Midwest natural gas markets.

CRESCENT POINT ENERGY CORP. 8

Exhibit 8

(1)The results are presented on a continuing operations basis. Comparative period results have been revised to reflect current period presentation.

Netback

($/boe) (1)	2023	2022	% Change
Oil and gas sales	69.30	92.66	(25)
Royalties	(7.43)	(10.49)	(29)
Operating expenses	(15.26)	(15.13)	1
Transportation expenses	(3.45)	(3.16)	9
Operating netback (2)	43.16	63.88	(32)
Realized gain (loss) on commodity derivatives	0.31	(15.46)	(102)
Netback (2)	43.47	48.42	(10)

(1)The dominant production category for the Company's properties is crude oil and condensate. These categories include associated natural gas and NGL volumes, therefore, the total operating netback and netback have been presented.

(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, 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.

The Company's operating netback for the year ended December 31, 2023 decreased to $43.16 per boe from $63.88 per boe in 2022. The decrease in the Company's operating netback was primarily due to the decrease in average selling price and an increase in transportation expenses, partially offset by lower royalty expenses. The decrease in the Company's netback was a result of the decrease in the operating netback, partially offset by the realized gain on commodity derivatives in 2023 compared to a realized loss in 2022.

Exhibit 9

(1)The results are presented on a continuing operations basis. Comparative period results have been revised to reflect current period presentation.

CRESCENT POINT ENERGY CORP. 9

General and Administrative Expenses

($ millions, except per boe amounts)	2023	2022	% Change
Gross general and administrative expenses	179.0	128.8	39
Overhead recoveries	(18.2)	(18.2)	—
Capitalized	(34.3)	(32.2)	7
Total general and administrative expenses	126.5	78.4	61
Transaction costs	(39.8)	(4.6)	765
General and administrative expenses	86.7	73.8	17
Per boe	1.72	1.78	(3)

General and administrative ("G&A") expenses increased to $86.7 million in 2023, compared to $73.8 million in 2022. The increase is primarily due to higher employee related costs and professional fees. The fourth quarter of 2023 was impacted by severance charges.

For the year ended December 31, 2023, G&A expenses on a per boe basis decreased 3 percent compared to 2022, primarily due to higher production volumes, partially offset by the increase in G&A discussed above.

Transaction costs relate to the Company's acquisition and disposition transactions in Canada. Refer to the Capital Acquisitions and Dispositions section in this MD&A for further information.

Exhibit 10

(1)The results are presented on a continuing operations basis. Comparative period results have been revised to reflect current period presentation.

Interest Expense

($ millions, except per boe amounts)	2023	2022	% Change
Interest expense on long-term debt	126.0	64.7	95
Unrealized (gain) loss on interest derivative contracts	3.4	(1.1)	(409)
Interest expense	129.4	63.6	103
Per boe - continuing operations	2.56	1.53	67
Per boe - total average daily production	2.22	1.32	68

Interest expense on long-term debt increased 95 percent in 2023 compared to 2022, due to the Company's higher average debt balance and higher effective interest rate. The Company's higher average debt balance in 2023 was due to the acquisitions of the Alberta Montney assets in May 2023 and Hammerhead in December 2023, partially offset by the proceeds of the North Dakota disposition. The Company's hedged effective interest rate increased to 5.40 percent in 2023 compared to 3.97 percent in 2022 reflecting higher underlying benchmark interest rates and the impact on the Company's outstanding floating rate debt.

At December 31, 2023, approximately 25 percent of the Company's outstanding long-term debt had fixed interest rates.

CRESCENT POINT ENERGY CORP. 10

Exhibit 11

Foreign Exchange Gain (Loss)

($ millions)	2023	2022	% Change
Realized gain on CCS - principal	151.8	63.8	138
Translation of US dollar long-term debt	16.8	(94.3)	(118)
Unrealized (gain) loss on CCS - principal and foreign exchange swaps	(153.6)	4.4	(3,591)
Other	(5.0)	7.3	(168)
Foreign exchange gain (loss)	10.0	(18.8)	(153)

The Company hedges its foreign exchange exposure using a combination of cross currency swaps ("CCS") and foreign exchange swaps. During the year ended December 31, 2023, the Company realized a $151.8 million gain on CCS related to senior guaranteed note maturities and Secured Overnight Financing Rate ("SOFR") loan maturities.

The Company records foreign exchange gains or losses on the period end translation of US dollar long-term debt and related accrued interest. For the year ended December 31, 2023, the Company recorded foreign exchange gains of $16.8 million which was attributed to the stronger Canadian dollar at December 31, 2023 as compared to December 31, 2022.

For the year ended December 31, 2023, Crescent Point recorded an unrealized derivative loss on CCS and foreign exchange swaps of $153.6 million, primarily due to the maturity of in-the-money CCS contracts and the impact of the stronger forward Canadian dollar on the Company's CCS at December 31, 2023, as compared to December 31, 2022.

Share-based Compensation Expense

($ millions, except per boe amounts)	2023	2022	% Change
Share-based compensation costs	40.4	75.6	(47)
Realized gain on equity derivative contracts	(25.6)	(26.4)	(3)
Unrealized loss on equity derivative contracts	29.3	2.9	910
Capitalized	(5.4)	(13.3)	(59)
Share-based compensation expense	38.7	38.8	—
Per boe	0.77	0.93	(17)

During the year ended December 31, 2023, the Company recorded share-based compensation ("SBC") costs of $40.4 million compared to $75.6 million in 2022. The lower SBC costs are primarily attributable to a lower number of awards outstanding and lower share price at December 31, 2023 as compared to December 31, 2022.

In 2023, the Company recognized a realized gain of $25.6 million on the maturity of in-the-money equity derivative contracts in the first quarter of 2023. The realized gain is primarily due to the increase in the Company's share price compared to the hedge price at the time of grant. The Company also recognized an unrealized loss on equity derivative contracts of $29.3 million in 2023, compared to $2.9 million in 2022. The unrealized loss in 2023 was primarily due to the maturity of in-the-money equity derivative contracts and the decrease in the Company's share price at December 31, 2023 compared to December 31, 2022.

The Company capitalized share-based compensation costs of $5.4 million in 2023, a decrease of 59 percent from 2022. The decrease was primarily due to the decrease in total share-based compensation costs as noted above.

CRESCENT POINT ENERGY CORP. 11

Exhibit 12

The following table summarizes the number of restricted shares, Employee Share Value Plan ("ESVP") awards, Performance Share Units ("PSUs"), Deferred Share Units ("DSUs") and stock options outstanding:

	December 31, 2023	December 31, 2022
Restricted Share Bonus Plan (1)	1,380,685	2,244,738
Employee Share Value Plan	2,660,066	5,274,478
Performance Share Unit Plan (2)	1,623,248	2,713,176
Deferred Share Unit Plan	1,728,423	1,745,879
Stock Option Plan (3)	3,224,260	3,889,130

(1)At December 31, 2023, the Company was authorized to issue up to 9,774,533 common shares (December 31, 2022 - 11,210,550 common shares).

(2)Based on underlying units before any effect of performance multipliers.

(3)At December 31, 2023, the weighted average exercise price is $4.74 per share (December 31, 2022 - $4.43 per share).

As of the date of this report, the Company had 1,380,685 restricted shares, 2,788,129 ESVP awards, 2,844,523 PSUs, 1,738,614 DSUs and 3,204,260 stock options outstanding.

Depletion, Depreciation and Amortization

($ millions, except per boe amounts)	2023	2022	% Change
Depletion and depreciation	863.8	792.0	9
Amortization of exploration and evaluation undeveloped land	30.9	15.2	103
Depletion, depreciation and amortization	894.7	807.2	11
Per boe	17.72	19.44	(9)

For the year ended December 31, 2023, the Company's depletion, depreciation and amortization ("DD&A") rate decreased to $17.72 per boe compared to $19.44 per boe in 2022. The decrease in the DD&A rate per boe in 2023 was primarily attributable to the impairment loss recorded in the fourth quarter of 2022, which decreased the carrying value of the Company's property, plant and equipment ("PP&E"), and a lower DD&A rate on acquired assets relative to the corporate average. This was partially offset by the increase in amortization of exploration and evaluation ("E&E") undeveloped land, primarily as a result of the acquisition of the Alberta Montney and Kaybob Duvernay assets in 2023.

For the year ended December 31, 2023, DD&A expense increased 11 percent compared to 2022, primarily due to higher production volumes in 2023, partially offset by the lower DD&A rate.

CRESCENT POINT ENERGY CORP. 12

Exhibit 13

Impairment (Impairment Reversal)

($ millions, except per boe amounts)	2023	2022	% Change
Impairment (impairment reversal)	93.8	(357.3)	(126)
Per boe	1.86	(8.61)	(122)

The Company recognized an impairment loss of $93.8 million in 2023 compared to an impairment reversal of $357.3 million in 2022. At December 31, 2023, the Company had certain non-core assets in its Alberta cash-generating unit ("CGU") classified as held for sale. Immediately prior to classifying the assets as held for sale and at the balance sheet date, the Company conducted a review of the assets' recoverable amounts and recorded impairment losses of $93.8 million on PP&E. See Note 10 – "Property, Plant and Equipment" in the audited consolidated financial statements for the year ended December 31, 2023 for further information.

Other Income

The Company recorded other income of $13.4 million in 2023 compared to $59.0 million in 2022. Other income in 2023 was comprised primarily of government grants for decommissioning expenditures and sublease income, partially offset by losses on asset dispositions. Other income in 2022 was primarily comprised of gains on asset dispositions, government grants for decommissioning expenditures and sublease income. See Note 21 – "Other Income" in the audited consolidated financial statements for the year ended December 31, 2023 for further information.

Taxes

($ millions)	2023	2022	% Change
Current tax recovery	(0.7)	—	—
Deferred tax expense	254.4	415.1	(39)

Current Tax Recovery

In the year ended December 31, 2023, the Company recorded a current tax recovery of $0.7 million, compared to nil for the year ended December 31, 2022. Refer to the Company's Annual Information Form for the year ended December 31, 2023 for information on the Company's expected tax horizon, which is available on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov/edgar.

Deferred Tax Expense

In the year ended December 31, 2023, the Company recorded deferred tax expense of $254.4 million compared to $415.1 million in 2022. The decrease in the deferred tax expense in 2023 primarily relates to the decrease in net income before taxes.

CRESCENT POINT ENERGY CORP. 13

Cash Flow from Operating Activities, Adjusted Funds Flow from Operations, Net Income and Adjusted Net Earnings from Operations

($ millions, except per share amounts)	2023	2022	% Change
Cash flow from operating activities from continuing operations	1,796.7	1,828.7	(2)
Adjusted funds flow from continuing operations (1)	1,975.6	1,848.6	7
Net income from continuing operations	799.4	1,146.7	(30)
Net income from continuing operations per share - diluted	1.46	2.01	(27)
Adjusted net earnings from continuing operations (1)	795.9	764.1	4
Adjusted net earnings from continuing operations per share - diluted (1)	1.45	1.34	8

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, 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.

Cash flow from operating activities from continuing operations decreased from $1.83 billion in 2022 to $1.80 billion in 2023.

Exhibit 14

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, 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.

The Company's adjusted funds flow from continuing operations increased from $1.85 billion in 2022 to $1.98 billion in 2023.

Exhibit 15

The Company reported net income from continuing operations of $799.4 million in 2023 ($1.46 per fully diluted share) compared to $1.15 billion in 2022 ($2.01 per fully diluted share).

CRESCENT POINT ENERGY CORP. 14

Exhibit 16

The Company's adjusted net earnings from continuing operations was $795.9 million in 2023 ($1.45 per fully diluted share) compared to $764.1 million in 2022 ($1.34 per fully diluted share).

Exhibit 17

Excess Cash Flow

Excess cash flow decreased from $1.15 billion in 2022 to $981.6 million in 2023, primarily as a result of higher capital expenditures, partially offset by the increase in total adjusted funds flow from operations.

Excess cash flow is a specified financial measures based on total corporate results that does not have any standardized meaning prescribed by IFRS and, therefore, 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.

Discontinued Operations

($ millions, except per share amounts)	2023	2022	% Change
Cash flow from operating activities from discontinued operations	399.0	363.5	10
Adjusted funds flow from discontinued operations (1)	363.5	383.8	(5)
Net income (loss) from discontinued operations	(229.1)	336.7	(168)
Net income (loss) from discontinued operations per share - diluted	(0.42)	0.59	(171)
Adjusted net earnings from discontinued operations (1)	136.7	201.6	(32)
Adjusted net earnings from discontinued operations per share - diluted (1)	0.25	0.35	(29)

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, 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.

Cash flow from operating activities from discontinued operations in 2023 increased to $399.0 million compared to $363.5 million in the same period of 2022. Changes in cash flow from operating activities were due to fluctuations in adjusted FFO and working capital.

In the year ended December 31, 2023, the Company's adjusted funds flow from discontinued operations decreased to $363.5 million from $383.8 million in 2022. The decrease in adjusted funds flow from discontinued operations was primarily due to lower netback from discontinued operations, partially offset by higher production in North Dakota.

CRESCENT POINT ENERGY CORP. 15

The Company recognized a net loss from discontinued operations of $229.1 million for the year ended December 31, 2023 compared to net income from discontinued operations of $336.7 million in the same period of 2022. The net loss for the year ended December 31, 2023 was primarily a result of the impairment expense and fluctuations in deferred tax, partially offset by a foreign exchange gain. Upon disposition of the Company's U.S. operations, the cumulative foreign currency translation recognized in accumulated other comprehensive income was reclassified from shareholders' equity to profit or loss. As a result, the Company recognized a foreign exchange gain of $621.7 million in the year ended December 31, 2023.

The following is a summary of the Company's operating netback and netback from discontinued operations:

($/boe) (1)	2023	2022	% Change
Oil and gas sales	79.64	95.53	(17)
Royalties	(20.26)	(24.46)	(17)
Operating expenses	(10.39)	(12.55)	(17)
Transportation expenses	(1.59)	(1.30)	22
Operating netback from discontinued operations (2)	47.40	57.22	(17)
Realized loss on commodity derivatives	(0.58)	—	—
Netback from discontinued operations (2)	46.82	57.22	(18)

(1)The dominant production category for the Company's discontinued operations is crude oil and condensate. These properties include associated natural gas and NGL volumes, therefore, the total operating netback and netback have been presented.

(2)Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, 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.

The Company's operating netback from discontinued operations for the year ended December 31, 2023 decreased to $47.40 per boe from $57.22 per boe in 2022. The decrease in the operating netback at December 31, 2023, was primarily due to the decrease in average selling price primarily due to the lower WTI benchmark price, partially offset by lower royalties and operating expenses. The decrease in the Company's netback from discontinued operations at December 31, 2023 was a result of the decrease in the operating netback and the realized loss on commodity derivatives in 2023.

Dividends Declared

($ millions, except per share amounts)	2023	2022	% Change
Dividends declared	211.9	200.6	6
Dividends declared per share	0.387	0.360	8

Crescent Point declared $164.2 million of quarterly cash dividends and $47.7 million of special cash dividends in 2023 compared to $181.2 million and $19.4 million, respectively, in 2022.

In 2023, the Company declared total cash dividends of $0.387 per share, compared to $0.360 per share in 2022.

Subsequent to year-end, Crescent Point’s Board of Directors approved and declared a first quarter 2024 quarterly dividend of $0.115 per share, an increase of 15 percent from the prior level. This quarterly dividend increase follows the closing of the Company’s accretive Alberta Montney consolidation in late 2023 and equates to an annualized base dividend of $0.460 per share.

Related Party Transactions

Key management personnel of the Company include its directors and executive officers. In 2023, the Company recorded $7.3 million (2022 – $6.1 million) relating to compensation of key management personnel. In 2023, share-based compensation costs relating to compensation of key management personnel was $19.4 million (2022 – $24.2 million).

Capital Expenditures

($ millions)	2023	2022	% Change
Development capital expenditures	1,138.7	956.1	19
Land expenditures	33.6	19.2	75
Capitalized administration (1)	42.3	49.5	(15)
Corporate assets	5.9	2.6	127
Development capital and other expenditures	1,220.5	1,027.4	19
Total capital acquisitions (2)	4,589.7	90.7	4,960
Total capital dispositions (2)	(613.6)	(283.6)	116
Total (3)	5,196.6	834.5	523

(1)Capitalized administration excludes capitalized equity-settled SBC.

(2)Specified financial measures that does not have any standardized meaning prescribed by IFRS and, therefore 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)Includes both continuing and discontinued operations.

CRESCENT POINT ENERGY CORP. 16

Capital Acquisitions and Dispositions

Corporate Acquisition

Hammerhead Energy Inc.

On December 21, 2023, Crescent Point completed the acquisition, by way of statutory arrangement, of all issued and outstanding common shares of Hammerhead Energy Inc., a public oil and liquids-rich Alberta Montney producer. Total consideration was approximately $2.52 billion, including $1.54 billion of cash, the issuance of 53.2 million common shares, assumed long-term debt and working capital ($2.41 billion was allocated to PP&E and $354.8 million was allocated to E&E assets, including $9.9 million related to decommissioning liability). Long-term debt acquired of $363.8 million was repaid on December 21, 2023.

Major Property Acquisitions and Dispositions

Kaybob Duvernay acquisition

On January 11, 2023, the Company closed the acquisition of Kaybob Duvernay assets in Alberta for total consideration of $370.4 million ($323.7 million was allocated to PP&E and $52.1 million was allocated to E&E, including $5.4 million related to decommissioning liability).

Alberta Montney acquisition

On May 10, 2023, the Company closed the acquisition of Montney assets in Alberta for total consideration of $1.70 billion ($1.62 billion was allocated to PP&E and $108.3 million was allocated to E&E, including $24.6 million related to decommissioning liability).

North Dakota disposition

On October 24, 2023, the Company completed the disposition of its producing North Dakota assets for total consideration of $585.8 million, including interim closing adjustments. Total consideration consisted of $504.6 million (US$372.7 million) in cash and $81.2 million (US$60.0 million) in deferred consideration receivable to be settled in two equal installments due June 2024 and December 2024. These assets had a net carrying value of $595.1 million, resulting in a loss of $9.3 million.

Minor Property Acquisitions and Dispositions

In the year ended December 31, 2023, the Company completed minor property acquisitions and dispositions for net consideration received of $17.3 million. These assets had a net carrying value of $17.2 million, resulting in a gain of $0.1 million.

Assets Held for Sale

At December 31, 2023, the Company had certain non-core assets in its Alberta CGU as held for sale. These assets were recorded at the lesser of their carrying value and recoverable amount. The Company completed the disposition of its Southern Alberta assets in January 2024. Refer to the Subsequent Events section in this MD&A for further information.

Development Capital Expenditures

($ millions)	2023	2022	% Change
Development capital expenditures from continuing operations	844.9	698.0	21
Development capital expenditures from discontinued operations	293.8	258.1	14
Development capital expenditures	1,138.7	956.1	19

The Company's development capital expenditures for the year ended December 31, 2023 were $1.14 billion, compared to $956.1 million in 2022. The increase was primarily due to increased activity in the Alberta Montney and Kaybob Duvernay areas and the higher overall unit costs due to inflationary pressures in 2023 compared to relative average costs in 2022. During 2023, 177 (172.4 net) wells were drilled and $121.8 million was spent on facilities and seismic (2022 - $90.4 million).

Refer to the Guidance section in this MD&A for Crescent Point's development capital expenditure guidance for 2024.

CRESCENT POINT ENERGY CORP. 17

Exhibit 18

Goodwill

The Company's goodwill balance is attributable to corporate acquisitions completed during the period from 2003 through 2023. The goodwill balance as at December 31, 2023 was $275.9 million compared to $203.9 million at December 31, 2022. The increase of $72.0 million is primarily attributable to the Hammerhead acquisition in December 2023.

Other Current Assets

At December 31, 2023, other current assets consist of $79.2 million related to deferred consideration receivable from capital dispositions.

Other Current Liabilities

At December 31, 2023, other current liabilities consist of $37.5 million related to the current portion of long-term share-based compensation, $40.5 million related to the current portion of lease liabilities, and $40.0 million related to decommissioning liability.

Other Long-Term Liabilities

At December 31, 2023, other long-term liabilities consist of $31.0 million of long-term compensation liability related to share-based compensation.

Lease Liability

At December 31, 2023, the Company had $144.7 million of lease liabilities for contracts related to office space, fleet vehicles and equipment.

Decommissioning Liability

The decommissioning liability increased by $34.9 million during 2023, from $703.9 million at December 31, 2022 to $738.8 million at December 31, 2023. The increase primarily relates to liabilities acquired through capital acquisitions, partially offset by the Company's continued abandonment and reclamation program and change in discount and inflation rate estimates. The liability is based on estimated undiscounted cash flows before inflation to settle the obligation of $1.03 billion.

Subsequent to year-end, the Company completed the disposition of its Southern Alberta assets which were classified as held for sale at December 31, 2023. This transaction reduces the Company's decommissioning liability balance by $92.4 million. Refer to the Subsequent Events section in this MD&A for further information.

CRESCENT POINT ENERGY CORP. 18

Liquidity and Capital Resources

Capitalization Table ($ millions, except share, per share, ratio and percent amounts)	December 31, 2023	December 31, 2022
Net debt (1)	3,738.1	1,154.7
Shares outstanding	619,929,490	550,888,983
Market price at end of period (per share)	9.19	9.66
Market capitalization	5,697.2	5,321.6
Enterprise value (1)	9,435.3	6,476.3
Net debt as a percentage of enterprise value (1)	40	18
Adjusted funds flow from operations (1) (2)	2,339.1	2,232.4
Net debt to adjusted funds flow from operations (1)(3)	1.6	0.5

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, 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)The sum of adjusted funds flow from operations for the trailing four quarters. Includes both continuing and discontinued operations.

(3)The net debt reflects the financing of acquisitions, however, the adjusted funds flow from operations only reflects adjusted funds flow from operations generated from the acquired properties since the closing date of the acquisitions.

At December 31, 2023, Crescent Point's enterprise value was $9.44 billion and the Company was capitalized with 60 percent equity compared to $6.48 billion and 82 percent at December 31, 2022, respectively. The Company's net debt to adjusted funds flow from operations ratio at December 31, 2023 increased to 1.6 times from 0.5 times at December 31, 2022. The increase was largely due to higher net debt as a result of the Hammerhead, Alberta Montney and Kaybob Duvernay acquisitions, partially offset by the proceeds of the North Dakota disposition and the bought deal public offering.

Crescent Point's market capitalization increased to $5.70 billion at December 31, 2023 from $5.32 billion at December 31, 2022, primarily due to shares issued in conjunction with the bought deal public offering and the Hammerhead acquisition, partially offset by the decrease in the Company's share price and the impact of shares repurchased throughout the year.

Exhibit 19

(1)The sum of adjusted funds flow from operations for the trailing four quarters.

(2)The net debt reflects the financing of acquisitions, however, the adjusted funds flow from operations only reflects adjusted funds flow from operations generated from the acquired properties since the closing date of the acquisitions.

At December 31, 2023, the Company had combined facilities of $2.76 billion. This includes a $2.26 billion syndicated unsecured credit facility with eleven banks and a $100.0 million unsecured operating credit facility with one Canadian chartered bank, both with a current maturity date of November 26, 2026. Both of these facilities constitute revolving credit facilities and are extendible annually. On May 10, 2023, concurrent with the closing of the Alberta Montney acquisition, Crescent Point entered into an additional $400.0 million syndicated unsecured revolving credit facility with ten banks that matures on May 10, 2025.

On December 21, 2023, concurrent with the closing of the Hammerhead acquisition, the Company entered into a $750.0 million syndicated term loan with twelve banks that matures on November 26, 2026.

At December 31, 2023, the Company had available unused borrowing capacity on its bank credit facilities of approximately $801.1 million, including $26.2 million outstanding in letters of credit and cash of $17.3 million.

At December 31, 2023, the Company had senior guaranteed notes of US$589.5 million and Cdn$105.0 million outstanding. The notes are unsecured and rank pari passu with the Company's bank credit facilities and carry a bullet repayment on maturity. The senior guaranteed notes have financial covenants similar to those of the combined credit facilities described above.

CRESCENT POINT ENERGY CORP. 19

Concurrent with the issuance of senior guaranteed notes with total principal of US$517.0 million, the Company entered into CCS to manage the Company's foreign exchange risk. CCS fixes the US dollar amount of the individual tranches of notes for purposes of interest and principal repayments at a notional amount of $606.9 million. See Note 27 - "Financial Instruments and Derivatives" in the audited consolidated financial statements for the year ended December 31, 2023 for additional information.

The Company is in compliance with all debt covenants at December 31, 2023 which are listed in the table below:

Covenant Description	Maximum Ratio	December 31, 2023
Senior debt to adjusted EBITDA (1) (2)	3.5	1.13
Total debt to adjusted EBITDA (1) (3)	4.0	1.13
Senior debt to capital (2) (4)	0.55	0.35

(1)Adjusted EBITDA is calculated as earnings before interest, taxes, depletion, depreciation, amortization, impairment and impairment reversals, adjusted for certain non-cash items. Adjusted EBITDA is calculated on a trailing twelve month basis adjusted for material acquisitions and dispositions.

(2)Senior debt is calculated as the sum of amounts drawn on the combined facilities, outstanding letters of credit and the principal amount of the senior guaranteed notes.

(3)Total debt is calculated as the sum of senior debt plus subordinated debt. Crescent Point does not have any subordinated debt.

(4)Capital is calculated as the sum of senior debt and shareholders' equity and excludes the effect of unrealized derivative gains or losses and the adoption of IFRS 16.

The Company's ongoing working capital requirements are expected to be financed through cash, adjusted funds flow from operations and its bank credit facilities.

Shareholders' Equity

At December 31, 2023, Crescent Point had 619.9 million common shares issued and outstanding compared to 550.9 million common shares at December 31, 2022. The increase of 69.0 million shares is due to shares issued in conjunction with the bought deal public offering in November 2023 and shares issued as partial consideration for the acquisition of Hammerhead in December 2023, partially offset by shares purchased for cancellation under the Company's Normal Course Issuer Bids ("NCIBs").

As of the date of this report, the Company had 619,949,490 common shares outstanding.

Normal Course Issuer Bids ("NCIBs")    

On March 4, 2022, the Company announced the acceptance by the Toronto Stock Exchange of its notice to implement an NCIB. This NCIB allowed the Company to purchase, for cancellation, up to 57,309,975 common shares, or 10 percent of the Company's public float, as at February 28, 2022. This NCIB commenced on March 9, 2022 and expired on March 8, 2023.

On March 7, 2023, the Company announced the approval by the Toronto Stock Exchange of its notice to implement an NCIB. This NCIB allows the Company to purchase, for cancellation, up to 54,605,659 common shares, or 10 percent of the Company's public float, as at February 23, 2023. This NCIB commenced on March 9, 2023 and is due to expire on March 8, 2024. The Company intends to renew the NCIB.

During the year ended December 31, 2023, the Company purchased 34.6 million common shares for a total consideration of $349.9 million under its NCIBs. The total cost paid, including commissions and fees, was recognized directly as a reduction in shareholders' equity. Under the NCIB, all common shares purchased are cancelled.

Contractual Obligations and Commitments

At December 31, 2023, the Company had contractual obligations and commitments as follows:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Off balance sheet commitments
Operating (1)	15.8	19.7	11.5	7.9	54.9
Gas processing	115.6	193.4	147.9	280.8	737.7
Transportation	186.1	361.5	276.5	524.5	1,348.6
Total contractual commitments (2)	317.5	574.6	435.9	813.2	2,141.2

(1)Includes operating costs on the Company's office space, net of $16.7 million of recoveries from subleases.

(2)Excludes contracts accounted for under IFRS 16. See Note 14 - "Leases" in the annual consolidated financial statements for the year ended December 31, 2023 for further information.

CRESCENT POINT ENERGY CORP. 20

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Other contractual commitments
Senior guaranteed notes (1)	342.8	476.5	27.0	—	846.3
Bank debt (2)	236.3	3,118.8	—	—	3,355.1
Total contractual commitments	579.1	3,595.3	27.0	—	4,201.4

(1)These amounts include the notional principal and interest payments pursuant to the related CCS which fix the amounts due in Canadian dollars. US dollar senior guaranteed notes that do not have any underlying CCS are translated at the period end foreign exchange rate.

(2)These amounts include interest based on debt outstanding and interest rates effective as at December 31, 2023, and includes undiscounted cash outflows pursuant to the CCS related to SOFR loans.

Subsequent Events

Disposition of Southern Alberta Assets

On January 26, 2024, Crescent Point completed the disposition of its Southern Alberta assets for total consideration of approximately $38.1 million, including interim closing adjustments. Total consideration includes $25.0 million of deferred consideration receivable.

Off Balance Sheet Arrangements

The Company has off-balance sheet arrangements consisting of various contracts which are entered into in the normal course of operations. Contracts that contain a lease are accounted for under IFRS 16 and recorded on the balance sheet as at December 31, 2023. All other contracts which are entered into in the normal course of operations are captured in the "off balance sheet commitments" table in the Contractual Obligations and Commitments section above and no asset or liability value has been assigned to these contracts on the balance sheet as at December 31, 2023.

Critical Accounting Estimates

The preparation of the Company’s consolidated financial statements requires management to adopt accounting policies that involve the use of significant estimates and assumptions. These estimates and assumptions are developed based on the best available information and are believed by management to be reasonable under the existing circumstances. New events or additional information may result in the revision of these estimates over time. A summary of the significant accounting policies used by Crescent Point can be found in Note 3 – "Material Accounting Policies" in the audited consolidated financial statements for the year ended December 31, 2023. The following discussion outlines what management believes are the most critical policies involving the use of estimates and assumptions.

Oil and gas activities

Reserves estimates, although not reported as part of the Company’s consolidated financial statements, can have a significant effect on net income, assets and liabilities as a result of their impact on DD&A, decommissioning liability, deferred taxes, asset impairments and impairment reversals, and business combinations. Independent petroleum reservoir engineers perform evaluations of the Company’s oil and gas reserves on an annual or as needed basis. The estimation of oil and gas reserves is an inherently complex process requiring significant judgment. Estimates of economically recoverable oil and gas reserves are based upon a number of variables and assumptions such as production forecasts, commodity prices, costs and related future cash flows, all of which may vary considerably from actual results. These estimates are revised upward or downward over time, as additional information such as reservoir performance becomes available, or as economic conditions change.

For purposes of impairment testing, PP&E is aggregated into CGUs, based on separately identifiable and largely independent cash inflows. The determination of the Company’s CGUs is subject to judgment. Factors considered in the classification of CGUs include the integration between assets, shared infrastructures, the existence of common sales points, geography, geologic structure and the manner in which management monitors and makes decisions regarding operations.

The determination of technical feasibility and commercial viability is subject to judgment as it is based on the presence of reserves and results in the transfer of assets from E&E to PP&E.

Decommissioning liability

Upon retirement of its oil and gas assets, the Company anticipates incurring substantial costs associated with decommissioning. Estimates of these costs are subject to uncertainty associated with the method, timing and extent of future decommissioning activities. The liability, the related asset and the expense are based on estimates with respect to the cost and timing of decommissioning.

Business combinations

Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of PP&E and E&E assets acquired generally require the most judgment and include estimates of oil and gas reserves acquired, forecast benchmark commodity prices and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill. Future net earnings can be affected as a result of changes in future DD&A, asset impairment or goodwill impairment.

CRESCENT POINT ENERGY CORP. 21

Fair value measurement

The estimated fair value of derivative instruments resulting in derivative assets and liabilities, by its very nature, is subject to measurement uncertainty. Estimates included in the determination of the fair value of derivative instruments include forward benchmark prices, discount rates, share price and forward foreign exchange rates.

Joint control

Judgment is required to determine when the Company has joint control over an arrangement, which requires an assessment of the capital and operating activities of the projects it undertakes with partners and when the decisions in relation to those activities require unanimous consent.

Share-based compensation

Compensation costs recorded pursuant to share-based compensation plans are subject to estimated fair values, forfeiture rates and the future attainment of performance criteria.

Income taxes

Tax regulations and legislation and the interpretations thereof are subject to change. In addition, deferred income tax assets and liabilities recognize the extent that temporary differences will be receivable and payable in future periods. The calculation of the related asset and liability involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, expected cash flows from estimated proved plus probable oil and gas reserves and the application of tax laws. Changes in tax regulations and legislation and the other assumptions listed are subject to measurement uncertainty.

Risk Factors

Financial Risk

Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions that could have an impact on Crescent Point’s business. Financial risks the Company is exposed to include: marketing production at an acceptable price given market conditions and market access; finding and producing oil and gas reserves at a reasonable cost; volatility in market prices for oil and natural gas; volatility in crude oil price differentials; fluctuations in foreign exchange and interest rates; stock market volatility; debt service which may limit timing or amount of dividends as well as market price of shares; the continued availability of adequate debt and equity financing and cash flow to fund planned expenditures; sufficient liquidity for future operations; lost revenue or increased expenditures as a result of delayed or denied environmental, safety or regulatory approvals; adverse changes to income tax laws or other laws or government incentive programs and regulations relating to the oil and gas industry; cost of capital risk to carry out the Company’s operations; and uncertainties associated with credit facilities and counterparty credit risk.

Operational Risk

Operational risk is the risk of loss or lost opportunity resulting from operating and capital activities that, by their nature, could have an impact on the Company’s ability to achieve objectives. Operational risks to which Crescent Point is exposed include: uncertainties associated with estimating oil and natural gas reserves; incorrect assessments of the value of acquisitions and exploration and development programs; failure to realize the anticipated benefits of acquisitions and dispositions; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; inability to secure adequate product transportation including sufficient crude-by-rail or other alternate transportation; delays in business operations, pipeline restrictions, public infrastructure constraints including blockades and blowouts; unforeseen title defects; increased competition for, among other things, capital, acquisitions of oil and gas reserves and undeveloped lands; competition for and availability of qualified personnel or management; outbreaks; mobility restrictions, loss and health of key personnel; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; competitive action by other companies; the ability of suppliers to meet commitments and risks; and cyber security risks.

Potential drought conditions can result in a higher likelihood of water restrictions and increased susceptibility to wildfire conditions. During drought conditions provincial regulators can restrict water licence allocations and limit the water we use that are critical to our operations. Wildfires may restrict the Company's ability to access and operate its properties and cause operational difficulties, including damage to equipment and infrastructure. Wildfires also increase the risk of personnel injury as a result of dangerous working conditions.

CRESCENT POINT ENERGY CORP. 22

Safety, Environmental and Regulatory Risks

Safety, environmental and regulatory risks are the risks of loss or lost opportunity resulting from changes to laws governing safety, the environment, royalties and taxation. Safety, environmental and regulatory risks Crescent Point is exposed to include: the risk of wildfires or drought; indigenous land claims; uncertainties associated with regulatory approvals; uncertainty of government policy changes; the risk of carrying out operations with minimal environmental impact; changes in or adoption of new laws and regulations or changes in how they are interpreted or enforced; obtaining required approvals of regulatory authorities and stakeholder support for activities and growth plans.

The Company’s operations are subject to costs being incurred to pay carbon taxes, to reduce Greenhouse Gas ("GHG") emissions (including methane emissions) and to perform necessary monitoring, measurement, verification and reporting of GHG emissions. Future environmental legislation may require further reductions in emissions from the Company’s operations and result in increased capital and operational expenditures related to the transition to a low-carbon economy.

Refer to the Company's Annual Information Form for the year ended December 31, 2023 for additional information on the Company's risk factors.

Risk Management

Crescent Point is committed to identifying and managing its risks in the near term, as well as on a strategic and longer term basis at all levels in the organization in accordance with the Company's Board-approved Risk Management and Counterparty Credit Policy and risk management programs. Issues affecting, or with the potential to affect, our assets, operations and/or reputation, are generally of a strategic nature or are emerging issues that can be identified early and then managed, but occasionally include unforeseen issues that arise unexpectedly and must be managed on an urgent basis. Crescent Point takes a proactive approach to the identification and management of issues that can affect the Company’s assets, operations and/or reputation and have established consistent and clear policies, procedures, guidelines and responsibilities for issue identification and management.

Specific actions Crescent Point takes to ensure effective risk management include but are not limited to: employing qualified professional and technical staff; concentrating in a limited number of areas with lower risk development projects; utilizing market proven technology for finding and developing oil and gas reserves; constructing quality, environmentally sensitive and safe production facilities; adopting and communicating sound policies governing all areas of our business; maximizing operational control of drilling and production operations; strategic hedging program including commodity prices, interest and foreign exchange rates; adhering to conservative borrowing guidelines and maintaining significant liquidity; monitoring counterparty creditworthiness and obtaining supplementary credit protection when warranted.

Changes in Accounting Policies

Income Taxes

IAS 12 Income Taxes was amended in May 2021 by the International Accounting Standards Board which requires companies, on initial recognition, to recognize deferred tax on transactions that result in equal amounts of taxable and deductible temporary differences. The Company adopted the amendment in 2023 and the adoption did not have an impact on the Company's consolidated financial statements.

New accounting standards and amendments not yet adopted

Income Taxes

IAS 12 Income Taxes was amended in May 2023 by the International Accounting Standards Board to provide guidance on current and deferred taxes arising from Pillar Two model rules published by the Organisation for Economic Co-operation and Development. The adoption of this amendment is not expected to have an impact on the Company's consolidated financial statements.

Presentation of Financial Statements

IAS 1 Presentation of Financial Statements was amended in January 2020 by the International Accounting Standards Board to clarify the presentation requirements of liabilities as either current or non-current within the statement of financial position. This amendment is effective for fiscal years beginning on or after January 1, 2024. The adoption of this amendment is not expected to have an impact on the Company's consolidated financial statements.

CRESCENT POINT ENERGY CORP. 23

Selected Annual Information

($ millions, except per share amounts)	2023	2022	2021
Oil and gas sales from continuing operations	3,499.0	3,847.0	2,735.3
Total oil and gas sales	4,111.9	4,493.1	3,206.5
Average daily production from continuing operations
Crude oil and condensate (bbls/d)	88,087	79,323	82,435
NGLs (bbls/d)	15,026	13,079	13,386
Natural gas (mcf/d)	211,275	128,099	100,868
Production from continuing operations (boe/d)	138,326	113,752	112,632
Total average daily production (boe/d)	159,411	132,282	132,683
Net income from continuing operations	799.4	1,146.7	1,873.6
Net income per share from continuing operations - diluted	1.46	2.01	3.26
Net income	570.3	1,483.4	2,364.1
Net income per share - diluted	1.04	2.60	4.11
Adjusted net earnings from continuing operations (1)	795.9	764.1	409.1
Adjusted net earnings from continuing operations per share – diluted (1)	1.45	1.34	0.71
Adjusted net earnings from operations (1)	932.6	965.7	515.3
Adjusted net earnings from operations per share – diluted (1)	1.70	1.69	0.90
Cash flow from operating activities from continuing operations	1,796.7	1,828.7	1,237.8
Cash flow from operating activities	2,195.7	2,192.2	1,495.8
Adjusted funds flow from continuing operations (1)	1,975.6	1,848.6	1,223.0
Adjusted funds flow from operations (1)	2,339.1	2,232.4	1,476.9
Adjusted working capital surplus (deficiency) (1)	(196.3)	95.1	(201.6)
Total assets	12,775.7	9,486.4	9,171.2
Total liabilities	5,908.2	2,993.0	3,765.9
Net debt (1)	3,738.1	1,154.7	2,005.0
Weighted average shares - diluted (millions)	548.3	571.1	575.1
Total capital acquisitions	4,589.7	90.7	942.4
Total capital dispositions	(613.6)	(283.6)	(99.0)
Development capital expenditures from continuing operations	844.9	698.0	517.7
Development capital expenditures	1,138.7	956.1	624.2
Dividends declared	211.9	200.6	47.8
Dividends declared per share	0.3870	0.3600	0.0825

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, 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.

Crescent Point’s oil and gas sales, cash flow from operating activities, adjusted funds flow from operations and total assets have fluctuated for the years 2021 through 2023, primarily due to changes in the Cdn$ WTI benchmark prices and corporate oil price differentials, numerous acquisitions and dispositions and the Company's drilling program.

Net income over the past three years has fluctuated, primarily due to unrealized derivative gains and losses on commodity contracts, which fluctuate with changes in market conditions, and PP&E impairment charges and reversals, along with associated fluctuations in deferred tax expense (recovery).

Adjusted net earnings from operations fluctuated over the past three years, primarily due to changes in adjusted funds flow from operations, depletion and share-based compensation expense along with associated fluctuations in deferred tax expense (recovery).

CRESCENT POINT ENERGY CORP. 24

Summary of Quarterly Results

	2023				2022
($ millions, except per share amounts)	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Oil and gas sales from continuing operations	946.7	998.7	791.6	762.0	864.2	930.3	1,120.5	932.0
Total oil and gas sales	1,012.4	1,236.3	949.6	913.6	1,016.6	1,097.3	1,286.5	1,092.7
Average daily production from continuing operations
Crude oil and condensate (bbls/d)	96,144	92,824	84,944	78,191	78,051	79,077	79,767	80,428
NGLs (bbls/d)	16,023	16,119	14,360	13,562	13,427	13,070	12,962	12,849
Natural gas (mcf/d)	248,306	244,777	192,964	157,690	139,206	131,377	120,635	120,942
Production from continuing operations (boe/d)	153,551	149,739	131,465	118,035	114,679	114,043	112,835	113,435
Total average daily production (boe/d)	162,269	180,581	155,031	139,280	134,124	133,019	129,176	132,788
Net income (loss) from continuing operations	302.6	133.6	178.4	184.8	(577.8)	415.1	279.6	1,029.8
Net income (loss) per share from continuing operations - diluted	0.54	0.25	0.33	0.33	(1.04)	0.73	0.49	1.77
Net income (loss)	951.2	(809.9)	212.3	216.7	(498.1)	466.4	331.5	1,183.6
Net income (loss) per share – diluted	1.70	(1.52)	0.39	0.39	(0.90)	0.82	0.58	2.03
Adjusted net earnings from continuing operations (1)	210.0	226.6	171.6	187.7	165.5	195.7	212.5	190.3
Adjusted net earnings from continuing operations per share – diluted (1)	0.37	0.42	0.32	0.34	0.30	0.35	0.37	0.33
Adjusted net earnings from operations (1)	192.8	315.5	205.4	218.9	209.8	242.9	272.1	240.9
Adjusted net earnings from operations per share – diluted (1)	0.34	0.59	0.38	0.40	0.38	0.43	0.47	0.41
Cash flow from operating activities from continuing operations	524.0	537.1	365.9	369.8	507.5	530.5	435.5	355.2
Cash flow from operating activities	611.3	648.9	462.1	473.4	589.5	647.0	529.6	426.1
Adjusted funds flow from continuing operations (1)	535.1	548.6	453.4	438.6	430.9	479.1	497.2	441.4
Adjusted funds flow from operations (1)	574.5	687.1	552.6	524.9	522.8	576.5	599.1	534.0
Adjusted working capital surplus (deficiency) (1)	(196.3)	(45.7)	(82.5)	(79.9)	95.1	47.9	(40.9)	(91.8)
Total assets	12,775.7	10,371.0	11,277.2	9,759.6	9,486.4	10,437.6	10,279.4	10,412.5
Total liabilities	5,908.2	4,660.6	4,597.5	3,113.8	2,993.0	3,224.6	3,501.3	3,901.2
Net debt (1)	3,738.1	2,876.2	3,000.7	1,436.3	1,154.7	1,198.3	1,467.9	1,775.2
Weighted average shares – diluted (millions)	559.1	536.9	545.3	552.7	559.2	567.4	575.9	582.7
Total capital acquisitions	2,513.9	1.1	1,702.7	372.0	1.3	88.2	0.3	0.9
Total capital dispositions	(602.4)	(0.2)	(8.4)	(2.6)	1.2	(244.1)	(37.8)	(2.9)
Development capital expenditures from continuing operations	276.0	260.4	123.5	185.0	160.5	224.3	140.8	172.4
Development capital expenditures	278.9	315.5	230.1	314.2	246.4	308.5	196.9	204.3
Dividends declared	68.3	71.7	54.8	17.1	118.8	44.9	37.1	(0.2)
Dividends declared per share	0.120	0.135	0.100	0.032	0.215	0.080	0.065	—

(1)Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, 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.

Over the past eight quarters, the Company's oil and gas sales have fluctuated due to volatility in the crude oil, condensate and natural gas benchmark prices, changes in production and fluctuations in corporate oil price differentials. The Company's production has fluctuated due to changes in its development capital spending levels, acquisitions and dispositions and natural declines.

Net income (loss) has fluctuated over the past eight quarters, primarily due to changes in PP&E impairment charges and reversals, changes in adjusted funds flow from operations, unrealized derivative gains and losses, which fluctuate with changes in forward market prices and foreign exchange rates, gains and losses on capital dispositions, and fluctuations in deferred tax expense.

CRESCENT POINT ENERGY CORP. 25

Adjusted net earnings from operations has fluctuated over the past eight quarters, primarily due to changes in adjusted funds flow from operations, depletion and share-based compensation expense along with associated fluctuations in deferred tax expense.

Capital expenditures have also fluctuated throughout this period due to the timing of acquisitions, dispositions and changes in the Company's development capital spending levels which vary based on a number of factors, including the prevailing commodity price environment.

CRESCENT POINT ENERGY CORP. 26

Fourth Quarter 2023 Review

•Crescent Point's total production averaged 162,269 boe/d in the fourth quarter of 2023, weighted 74 percent towards crude oil and liquids.

•Adjusted funds flow from operations totaled $574.5 million in the fourth quarter of 2023, a 16 percent decrease from $687.1 million in the third quarter of 2023. The decrease was primarily attributable to lower WTI pricing and a wider corporate differential.

•During the fourth quarter of 2023, the Company spent $239.1 million on drilling and development activities, drilling 49 (48.1 net) wells. Crescent Point also spent $39.8 million on facilities and seismic, for total development capital expenditures of $278.9 million.

•Net debt increased by $861.9 million in the fourth quarter of 2023 to $3.74 billion or 1.6 times trailing adjusted funds flow from operations. The increase was primarily due to the Hammerhead acquisition, partially offset by the proceeds from the North Dakota acquisition and the bought deal public offering.

Disclosure Controls and Procedures

Disclosure controls and procedures (“DC&P”), as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, are designed to provide reasonable assurance that information required to be disclosed in the Company’s annual filings, interim filings or other reports filed, or submitted by the Company under securities legislation is recorded, processed, summarized and reported within the time periods specified under securities legislation and include controls and procedures designed to ensure that information required to be so disclosed is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The Chief Executive Officer and the Chief Financial Officer of Crescent Point evaluated the effectiveness of the design and operation of the Company’s DC&P. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that Crescent Point’s DC&P were effective as at December 31, 2023.

Internal Controls over Financial Reporting

Internal control over financial reporting (“ICFR”), as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109 - Certification of Disclosure in Issuers' Annual and Interim Filings, includes those policies and procedures that:

1.pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets of Crescent Point;

2.are designed to 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 Crescent Point are being made in accordance with authorizations of management and Directors of Crescent Point; and

3.are designed to 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 annual financial statements or interim financial reports.

Management is responsible for establishing and maintaining ICFR for Crescent Point. They have, as at the financial year ended December 31, 2023, designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The control framework Crescent Point’s officers used to design the Company’s ICFR is the Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

Under the supervision of Management, Crescent Point conducted an evaluation of the effectiveness of the Company’s ICFR as at December 31, 2023 based on the COSO Framework. Based on this evaluation, Management concluded that as of December 31, 2023, Crescent Point maintained effective ICFR.

The effectiveness of Crescent Point's ICFR as of December 31, 2023 was audited by PricewaterhouseCoopers LLP, as reflected in their report accompanying the Company's financial statements for the year ended December 31, 2023. Other than as described below, there were no changes in Crescent Point’s ICFR during the year ended December 31, 2023 that materially affected, or are reasonably likely to materially affect, the Company’s ICFR. On October 24, 2023, the Company closed the disposition of its producing assets in North Dakota which allowed it to eliminate the key ICFR specific to its US operations.

It should be noted that while Crescent Point’s officers believe that the Company’s controls provide a reasonable level of assurance with regard to their effectiveness, they do not expect that the DC&P and ICFR will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system are met.

CRESCENT POINT ENERGY CORP. 27

Guidance

Crescent Point's guidance for 2024 is as follows:

Total Annual Average Production (boe/d) (1)	198,000 - 206,000
Capital Expenditures
Development capital expenditures ($ millions)	$1,400 - $1,500
Capitalized administration ($ millions)	$40
Total ($ millions) (2)	$1,440 - $1,540
Other Information
Reclamation activities ($ millions) (3)	$40
Capital lease payments ($ millions)	$20
Annual operating expenses ($/boe)	$12.75 - $13.75
Royalties	10.00% - 11.00%

(1)Total annual average production (boe/d) is comprised of approximately 65% Oil, Condensate & NGLs and 35% Natural Gas.

(2)Land expenditures and net property acquisitions and dispositions are not included. Development capital expenditures spend is allocated on an approximate basis as follows: 90% drilling & development and 10% facilities & seismic.

(3)Reflects Crescent Point's portion of its expected total budget.

Return of Capital Outlook

Base Dividend
Current quarterly base dividend per share	$0.115
Total Return of Capital
% of excess cash flow (1)	60%

(1)Total return of capital is based on a framework that targets to return to shareholders 60% of excess cash flow on an annual basis. Refer to the Specified Financial Measures section in this MD&A for further information on base dividends and excess cash flow.

Additional information relating to Crescent Point, including the Company's December 31, 2023 Annual Information Form, which along with other relevant documents are available on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov/edgar.

CRESCENT POINT ENERGY CORP. 28

Specified Financial Measures

Throughout this MD&A, the Company uses the terms “total operating netback”, "total operating netback from continuing operations", "total operating netback from discontinued operations", “total netback”, “total netback from continuing operations”, “total netback from discontinued operations”, "operating netback", "netback", “adjusted funds flow from operations” (or "adjusted FFO"), “adjusted funds flow from continuing operations”, “adjusted funds flow from discontinued operations”, "excess cash flow", "base dividends", "adjusted working capital (surplus) deficiency", “net debt”, “enterprise value”, “net debt to adjusted funds flow from operations”, "net debt as a percentage of enterprise value", “adjusted net earnings from operations”, “adjusted net earnings from continuing operations”, “adjusted net earnings from continuing operations per share – diluted”, “adjusted net earnings from discontinued operations”, “adjusted net earnings from discontinued operations per share – diluted”, “adjusted net earnings from operations per share”, “adjusted net earnings from operations per share - diluted”, "total capital acquisitions" and "total capital dispositions". These terms do not have any standardized meaning as prescribed by IASB and, therefore, may not be comparable with the calculation of similar measures presented by other issuers.

Total operating netback and total netback are historical non-GAAP financial measures. Total operating netback is calculated as oil and gas sales, less royalties, operating and transportation expenses. Total netback is calculated as total operating netback plus realized commodity derivative gains and losses. Total operating netback and total netback are common metrics used in the oil and gas industry and are used to measure operating results to better analyze performance against prior periods on a comparable basis. The most directly comparable financial measure to total operating netback and total netback is oil and gas sales.

The following table reconciles oil and gas sales to total operating netback and total netback from continuing operations:

($ millions)	2023	2022	% Change
Oil and gas sales	3,499.0	3,847.0	(9)
Royalties	(375.3)	(435.5)	(14)
Operating expenses	(770.5)	(628.2)	23
Transportation expenses	(174.3)	(131.0)	33
Total operating netback from continuing operations	2,178.9	2,652.3	(18)
Realized gain (loss) on commodity derivatives	15.5	(641.8)	(102)
Total netback from continuing operations	2,194.4	2,010.5	9

The following table reconciles oil and gas sales to total operating netback and total netback from discontinued operations:

($ millions) (1)	2023	2022	% Change
Oil and gas sales	612.9	646.1	(5)
Royalties	(155.9)	(165.4)	(6)
Operating expenses	(80.0)	(84.9)	(6)
Transportation expenses	(12.2)	(8.8)	39
Total operating netback from discontinued operations	364.8	387.0	(6)
Realized loss on commodity derivatives	(4.5)	—	100
Total netback from discontinued operations	360.3	387.0	(7)

(1)See Note 9 - "Discontinued Operations" in the audited consolidated financial statements for the period ended December 31, 2023 for further information.

The following tables reconcile total operating netback and total netback from continuing and discontinued operations:

($ millions)	2023	2022	% Change
Total operating netback from continuing operations	2,178.9	2,652.3	(18)
Total operating netback from discontinued operations	364.8	387.0	(6)
Total operating netback	2,543.7	3,039.3	(16)

($ millions)	2023	2022	% Change
Total netback from continuing operations	2,194.4	2,010.5	9
Total netback from discontinued operations	360.3	387.0	(7)
Total netback	2,554.7	2,397.5	7

Operating netback and netback are non-GAAP ratios and are calculated as total operating netback and total netback, respectively, divided by total production. Operating netback and netback are common metrics used in the oil and gas industry and are used to measure operating results on a per boe basis.

Base dividends is a historical non-GAAP financial measure and is calculated as dividends declared less special dividends declared as part of the Company’s return of capital framework and adjusted for timing of the dividend record date. Base dividends are based on a framework that targets dividend sustainability at lower commodity prices, allows for flexibility in the capital allocation process and dividend growth over time, and assists in determining the additional return of capital to shareholders as part of the Company’s return of capital framework.

CRESCENT POINT ENERGY CORP. 29

Adjusted funds flow from operations is a capital management measure and is calculated based on cash flow from operating activities before changes in non-cash working capital, transaction costs and decommissioning expenditures funded by the Company. Transaction costs are excluded as they vary based on the Company's acquisition and disposition activity and to ensure that this metric is more comparable between periods. Decommissioning expenditures are discretionary and are excluded as they may vary based on the stage of the Company's assets and operating areas. The most directly comparable financial measure to adjusted funds flow from operations is cash flow from operating activities. Adjusted funds flow from operations is a key measure that assesses the ability of the Company to finance dividends, potential share repurchases, operating activities, capital expenditures and debt repayments. Adjusted funds flow from operations as presented is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. See Note 19 – "Capital Management" in the audited consolidated financial statements for the year ended December 31, 2023 for additional information on the Company's capital management.

Excess cash flow is a historical non-GAAP financial measure and is defined as adjusted funds flow from operations less development capital and other expenditures, payments on lease liability, decommissioning expenditures funded by the Company, unrealized gains and losses on equity derivative contracts, transaction costs and other items (excluding net acquisitions and dispositions). The Company has separated transaction costs and unrealized loss on equity derivative contracts from "other items" due to the materiality of the amounts in 2023. The prior period presentation has been revised to reflect current period presentation. The most directly comparable financial measure to excess cash flow disclosed in the Company's financial statements is cash flow from operating activities. Excess cash flow is a key measure that assesses the ability of the Company to finance dividends, potential share repurchases, debt repayments and returns-based growth.

The following table reconciles cash flow from operating activities to adjusted funds flow from operations and excess cash flow:

($ millions)	2023	2022 (1)	% Change
Cash flow from operating activities	2,195.7	2,192.2	—
Changes in non-cash working capital	54.9	15.0	266
Transaction costs	48.5	5.1	851
Decommissioning expenditures (2)	40.0	20.1	99
Adjusted funds flow from operations	2,339.1	2,232.4	5
Development capital and other expenditures	(1,220.5)	(1,027.4)	19
Payments on lease liability	(20.8)	(20.4)	2
Decommissioning expenditures	(40.0)	(20.1)	99
Unrealized loss on equity derivative contracts	(29.3)	(2.9)	910
Transaction costs	(48.5)	(5.1)	851
Other items (3)	1.6	(4.3)	(137)
Excess cash flow	981.6	1,152.2	(15)

(1) Comparative period revised to reflect current period presentation.

(2) Excludes amounts received from government grant programs.

(3) Other items exclude net acquisitions and dispositions.

The following table reconciles cash flow from operating activities from discontinued operations to adjusted funds flow from discontinued operations:

($ millions)	2023	2022	% Change
Cash flow from operating activities from discontinued operations	399.0	363.5	10
Changes in non-cash working capital	(44.6)	19.8	(325)
Transaction costs	8.7	0.5	1,640
Decommissioning expenditures (1)	0.4	—	100
Adjusted funds flow from discontinued operations	363.5	383.8	(5)

(1) Excludes amounts received from government grant programs.

The following tables reconcile cash flow from operating activities and adjusted funds flow from operations from continuing and discontinued operations:

($ millions)	2023	2022	% Change
Cash flow from operating activities from continuing operations	1,796.7	1,828.7	(2)
Cash flow from operating activities from discontinued operations	399.0	363.5	10
Cash flow from operating activities	2,195.7	2,192.2	—

($ millions)	2023	2022	% Change
Adjusted funds flow from continuing operations	1,975.6	1,848.6	7
Adjusted funds flow from discontinued operations	363.5	383.8	(5)
Adjusted funds flow from operations	2,339.1	2,232.4	5

CRESCENT POINT ENERGY CORP. 30

Adjusted working capital (surplus) deficiency is a capital management measure and is calculated as accounts payable and accrued liabilities, dividends payable and long-term compensation liability net of equity derivative contracts, less cash, accounts receivable, prepaids and deposits and other current assets. The Company has added other current assets to the adjusted working capital (surplus) deficiency calculation to reflect current period presentation on the balance sheet and to include deferred consideration incurred in 2023. The prior period presentation has been revised as a result. Adjusted working capital (surplus) deficiency is a component of net debt and is a measure of the Company's liquidity.

The following table reconciles adjusted working capital (surplus) deficiency:

($ millions)	2023	2022	% Change
Accounts payable and accrued liabilities	634.9	448.2	42
Dividends payable	56.8	99.4	(43)
Long-term compensation liability (1)	66.8	59.2	13
Cash	(17.3)	(289.9)	(94)
Accounts receivable	(377.9)	(327.8)	15
Prepaids and deposits	(87.8)	(65.5)	34
Other current assets (2)	(79.2)	(18.7)	324
Adjusted working capital (surplus) deficiency	196.3	(95.1)	(306)

(1)Includes current portion of long-term compensation liability and is net of equity derivative contracts.

(2)Includes deferred consideration receivable and deposit on acquisition.

Net debt is a capital management measure and is calculated as long-term debt plus adjusted working capital (surplus) deficiency, excluding the unrealized foreign exchange on translation of hedged US dollar long-term debt. The most directly comparable financial measure to net debt disclosed in the Company's financial statements is long-term debt. Net debt is a key measure of the Company's liquidity.

The following table reconciles long-term debt to net debt:

($ millions)	2023	2022	% Change
Long-term debt (1)	3,566.3	1,441.5	147
Adjusted working capital (surplus) deficiency	196.3	(95.1)	(306)
Unrealized foreign exchange on translation of hedged US dollar long-term debt	(24.5)	(191.7)	(87)
Net debt	3,738.1	1,154.7	224

(1)Includes current portion of long-term debt.

Enterprise value is a supplementary financial measure and is calculated as market capitalization plus net debt. Enterprise value is used to assess the valuation of the Company. Refer to the Liquidity and Capital Resources section in this MD&A for further information.

Net debt to adjusted funds flow from operations is a capital management measure and is calculated as the period end net debt divided by the sum of adjusted funds flow from operations for the trailing four quarters. Net debt as a percentage of enterprise value is a supplementary financial measure and is calculated as net debt divided by enterprise value. The measures of net debt to adjusted funds flow from operations and net debt as a percentage of enterprise value are used to measure the Company's overall debt position and to measure the strength of the Company's balance sheet. Crescent Point monitors these measures and uses them as key measures in capital allocation decisions including capital spending levels, returns to shareholders including dividends and share repurchases, and financial considerations.

Adjusted net earnings from operations is a historical non-GAAP financial measure and is calculated based on net income before amortization of E&E undeveloped land, impairment or impairment reversals, unrealized derivative gains or losses, unrealized foreign exchange gain or loss on translation of hedged US dollar long-term debt, unrealized gains or losses on long-term investments, gains or losses on the sale of long-term investments, gains or losses on capital acquisitions and dispositions, cumulative foreign currency translation of discontinued foreign operations, and deferred tax related to these adjustments. Adjusted net earnings from operations is a key measure of financial performance that is more comparable between periods. The most directly comparable financial measure to adjusted net earnings from operations disclosed in the Company's financial statements is net income.

CRESCENT POINT ENERGY CORP. 31

The following table reconciles net income to adjusted net earnings from operations:

($ millions)	2023	2022	% Change
Net income	570.3	1,483.4	(62)
Amortization of E&E undeveloped land	30.9	15.2	103
Impairment (impairment reversal)	822.2	(428.6)	(292)
Unrealized derivative (gains) losses	56.9	(171.0)	(133)
Unrealized foreign exchange (gain) loss on translation of hedged US dollar long-term debt	(168.6)	27.7	(709)
Net (gain) loss on capital dispositions	9.6	(25.9)	(137)
Reclassification of cumulative foreign currency translation of discontinued foreign operations	(621.7)	—	100
Deferred tax adjustments	233.0	64.9	259
Adjusted net earnings from operations	932.6	965.7	(3)

The following table reconciles net income (loss) from discontinued operations to adjusted net earnings from discontinued operations:

($ millions)	2023	2022	% Change
Net income (loss) from discontinued operations	(229.1)	336.7	(168)
Amortization of E&E undeveloped land	—	—	100
Impairment (impairment reversal)	728.4	(71.3)	(1,122)
Unrealized derivative losses	18.9	—	100
Net loss on capital dispositions	9.0	0.2	4,400
Reclassification of cumulative foreign currency translation of discontinued foreign operations	(621.7)	—	100
Deferred tax adjustments	231.2	(64.0)	(461)
Adjusted net earnings from discontinued operations	136.7	201.6	(32)

The following table reconciles adjusted net earnings from continuing and discontinued operations:

($ millions)	2023	2022	% Change
Adjusted net earnings from continuing operations	795.9	764.1	4
Adjusted net earnings from discontinued operations	136.7	201.6	(32)
Adjusted net earnings from operations	932.6	965.7	(3)

Adjusted net earnings from operations per share and adjusted net earnings from operations per share - diluted are non-GAAP ratios and are calculated as adjusted net earnings from operations divided by the number of weighted average basic and diluted shares outstanding, respectively. Adjusted net earnings from operations presents a measure of financial performance that is more comparable between periods. Adjusted net earnings from operations as presented is not intended to represent net earnings or other measures of financial performance calculated in accordance with IFRS.

The following table reconciles capital acquisitions, net of cash acquired to total capital acquisitions:

($ millions)	2023	2022	% Change
Capital acquisitions, net of cash acquired	3,616.2	90.7	3,887
Common shares issued on capital acquisition	493.0	—	100
Working capital acquired through capital acquisition	116.7	—	100
Long-term debt acquired through capital acquisition	363.8	—	100
Total capital acquisitions	4,589.7	90.7	4,960

The following table reconciles capital dispositions to total capital dispositions:

($ millions)	2023	2022	% Change
Capital dispositions	(604.5)	(283.6)	113
Working capital disposed through capital disposition	(9.1)	—	100
Total capital dispositions	(613.6)	(283.6)	116

Total capital acquisitions and total capital dispositions are non-GAAP financial measures. Total capital acquisitions are calculated as capital acquisitions, net of cash acquired plus common shares issued on capital acquisition, working capital acquired through capital acquisition and long-term debt acquired through capital acquisition. Total capital dispositions are calculated as capital dispositions less working capital disposed through capital dispositions. Total capital acquisitions and total capital dispositions present the total consideration, including share consideration and working capital, that are included in corporate acquisitions.

Management believes the presentation of the specified financial measures above provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis.

CRESCENT POINT ENERGY CORP. 32

Forward-Looking Information

Certain statements contained in this management's discussion and analysis constitute forward-looking statements and are based on Crescent Point's beliefs and assumptions based on information available at the time the assumption was made. By its nature, such forward-looking information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Company believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. These statements are effective only as of the date of this report. Crescent Point undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required to do so pursuant to applicable law. Refer to Crescent Point's news release dated November 6, 2023 available at www.sedarplus.ca.

Any “financial outlook” or “future oriented financial information” in this management’s discussion and analysis, as defined by applicable securities legislation, have been approved by management of Crescent Point. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

Certain statements contained in this MD&A, including statements related to Crescent Point's capital expenditures, projected asset growth, view and outlook toward future commodity prices, drilling activity and statements that contain words such as "could", "should", "can", "anticipate", "expect", "believe", "will", "may", “projected”, “sustain”, “continues”, “strategy”, “potential”, “projects”, “grow”, “take advantage”, “estimate” and similar expressions and statements relating to matters that are not historical facts constitute "forward-looking information" within the meaning of applicable Canadian securities legislation. The material assumptions and factors in making these forward-looking statements are disclosed in this MD&A under the headings "Overview", "Commodity Derivatives", “Liquidity and Capital Resources” and “Guidance”.

In particular, forward-looking statements include:

l Crescent Point's approach to proactively manage the risk exposure inherent in movements in the price of crude oil, propane, natural gas, the Company's share price, the US/Cdn dollar exchange rate and interest rates through the use of derivatives with investment-grade counterparties; l Crescent Point's use of derivatives to reduce the volatility of the selling price of its crude oil and natural gas production and how this provides a measure of stability to cash flow; l The extent and effectiveness of hedges; l Commitment to shareholder returns; l Over 20 years of premium drilling inventory; l Expectations of generating strong returns and excess cash flow to provide continued returns to shareholders; l Crescent Point's 2024 production and capital expenditures guidance, and other information forming part of the 2024 guidance; l Crescent Point's return of capital outlook including dividend expectations and additional return of capital target as a percentage of excess cash flow; l The Company's liquidity and financial flexibility; l Timing for closing Swan Hills disposition; l Benefits and expectations of the Montney assets; l Focus on reducing net debt; l Impacts of changes in accounting policies; l Materiality enhanced long-term sustainability of the business; l NCIB expectations; and l Estimated undiscounted and uninflated cash flows to settle decommissioning liability.

This information contains certain forward-looking estimates that involve substantial known and unknown risks and uncertainties, many of which are beyond Crescent Point's control. Such risks and uncertainties include, but are not limited to: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas, decisions or actions of OPEC and non-OPEC countries in respect of supplies of oil and gas; delays in business operations or delivery of services due to pipeline restrictions, rail blockades, outbreaks, pandemics, and blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; risks and uncertainties related to oil and gas interests and operations on Indigenous lands; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value and likelihood of acquisitions and dispositions, and exploration and development programs; unexpected geological, technical, drilling, construction, processing and transportation problems; the impacts of drought, wildfires and severe weather events; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; general economic, market and business conditions, including uncertainty in the demand for oil and gas and economic activity in general; changes in interest rates and inflation; uncertainties associated with regulatory approvals; geopolitical conflicts, including the Russian invasion of Ukraine and conflict between Israel and Hamas; uncertainty of government policy changes; the impact of the implementation of the Canada-United States-Mexico Agreement; uncertainty regarding the benefits and costs of dispositions; failure to complete acquisitions and dispositions; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry; and other factors, many of which are outside the control of the Company.

CRESCENT POINT ENERGY CORP. 33

Therefore, Crescent Point's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking estimates and if such actual results, performance or achievements transpire or occur, or if any of them do so, there can be no certainty as to what benefits or detriments Crescent Point will derive therefrom.

Crude oil and condensate, and natural gas information is provided in accordance with the United States Financial Accounting Standards Board ("FASB") Topic 932 - "Extractive Activities - Oil and Gas" and where applicable, financial information is prepared in accordance with International Financial Reporting Standards ("IFRS").

The Company files its reserves information under National Instrument 51-101 - "Standards of Disclosure of Oil and Gas Activities" (NI 51-101), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada.

There are significant differences to the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission (“SEC”) requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using 12-month average prices and current costs; whereas NI 51-101 requires Company gross reserves, before royalties, using forecast pricing and costs. Therefore the difference between the reported numbers under the two disclosure standards may be material.

Barrels of oil equivalent (“boe”) 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. Given that the value ratio based on the current price of crude oil and condensate as compared to natural gas is significantly different from the energy equivalency of oil, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Oil and gas metrics such as operating netback and netback do not have standardized meaning and as such may not be reliable, and should not be used to make comparisons.

Years of corporate inventory figures include proved and probable locations, as derived from the independently evaluated (by McDaniel & Associates Consultants Ltd.) Reserves Report in accordance with NI 51-101 and the COGE Handbook, and additional internally identified net drilling locations.

NI 51-101 includes condensate within the natural gas liquids (NGLs) product type. The Company has disclosed condensate as combined with crude oil and separately from other natural gas liquids in this MD&A since the price of condensate as compared to other natural gas liquids is currently significantly higher and the Company believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefrom.

The Company’s annual aggregate production for 2023 and 2022, the aggregate production for the past eight quarters and the references to “natural gas”, “crude oil" and "condensate”, reported in this MD&A consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 6 mcf : 1 bbl where applicable:

	2023					2022
	Annual	Q4	Q3	Q2	Q1	Annual	Q4	Q3	Q2	Q1
Light & Medium Crude Oil (bbl/d)	12,665	12,198	12,405	13,188	12,879	14,274	13,671	12,347	15,752	15,365
Heavy Crude Oil (bbl/d)	3,818	3,795	3,617	3,857	4,010	4,027	3,870	4,102	4,103	4,034
Tight Oil (bbl/d)	49,779	56,657	54,605	48,151	39,464	42,134	40,068	42,030	42,553	43,932
Total Crude Oil (bbl/d)	66,262	72,650	70,627	65,196	56,353	60,435	57,609	58,479	62,408	63,331
NGLs (bbl/d)	36,851	39,517	38,316	34,108	35,401	31,967	33,871	33,668	30,322	29,947
Shale Gas (mcf/d)	200,514	236,926	232,235	184,105	147,458	117,617	128,437	121,070	109,835	110,898
Conventional Natural Gas (mcf/d)	10,761	11,380	12,542	8,859	10,233	10,482	10,769	10,307	10,800	10,045
Total Natural Gas (mcf/d)	211,275	248,306	244,777	192,964	157,691	128,099	139,206	131,377	120,635	120,943
Total production from continuing operations (boe/d)	138,326	153,551	149,739	131,465	118,036	113,752	114,681	114,043	112,836	113,435

CRESCENT POINT ENERGY CORP. 34

	2023					2022
	Annual	Q4	Q3	Q2	Q1	Annual	Q4	Q3	Q2	Q1
Light & Medium Crude Oil (bbl/d)	12,665	12,198	12,408	13,190	12,879	14,274	13,671	12,347	15,752	15,365
Heavy Crude Oil (bbl/d)	3,818	3,795	3,617	3,857	4,010	4,027	3,870	4,102	4,103	4,034
Tight Oil (bbl/d)	63,906	62,512	75,879	63,812	53,184	53,861	52,095	54,030	53,521	55,837
Total Crude Oil (bbl/d)	80,389	78,505	91,904	80,859	70,073	72,162	69,636	70,479	73,376	75,236
NGLs (bbl/d)	41,534	41,373	44,728	39,399	40,592	36,556	38,893	38,481	34,013	34,774
Shale Gas (mcf/d)	214,165	242,965	251,152	199,781	161,459	130,902	142,803	134,049	119,924	126,622
Conventional Natural Gas (mcf/d)	10,761	11,380	12,542	8,859	10,233	10,482	10,769	10,307	10,800	10,045
Total Natural Gas (mcf/d)	224,926	254,345	263,694	208,640	171,692	141,384	153,572	144,356	130,724	136,667
Total average daily production (boe/d)	159,411	162,269	180,581	155,031	139,280	132,282	134,124	133,019	129,176	132,788

CRESCENT POINT ENERGY CORP. 35

Directors Barbara Munroe, Chair (6) James Craddock (2) (3) (5) John Dielwart (3) (4) Mike Jackson (1) (5) Jennifer Koury (2) (5) Francois Langlois (1) (3) (4) Myron Stadnyk (1) (2) (4) Mindy Wight (1) (2) Craig Bryksa (4) (1) Member of the Audit Committee of the Board of Directors (2) Member of the Human Resources and Compensation Committee of the Board of Directors (3) Member of the Reserves Committee of the Board of Directors (4) Member of the Environment, Safety and Sustainability Committee of the Board of Directors (5) Member of the Corporate Governance and Nominating Committee (6) Chair of the Board serves in an ex officio capacity on each Committee Officers Craig Bryksa President and Chief Executive Officer Ken Lamont Chief Financial Officer Ryan Gritzfeldt Chief Operating Officer Mark Eade Senior Vice President, General Counsel and Corporate Secretary Garret Holt Senior Vice President, Strategy and Planning Michael Politeski Senior Vice President, Finance and Treasurer Shelly Witwer Senior Vice President, Business Development Justin Foraie Vice President, Operations and Marketing Head Office Suite 2000, 585 - 8th Avenue S.W. Calgary, Alberta T2P 1G1 Tel: (403) 693-0020 Fax: (403) 693-0070 Toll Free: (888) 693-0020 Banker The Bank of Nova Scotia Calgary, Alberta Auditor PricewaterhouseCoopers LLP Calgary, Alberta Legal Counsel Norton Rose Fulbright Canada LLP Calgary, Alberta Evaluation Engineers McDaniel & Associates Consultants Ltd. Calgary, Alberta Registrar and Transfer Agent Investors are encouraged to contact Crescent Point's Registrar and Transfer Agent for information regarding their security holdings: Computershare Trust Company of Canada 600, 530 - 8th Avenue S.W. Calgary, Alberta T2P 3S8 Tel: (403) 267-6800 Stock Exchanges Toronto Stock Exchange - TSX New York Stock Exchange - NYSE Stock Symbol CPG Investor Contacts Shant Madian Vice President, Capital Markets (403) 693-0020 Sarfraz Somani Manager, Investor Relations (403) 693-0020

CRESCENT POINT ENERGY CORP. 36

EX-99.4

- 1 -

Exhibit 99.4

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF

THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Craig Bryksa, certify that:

1.I have reviewed this annual report of Crescent Point Energy Corp. on Form 40-F;

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 period 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:

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;

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;

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

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):

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

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:    February 29, 2024	CRESCENT POINT ENERGY CORP.
		/s/ Craig Bryksa
	Name: Title:	Craig Bryksa President and Chief Executive Officer

EX-99.5

- 1 -

Exhibit 99.5

CERTIFICATION PURSUANT TO RULE 13a-14 OR 15d-14 OF

THE SECURITIES EXCHANGE ACT OF 1934, AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Ken Lamont, certify that:

1.I have reviewed this annual report of Crescent Point Energy Corp. on Form 40-F;

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 period 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:

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;

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;

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

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):

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

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:    February 29, 2024	CRESCENT POINT ENERGY CORP.
		/s/ Ken Lamont
	Name: Title:	Ken Lamont Chief Financial Officer

EX-99.6

Exhibit 99.6

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 Crescent Point Energy Corp. (the “Company”) on Form 40-F for the fiscal year ended December 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Craig Bryksa, 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.    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:    February 29, 2024	CRESCENT POINT ENERGY CORP.
		/s/ Craig Bryksa
	Name: Title:	Craig Bryksa President and Chief Executive Officer

EX-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 Crescent Point Energy Corp. (the “Company”) on Form 40-F for the fiscal year ended December 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ken Lamont, 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.    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:    February 29, 2024	CRESCENT POINT ENERGY CORP.
		/s/ Ken Lamont
	Name: Title:	Ken Lamont Chief Financial Officer

EX-99.8

Exhibit 99.8

Consent of Independent Registered Public Accounting Firm

We hereby consent to the incorporation by reference in this Annual Report on Form 40-F for the year ended December 31, 2023 of Crescent Point Energy Corp. of our report dated February 28, 2024, relating to the consolidated financial statements and the effectiveness of internal control over financial reporting, which appears in the Exhibit incorporated by reference in this Annual Report.

We also consent to the incorporation by reference in the Registration Statements on Form F-10 (File No. 333-275312) as amended, Form S-8 (File No. 333-226210) and Form F-3D (File No. 333-205592) of Crescent Point Energy Corp.of our report dated February 28, 2024referred to above. We also consent to reference to us under the heading “Interests of Experts” in the Annual Information Form, filed as Exhibit incorporated by reference in this Annual Report on Form 40-F, which is incorporated by reference in such Registration Statements.

/s/PricewaterhouseCoopers LLP

Calgary, Alberta

Canada

February 29, 2024

EX-99.9

Exhibit 99.9

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

We hereby consent to the use of and reference to our name and report evaluating the petroleum and natural gas reserves attributable to Crescent Point Energy Corp’s (the “Company”) and its affiliates, including estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2023, estimated using forecast prices and costs, and the information derived from our reports entitled “Crescent Point Energy Corp, Evaluation of Petroleum Reserves, Based on Forecast Prices and Costs, As at December 31, 2023, dated February 7, 2024”, and our report “Crescent Point Energy Corp, Evaluation of Petroleum Reserves, Based on Constant Prices and Costs, As at December 31, 2023, dated February 7, 2024” as described or incorporated by reference in the Company’s annual report on Form 40-F for the year ended December 31, 2023 filed with the United States Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended or the Securities Act of 1933, as amended, as applicable.

We also confirm that we have read the Company’s Annual Information Form for the year ended December 31, 2023 dated February 28, 2024, 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.

McDANIEL & ASSOCIATES CONSULTANTS LTD.

/s/ Michael J. Verney

Michael J. Verney, P.Eng.

Executive Vice President

Calgary, Alberta

February 28, 2024

EX-99.10

Exhibit 99.10

Crescent Point Energy Corp.

Supplemental Disclosures about Extractive Activities - Oil & Gas (unaudited)

December 31, 2023

The following disclosures have been prepared by Crescent Point Energy Corp. ("Crescent Point" or the "Company") in accordance with Accounting Standards Codification 932 "Extractive Activities — Oil & Gas" ("ASC 932") issued by the Financial Accounting Standards Board ("FASB") and where applicable, financial information is prepared in accordance with International Financial Reporting Standards ("IFRS").

For the years ended December 31, 2023 and 2022, the Company filed its reserves information under National Instrument 51-101 – "Standards of Disclosure of Oil and Gas Activities" ("NI 51-101"), which prescribes the standards for the preparation and disclosure of reserves and related information for companies listed in Canada.

There are significant differences to the type of volumes disclosed and the basis from which the volumes are economically determined under the United States Securities and Exchange Commission ("SEC") requirements and NI 51-101. The SEC requires disclosure of net reserves, after royalties, using trailing 12-month average prices and current costs; whereas NI 51-101 requires Company gross reserves, before royalties, using forecast pricing and costs. The difference between the reported numbers under the two disclosure standards can, therefore, be material.

Petroleum and Natural Gas Reserve Information

Reserves are estimated quantities of crude oil, NGLs and natural gas anticipated from geological and engineering data to be recoverable from known accumulations, from a given date forward, by known technology, under existing operating conditions and considered to be economic at average commodity prices based upon the prior 12-month period. Estimates of petroleum and natural gas reserves are very complex, subject to uncertainty, require significant subjective decisions in the evaluation of all available geological, engineering and economic data, and will change as additional information regarding the producing fields and technology becomes available and as future economic conditions change. Net reserves presented in this section represent the Company's working interest and overriding royalty share of the gross remaining reserves, after deduction of any crown, freehold and overriding 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.

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. Additional future expenditures would be minor compared to the cost of drilling a new well.

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

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.

CRESCENT POINT ENERGY CORP. 1

The changes in Crescent Point's net proved crude oil, NGL and natural gas reserves under constant prices and costs for the two-year period ended December 31, 2023 were as follows:

	Canada				United States				Total
Net Proved Reserves (1)	Crude Oil (Mbbls)	NGLs (Mbbls)	Natural Gas (MMcf)	Total (Mboe)	Crude Oil (Mbbls)	NGLs (Mbbls)	Natural Gas (MMcf)	Total (Mboe)	Crude Oil (Mbbls)	NGLs (Mbbls)	Natural Gas (MMcf)	Total (Mboe)
December 31, 2021	217,832	108,579	427,816	397,714	27,456	9,324	29,600	41,713	245,288	117,903	457,416	439,427
Revisions of previous estimates	10,883	504	2,288	11,769	2,442	1,624	4,765	4,861	13,326	2,128	7,054	16,630
Improved recovery	—	—	—	—	—	—	—	—	—	—	—	—
Purchases of reserves in place	—	7,872	54,199	16,905	—	—	—	—	—	7,872	54,199	16,905
Extensions and discoveries	3,999	16,776	80,646	34,216	—	—	—	—	3,999	16,776	80,646	34,216
Production	(19,621)	(10,378)	(47,062)	(37,843)	(3,477)	(1,367)	(3,948)	(5,502)	(23,098)	(11,745)	(51,010)	(43,345)
Sales of reserves in place	(9,560)	(5,973)	(36,770)	(21,661)	—	—	—	—	(9,560)	(5,973)	(36,770)	(21,661)
December 31, 2022	203,534	117,380	481,118	401,100	26,421	9,581	30,417	41,072	229,955	126,961	511,535	442,172
Revisions of previous estimates	(5,471)	9,919	73,095	16,631	—	—	—	—	(5,471)	9,919	73,095	16,631
Improved recovery	—	—	—	—	—	—	—	—	—	—	—	—
Purchases of reserves in place	91,389	45,791	1,021,291	307,395	—	—	—	—	91,389	45,791	1,021,291	307,395
Extensions and discoveries	4,088	1,675	6,559	6,855	—	—	—	—	4,088	1,675	6,559	6,855
Production	(19,621)	(10,378)	(47,062)	(37,843)	(3,477)	(1,367)	(3,948)	(5,502)	(23,098)	(11,745)	(51,010)	(43,345)
Sales of reserves in place	(1,187)	(114)	(2,217)	(1,670)	(22,944)	(8,215)	(26,469)	(35,570)	(24,131)	(8,328)	(28,685)	(37,240)
December 31, 2023	272,731	164,273	1,532,785	692,468	—	—	—	—	272,731	164,273	1,532,785	692,468
Net Proved Developed Reserves
December 31, 2021	161,205	60,650	268,242	266,562	13,054	5,284	16,774	21,133	174,259	65,934	285,016	287,695
December 31, 2022	156,630	62,226	277,787	265,154	16,602	6,782	21,531	26,973	173,232	69,009	299,318	292,127
December 31, 2023	171,093	71,275	632,104	347,719	—	—	—	—	171,093	71,275	632,104	347,719
Net Proved Undeveloped Reserves
December 31, 2021	56,627	47,929	159,574	131,152	14,402	4,040	12,826	20,579	71,029	51,970	172,400	151,731
December 31, 2022	46,904	55,153	203,331	135,946	9,819	2,799	8,886	14,099	56,723	57,952	212,217	150,044
December 31, 2023	101,638	92,998	900,681	344,749	—	—	—	—	101,638	92,998	900,681	344,749

(1) Numbers may not add due to rounding.

Revisions of previous estimates - 2022

In 2022, total proved reserves increased by approximately 19.3 MMboe in Canada, and 2.9 MMboe in the United States due to increases in constant pricing for crude oil, natural gas, and NGL constituents at December 31, 2022 compared to December 31, 2021. Revisions due to higher commodity pricing were offset by revisions due to higher inflationary operating costs.

Revisions of previous estimates - 2023

In 2023, total proved reserves increased by approximately 28.1 MMboe in Canada, due to development downspacing and higher than original anticipated per area recoveries in the Company's Kaybob Duvernay asset. This was slightly offset by revisions due to decreases in constant pricing for crude oil, natural gas, and NGL constituents at December 31, 2023 compared to December 31, 2022, as well as revisions due to marginally higher operating costs due to inflation.

Purchase of reserves in place - 2022

The Company purchased gas and NGL constituent volumes within the Kaybob area in Canada.

Purchase of reserves in place - 2023

The Company purchased 25.2 MMboe gas and NGL constituent volumes within the Kaybob area in Canada. In addition, the Company completed two significant acquisitions in the Montney play consisting of crude oil, natural gas, and NGL constituents totaling 282.0 MMboe.

Extensions and discoveries - 2022

In 2022, the Company added significant extension reserves within the Kaybob area in Canada.

CRESCENT POINT ENERGY CORP. 2

Sale of reserves in place - 2022

In 2022, the Company realized dispositions within Canada including the disposition of assets within Southwest Saskatchewan and East Shale Duvernay.

Sale of reserves in place - 2023

In 2023, the Company divested its entire North Dakota Bakken position in the United States.

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, as updated by Accounting Standards Update 2010-03 "Oil and Gas Reserve Estimation and Disclosures", and based on crude oil, NGL and natural gas reserve and production volumes estimated by Crescent Point's independent reserves evaluators, McDaniel & Associates Consultants Ltd. The methodology used in calculating our price and cost assumptions for the standardized measure of discounted future net cash flows for reserve estimation is based upon 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.

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 provision 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 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 Crescent Point'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.

Commodity Pricing	2023	2022
WTI at Cushing Oklahoma ($US/bbl)	78.21	94.14
Edmonton ($Cdn/bbl)	100.49	119.13
Exchange Rate ($US/$Cdn)	0.7405	0.7700
AECO/NIT Spot ($Cdn/MMBTU)	2.84	5.62
Henry Hub NYMEX ($US/MMBTU)	2.59	6.25

The standardized measure of discounted future net cash flows relating to net proved crude oil, NGL and natural gas reserves are as follows:

December 31, 2023 (millions of Canadian dollars) (1)	Canada	United States	Total
Future cash inflows	39,713	—	39,713
Future production costs	(15,379)	—	(15,379)
Future development costs and asset retirement obligations (2)	(7,248)	—	(7,248)
Future income taxes (3)	(2,256)	—	(2,256)
Future net cash flows	14,831	—	14,831
Deduct: 10% annual discount factor for timing of future cash flows	(5,698)	—	(5,698)
Standardized measure of future net cash flows	9,132	—	9,132

(1) Numbers may not add due to rounding.

(2) Asset retirement obligations include the costs related to producing wells, future undeveloped proved locations for which there are reserves assigned, as well as all entities that do not have reserves assigned including facilities and gathering systems.

(3) At December 31, 2023, the Company's Canadian tax pools were approximately $8.3 billion.

CRESCENT POINT ENERGY CORP. 3

December 31, 2022 (millions of Canadian dollars) (1)	Canada	United States	Total
Future cash inflows	34,653	3,519	38,172
Future production costs	(11,226)	(1,127)	(12,353)
Future development costs and asset retirement obligations (2)	(3,967)	(329)	(4,296)
Future income taxes (3)	(3,364)	(159)	(3,523)
Future net cash flows	16,097	1,904	18,001
Deduct: 10% annual discount factor for timing of future cash flows	(6,607)	(549)	(7,156)
Standardized measure of future net cash flows	9,490	1,354	10,845

(1) Numbers may not add due to rounding.

(2) Asset retirement obligations include the costs related to producing wells, future undeveloped proved locations for which there are reserves assigned, as well as all entities that do not have reserves assigned including facilities and gathering systems.

(3) At December 31, 2022, the Company's Canadian and United States tax pools in Canadian dollars were approximately $5.7 billion and $3.0 billion, respectively.

Reconciliation of Changes in Standardized Measure of Future Net Cash Flows Discounted at 10% per Year Relating to Proved Petroleum and Natural Gas Reserves

December 31, 2023 (millions of Canadian dollars) (1)	Canada	United States	Total
Balance, beginning of year	9,490	1,354	10,845
Sales, net of production costs and royalties	(2,179)	(365)	(2,544)
Net change in prices and royalties related to forecast production	(3,844)	—	(3,844)
Development costs incurred during the period	850	296	1,146
Changes in estimated future development costs	(197)	—	(197)
Extensions, discoveries and improved recovery, net of related costs	241	—	241
Technical reserve revisions (2)	155	—	155
Purchases of reserves in place	3,899	—	3,899
Sales of reserves in place	(48)	(1,399)	(1,447)
Accretion of discount	949	113	1,062
Net change in income taxes	512	—	512
All other changes (3)	(695)	—	(695)
Balance, end of year	9,132	—	9,132

(1) Numbers may not add due to rounding.

(2) Includes change in future net values attributed to infill drilling and technical revisions, which include changes to abandonment obligations and carbon tax assumptions.

(3) Includes changes due to revised production profiles, development timing, operating costs, royalty rates, currency exchange rates and actual prices received in 2023 versus forecast.

December 31, 2022 (millions of Canadian dollars) (1)	Canada	United States	Total
Balance, beginning of year	6,489	715	7,204
Sales, net of production costs and royalties	(2,653)	(387)	(3,039)
Net change in prices and royalties related to forecast production	6,345	918	7,263
Development costs incurred during the period	707	259	966
Changes in estimated future development costs	(250)	(61)	(310)
Extensions, discoveries and improved recovery, net of related costs	1,064	—	1,064
Technical reserve revisions (2)	(227)	216	(11)
Purchases of reserves in place	361	—	361
Sales of reserves in place	(321)	—	(321)
Accretion of discount	714	72	786
Net change in income taxes	(1,191)	(102)	(1,292)
All other changes (3)	(1,549)	(275)	(1,824)
Balance, end of year	9,490	1,354	10,845

(1) Numbers may not add due to rounding.

(2) Includes change in future net values attributed to infill drilling and technical revisions, which include changes to abandonment obligations and carbon tax assumptions.

(3) Includes changes due to revised production profiles, development timing, operating costs, royalty rates, currency exchange rates and actual prices received in 2022 versus forecast. Increases in operating expenses due to heightened inflation make up a large majority of this change.

CRESCENT POINT ENERGY CORP. 4

Capitalized Costs Relating to Petroleum and Natural Gas Producing Activities

As at December 31, 2023 (millions of Canadian dollars)	Canada	United States	Total
Proved properties	24,579	2	24,581
Unproved properties	1,578	—	1,578
Total capital costs	26,157	2	26,159
Accumulated depletion, amortization and impairment	(14,873)	—	(14,873)
Net capitalized costs	11,284	2	11,286

As at December 31, 2022 (millions of Canadian dollars)	Canada	United States	Total
Proved properties	20,194	2,145	22,339
Unproved properties	1,162	292	1,454
Total capital costs	21,356	2,437	23,793
Accumulated depletion, amortization and impairment	(14,802)	(1,199)	(16,001)
Net capitalized costs	6,554	1,238	7,792

Costs Incurred in Petroleum and Natural Gas Property Acquisitions, Exploration and Development Activities

Year ended December 31, 2023 (millions of Canadian dollars) (1)	Canada	United States	Total
Property acquisition costs (2)
Proved properties	4,075	—	4,075
Unproved properties	515	—	515
Development costs (3)	850	296	1,146
Exploration costs	27	—	27
Total	5,466	296	5,762

(1) Numbers may not add due to rounding.

(2) Excludes disposition proceeds of $611.7 million and $1.9 million for proved and unproved properties, respectively.

(3) Costs incurred exclude capitalized administration.

Year ended December 31, 2022 (millions of Canadian dollars) (1)	Canada	United States	Total
Property acquisition costs (2)
Proved properties	61	2	63
Unproved properties	28	—	28
Development costs (3)	707	259	966
Exploration costs	9	—	9
Total	805	261	1,066

(1) Numbers may not add due to rounding.

(2) Excludes disposition proceeds of $272.7 million and $10.9 million for proved and unproved properties, respectively.

(3) Costs incurred exclude capitalized administration.

Results of Operations From Crude Oil and Natural Gas Producing Activities

Year ended December 31, 2023 (millions of Canadian dollars)	Canada	United States	Total
Petroleum and natural gas revenues, net of royalties	3,124	457	3,581
Less:
Operating expenses	771	80	851
Transportation expenses	174	12	186
Depletion and amortization	871	169	1,040
Impairment	94	728	822
Accretion	22	—	22
Operating income	1,192	(532)	660
Income tax recovery	1	—	1
Results of operations	1,193	(532)	661

CRESCENT POINT ENERGY CORP. 5

Year ended December 31, 2022 (millions of Canadian dollars)	Canada	United States	Total
Petroleum and natural gas revenues, net of royalties	3,411	481	3,892
Less:
Operating expenses	628	85	713
Transportation expenses	131	9	140
Depletion and amortization	783	144	927
Impairment reversal	(358)	(71)	(429)
Accretion	19	—	19
Operating income	2,208	314	2,522
Income taxes	—	—	—
Results of operations	2,208	314	2,522

CRESCENT POINT ENERGY CORP. 6

XML

Document and Entity Information	12 Months Ended
	Dec. 31, 2023 shares
Document Information [Line Items]
Document Type	40-F
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Entity File Number	001-36258
Entity Registrant Name	CRESCENT POINT ENERGY CORP.
Entity Incorporation, State or Country Code	A0
Entity Primary SIC Number	1311
Entity Address, Address Line Two	Suite 2000
Entity Address, Address Line One	585-8th Avenue S.W.
Entity Address, City or Town	Calgary
Entity Address, State or Province	AB
Entity Address, Postal Zip Code	T2P 1G1
City Area Code	403
Local Phone Number	693-0020
Title of 12(b) Security	Common Shares
Trading Symbol	CPG
Security Exchange Name	NYSE
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	619,929,490
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Amendment Flag	false
Entity Central Index Key	0001545851
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Business Contact
Document Information [Line Items]
Contact Personnel Name	CT Corporation System
Entity Address, Address Line One	28 Liberty Street
Entity Address, City or Town	New York
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10005
City Area Code	212
Local Phone Number	894-8940

XML

Audit Information	12 Months Ended
	Dec. 31, 2023
Audit Information [Abstract]
Auditor Name	Chartered Professional Accountants
Auditor Firm ID	271
Auditor Location	Calgary, Canada

XML

Consolidated Balance Sheets - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
ASSETS
Cash	$ 17.3	$ 289.9
Accounts receivable	377.9	327.8
Prepaids and deposits	87.8	65.5
Derivative asset	240.7	138.9
Other current assets	79.2	18.7
Assets held for sale	247.1	148.4
Total current assets	1,050.0	989.2
Derivative asset	14.3	96.4
Other long-term assets	7.4	6.4
Exploration and evaluation	607.0	104.2
Property, plant and equipment	10,718.3	7,729.4
Right-of-use asset	102.8	78.1
Goodwill	275.9	203.9
Deferred income tax	0.0	278.8
Total assets	12,775.7	9,486.4
LIABILITIES
Accounts payable and accrued liabilities	634.9	448.2
Dividends payable	56.8	99.4
Current portion of long-term debt	380.0	538.7
Derivative liability	51.4	8.7
Other current liabilities	118.0	115.6
Liabilities associated with assets held for sale	132.4	28.4
Total current liabilities	1,373.5	1,239.0
Long-term debt	3,186.3	902.8
Derivative liability	3.8	0.0
Other long-term liabilities	31.0	40.8
Lease liability	104.2	99.2
Decommissioning liability	566.4	633.9
Deferred income tax	643.0	77.3
Total liabilities	5,908.2	2,993.0
SHAREHOLDERS’ EQUITY
Shareholders’ capital	17,052.7	16,419.3
Contributed surplus	17.4	17.1
Deficit	(10,202.5)	(10,563.3)
Accumulated other comprehensive income	(0.1)	620.3
Total shareholders' equity	6,867.5	6,493.4
Total liabilities and shareholders' equity	$ 12,775.7	$ 9,486.4

XML

Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
REVENUE AND OTHER INCOME
Revenue from contracts with customers	$ 3,189.9	$ 3,512.3	[1]
Commodity derivative gains (losses)	163.8	(473.4)	[1]
Other income	13.4	59.0	[1]
Revenue and other income	3,367.1	3,097.9	[1]
EXPENSES
Operating	770.5	628.2	[1]
Purchased product	68.6	102.9	[1]
Transportation	174.3	131.0	[1]
General and administrative	126.5	78.4	[1]
Interest	129.4	63.6	[1]
Foreign exchange gain (loss)	(10.0)	18.8	[1]
Share-based compensation	38.7	38.8	[1]
Depletion, depreciation and amortization	894.7	807.2	[1]
Impairment (impairment reversal)	93.8	(357.3)	[1]
Accretion and financing	27.5	24.5	[1]
Total Expenses	2,314.0	1,536.1	[1]
Net income before tax from continuing operations	1,053.1	1,561.8	[1]
Tax expense (recovery)
Current	(0.7)	0.0	[1]
Deferred	254.4	415.1	[1]
Net income from continuing operations	799.4	1,146.7	[1]
Net income (loss) from discontinued operations	(229.1)	336.7	[1]
Net income	570.3	1,483.4	[1]
Items that may be subsequently reclassified to profit or loss
Foreign currency translation of foreign operations	1.3	90.7	[1]
Reclassification of cumulative foreign currency translation of discontinued foreign operations	(621.7)	0.0	[1]
Comprehensive income (loss)	$ (50.1)	$ 1,574.1	[1]
Net income (loss) per share
Continuing operations - basic (in cad per share)	$ 1.47	$ 2.03	[1]
Discontinued operations - basic (in cad per share)	(0.42)	0.59	[1]
Net income (loss) per share - basic (in cad per share)	1.05	2.62	[1]
Continuing operations - diluted (in cad per share)	1.46	2.01	[1]
Discontinued operations - diluted (in cad per share)	(0.42)	0.59	[1]
Net income (loss) per share - diluted (in cad per share)	$ 1.04	$ 2.60	[1]
Weighted average shares outstanding
Basic (in shares)	545,644,234	566,710,644
Diluted (in shares)	548,328,707	571,068,066
Oil and gas sales
REVENUE AND OTHER INCOME
Revenue from contracts with customers	$ 3,499.0	$ 3,847.0	[1]
Purchased product sales
REVENUE AND OTHER INCOME
Revenue from contracts with customers	66.2	100.8	[1]
Royalties
REVENUE AND OTHER INCOME
Revenue from contracts with customers	$ (375.3)	$ (435.5)	[1]

[1] Comparative period revised to reflect current period presentation. See Note 9 - "Discontinued Operations" for additional information.

XML

Consolidated Statement of Changes in Shareholders' Equity - CAD ($) $ in Millions		Total		Shareholders’ capital	Contributed surplus	Deficit	Accumulated other comprehensive income
Equity, beginning of year at Dec. 31, 2021		$ 5,405.3		$ 16,706.9	$ 17.5	$ (11,848.7)	$ 529.6
Redemption of restricted shares		2.6		5.2	(5.2)	2.6
Common shares repurchased for cancellation		(294.2)		(294.2)
Share-based compensation		6.2			6.2
Stock options exercised		0.0		1.4	(1.4)
Net income		1,483.4	[1]			1,483.4
Dividends declared		(200.6)				(200.6)
Foreign currency translation adjustment		90.7	[1]				90.7
Reclassification of cumulative foreign currency translation of discontinued foreign operations	[1]	0.0
Equity, end of year at Dec. 31, 2022		6,493.4		16,419.3	17.1	(10,563.3)	620.3
Issued for cash		500.1		500.1
Issued on capital acquisition		493.0		493.0
Redemption of restricted shares		2.4		4.9	(4.9)	2.4
Common shares repurchased for cancellation		(349.9)		(349.9)
Share issue costs, net of tax		(15.4)		(15.4)
Share-based compensation		5.8			5.8
Stock options exercised		0.1		0.7	(0.6)
Net income		570.3				570.3
Dividends declared		(211.9)				(211.9)
Foreign currency translation adjustment		1.3					1.3
Reclassification of cumulative foreign currency translation of discontinued foreign operations		(621.7)					(621.7)
Equity, end of year at Dec. 31, 2023		$ 6,867.5		$ 17,052.7	$ 17.4	$ (10,202.5)	$ (0.1)

[1] Comparative period revised to reflect current period presentation. See Note 9 - "Discontinued Operations" for additional information.

XML

Consolidated Statement of Changes in Shareholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Statement of changes in equity [abstract]
Dividends (in cad per share)	$ 0.387	$ 0.360

XML

Consolidated Statements of Cash Flows - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
CASH PROVIDED BY (USED IN):
Net income	$ 570.3	$ 1,483.4	[1]
Items not affecting cash
Other (income) loss	4.2	(49.0)
Deferred tax expense	533.0	387.9
Share-based compensation	5.7	6.0
Depletion, depreciation and amortization	1,065.0	951.7
Impairment	822.2
Impairment reversal		(428.6)
Accretion	22.7	19.2
Unrealized (gains) losses on derivatives	56.9	(171.0)
Translation of US dollar long-term debt	(16.8)	91.5
Reclassification of cumulative foreign currency translation of discontinued foreign operations	(621.7)	0.0	[1]
Translation of US dollar derivatives	0.9	0.0
Realized gain on cross currency swap maturity	(151.8)	(63.8)
Decommissioning expenditures	(40.0)	(20.1)
Changes in non-cash working capital:	(54.9)	(15.0)
Cash flows from (used in) operations	2,195.7	2,192.2
INVESTING ACTIVITIES
Development capital and other expenditures	(1,220.5)	(1,027.4)
Capital acquisitions, net of cash acquired	(3,616.2)	(90.7)
Capital dispositions	604.5	283.6
Other long-term assets	(0.8)	0.0
Changes in non-cash working capital:	(4.2)	(26.1)
Cash flows from (used in) investing activities	(4,237.2)	(860.6)
FINANCING ACTIVITIES
Issue of shares, net of issue costs	479.7	0.0
Common shares repurchased for cancellation	349.9	294.2
Increase (decrease) in bank debt, net	2,675.1	(338.5)
Repayment of senior guaranteed notes and acquired long-term debt	(897.9)	(281.8)
Realized gain on cross currency swap maturity	151.8	63.8
Payments on principal portion of lease liability	(20.8)	(20.4)
Dividends declared	(211.9)	(200.6)
Change in non-cash working capital	(57.2)	15.7
Cash flows from (used in) financing activities	1,768.9	(1,056.0)
Impact of foreign currency on cash balances	0.0	0.8
INCREASE (DECREASE) IN CASH	(272.6)	276.4
CASH AT BEGINNING OF YEAR	289.9	13.5
CASH AT END OF YEAR	17.3	289.9
Supplemental Information [Abstract]
Cash taxes paid	(0.1)	0.0
Cash interest paid	$ (118.1)	$ (68.0)

[1] Comparative period revised to reflect current period presentation. See Note 9 - "Discontinued Operations" for additional information.

XML

Structure of the Business

12 Months Ended

Dec. 31, 2023

Corporate information and statement of IFRS compliance [abstract]

Structure of the Business

STRUCTURE OF THE BUSINESS

The principal undertaking of Crescent Point Energy Corp. (the “Company” or “Crescent Point”) is to carry on the business of acquiring, developing and holding interests in petroleum and natural gas properties and assets related thereto through a general partnership and wholly owned subsidiaries.

Crescent Point is the ultimate parent and is amalgamated in Alberta, Canada under the Alberta Business Corporations Act. The address of the principal place of business is 2000, 585 - 8th Ave S.W., Calgary, Alberta, Canada, T2P 1G1.

These annual consolidated financial statements were approved and authorized for issue by the Company's Board of Directors on February 28, 2024.

XML

Basis of Preparation

12 Months Ended

Dec. 31, 2023

Corporate information and statement of IFRS compliance [abstract]

Basis of Preparation

BASIS OF PREPARATION

a)Preparation

These consolidated financial statements are presented under IFRS Accounting Standards as issued by the International Accounting Standards Board. The policies applied in these consolidated financial statements are based on IFRS Accounting Standards issued and outstanding as of February 28, 2024, the date the Board of Directors approved the statements.

The Company’s presentation currency is Canadian dollars and all amounts reported are Canadian dollars unless noted otherwise. References to “US$” and "US dollars" are to United States ("U.S.") dollars. Crescent Point's Canadian operations are presented herein as continuing operations. The Company's U.S. operations have been classified and presented as discontinued operations. See Note 9 - "Discontinued Operations" for additional information.

b)Basis of measurement, functional and presentation currency

The Company’s presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period end exchange rates for assets and liabilities and at the average rate over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in other comprehensive income as cumulative translation adjustments.

c)Use of estimates and judgments

The preparation of consolidated financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future years affected.

The Company also faces uncertainties related to future environmental laws and climate-related regulations, which could affect the Company's financial position and future earnings. This transition to a lower-carbon society, as well as the physical impacts of climate change, could result in increased operating costs and reduced demand for oil and gas products. As a result, this could change a number of variables and assumptions used to determine the estimated recoverable amounts of the Company's oil and gas assets. The unpredictable nature, timing and extent of climate-related initiatives presents various risks and uncertainties, including to management's judgements, estimates and assumptions that affect the application of accounting policies. Significant estimates and judgments made by management in the preparation of these consolidated financial statements are outlined below.

Oil and gas activities

Reserves estimates, although not reported as part of the Company’s consolidated financial statements, can have a significant effect on net income, assets and liabilities as a result of their impact on depletion, depreciation and amortization (“DD&A”), decommissioning liability, deferred taxes, asset impairments and impairment reversals, and business combinations. Independent petroleum reservoir engineers perform evaluations of the Company’s oil and gas reserves on an annual basis. The estimation of reserves is an inherently complex process requiring significant judgment. Estimates of economically recoverable oil and gas reserves are based upon a number of variables and assumptions such as production forecasts, commodity prices, costs and related future cash flows, all of which may vary considerably from actual results. These estimates are expected to be revised upward or downward over time, as additional information such as reservoir performance becomes available, or as economic conditions change.

For purposes of impairment testing, property, plant and equipment (“PP&E”) is aggregated into cash-generating units (“CGUs”), based on separately identifiable and largely independent cash inflows. The determination of the Company’s CGUs is subject to judgment. Factors considered in the classification of CGUs include the integration between assets, shared infrastructure, the existence of common sales points, geography, geologic structure and the manner in which management monitors and makes decisions regarding operations.

The determination of technical feasibility and commercial viability, based on the presence of reserves and which results in the transfer of assets from exploration and evaluation ("E&E") to PP&E, is subject to judgment.

Decommissioning liability

Upon retirement of its oil and gas assets, the Company anticipates incurring substantial costs associated with decommissioning. Estimates of these costs are subject to uncertainty associated with the method, timing and extent of future decommissioning activities. The liability, the related asset and the expense are impacted by estimates with respect to the cost and timing of decommissioning.

Business combinations

Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of PP&E and E&E assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, production forecasts, costs and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill. Future net earnings can be affected as a result of changes in future DD&A, asset impairment or goodwill impairment.

Fair value measurement

The estimated fair value of derivative instruments resulting in derivative assets and liabilities, by their very nature, are subject to measurement uncertainty. Estimates included in the determination of the fair value of derivative instruments include forward benchmark prices, discount rates, share price, forward foreign exchange rates and forward interest rates.

Joint control

Judgment is required to determine when the Company has joint control over an arrangement, which requires an assessment of the capital and operating activities of the projects it undertakes with partners and when the decisions in relation to those activities require unanimous consent.

Share-based compensation

Compensation costs recorded pursuant to share-based compensation plans are subject to estimated fair values, forfeiture rates and the future attainment of performance criteria.

Income taxes

Tax regulations and legislation and the interpretations thereof are subject to change. In addition, deferred income tax assets and liabilities recognize the extent that temporary differences will be receivable and payable in future periods. The calculation of the asset and liability involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, expected cash flows from estimated proved plus probable reserves and the application of tax laws. Changes in tax regulations and legislation and the other assumptions listed are subject to measurement uncertainty.

XML

Material Accounting Policies

12 Months Ended

Dec. 31, 2023

Corporate information and statement of IFRS compliance [abstract]

Material Accounting Policies

MATERIAL ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently by the Company and its subsidiaries for all periods presented in these annual consolidated financial statements.

a)Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries and any reference to the “Company” throughout these consolidated financial statements refers to the Company and its subsidiaries. All transactions between the Company and its subsidiaries have been eliminated.

The Company conducts some of its oil and gas production activities through jointly controlled operations and the financial statements reflect only the Company's proportionate interest in such activities. Joint control exists for contractual arrangements governing the Company's assets whereby the Company has less than 100 percent working interest, all the partners have control of the arrangement collectively, and share the associated risks. The Company does not have any joint arrangements that are material to the Company or that are structured through joint venture arrangements.

b)Property, Plant and Equipment

Items of PP&E, which primarily consist of oil and gas development and production assets, are measured at cost less accumulated depletion, depreciation and any accumulated impairment losses or impairment reversals. Development and production assets are accumulated into CGUs and account for the cost of developing the commercial reserves and initiating production.

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PP&E are recognized as development and production assets only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in net income as incurred. Capitalized development and production assets generally represent costs incurred in developing reserves and initiating or enhancing production from such reserves. The carrying amount of any sold component is derecognized.

Depletion and Depreciation

Development and production assets are depleted using the unit-of-production method based on estimated proved plus probable oil and gas reserves before royalties, as determined by independent petroleum reservoir engineers. Natural gas reserves and production are converted to equivalent barrels of oil based upon the relative energy content (6:1). The depletion base includes capitalized costs, plus future costs to be incurred in developing proved plus probable oil and gas reserves.

Corporate assets are depreciated on a straight line basis over the estimated useful lives of the related assets, ranging from 5 to 16 years.

Impairment

The carrying amounts of PP&E, which takes into account the discounted abandonment and reclamation costs on proved plus probable undeveloped oil and gas reserves, are grouped into CGUs and reviewed quarterly for indicators of impairment. Indicators are events or changes in circumstances that indicate the carrying amount may not be recoverable. If indicators of impairment exist, the recoverable amount of the CGU is estimated. If the carrying amount of the CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income.

Assets are grouped into CGUs based on the integration between assets, shared infrastructure, the existence of common sales points, geography, geological structure and the manner in which management monitors and makes decisions regarding operations. Estimates of future cash flows used in the calculation of the recoverable amount are based on reserve evaluation reports prepared by independent petroleum reservoir engineers. The recoverable amount is the higher of fair value less costs of disposal and the value-in-use. Fair value less costs of disposal is derived by estimating the discounted after-tax future net cash flows from proved plus probable oil and gas reserves. Discounted future net cash flows are based on forecasted commodity prices and costs over the expected economic life of the reserves and discounted using market-based rates to reflect a market participant’s view of the risks associated with the assets. Value-in-use is assessed using the expected future cash flows from proved plus probable oil and gas reserves discounted at a pre-tax rate. The fair value less costs of disposal and value in use estimates are categorized as Level 3 according to the IFRS 13 fair value hierarchy.

Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined, net of depletion, had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net income.

c)Exploration and Evaluation

Exploration and evaluation assets are comprised of the accumulated expenditures incurred in an area where technical feasibility and commercial viability has not yet been determined. Exploration and evaluation assets include undeveloped land and any drilling costs thereon.

Technical feasibility and commercial viability are considered to be determinable when reserves are discovered. Upon determination of reserves, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to PP&E.

Costs incurred prior to acquiring the legal rights to explore an area are expensed as incurred.

Amortization

Undeveloped land classified as E&E assets is amortized by major area over the average primary lease term and recognized in net income. Drilling costs classified as E&E assets are not amortized, but are subject to impairment.

Impairment

Exploration and evaluation assets are reviewed quarterly for indicators of impairment and upon reclassification from E&E assets to PP&E. Exploration and evaluation assets are tested for impairment at the operating segment level by combining E&E assets with PP&E. The recoverable amount is the greater of fair value less costs of disposal or value-in-use. Fair value less costs of disposal is derived by estimating the discounted after-tax future net cash flows from proved plus probable oil and gas reserves, plus the fair market value of undeveloped land. Value-in-use is assessed using the expected future cash flows from proved plus probable oil and gas reserves discounted at a pre-tax rate.

Impairments of E&E assets are reversed when there has been a subsequent increase in the recoverable amount, but only to the extent of what the carrying amount would have been, net of amortization, had no impairment been recognized.

d)Decommissioning Liability

The Company recognizes the present value of a decommissioning liability in the period in which it is incurred. The obligation is recorded as a liability on a discounted basis using the relevant risk free rate, with a corresponding increase to the carrying amount of the related asset. Over time, the liabilities are accreted for the change in their present value and the capitalized costs are depleted on a unit-of-production basis over the life of the underlying proved plus probable oil and gas reserves. Accretion expense is recognized in net income. Revisions to the discount rate, estimated timing or amount of future cash flows would also result in an increase or decrease to the decommissioning liability and related asset.

e)Goodwill

The Company records goodwill relating to business combinations when the purchase price exceeds the fair value of the net identifiable assets and liabilities of the acquired business. The goodwill balance is assessed for impairment annually or as events occur that could result in impairment. Goodwill is tested for impairment at an operating segment level by combining the carrying amounts of PP&E, E&E assets and goodwill and comparing this to the recoverable amount. Any excess of the carrying amount over the recoverable amount is the impairment amount. The recoverable amount estimates is categorized as Level 3 according to the IFRS 13 fair value hierarchy. Impairment charges, which are not tax affected, are recognized in net income. Goodwill is reported at cost less any accumulated impairment. Goodwill impairments are not reversed.

f)Share-based Compensation

Restricted shares granted under the Restricted Share Bonus Plan are accounted for at fair value and vest on terms up to three years from the grant date determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of shares on the date of grant. Forfeitures are estimated at the grant date and recognized when they occur. The expense is recognized over the service period, with a corresponding increase to contributed surplus. The Company capitalizes the portion of share-based compensation directly attributable to development activities, with a corresponding decrease to share-based compensation expense. At the time the restricted shares vest, the issuance of shares is recorded as an increase to shareholders’ capital and a corresponding decrease to contributed surplus.

Employee Share Value Plan ("ESVP") awards are accounted for at fair value and vest on terms of up to three years from the grant date as determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of the ESVP awards on the date of grant and subsequently adjusted to reflect the fair value at each period end. The expense is recognized over the service period, with a corresponding increase to long-term compensation liability. ESVP awards are settled in cash upon vesting based on the prevailing Crescent Point share price and the aggregate amount of dividends paid from the grant date.

Performance share units ("PSUs") are accounted for at fair value and vest on terms of up to three years from the grant date as determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of the PSUs on the date of the grant and subsequently adjusted to reflect the fair value at each period end. Market performance conditions are factored into the fair value and the best estimate of non-market performance conditions is used to determine an estimate of the number of units that will vest. Fair value is based on the expected cash payment per PSU and the expected number of PSUs to vest, calculated from multipliers based on internal and external performance metrics. The expense is recognized over the service period, with a corresponding increase to long-term compensation liability. PSUs are settled in cash upon vesting based on the prevailing Crescent Point share price, performance multiplier, and factors in the aggregate amount of dividends paid over the vesting term.

Deferred share units (“DSUs”) are accounted for at fair value. Share-based compensation expense is determined based on the estimated fair value of the DSUs on the date of the grant and subsequently adjusted to reflect the fair value at each period end. Fair value is based on the prevailing Crescent Point share price.

Stock options are accounted for at fair value and have a maximum term of seven years and vest on terms as determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of the stock options on the date of the grant. Upon vesting, the stock option holder may either exercise their stock options to purchase one common share per option at the exercise price or, at the Company's discretion, surrender their stock options for a cash payment in an amount equal to the aggregate positive difference, if any, between the market price and the exercise price of the number of common shares associated with the stock options surrendered. Alternatively, the stock option holder may also, at the Company's discretion, surrender their stock options for common shares having a value equivalent to the cash payment.

g)Income Taxes

The Company follows the liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the estimated effect of any differences between the accounting and tax basis of assets and liabilities, using enacted or substantively enacted income tax rates expected to apply when the deferred tax asset or liability is settled. The effect of a change in income tax rates on deferred income taxes is recognized in net income in the period in which the change occurs.

The tax expense for the period comprises current and deferred tax. Tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity. In this case, the tax is also recognized in other comprehensive income or directly in equity, respectively.

The Company is able to deduct certain settlements under its Restricted Share Bonus Plan. To the extent the tax deduction exceeds the cumulative remuneration cost for a particular restricted share grant recorded in net income, the tax benefit related to the excess is recorded directly within equity.

A deferred tax asset is recognized to the extent that it is probable that future taxable income will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized. Deferred income tax assets and liabilities are presented as non-current.

h)Financial Instruments

The Company uses financial derivative instruments and physical delivery commodity contracts from time to time to reduce its exposure to fluctuations in commodity prices, share price, foreign exchange rates and interest rates. The Company also makes investments in companies from time to time in connection with the Company’s acquisition and divestiture activities.

Financial derivative instruments

Financial derivative instruments are included in current assets/liabilities except for those with maturities greater than 12 months after the end of the reporting period, which are classified as non-current assets/liabilities.

The Company has not designated any of its financial derivative contracts as effective accounting hedges and, accordingly, fair values its financial derivative contracts with the resulting gains and losses recorded in net income.

The fair value of a financial derivative instrument on initial recognition is normally the transaction price. Subsequent to initial recognition, the fair values are based on quoted market prices where available from active markets, otherwise fair values are estimated based on market prices at the reporting date for similar assets or liabilities with similar terms and conditions, or by discounting future payments of interest and principal at estimated interest rates that would be available to the Company at the reporting date.

Financial assets and liabilities

Financial assets and liabilities are measured at fair value on initial recognition. For non-equity instruments, measurement in subsequent periods depends on the classification of the financial asset or liability as “fair value through profit or loss” or “amortized cost”.

Financial assets and liabilities classified as fair value through profit or loss are subsequently carried at fair value, with changes recognized in net income.

Financial assets and liabilities classified as amortized cost are subsequently carried at amortized cost using the effective interest rate method.

Currently, the Company classifies all non-equity financial instruments which are not financial derivative instruments as amortized cost.

At each reporting date, the Company assesses whether there is objective evidence that a financial asset carried at amortized cost is impaired. If such evidence exists, the Company recognizes an impairment loss in net income. Impairment losses are reversed in subsequent periods if the impairment loss decrease can be related objectively to an event occurring after the impairment was recognized.

For investments in equity instruments, the subsequent measurement is dependent on the Company’s election to classify such instruments as fair value through profit or loss or fair value through other comprehensive income. Currently, the Company classifies all investments in equity instruments as fair value through profit or loss, whereby the Company recognizes movements in the fair value of the investment (adjusted for dividends) in net income. If the fair value through other comprehensive income classification is selected, the Company would recognize any dividends from the investment in net income and would recognize fair value re-measurements of the investment in other comprehensive income.

Impairment of financial assets

Impairment losses are recognized using an expected credit loss model. The Company has adopted the simplified expected credit loss model for its accounts receivable, which permits the use of the lifetime expected loss provision.

To measure the expected credit losses, accounts receivable have been grouped based on shared credit risk characteristics and days past due. The Company uses judgment in making these assumptions and selecting the inputs into the expected loss calculation based on past history, existing market conditions and forward looking estimates at the end of each reporting period.

i)Business Combinations

Business combinations are accounted for using the acquisition method. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured at their fair values at the acquisition date. The acquisition is measured as the fair value of the acquired assets by estimating the discounted after-tax future net cash flows, the fair value of equity instruments issued and the fair value of liabilities incurred or assumed at the acquisition date. The excess of the cost of the acquisition over the fair value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of the acquisition is less than the fair value of the net assets acquired, the difference is recognized immediately in net income. Transaction costs associated with business combinations are expensed as incurred.

j)Foreign Currency Translation

Foreign operations

The Company has operations in the U.S. transacted via U.S. subsidiaries. The assets and liabilities of foreign operations are translated to Canadian dollars at exchange rates in effect at the balance sheet date. The income and expenses of foreign operations are translated to Canadian dollars using average exchange rates for the period. The resulting unrealized gain or loss is included in other comprehensive income. The unrealized gain or loss is subsequently reclassified to profit and loss upon discontinuation of the foreign operations.

Foreign transactions

Transactions in foreign currencies not incurred by the Company’s U.S. subsidiaries are translated to Canadian dollars at exchange rates in effect at the transaction dates. Foreign currency assets and liabilities are translated to Canadian dollars at exchange rates in effect at the balance sheet date and income and expenses are translated to Canadian dollars using average exchange rates for the period. Both realized and unrealized gains and losses resulting from the settlement or restatement of foreign currency transactions are included in net income.

k)Revenue Recognition

The Company’s major revenue sources are comprised of sales from the production of crude oil and condensate, natural gas liquids ("NGLs") and natural gas. Revenue is recognized when control of the product transfers to the customer and the collection is reasonably probable, generally upon delivery of the product. Sales of crude oil and condensate, NGLs and natural gas production are based on variable pricing as the transaction prices are based on benchmark commodity prices and other variable factors, including quality differentials and location.

Each contract is 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, revenue is recognized on a gross basis. Where the Company acts as agent, revenue is recognized on a net basis.

l)Cash and Cash Equivalents

Cash and cash equivalents include short-term investments with original maturities of three months or less.

m)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. At the commencement date, the lease liability is recognized at the present value of the future lease payments and discounted using the interest rate implicit in the lease or the Company's incremental borrowing rate. A corresponding right-of-use ("ROU") asset will be recognized at the amount of the lease liability, adjusted for any lease incentives received and initial direct costs incurred. Over the term of the lease, financing expense is recognized on the lease liability using the effective interest rate method and charged to net income, lease payments are applied against the lease liability and depreciation on the ROU asset is recorded by class of underlying asset.

The lease term is the non-cancellable period of a lease and includes periods covered by an optional lease extension option if reasonably certain the Company will exercise the option to extend. Conversely, periods covered by an option to terminate are included if the Company does not expect to end the lease during that time frame. Leases with a term of less than twelve months or leases for underlying low value assets are recognized as an expense in net income on a straight-line basis over the lease term.

A lease modification will be accounted for as a separate lease if it materially changes the scope of the lease. For a modification that is not a separate lease, on the effective date of the lease modification, the Company will remeasure the lease liability and corresponding ROU asset using the interest rate implicit in the lease or the Company's incremental borrowing rate. Any variance between the remeasured ROU asset and lease liability will be recognized as a gain or loss in net income to reflect the change in scope.

The Company also acts as an intermediate lessor for office space sub-leased to other companies. As a lessor, the Company will evaluate whether a lease is a finance or operating lease. Leases where the Company transfers substantially all the risks and rewards of ownership are classified as finance leases. Conversely, leases where the risks and rewards of ownership are retained by the Company are operating leases. The head lease between the Company and the building, and the sub-lease between the Company and tenants, are accounted for separately. The lease classification of the sub-lease is based upon the head lease and not the underlying asset.

n)Earnings Per Share

Basic earnings per share (“EPS”) is calculated by dividing the net income for the period attributable to equity owners of the Company by the weighted average number of common shares outstanding during the period.

Diluted EPS is calculated by adjusting the weighted average number of common shares outstanding for dilutive instruments. The number of shares included with respect to dilutive instruments, being restricted shares issued under the Company’s Restricted Share Bonus Plan and stock options under the Company's Stock Option Plan, is computed using the treasury stock method. The treasury stock method assumes that the deemed proceeds related to unrecognized share-based compensation are used to repurchase shares at the average market price during the period.

o)Government Grants

The Company may receive government grants which provide immediate financial assistance as compensation for costs or expenditures to be incurred. Government grants are accounted for when there is reasonable assurance that conditions attached to the grants are met and that the grants will be received. The Company recognizes government grants in net income on a systematic basis and in line with recognition of the expense that the grants are intended to compensate.

p)Assets Held for Sale

PP&E and E&E assets are classified as held for sale if it is highly probable their carrying amounts will be recovered through a capital disposition rather than through future operating cash flows. Before PP&E and E&E assets are classified as held for sale, they are assessed for indicators of impairment or reversal of previously recorded impairments and are measured at the lower of their carrying amount and fair value less costs of disposal. Any impairment charges or reversals are recognized in net income. Assets held for sale are classified as current assets and are not subject to DD&A. Decommissioning liabilities associated with assets held for sale are classified as current liabilities.

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Changes in Accounting Policies

12 Months Ended

Dec. 31, 2023

Disclosure of changes in accounting policies [Abstract]

Changes In Accounting Policies

CHANGES IN ACCOUNTING POLICIES

Income Taxes

IAS 12 Income Taxes was amended in May 2021 by the International Accounting Standards Board which requires companies, on initial recognition, to recognize deferred tax on transactions that result in equal amounts of taxable and deductible temporary differences. The Company adopted the amendment in 2023 and the adoption did not have an impact on the Company's consolidated financial statements.

New accounting standards and amendments not yet adopted

Income Taxes

IAS 12 Income Taxes was amended in May 2023 by the International Accounting Standards Board to provide guidance on current and deferred taxes arising from Pillar Two model rules published by the Organisation for Economic Co-operation and Development. The adoption of this amendment is not expected to have an impact on the Company's consolidated financial statements.

Presentation of Financial Statements

IAS 1 Presentation of Financial Statements was amended in January 2020 by the International Accounting Standards Board to clarify the presentation requirements of liabilities as either current or non-current within the statement of financial position. This amendment is effective for fiscal years beginning on or after January 1, 2024. The adoption of this amendment is not expected to have an impact on the Company's consolidated financial statements.

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Other Current Assets

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Other Current Assets

OTHER CURRENT ASSETS

($ millions)	2023	2022
Deferred consideration receivable	79.2	—
Deposit on acquisition	—	18.7
Other current assets	79.2	18.7

At December 31, 2023, deferred consideration receivable relates to US$60.0 million deferred consideration from the disposition of the Company's North Dakota assets, which will be settled in two equal installments due June 2024 and December 2024. See Note 8 - "Capital Acquisitions and Dispositions" for additional information.

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Other Long-term Assets

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Other Long-term Assets

OTHER LONG-TERM ASSETS

At December 31, 2023, other long-term assets relates to investment tax credits of $7.2 million (December 31, 2022 - $6.4 million) and other investments of $0.2 million (December 31, 2022 - nil).

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Exploration and Evaluation Assets

12 Months Ended

Dec. 31, 2023

Exploration For And Evaluation Of Mineral Resources [Abstract]

Exploration and Evaluation Assets

EXPLORATION AND EVALUATION ASSETS

($ millions)	2023	2022
Exploration and evaluation assets at cost	1,578.6	1,453.4
Accumulated amortization	(971.6)	(1,349.2)
Net carrying amount	607.0	104.2
Reconciliation of movements during the year
Cost, beginning of year	1,453.4	1,613.3
Accumulated amortization, beginning of year	(1,349.2)	(1,564.5)
Net carrying amount, beginning of year	104.2	48.8
Net carrying amount, beginning of year	104.2	48.8
Acquisitions through business combinations	515.2	28.0
Additions	224.8	134.2
Dispositions	(1.9)	(10.9)
Transfers to property, plant and equipment	(204.3)	(80.8)
Amortization	(30.9)	(15.2)
Foreign exchange	(0.1)	0.1
Net carrying amount, end of year	607.0	104.2

Impairment test of exploration and evaluation assets

There were no indicators of impairment at December 31, 2023 or December 31, 2022.

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Capital Acquisitions and Dispositions

12 Months Ended

Dec. 31, 2023

Business Combinations And Dispositions [Abstract]

Capital Acquisitions and Dispositions

CAPITAL ACQUISITIONS AND DISPOSITIONS

In the year ended December 31, 2023, the Company incurred $48.5 million (year ended December 31, 2022 - $5.1 million) of total transaction costs related to acquisitions through business combinations and dispositions. In the year ended December 31, 2023, $39.8 million (year ended December 31, 2022 - $4.6 million) related to continuing operations that were recorded as general and administrative expenses.

a) Corporate acquisition

Hammerhead Energy Inc.

On December 21, 2023, Crescent Point completed the acquisition, by way of statutory arrangement, of all issued and outstanding common shares of Hammerhead Energy Inc. ("Hammerhead"), a public oil and liquids-rich Alberta Montney producer, which was accounted for as a business combination. Total consideration was $2.04 billion, consisting of $1.54 billion in cash and the issuance of 53.2 million common shares. Long-term debt acquired of $363.8 million was repaid on December 21, 2023.

Oil and gas sales of $24.7 million and oil and gas sales less royalties, transportation and operating expenses of $14.8 million are attributable to the Hammerhead acquisition from the date of acquisition to December 31, 2023. Had the acquisition occurred on January 1, 2023, estimated oil and gas sales of $833.3 million and oil and gas sales less royalties, transportation and operating expenses of $527.6 million would have been recognized for the period ended December 31, 2023. This pro-forma information is not necessarily indicative of the results should the acquisition have actually occurred on January 1, 2023.

b) Major property acquisitions and dispositions

Kaybob Duvernay acquisition

On January 11, 2023, the Company closed the acquisition of certain Kaybob Duvernay assets in Alberta for total consideration of $370.4 million, which was accounted for as a business combination.

Oil and gas sales of $56.4 million and oil and gas sales less royalties, transportation and operating expenses of $37.0 million are attributable to the Kaybob Duvernay acquisition from the date of acquisition to December 31, 2023. Had the acquisition occurred on January 1, 2023, estimated oil and gas sales of $58.8 million and oil and gas sales less royalties, transportation and operating expenses of $38.7 million would have been recognized for the period ended December 31, 2023. This pro-forma information is not necessarily indicative of the results should the acquisition have actually occurred on January 1, 2023.

Alberta Montney acquisition

On May 10, 2023, the Company closed the acquisition of Montney assets in Alberta for total consideration of $1.70 billion, which was accounted for as a business combination.

Oil and gas sales of $505.1 million and oil and gas sales less royalties, transportation and operating expenses of $329.4 million are attributable to the Alberta Montney acquisition from the date of acquisition to December 31, 2023. Had the acquisition occurred on January 1, 2023, estimated oil and gas sales of $755.7 million and oil and gas sales less royalties, transportation and operating expenses of $512.6 million would have been recognized for the period ended December 31, 2023. This pro-forma information is not necessarily indicative of the results should the acquisition have actually occurred on January 1, 2023.

North Dakota disposition

On October 24, 2023, the Company completed the disposition of its producing North Dakota assets for total consideration of $585.8 million, including interim closing adjustments and working capital items. Total consideration consisted of $504.6 million (US$372.7 million) in cash and $81.2 million (US$60.0 million) in deferred consideration receivable. See Note 5 - "Other Current Assets" and Note 9 - "Discontinued Operations" for additional information.

c) Minor property acquisitions and dispositions

In the year ended December 31, 2023, the Company completed minor property acquisitions and dispositions for net consideration received of $17.3 million. These assets had a net carrying value of $17.2 million, resulting in a gain of $0.1 million.

The following table summarizes the Company's capital acquisitions and dispositions:

($ millions)	Hammerhead Acquisition (1) (2)	Kaybob Duvernay Acquisition	Alberta Montney Acquisition	North Dakota Disposition (3) (4)	Other minor dispositions, net
Cash	(1,544.0)	(370.4)	(1,700.4)	504.6	17.3
Common shares	(493.0)	—	—	—	—
Deferred consideration receivable	—	—	—	81.2	—
Consideration (paid) received	(2,037.0)	(370.4)	(1,700.4)	585.8	17.3
Working capital	(116.7)	—	—	9.1	—
Derivative asset	12.3	—	—	—	—
Other long-term assets	—	—	0.1	—	—
Exploration and evaluation	354.8	52.1	108.3	(1.8)	(0.1)
Property, plant and equipment	2,406.6	323.7	1,616.6	(635.2)	(20.8)
Right-of-use asset	4.3	—	—	(1.0)	—
Goodwill	72.6	—	—	—	(0.6)
Long-term debt	(363.8)	—	—	—	—
Decommissioning liability	(9.9)	(5.4)	(24.6)	13.7	4.3
Derivative liability	(0.3)	—	—	19.0	—
Lease liability	(4.3)	—	—	1.1	—
Deferred income tax liability	(318.6)	—	—	—	—
Fair value of net assets acquired (Carrying value of net assets disposed)	2,037.0	370.4	1,700.4	(595.1)	(17.2)
Gain (loss) on capital dispositions	—	—	—	(9.3)	0.1

(1)Total net assets acquired excludes $696.6 million of commitments relating to transportation, $156.7 million related to gas processing and $4.8 million related to operating.

(2)Working capital includes $115.4 million of accounts receivable, $7.6 million of prepaids and deposits, and $239.7 million of accounts payable and accrued liabilities.

(3)Working capital includes $9.1 million of accounts payable and accrued liabilities.

(4)See Note 5 - "Other Current Assets" for additional information on deferred consideration receivable.

d) Assets held for sale

At December 31, 2023, certain non-core assets in the Company's Alberta CGU remain held for sale. Upon classification, assets held for sale were recorded at the lesser of their carrying value and recoverable amount. The Company completed the disposition of its Southern Alberta assets in January 2024. See Note 33 - "Subsequent Events" for additional information.

($ millions)	2023	2022
Assets held for sale - PP&E	247.1	148.4
Liabilities held for sale - Decommissioning liability	(132.4)	(28.4)

For additional information on the Company's assets and liabilities held for sale see Note 10 - "Property, Plant and Equipment" and Note 16 - "Decommissioning Liability", respectively.

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Discontinued Operations

12 Months Ended

Dec. 31, 2023

Disclosure of analysis of single amount of discontinued operations [abstract]

Discontinued Operations

DISCONTINUED OPERATIONS

On October 24, 2023, the Company completed the disposition of the assets in its Northern U.S. CGU. The Northern U.S. CGU represents a geographical area of the Company's operations, therefore, its results have been classified as a discontinued operation in accordance with IFRS 5 Non-current Assets Held for Sale and Discontinued Operations. See Note 8 - "Capital Acquisitions and Dispositions" for additional information. Upon disposition of the Company's U.S. operations, the cumulative foreign currency translation recognized in accumulated other comprehensive income was reclassified from shareholders' equity to profit or loss. As a result, the Company recognized a foreign exchange gain of $621.7 million in the year ended December 31, 2023.

In the year ended December 31, 2023, the Company derecognized its U.S. tax pools as a result of the completed North Dakota asset sale.

a) Results from discontinued operations

The following table summarizes the Company's financial results from discontinued operations:

For the years ended December 31
(Cdn$ millions)	2023	2022
REVENUE AND OTHER INCOME
Oil and gas sales	612.9	646.1
Royalties	(155.9)	(165.4)
Oil and gas revenue	457.0	480.7
Commodity derivative losses	(23.4)	—
Other loss	(2.2)	(0.2)
	431.4	480.5
EXPENSES
Operating	80.0	84.9
Transportation	12.2	8.8
General and administrative	12.7	3.4
Foreign exchange gain	(621.7)	—
Share-based compensation	(0.4)	0.3
Depletion, depreciation and amortization	170.3	144.5
Impairment (impairment reversal)	728.4	(71.3)
Accretion and financing	0.4	0.4
	381.9	171.0
Net income before tax from discontinued operations	49.5	309.5
Tax expense (recovery)
Current	—	—
Deferred	278.6	(27.2)
Net income (loss) from discontinued operations	(229.1)	336.7

b) Cash flows from discontinued operations

The following table summarizes cash flows from discontinued operations reported in the consolidated statements of cash flows:

For the years ended December 31
(Cdn$ millions)	2023	2022
Cash provided by (used in) discontinued operations
Operating activities	399.0	363.5
Investing activities	177.3	(252.3)
Increase in cash from discontinued operations	576.3	111.2

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2023

Property, plant and equipment [abstract]

Property, Plant and Equipment

PROPERTY, PLANT AND EQUIPMENT

($ millions)	2023	2022
Development and production assets	24,580.6	22,340.0
Corporate assets	132.1	126.2
Property, plant and equipment at cost	24,712.7	22,466.2
Accumulated depletion, depreciation and impairment	(13,994.4)	(14,736.8)
Net carrying amount	10,718.3	7,729.4
Reconciliation of movements during the year
Development and production assets
Cost, beginning of year	22,340.0	23,402.9
Accumulated depletion and impairment, beginning of year	(14,651.8)	(15,762.6)
Net carrying amount, beginning of year	7,688.2	7,640.3
Net carrying amount, beginning of year	7,688.2	7,640.3
Acquisitions through business combinations	4,348.6	66.0
Additions	1,025.8	741.9
Dispositions	(657.7)	(285.8)
Transfers from exploration and evaluation assets	204.3	80.8
Reclassified as assets held for sale	(98.7)	(148.4)
Depletion	(1,009.3)	(911.4)
Impairment reversal (impairment)	(822.2)	428.6
Foreign exchange	0.2	76.2
Net carrying amount, end of year	10,679.2	7,688.2
Cost, end of year	24,580.6	22,340.0
Accumulated depletion and impairment, end of year	(13,901.4)	(14,651.8)
Net carrying amount, end of year	10,679.2	7,688.2
Corporate assets
Cost, beginning of year	126.2	123.2
Accumulated depreciation, beginning of year	(85.0)	(76.2)
Net carrying amount, beginning of year	41.2	47.0
Net carrying amount, beginning of year	41.2	47.0
Additions	5.9	2.6
Depreciation	(8.0)	(8.5)
Foreign exchange	—	0.1
Net carrying amount, end of year	39.1	41.2
Cost, end of year	132.1	126.2
Accumulated depreciation, end of year	(93.0)	(85.0)
Net carrying amount, end of year	39.1	41.2

At December 31, 2023, future development costs of $9.08 billion (December 31, 2022 - $5.16 billion) were included in costs subject to depletion.

Direct general and administrative costs capitalized by the Company during the year ended December 31, 2023 were $42.4 million (year ended December 31, 2022 - $49.7 million), including $5.7 million of share-based compensation costs (year ended December 31, 2022 - $14.7 million).

Impairment test of property, plant and equipment

The following table summarizes the total impairment (impairment reversal) on the consolidated statements of comprehensive income:

($ millions)	2023	2022 (1)
Impairment reversal	—	(1,469.6)
Impairment	—	985.0
Impairment on assets held for sale	93.8	127.3
Impairment (impairment reversal)	93.8	(357.3)

(1)Comparative period revised to reflect current period presentation.

Assets Held for Sale

At December 31, 2022, the Company classified certain non-core assets in its Alberta CGU as held for sale. Immediately prior to classifying the assets as held for sale, the Company conducted a review of the assets' recoverable amounts and recorded an impairment loss of $71.3 million on PP&E as a component of net impairment reversal in 2022. At December 31, 2023, these assets remained as held for sale. An additional impairment loss of $42.2 million was recorded in the fourth quarter of 2023. The recoverable amount was determined based on the assets' fair value less costs of disposal and based on expected consideration.

At September 30, 2023, the Company classified additional non-core assets in its Alberta CGU as assets held for sale. Immediately prior to classifying the assets as held for sale, the Company conducted a review of the assets' recoverable amounts and recorded an impairment loss of $45.4 million on PP&E. An additional impairment loss of $6.2 million related to these assets was recorded in the fourth quarter of 2023. The recoverable amount was determined based on the assets' fair value less costs of disposal and based on expected consideration. The assets were sold in January 2024. See Note 33 - "Subsequent Events" for additional information.

Q4 2023 Impairment Assessment

At December 31, 2023, there were no indicators of impairment or impairment reversal.

Q4 2022 Impairment

At December 31, 2022, there were no indicators of impairment or impairment reversal in the Alberta and Northern U.S. CGUs.

At December 31, 2022, the Company identified indicators that its Southeast Saskatchewan and Southwest Saskatchewan CGUs might be impaired. Increases in forecast costs and the reallocation of forecast capital spending from Saskatchewan to other CGUs were considered indicators of impairment. As a result, a test for impairment was conducted and the Company prepared estimates of future cash flows to determine the recoverable amount of the respective assets.

The following table outlines the forecast benchmark commodity prices and the exchange rate used in the impairment calculation of PP&E at December 31, 2022:

	2023 (1)	2024	2025	2026	2027	2028	2029	2030	2031	2032	2033 (3)
WTI ($US/bbl) (2)	80.33	78.50	76.95	77.61	79.16	80.74	82.36	84.00	85.69	87.40	89.15
Exchange Rate ($US/$Cdn)	0.745	0.765	0.768	0.772	0.775	0.775	0.775	0.775	0.775	0.775	0.775
WTI ($Cdn/bbl)	107.83	102.61	100.20	100.53	102.14	104.18	106.27	108.39	110.57	112.77	115.03
AECO ($Cdn/mmbtu) (2)	4.23	4.40	4.21	4.27	4.34	4.43	4.51	4.60	4.69	4.79	4.88

(1)Effective January 1, 2023.

(2)The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, distance to market and other factors in performing the impairment tests.

(3)Forecast benchmark commodity prices are assumed to increase by 2.0% in each year after 2033 to the end of the reserve life. Exchange rates are assumed to be constant at 0.775.

The following table summarizes the impairment expense for the year ended December 31, 2022 by CGU:

CGU ($ millions, except %)	Operating segment	Recoverable amount	Discount rate		Impairment	Impairment,  net of tax
Southeast Saskatchewan	Canada	2,868.3	15.00	%	564.5	424.4
Southwest Saskatchewan	Canada	1,356.6	15.00	%	420.5	316.1
Total impairment		4,224.9			985.0	740.5

The following sensitivities show the resulting impact on income before tax of the changes in discount rate, forecast benchmark commodity price estimates and forecast operating cost estimates at December 31, 2022, with all other variables held constant:

CGU	Discount Rate		Commodity Prices		Operating Costs
($ millions)	Increase 1%	Decrease 1%	Increase 5%	Decrease 5%	Increase 5%	Decrease 5%
Southeast Saskatchewan	(167.8)	185.2	349.4	(348.3)	(117.7)	118.7
Southwest Saskatchewan	(88.0)	97.3	185.6	(185.3)	(64.8)	65.0
Increase (decrease)	(255.8)	282.5	535.0	(533.6)	(182.5)	183.7

Q1 2022 Impairment Reversal

At March 31, 2022, the significant increase in forecast benchmark commodity prices and the increase in the Company's market capitalization since the last impairment test at June 30, 2021, were indicators of impairment reversal.

The following table outlines the forecast benchmark commodity prices and the exchange rate used in the impairment calculation of PP&E at March 31, 2022:

	2022 (1)	2023	2024	2025	2026	2027	2028	2029	2030	2031	2032 (3)
WTI ($US/bbl) (2)	94.17	84.05	75.38	74.41	75.90	77.42	78.97	80.55	82.16	83.80	85.48
Exchange Rate ($US/$Cdn)	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800
WTI ($Cdn/bbl)	117.71	105.06	94.23	93.01	94.88	96.78	98.71	100.69	102.70	104.75	106.85
AECO ($Cdn/mmbtu) (2)	5.18	4.18	3.38	3.34	3.41	3.48	3.54	3.61	3.69	3.76	3.84

(1)Effective April 1, 2022.

(2)The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, distance to market and other factors in performing the impairment tests.

(3)Forecast benchmark commodity prices are assumed to increase by 2.0% in each year after 2032 to the end of the reserve life. Exchange rates are assumed to be constant at 0.800.

The following table summarizes the impairment reversal for the three months ended March 31, 2022 by CGU:

CGU ($ millions, except %)	Operating segment	Recoverable amount	Discount rate		Impairment reversal	Impairment reversal, net of tax
Southeast Saskatchewan	Canada	3,413.8	15.00	%	806.0	605.3
Southwest Saskatchewan	Canada	1,715.0	15.00	%	419.4	315.0
Alberta	Canada	2,567.1	15.00	%	244.2	183.4
Total impairment reversal		7,695.9			1,469.6	1,103.7

The following sensitivities show the resulting impact on income before tax of the changes in discount rate and forecast benchmark commodity price estimates at March 31, 2022, with all other variables held constant:

CGU	Discount Rate		Commodity Prices
($ millions)	Increase 1%	Decrease 1%	Increase 5%	Decrease 5%
Southeast Saskatchewan	(186.2)	204.8	367.6	(366.6)
Southwest Saskatchewan	(95.0)	104.6	201.1	(201.1)
Alberta	—	—	—	—
Increase (decrease)	(281.2)	309.4	568.7	(567.7)

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Goodwill

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Goodwill

GOODWILL

($ millions)	2023	2022
Goodwill, beginning of year	203.9	211.5
Hammerhead acquisition	72.6	—
Saskatchewan Viking asset disposition	—	(6.8)
Other dispositions	(0.6)	(0.8)
Goodwill, end of year	275.9	203.9

In the year ended December 31, 2023, the Company recognized $72.6 million of goodwill associated with the Hammerhead acquisition, primarily due to the deferred tax liability. See Note 8 - "Capital Acquisitions and Dispositions" for additional information. Goodwill has been assigned to the Canadian operating segment.

Impairment test of goodwill

The impairment tests of goodwill compared the recoverable amount of the Company's PP&E and E&E to the carrying amount of the combined PP&E, E&E and goodwill at December 31, 2023 and December 31, 2022. The recoverable amount of the Company's PP&E and E&E was estimated using independent reserve evaluator forecast benchmark commodity prices, proved plus probable oil and gas reserve estimates and management's estimate of the fair market value of undeveloped land. As a result of these tests, the Company concluded that the estimated recoverable amounts exceeded the carrying amounts and no impairments were recorded.

The following table outlines the forecast benchmark commodity prices and the exchange rate used in the impairment calculation of goodwill at December 31, 2023:

	2024 (1)	2025	2026	2027	2028	2029	2030	2031	2032	2033	2034 (3)
WTI ($US/bbl) (2)	73.67	74.98	76.14	77.66	79.22	80.80	82.42	84.06	85.74	87.46	89.21
Exchange Rate ($US/$Cdn)	0.752	0.752	0.755	0.755	0.755	0.755	0.755	0.755	0.755	0.755	0.755
WTI ($Cdn/bbl)	97.97	99.71	100.85	102.86	104.93	107.02	109.17	111.34	113.56	115.84	118.16
AECO ($Cdn/mmbtu) (2)	2.20	3.37	4.05	4.13	4.21	4.30	4.38	4.47	4.56	4.65	4.74

(1)Effective January 1, 2024.

(2)The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, distance to market and other factors in performing the impairment tests.

(3)Forecast benchmark commodity prices are assumed to increase by 2.0% in each year after 2034 to the end of the reserve life. Exchange rates are assumed to be constant at 0.755.

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Other Current Liabilities

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Other Current Liabilities

OTHER CURRENT LIABILITIES

($ millions)	2023	2022
Long-term compensation liability	37.5	49.1
Lease liability	40.5	24.9
Decommissioning liability	40.0	41.6
Other current liabilities	118.0	115.6

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Long-term Debt

12 Months Ended

Dec. 31, 2023

Financial Instruments [Abstract]

Long-term Debt

LONG-TERM DEBT

($ millions)	2023	2022
Revolving bank debt	1,932.9	—
Bank term loan	750.0	—
Senior guaranteed notes	883.4	1,441.5
Long-term debt	3,566.3	1,441.5
Long-term debt due within one year	380.0	538.7
Long-term debt due beyond one year	3,186.3	902.8

Bank debt

Revolving bank debt

At December 31, 2023, the Company had combined facilities of $2.76 billion. This includes a $2.26 billion syndicated unsecured credit facility with eleven banks and a $100.0 million unsecured operating credit facility with one Canadian chartered bank, both with a current maturity date of November 26, 2026. Both of these facilities constitute revolving credit facilities and are extendible annually. On May 10, 2023, concurrent with the closing of the Alberta Montney acquisition, Crescent Point entered into an additional $400.0 million syndicated unsecured revolving credit facility with ten banks that matures on May 10, 2025.

The credit facilities have covenants which restrict the Company's ratio of senior debt to adjusted EBITDA to a maximum of 3.5:1.0, the ratio of total debt to adjusted EBITDA to a maximum of 4.0:1.0 and the ratio of senior debt to capital, adjusted for certain non-cash items as noted above, to a maximum of 0.55:1.0. The Company was in compliance with all debt covenants at December 31, 2023.

The Company had letters of credit in the amount of $26.2 million outstanding at December 31, 2023 (December 31, 2022 - $1.8 million).

Bank term loan

On December 21, 2023, concurrent with the closing of the Hammerhead acquisition, the Company entered into a $750.0 million syndicated term loan with twelve banks that matures on November 26, 2026.

The term loan has financial covenants similar to those of the combined credit facilities described above.

Senior guaranteed notes

At December 31, 2023, the Company had senior guaranteed notes of US$589.5 million and Cdn$105.0 million outstanding. The notes are unsecured and rank pari passu with the Company's bank credit facilities and carry a bullet repayment on maturity. The senior guaranteed notes have financial covenants similar to those of the combined credit facilities described above.

Concurrent with the issuance of senior guaranteed notes with total principal of US$517.0 million, the Company entered into cross currency swaps ("CCS") to manage the Company's foreign exchange risk. The CCS fix the US dollar amount of the individual tranches of notes for purposes of interest and principal repayments at a notional amount of $606.9 million. See Note 27 - "Financial Instruments and Derivatives" for additional information.

The following table summarizes the Company's senior guaranteed notes:

Principal ($ millions)	Coupon Rate		Hedged Principal (1) (Cdn$ millions)	Unhedged  Principal (2) (Cdn$ millions)	Interest Payment Dates	Maturity Date	Financial statement carrying value
							2023	2022
US$61.5	4.12	%	—	—	October 11 and April 11	April 11, 2023	—	83.2
Cdn$80.0	3.58	%	—	—	October 11 and April 11	April 11, 2023	—	80.0
Cdn$10.0	4.11	%	—	—	December 12 and June 12	June 12, 2023	—	10.0
US$270.0	3.78	%	—	—	December 12 and June 12	June 12, 2023	—	365.5
Cdn$40.0	3.85	%	40.0	—	December 20 and June 20	June 20, 2024	40.0	40.0
US$257.5	3.75	%	276.4	—	December 20 and June 20	June 20, 2024	340.0	348.5
US$82.0	4.30	%	67.9	39.6	October 11 and April 11	April 11, 2025	108.3	111.0
Cdn$65.0	3.94	%	65.0	—	October 22 and April 22	April 22, 2025	65.0	65.0
US$230.0	4.08	%	262.6	29.7	October 22 and April 22	April 22, 2025	303.7	311.3
US$20.0	4.18	%	—	26.4	October 22 and April 22	April 22, 2027	26.4	27.0
Senior guaranteed notes			711.9	95.7			883.4	1,441.5
Due within one year			316.4	—			380.0	538.7
Due beyond one year			395.5	95.7			503.4	902.8

(1)Includes underlying derivatives which fix the Company's foreign exchange exposure on its US dollar senior guaranteed notes or represents the Canadian dollar principal on Canadian dollar denominated senior guaranteed notes.

(2)Includes the principal balance translated at the period end foreign exchange rate on US dollar senior guaranteed notes that do not have underlying CCS

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Leases

12 Months Ended

Dec. 31, 2023

Disclosure of leases [Abstract]

Leases

LEASES

Right-of-use asset

($ millions)	Office (1)	Fleet Vehicles	Equipment	Total
Right-of-use asset at cost	124.8	37.2	38.6	200.6
Accumulated depreciation	(65.1)	(23.0)	(9.7)	(97.8)
Net carrying amount	59.7	14.2	28.9	102.8
Reconciliation of movements during the year
Cost, beginning of year	121.9	28.5	11.1	161.5
Accumulated depreciation, beginning of year	(55.4)	(20.4)	(7.6)	(83.4)
Net carrying amount, beginning of year	66.5	8.1	3.5	78.1
Net carrying amount, beginning of year	66.5	8.1	3.5	78.1
Acquisitions through business combinations	3.0	0.6	0.7	4.3
Additions	0.8	10.6	26.8	38.2
Dispositions	(0.1)	(0.9)	—	(1.0)
Depreciation	(10.5)	(4.2)	(2.1)	(16.8)
Net carrying amount, end of year	59.7	14.2	28.9	102.8

(1)A portion of the Company's office space is subleased. During the year ended December 31, 2023, the Company recorded sublease income of $3.7 million (year ended December 31, 2022 - $3.6 million) as a component of other income.

Lease liability

($ millions)	2023	2022
Lease liability, beginning of year	124.1	141.4
Acquisitions through business combinations	4.3	—
Additions	38.2	3.8
Dispositions	(1.1)	—
Financing	5.2	5.7
Payments on lease liability	(26.0)	(26.1)
Other	—	(0.7)
Lease liability, end of year	144.7	124.1
Expected to be incurred within one year	40.5	24.9
Expected to be incurred beyond one year	104.2	99.2

Some leases contain variable payments that are not included within the lease liability as the payments are based on amounts determined by the lessor annually and not dependent on an index or rate. For the year ended December 31, 2023, variable lease payments of $1.7 million were included in general and administrative expenses relating to property tax payments on office leases (year ended December 31, 2022 - $1.5 million).

During the year ended December 31, 2023, the Company recorded $0.8 million in payments related to short-term leases and leases for low dollar value underlying assets in operating and general and administrative expenses (year ended December 31, 2022 - $0.8 million).

The undiscounted cash flows relating to the lease liability are as follows:

($ millions)	December 31, 2023
1 year	41.8
2 to 3 years	59.6
4 to 5 years	35.5
More than 5 years	25.2
Total (1)	162.1

(1)Includes both the principal and amounts representing interest.

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Other Long-term Liabilities	12 Months Ended
	Dec. 31, 2023
Subclassifications of assets, liabilities and equities [abstract]
Other Long-term Liabilities	OTHER LONG-TERM LIABILITIESAt December 31, 2023, the Company had a long-term compensation liability of $31.0 million (December 31, 2022 - $40.8 million) related to share-based compensation. See Note 25 - "Share-based Compensation" for additional information.

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Decommissioning Liability

12 Months Ended

Dec. 31, 2023

Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]

Decommissioning Liability

DECOMMISSIONING LIABILITY

($ millions)	2023	2022
Decommissioning liability, beginning of year	675.5	918.8
Liabilities incurred	19.8	21.6
Liabilities acquired through capital acquisitions	40.1	3.4
Liabilities disposed through capital dispositions	(18.2)	(46.7)
Liabilities settled (1)	(45.4)	(43.1)
Revaluation of acquired decommissioning liabilities (2)	38.5	3.8
Change in estimates	(3.0)	(11.4)
Change in discount and inflation rate estimates	(19.6)	(163.0)
Accretion	22.7	19.2
Reclassified as liabilities associated with assets held for sale	(104.0)	(28.4)
Foreign exchange	—	1.3
Decommissioning liability, end of year	606.4	675.5
Expected to be incurred within one year	40.0	41.6
Expected to be incurred beyond one year	566.4	633.9

(1)Includes $5.4 million received from government grant programs during the year ended December 31, 2023 (year ended December 31, 2022 - $23.0 million).

(2)These amounts relate to the revaluation of acquired decommissioning liabilities at the end of the period using a risk-free discount rate. At the date of acquisition, acquired decommissioning liabilities are fair valued.

Upon retirement of its oil and gas assets, the Company anticipates incurring substantial costs associated with decommissioning. The total future decommissioning liability was estimated by management based on the Company’s net ownership in all wells and facilities. This includes all estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. The Company has estimated the net present value of its total decommissioning liability to be $606.4 million at December 31, 2023 (December 31, 2022 - $675.5 million) based on total estimated undiscounted and uninflated cash flows to settle the obligation of $847.7 million (December 31, 2022 - $894.9 million). These obligations are expected to be settled through 2073, with the majority expected after 2050. The estimated cash flows have been discounted using a risk-free rate of 3.02 percent and a derived inflation rate of 1.62 percent (December 31, 2022 - risk-free rate of 3.28 percent and inflation rate of 2.09 percent).

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Shareholders' Capital

12 Months Ended

Dec. 31, 2023

Disclosure of classes of share capital [abstract]

Shareholders' Capital

SHAREHOLDERS' CAPITAL

Crescent Point has an unlimited number of common shares authorized for issuance.

	2023		2022
	Number of shares	Amount ($ millions)	Number of shares	Amount ($ millions)
Common shares, beginning of year	550,888,983	16,675.8	579,484,032	16,963.4
Issued on capital acquisition	53,202,339	493.0	—	—
Issued for cash	48,550,000	500.1	—	—
Issued on redemption of restricted shares	1,436,017	4.9	1,713,730	5.2
Issued on exercise of stock options	464,051	0.7	1,038,321	1.4
Common shares repurchased for cancellation	(34,611,900)	(349.9)	(31,347,100)	(294.2)
Common shares, end of year	619,929,490	17,324.6	550,888,983	16,675.8
Cumulative share issue costs, net of tax	—	(271.9)	—	(256.5)
Total shareholders’ capital, end of year	619,929,490	17,052.7	550,888,983	16,419.3

Normal Course Issuer Bids ("NCIBs")    

On March 7, 2023, the Company announced the approval by the Toronto Stock Exchange of its notice to implement a NCIB. The NCIB allows the Company to purchase, for cancellation, up to 54,605,659 common shares, or 10 percent of the Company's public float, as at February 23, 2023. The NCIB commenced on March 9, 2023 and is due to expire on March 8, 2024. The Company's previous NCIB commenced on March 9, 2022 and expired on March 8, 2023.

During the year ended December 31, 2023, the Company purchased 34.6 million common shares for total consideration of $349.9 million under its NCIBs. The total cost paid, including commissions and fees, was recognized directly as a reduction in shareholders' equity. Under the NCIB, all common shares purchased are cancelled.

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Deficit

12 Months Ended

Dec. 31, 2023

Equity [abstract]

Deficit

DEFICIT

($ millions)	2023	2022
Accumulated earnings (deficit)	(2,130.3)	(2,700.6)
Accumulated gain on shares issued pursuant to DRIP (1) and SDP (2)	8.4	8.4
Accumulated tax effect on redemption of restricted shares	18.2	15.8
Accumulated dividends	(8,098.8)	(7,886.9)
Deficit	(10,202.5)	(10,563.3)

(1)Premium Dividend TM and Dividend Reinvestment Plan – suspended in 2015.

(2)Share Dividend Plan – suspended in 2015.

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Capital Management

12 Months Ended

Dec. 31, 2023

Capital Management [Abstract]

Capital Management

CAPITAL MANAGEMENT

($ millions)	2023	2022
Long-term debt (1)	3,566.3	1,441.5
Adjusted working capital (surplus) deficiency (2)	196.3	(95.1)
Unrealized foreign exchange on translation of hedged US dollar long-term debt	(24.5)	(191.7)
Net debt	3,738.1	1,154.7
Shareholders’ equity	6,867.5	6,493.4
Total capitalization	10,605.6	7,648.1

(1)Includes current portion of long-term debt.

(2)Adjusted working capital (surplus) deficiency is calculated as accounts payable and accrued liabilities, dividends payable and long-term compensation liability net of equity derivative contracts, less cash, accounts receivable, prepaids and deposits, and other current assets.

The following table reconciles cash flow from operating activities to adjusted funds flow from operations for the year ended December 31, 2023 and December 31, 2022:

($ millions)	2023	2022
Cash flow from operating activities	2,195.7	2,192.2
Changes in non-cash working capital	54.9	15.0
Transaction costs	48.5	5.1
Decommissioning expenditures	40.0	20.1
Adjusted funds flow from operations	2,339.1	2,232.4

Crescent Point's objective for managing its capital structure is to maintain a strong balance sheet and capital base to provide financial flexibility, position the Company to fund future development projects and provide returns to shareholders.

Crescent Point manages its capital structure and short-term financing requirements using a measure not defined in IFRS Accounting Standards, or standardized, the ratio of net debt to adjusted funds flow from operations. Net debt to adjusted funds flow from operations is used to measure the Company's overall debt position and to measure the strength of the Company's balance sheet and might not be comparable to similar financial measures disclosed by other issuers. Crescent Point's objective is to manage this metric to be well positioned to execute its business objectives during periods of volatile commodity prices. Crescent Point monitors this ratio and uses it as a key measure in capital allocation decisions including capital spending levels, returns to shareholders including dividends and share repurchases, and financing considerations. The Company's net debt to adjusted funds flow from operations ratio for the trailing four quarters at December 31, 2023 was 1.6 times (December 31, 2022 - 0.5 times).

Crescent Point is subject to certain financial covenants on its credit facilities and senior guaranteed notes agreements and was in compliance with all financial covenants as at December 31, 2023. See Note 13 - "Long-term Debt" for additional information regarding the Company's financial covenant requirements.

Crescent Point retains financial flexibility with liquidity on its credit facilities. The Company continuously monitors the commodity price environment and manages its counterparty exposure to mitigate credit losses and protect its balance sheet.

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Commodity Derivative Gains (Losses)

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Commodity Derivative Gains (Losses)

COMMODITY DERIVATIVE GAINS (LOSSES)

($ millions)	2023	2022
Realized gains (losses)	15.5	(641.8)
Unrealized gains	148.3	168.4
Commodity derivative gains (losses)	163.8	(473.4)

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Other Income

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Other Income (Loss)

OTHER INCOME

($ millions)	2023	2022 (1)
Gain (loss) on capital dispositions	(0.7)	26.1
Government grant for decommissioning expenditures	5.4	23.0
Sublease income	3.7	3.6
Other	5.0	6.3
Other income	13.4	59.0

(1)Comparative period revised to reflect current period presentation.

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Interest Expense

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Interest Expense

INTEREST EXPENSE

($ millions)	2023	2022
Interest expense on long-term debt	126.0	64.7
Unrealized (gain) loss on interest derivative contracts	3.4	(1.1)
Interest expense	129.4	63.6

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Foreign Exchange Gain (Loss)

12 Months Ended

Dec. 31, 2023

Foreign exchange rates [abstract]

Foreign Exchange Gain (Loss)

FOREIGN EXCHANGE GAIN (LOSS)

($ millions)	2023	2022
Realized gain on CCS - principal	151.8	63.8
Translation of US dollar long-term debt	16.8	(94.3)
Unrealized gain (loss) on CCS - principal and foreign exchange swaps	(153.6)	4.4
Other	(5.0)	7.3
Foreign exchange gain (loss)	10.0	(18.8)

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Income Taxes

12 Months Ended

Dec. 31, 2023

Income Taxes [Abstract]

Income Taxes

INCOME TAXES

The provision for income taxes is as follows:

($ millions)		2023	2022 (1)
Current tax:
	Canada	(0.7)	—
Current tax recovery		(0.7)	—
Deferred tax expense:
	Canada	254.4	415.1
Deferred tax expense		254.4	415.1
Income tax expense		253.7	415.1

(1)Comparative period revised to reflect current period presentation.

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:

($ millions, except percentages)	2023		2022 (1)
Net income before tax from continuing operations	1,053.1		1,561.8
Statutory income tax rate	24.58	%	24.82	%
Expected provision for income taxes	258.9		387.6
Change in corporate tax rates and tax rate variance	(5.6)		1.6
Derecognition (recognition) of deferred tax assets	0.5		(0.7)
Non-deductible capital losses (non-taxable capital gains)	0.1		(0.2)
Non-deductible disposition of goodwill	0.1		1.9
Other (2)	(0.3)		24.9
Income tax expense	253.7		415.1

(1)Comparative period revised to reflect current period presentation.

(2)For the year ended December 31, 2022, there is an expense deducted in a foreign jurisdiction for which a tax benefit is not recognized.

The composition of net deferred income tax asset (liability) is as follows:

($ millions)	2023	2022
Deferred income tax assets	—	278.8
Deferred income tax liabilities	(643.0)	(77.3)
Net deferred income tax asset (liability)	(643.0)	201.5

The net deferred income tax assets (liabilities) are expected to be settled in the following periods:

($ millions)	2023	2022
Deferred income tax:
To be settled within one year	(1.7)	19.6
To be settled beyond one year	(641.3)	181.9
Deferred income tax	(643.0)	201.5

The movement in deferred income tax assets (liabilities) are as follows:

($ millions)	At January 1, 2023	(Charges) / credits due to acquisitions, discontinued operations & other	(Charged) / credited to earnings	At December 31, 2023
Deferred income tax assets:
Decommissioning liability	167.4	(1.6)	(19.2)	146.6
Income tax losses carried forward	744.6	(348.2)	(80.6)	315.8
Risk management contracts	2.1	—	11.3	13.4
Lease liabilities	30.7	0.6	3.7	35.0
Other	29.9	6.8	16.5	53.2
	974.7	(342.4)	(68.3)	564.0
Deferred income tax liabilities:
Property, plant and equipment	(743.1)	(244.2)	(139.9)	(1,127.2)
Risk management contracts	(10.8)	(2.9)	(41.3)	(55.0)
ROU asset	(19.3)	(0.6)	(4.9)	(24.8)
	(773.2)	(247.7)	(186.1)	(1,207.0)
Net deferred income tax assets (liabilities)	201.5	(590.1)	(254.4)	(643.0)

($ millions)	At January 1, 2022	Credits due to acquisitions & other	(Charged) / credited to earnings	At December 31, 2022
Deferred income tax assets:
Decommissioning liability	229.6	—	(62.2)	167.4
Income tax losses carried forward	814.2	—	(69.6)	744.6
Risk management contracts	41.1	—	(39.0)	2.1
Lease liabilities	35.3	—	(4.6)	30.7
Other	19.5	19.3	(8.9)	29.9
	1,139.7	19.3	(184.3)	974.7
Deferred income tax liabilities:
Property, plant and equipment	(533.4)	—	(209.7)	(743.1)
Risk management contracts	(13.4)	—	2.6	(10.8)
ROU asset	(22.8)	—	3.5	(19.3)
	(569.6)	—	(203.6)	(773.2)
Net deferred income tax assets (liabilities)	570.1	19.3	(387.9)	201.5

The approximate amounts of tax pools available as at December 31, 2023 and 2022 are as follows:

($ millions)	2023	2022
Tax pools:
Canada	8,281.0	5,685.8
United States	2,319.7	3,025.2
Total	10,600.7	8,711.0

Deferred tax assets are recognized to the extent of expected utilization of tax attributes, based on estimated undiscounted future cash flows included in the Company's independent reserve report.

The above tax pools include estimated Canadian non-capital losses carried forward of $1.31 billion (December 31, 2022 - $1.36 billion) that expire in the years 2033 through 2040, and U.S. net operating losses of $2.32 billion (December 31, 2022 - $2.30 billion) of which $1.52 billion will expire in the years 2032 through 2037, while the remaining $802.2 million will not expire.

A deferred income tax asset has not been recognized for U.S. tax pools of $2.32 billion (December 31, 2022 - $507.2 million) or for other Canadian tax pools of $69.0 million (December 31, 2022 - $69.0 million) as there is not sufficient certainty regarding future utilization.

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Share-based Compensation

12 Months Ended

Dec. 31, 2023

Share-based Payment Arrangements [Abstract]

Share-based Compensation

SHARE-BASED COMPENSATION

The following table reconciles the number of restricted shares, ESVP awards, PSUs and DSUs for the year ended December 31, 2023:

	Restricted Shares	ESVP	PSUs (1)	DSUs
Balance, beginning of year	2,244,738	5,274,478	2,713,176	1,745,879
Granted	718,566	1,626,590	888,834	231,464
Redeemed	(1,436,017)	(3,721,568)	(1,627,028)	(248,920)
Forfeited	(146,602)	(519,434)	(351,734)	—
Balance, end of year	1,380,685	2,660,066	1,623,248	1,728,423

(1)Based on underlying units before any effect of performance multipliers.

The following table reconciles the number of restricted shares, ESVP awards, PSUs and DSUs for the year ended December 31, 2022:

	Restricted Shares	ESVP	PSUs (1)	DSUs
Balance, beginning of year	3,267,717	8,329,291	3,214,620	1,556,780
Granted	710,819	1,288,598	904,469	208,693
Redeemed	(1,718,906)	(3,691,820)	(1,405,913)	(19,594)
Forfeited	(14,892)	(651,591)	—	—
Balance, end of year	2,244,738	5,274,478	2,713,176	1,745,879

(1)Based on underlying units before any effect of performance multipliers.

The following table provides summary information regarding stock options outstanding as at December 31, 2023:

	Stock options (number of units)	Weighted average exercise price ($)
Balance, beginning of year	3,889,130	4.43
Exercised	(629,013)	2.92
Forfeited	(35,857)	3.43
Balance, end of year	3,224,260	4.74

The following table summarizes information regarding stock options outstanding as at December 31, 2023:

Range of exercise prices ($)	Number of stock options outstanding	Weighted average remaining term for stock options outstanding (years)	Weighted average exercise price per share for stock options outstanding ($)	Number of stock options exercisable	Weighted average exercise price per share for stock options exercisable ($)
1.09 - 1.65	1,541,362	3.25	1.09	505,996	1.09
1.66 - 5.16	254,950	2.27	3.94	245,820	3.99
5.17 - 9.86	438,417	3.70	6.01	177,060	7.15
9.87 - 10.06	989,531	1.02	10.06	989,531	10.06
	3,224,260	2.55	4.74	1,918,407	6.65

The following table provides summary information regarding stock options outstanding as at December 31, 2022:

	Stock options (number of units)	Weighted average exercise price ($)
Balance, beginning of year	5,839,464	4.04
Exercised	(1,446,571)	3.16
Forfeited	(398,610)	2.06
Expired	(105,153)	9.22
Balance, end of year	3,889,130	4.43

The volume weighted average trading price of the Company's common shares was $9.73 per share during the year ended December 31, 2023 (year ended December 31, 2022 - $9.52 per share).

For the year ended December 31, 2023, the Company calculated total share-based compensation of $40.4 million (year ended December 31, 2022 - $75.6 million), net of estimated forfeitures, of which $5.4 million was capitalized (year ended December 31, 2022 - $13.3 million).

At December 31, 2023, the current portion of long-term compensation liability of $37.5 million was included in other current liabilities (December 31, 2022 - $49.1 million) and $31.0 million was included in other long-term liabilities (December 31, 2022 - $40.8 million).

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Per Share Amounts

12 Months Ended

Dec. 31, 2023

Earnings per share [abstract]

Per Share Amounts

PER SHARE AMOUNTS

The following table summarizes the weighted average shares used in calculating net income (loss) per share:

	2023	2022
Weighted average shares – basic	545,644,234	566,710,644
Dilutive impact of share-based compensation	2,684,473	4,357,422
Weighted average shares – diluted	548,328,707	571,068,066

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Financial Instruments and Derivatives

12 Months Ended

Dec. 31, 2023

Financial Instruments [Abstract]

Financial Instruments and Derivatives

FINANCIAL INSTRUMENTS AND DERIVATIVES

The Company's financial assets and liabilities are comprised of cash, accounts receivable, deferred consideration receivable, derivative assets and liabilities, accounts payable and accrued liabilities, dividends payable and long-term debt.

Crescent Point's derivative assets and liabilities are transacted in active markets. The Company classifies the fair value of these transactions according to the following fair value hierarchy based on the amount of observable inputs used to value the instrument:

•Level 1 - Values are based on unadjusted quoted prices available in active markets for identical assets or liabilities as of the reporting date.

•Level 2 - Values are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. Prices in Level 2 are either directly or indirectly observable as of the reporting date.

•Level 3 - Values are based on prices or valuation techniques that are not based on observable market data.

Accordingly, Crescent Point's derivative assets and liabilities are classified as Level 2. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy.

Discussions of the fair values and risks associated with financial assets and liabilities, as well as summarized information related to derivative positions are detailed below:

a) Carrying amount and fair value of financial instruments

The fair value of cash, accounts receivable, accounts payable and accrued liabilities and dividends payable approximate their carrying amount due to the short-term nature of those instruments. The fair value of the amounts drawn on bank debt is equal to its carrying amount as the facilities and term loan bear interest at floating rates and credit spreads that are indicative of market rates. These financial instruments are classified as financial assets and liabilities at amortized cost and are reported at amortized cost.

Crescent Point's derivative assets and liabilities are transacted in active markets, classified as financial assets and liabilities at fair value through profit or loss and fair valued at each period with the resulting gain or loss recorded in net income.

The following table summarizes the carrying value of the Company's remaining financial assets and liabilities as compared to their respective fair values as at December 31, 2023:

	2023 Carrying Value	2023 Fair Value	Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs  (Level 3)
($ millions)
Financial assets
Derivatives	255.0	255.0	—	255.0	—
	255.0	255.0	—	255.0	—
Financial liabilities
Derivatives	55.2	55.2	—	55.2	—
Senior guaranteed notes (1)	883.4	853.0	—	853.0	—
	938.6	908.2	—	908.2	—

(1)The senior guaranteed notes are classified as financial liabilities at amortized cost and are reported at amortized cost. The notes denominated in US dollars are translated to Canadian dollars at the period end exchange rate. The fair value of the notes is calculated based on current interest rates and is not recorded in the financial statements.

The following table summarizes the carrying value of the Company's remaining financial assets and liabilities as compared to their respective fair values as at December 31, 2022:

	2022 Carrying Value	2022 Fair Value	Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs  (Level 3)
($ millions)
Financial assets
Derivatives	235.3	235.3	—	235.3	—
	235.3	235.3	—	235.3	—
Financial liabilities
Derivatives	8.7	8.7	—	8.7	—
Senior guaranteed notes (1)	1,441.5	1,372.9	—	1,372.9	—
	1,450.2	1,381.6	—	1,381.6	—

(1)The senior guaranteed notes are classified as financial liabilities at amortized cost and are reported at amortized cost. The notes denominated in US dollars are translated to Canadian dollars at the period end exchange rate. The fair value of the notes is calculated based on current interest rates and is not recorded in the financial statements.

Derivative assets and liabilities

Derivative assets and liabilities arise from the use of derivative contracts. Crescent Point's derivative assets and liabilities are classified as Level 2 with values based on inputs including quoted forward prices for commodities, time value and volatility factors. Accordingly, the Company's derivative financial instruments are classified as fair value through profit or loss and are reported at fair value with changes in fair value recorded in net income.

The following table summarizes the fair value as at December 31, 2023 and the change in fair value for the year ended December 31, 2023:

($ millions)	Commodity (1)	Interest (2)	Foreign exchange (3)	Equity	Total
Derivative assets, beginning of year	14.0	6.7	175.0	30.9	226.6
Acquisitions through business combinations	12.0	—	—	—	12.0
Dispositions	19.0	—	—	—	19.0
Unrealized change in fair value	129.4	(3.4)	(153.6)	(29.3)	(56.9)
Foreign exchange	(0.9)	—	—	—	(0.9)
Derivative assets, end of year	173.5	3.3	21.4	1.6	199.8
Derivative assets, end of year	176.5	3.3	72.2	3.0	255.0
Derivative liabilities, end of year	(3.0)	—	(50.8)	(1.4)	(55.2)

(1)Includes crude oil, crude oil differentials, natural gas and natural gas differential contracts.

(2)Interest payments on CCS.

(3)Includes principal portion of CCS and foreign exchange contracts.

The following table summarizes the fair value as at December 31, 2022 and the change in fair value for the year ended December 31, 2022:

($ millions)	Commodity (1)	Interest (2)	Foreign exchange (3)	Equity	Total
Derivative assets (liabilities), beginning of year	(154.4)	5.6	170.6	33.8	55.6
Unrealized change in fair value	168.4	1.1	4.4	(2.9)	171.0
Derivative assets, end of year	14.0	6.7	175.0	30.9	226.6
Derivative assets, end of year	22.6	6.7	175.1	30.9	235.3
Derivative liabilities, end of year	(8.6)	—	(0.1)	—	(8.7)

(1)Includes crude oil, crude oil differentials, propane, natural gas and natural gas differential contracts.

(2)Interest payments on CCS.

(3)Includes principal portion of CCS and foreign exchange contracts.

Offsetting financial assets and liabilities

Financial assets and liabilities are only offset if the Company has the legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. The Company offsets derivative assets and liabilities when the counterparty, commodity, currency and timing of settlement are the same. The following table summarizes the gross asset and liability positions of the Company's financial derivatives by contract that are offset on the balance sheet as at December 31, 2023 and December 31, 2022:

	2023			2022
($ millions)	Asset	Liability	Net	Asset	Liability	Net
Gross amount	258.4	(58.6)	199.8	246.3	(19.7)	226.6
Amount offset	(3.4)	3.4	—	(11.0)	11.0	—
Net amount	255.0	(55.2)	199.8	235.3	(8.7)	226.6

b) Risks associated with financial assets and liabilities

The Company is exposed to financial risks from its financial assets and liabilities. The financial risks include market risk relating to commodity prices, interest rates, foreign exchange rates and equity price as well as credit and liquidity risk.

Commodity price risk

The Company is exposed to commodity price risk on crude oil and condensate, NGLs and natural gas revenues. To manage a portion of this risk, the Company has entered into various derivative agreements.

The following table summarizes the unrealized gains (losses) on the Company's commodity financial derivative contracts and the resulting impact on income before tax due to fluctuations in commodity prices or differentials, with all other variables held constant:

	Impact on Income Before Tax		Impact on Income Before Tax
($ millions)	Year ended December 31, 2023		Year ended December 31, 2022
	Increase 10%	Decrease 10%	Increase 10%	Decrease 10%
Commodity price
Crude oil	(134.4)	135.5	(40.3)	38.8
Natural gas	(25.4)	25.8	(3.1)	3.2
Differential
Natural gas	15.5	(15.5)	2.6	(2.6)

Interest rate risk

The Company is exposed to interest rate risk on amounts drawn on its bank debt to the extent of changes in market interest rates. Based on the Company's floating rate debt position, as at December 31, 2023, a 1 percent increase or decrease in the interest rate on floating rate debt would amount to an impact on income before tax of $26.8 million on an annualized basis. At December 31, 2022, the Company was undrawn on its credit facilities and had no floating rate debt outstanding, therefore, no exposure to changes in market interest rates.

Foreign exchange risk

The Company is exposed to foreign exchange risk in relation to its US dollar denominated long-term debt, US dollar denominated commodity derivative contracts, investment in its U.S. subsidiary and on a portion of its commodity sales. Crescent Point utilizes foreign exchange derivatives to hedge its foreign exchange exposure on its US dollar denominated long-term debt. To reduce foreign exchange risk relating to commodity sales, the Company utilizes a combination of foreign exchange swaps and fixed price WTI crude oil contracts that settle in Canadian dollars.

The following table summarizes the resulting unrealized gains (losses) impacting income before tax due to the respective changes in the period end and applicable foreign exchange rates, with all other variables held constant:

		Impact on Income Before Tax		Impact on Income Before Tax
($ millions)	Exchange Rate	Year ended December 31, 2023		Year ended December 31, 2022
Cdn$ relative to US$		Increase 10%	Decrease 10%	Increase 10%	Decrease 10%
US dollar long-term debt	Period End	265.1	(265.1)	124.6	(124.6)
Cross currency swaps	Forward	(254.8)	254.8	(123.7)	123.7
Foreign exchange swaps	Forward	14.1	(14.1)	4.3	(4.3)

Equity price risk

The Company is exposed to equity price risk on its own share price in relation to certain share-based compensation plans detailed in Note 25 - "Share-based Compensation". The Company has entered into total return swaps to mitigate its exposure to fluctuations in its share price by fixing the future settlement cost on a portion of it's cash settled plans.

The following table summarizes the unrealized gains (losses) on the Company's equity derivative contracts and the resulting impact on income before tax due to the respective changes in the applicable share price, with all other variables held constant:

	Impact on Income Before Tax		Impact on Income Before Tax
($ millions)	Year ended December 31, 2023		Year ended December 31, 2022
Share price	Increase 50%	Decrease 50%	Increase 50%	Decrease 50%
Total return swaps	12.7	(12.7)	26.8	(26.8)

Credit risk

The Company is exposed to credit risk in relation to its physical oil and gas sales, financial counterparty and joint venture receivables. A substantial portion of the Company's accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risks. To mitigate credit risk associated with its physical sales portfolio, Crescent Point obtains financial assurances such as parental guarantees, letters of credit, prepayments and third party credit insurance. Including these assurances, approximately 98 percent of the Company's oil and gas sales are with entities considered investment grade.

At December 31, 2023, approximately 4 percent (December 31, 2022 - 4 percent) of the Company's accounts receivable balance was outstanding for more than 90 days and the Company's average expected credit loss was 0.83 percent (December 31, 2022 - 0.93 percent) on a portion of the Company’s accounts receivable balance relating to joint venture receivables.

Liquidity risk

The Company manages its liquidity risk through managing its capital structure and continuously monitoring forecast cash flows and available credit under existing banking facilities as well as other potential sources of capital.

At December 31, 2023, the Company had available unused borrowing capacity on bank credit facilities of approximately $801.1 million, including $26.2 million outstanding letters of credit and cash of $17.3 million.

The timing of undiscounted cash outflows relating to the financial liabilities outstanding as at December 31, 2023, is outlined in the table below:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Accounts payable and accrued liabilities	634.9	—	—	—	634.9
Dividends payable	56.8	—	—	—	56.8
Derivative liabilities (1)	—	3.2	—	—	3.2
Senior guaranteed notes (2)	342.8	476.5	27.0	—	846.3
Bank debt (3)	236.3	3,118.8	—	—	3,355.1

(1)These amounts exclude undiscounted cash outflows pursuant to the CCS and foreign exchange swaps.

(2)These amounts include the notional principal and interest payments pursuant to the CCS related to the senior guaranteed notes, which fix the amounts due in Canadian dollars. US dollar senior guaranteed notes that do not have any underlying CCS are translated at the period end foreign exchange rate.

(3)These amounts include interest based on debt outstanding and interest rates effective as at December 31, 2023, and includes undiscounted cash outflows pursuant to the CCS related to Secured Overnight Financing Rate loans.

The timing of undiscounted cash outflows relating to the financial liabilities outstanding as at December 31, 2022, is outlined in the table below:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Accounts payable and accrued liabilities	448.2	—	—	—	448.2
Dividends payable	99.4	—	—	—	99.4
Derivative liabilities (1)	12.6	—	—	—	12.6
Senior guaranteed notes (2)	486.6	816.2	26.9	—	1,329.7

(1)These amounts exclude undiscounted cash outflows pursuant to the CCS and foreign exchange swaps.

(2)These amounts include the notional principal and interest payments pursuant to the CCS and foreign exchange swap related to the senior guaranteed notes, which fix the amounts due in Canadian dollars.

c) Derivative contracts

The following is a summary of the derivative contracts in place as at December 31, 2023:

Financial WTI Crude Oil Derivative Contracts – Canadian Dollar (1)
	Swap		Collar
Term	Volume (bbls/d)	Average Price ($/bbl)	Volumes (bbls/d)	Average Sold Call Price ($/bbl)	Average Bought Put Price ($/bbl)
January 2024 - December 2024 (2)	15,414	102.02	28,488	114.40	97.52
January 2025 - December 2025	1,513	95.13	—	—	—

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

(2)Includes 5,000 bbls/d in the first half of 2024, which can be extended at the option of the counterparty for the second half of 2024 at an average swap price of $102.68/bbl.

Financial WTI Crude Oil Derivative Contracts – US Dollar (1)
	Swap
	Volume (bbls/d)	Average Price (US$/bbl)
Term
January 2024 - March 2024	10,050	82.44

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

Financial AECO Natural Gas Derivative Contracts – Canadian Dollar (1)
	Swap
	Volume (GJ/d)	Average Price ($/GJ)
Term
January 2024 - October 2024	31,403	3.33

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

Financial NYMEX Natural Gas Derivative Contracts – US Dollar (1)
	Swap		Collar
Term	Volume (mmbtu/d)	Average Price (US$/mmbtu)	Volume (mmbtu/d)	Average Sold Call Price (US$/mmbtu)	Average Bought Put Price (US$/mmbtu)
January 2024 - December 2024	31,027	3.44	60,000	4.21	3.14
January 2025 - December 2025	51,000	3.43	45,000	4.01	3.33

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

Financial NYMEX Natural Gas Differential Derivative Contracts – US Dollar (1)
Term	Volume (mmbtu/d)	Contract	Basis	Fixed Differential (US$/mmbtu)
January 2024 - December 2024	151,257	Basis Swap	AECO	(1.10)
January 2025 - December 2025	150,000	Basis Swap	AECO	(1.12)

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

Financial Cross Currency Derivative Contracts
Term	Contract	Receive Notional Principal (US$ millions)	Fixed Rate (US%)	Pay Notional Principal (Cdn$ millions)	Fixed Rate (Cdn%)
January 2024	Swap	783.0	7.18	1,075.6	6.69
January 2024 - March 2024	Swap	635.0	7.17	847.6	6.78
January 2024 - June 2024	Swap	257.5	3.75	276.4	4.03
January 2024 - April 2025	Swap	52.0	4.30	67.9	3.98
January 2024 - April 2025	Swap	207.5	4.08	262.6	4.13

Financial Foreign Exchange Forward Derivative Contracts
Settlement Date	Contract	Receive Currency	Receive Notional Principal ($ millions)	Pay Currency	Pay Notional Principal ($ millions)
January 2024	Swap (1)	Cdn$	64.1	US$	48.0
June 2024	Swap	Cdn$	40.5	US$	30.0
December 2024	Swap	Cdn$	40.5	US$	30.0

(1)Based on an average floating exchange rate.

Financial Equity Derivative Contracts		Notional Principal ($ millions)	Number of shares
Term	Contract
January 2024 - March 2024	Swap	11.8	1,549,947
January 2024 - March 2025	Swap	12.0	1,207,754

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Related Party Transactions

12 Months Ended

Dec. 31, 2023

Related party transactions [abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

Compensation of key management personnel

Key management personnel of the Company include its directors and executive officers. The compensation relating to key management personnel for the year ended December 31, 2023, recorded as general and administrative expenses was $7.3 million (year ended December 31, 2022 - $6.1 million) and share-based compensation costs were $19.4 million (year ended December 31, 2022 - $24.2 million)

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Commitments

12 Months Ended

Dec. 31, 2023

Capital commitments [abstract]

Commitments

COMMITMENTS

At December 31, 2023, the Company had contractual obligations and commitments as follows:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Operating (1)	15.8	19.7	11.5	7.9	54.9
Gas processing	115.6	193.4	147.9	280.8	737.7
Transportation	186.1	361.5	276.5	524.5	1,348.6
Total contractual commitments (2)	317.5	574.6	435.9	813.2	2,141.2

(1)Includes operating costs on the Company's office space, net of $16.7 million recoveries from subleases.

(2)Excludes contracts accounted for under IFRS 16. See Note 14 - "Leases" for additional information.

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Significant Subsidiaries

12 Months Ended

Dec. 31, 2023

Disclosure of subsidiaries [abstract]

Significant Subsidiaries

SIGNIFICANT SUBSIDIARIES

The Company has the following significant subsidiaries, each owned 100% directly and indirectly, at December 31, 2023:

Subsidiary Name	Country of Formation
Crescent Point Resources Partnership	Canada
Crescent Point Holdings Ltd.	Canada
Hammerhead Resources ULC	Canada
Crescent Point Energy U.S. Corp.	United States of America

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Supplemental Disclosures

12 Months Ended

Dec. 31, 2023

Supplemental Disclosures [Abstract]

Supplemental Disclosures

SUPPLEMENTAL DISCLOSURES

Comprehensive income statement presentation

The Company’s statements of comprehensive income are prepared primarily by nature of expense, with the exception of compensation expenses which are included in the operating, general and administrative and share-based compensation line items, as follows:

($ millions)	2023	2022 (1)
Operating	64.0	56.3
General and administrative	66.8	58.7
Share-based compensation	9.4	35.9
Total compensation expenses	140.2	150.9

(1)Comparative period revised to reflect current period presentation.

Cash flow statement presentation

($ millions)	2023	2022
Operating activities
Changes in non-cash working capital:
Accounts receivable	66.7	(11.3)
Prepaids and deposits	(2.2)	(13.9)
Accounts payable and accrued liabilities	(97.8)	(3.5)
Other current liabilities	(11.8)	8.6
Other long-term liabilities	(9.8)	5.1
	(54.9)	(15.0)
Investing activities
Changes in non-cash working capital:
Accounts receivable	—	0.2
Other current assets	(60.5)	(18.7)
Accounts payable and accrued liabilities	56.3	(7.6)
	(4.2)	(26.1)
Financing activities
Changes in non-cash working capital:
Prepaids and deposits	(12.6)	(44.2)
Accounts payable and accrued liabilities	(2.0)	4.0
Dividends payable	(42.6)	55.9
	(57.2)	15.7

Supplementary financing cash flow information

The Company's reconciliation of cash flow from financing activities is outlined in the table below:

($ millions)	Dividends payable	Long-term debt (1)	Lease liability (2)
December 31, 2021	43.5	1,970.2	141.4
Changes from cash flow from financing activities:
Decrease in bank debt, net		(338.5)
Repayment of senior guaranteed notes		(281.8)
Realized gain on cross currency swap maturity		63.8
Dividends paid	(144.7)
Payments on principal portion of lease liability			(20.4)
Non-cash changes:
Dividends declared	200.6
Additions			3.8
Other			(0.7)
Foreign exchange		27.8
December 31, 2022	99.4	1,441.5	124.1
Changes from cash flow from financing activities:
Increase in bank debt, net		2,675.1
Repayment of senior guaranteed notes and acquired long-term debt		(897.9)
Realized gain on cross currency swap maturity		147.7
Dividends paid	(254.5)
Payments on principal portion of lease liability			(20.8)
Non-cash changes:
Dividends declared	211.9
Acquisitions through business combinations		363.8	4.3
Additions			38.2
Dispositions			(1.1)
Foreign exchange		(163.9)
December 31, 2023	56.8	3,566.3	144.7

(1)Includes current portion of long-term debt.

(2)Includes current portion of lease liability.

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Oil and Gas Sales

12 Months Ended

Dec. 31, 2023

Disclosure of geographical areas [abstract]

Oil and Gas Sales

OIL AND GAS SALES

The following table reconciles oil and gas sales by country:

($ millions) (1)	2023	2022
Canada
Crude oil and condensate sales	3,082.5	3,319.1
NGL sales	180.2	224.8
Natural gas sales	236.3	303.1
Total Canada	3,499.0	3,847.0
U.S.
Crude oil and condensate sales	569.6	553.3
NGL sales	27.0	55.2
Natural gas sales	16.3	37.6
Total U.S. (2)	612.9	646.1
Total oil and gas sales	4,111.9	4,493.1

(1)Oil and gas sales are reported before realized derivatives.

(2)Discontinued operations.

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Subsequent Events

12 Months Ended

Dec. 31, 2023

Disclosure of non-adjusting events after reporting period [abstract]

Subsequent Events

SUBSEQUENT EVENTS

Disposition of Southern Alberta Assets

On January 26, 2024, Crescent Point completed the disposition of its Southern Alberta assets for total consideration of approximately $38.1 million, including interim closing adjustments. Total consideration includes $25.0 million of deferred consideration receivable. Due to significant decommissioning liabilities associated with these assets, this transaction reduces the Company's decommissioning liability balance by $92.4 million.

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Material Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Corporate information and statement of IFRS compliance [abstract]

Preparation

Preparation

These consolidated financial statements are presented under IFRS Accounting Standards as issued by the International Accounting Standards Board. The policies applied in these consolidated financial statements are based on IFRS Accounting Standards issued and outstanding as of February 28, 2024, the date the Board of Directors approved the statements.

The Company’s presentation currency is Canadian dollars and all amounts reported are Canadian dollars unless noted otherwise. References to “US$” and "US dollars" are to United States ("U.S.") dollars. Crescent Point's Canadian operations are presented herein as continuing operations. The Company's U.S. operations have been classified and presented as discontinued operations. See Note 9 - "Discontinued Operations" for additional information.

Basis of measurement, functional and presentation currency

Basis of measurement, functional and presentation currency

The Company’s presentation currency is Canadian dollars. The accounts of the Company’s foreign operations that have a functional currency different from the Company’s presentation currency are translated into the Company’s presentation currency at period end exchange rates for assets and liabilities and at the average rate over the period for revenues and expenses. Translation gains and losses relating to the foreign operations are recognized in other comprehensive income as cumulative translation adjustments.

Use of estimate and judgments

Use of estimates and judgments

The preparation of consolidated financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future years affected.

The Company also faces uncertainties related to future environmental laws and climate-related regulations, which could affect the Company's financial position and future earnings. This transition to a lower-carbon society, as well as the physical impacts of climate change, could result in increased operating costs and reduced demand for oil and gas products. As a result, this could change a number of variables and assumptions used to determine the estimated recoverable amounts of the Company's oil and gas assets. The unpredictable nature, timing and extent of climate-related initiatives presents various risks and uncertainties, including to management's judgements, estimates and assumptions that affect the application of accounting policies. Significant estimates and judgments made by management in the preparation of these consolidated financial statements are outlined below.

Oil and gas activities

Reserves estimates, although not reported as part of the Company’s consolidated financial statements, can have a significant effect on net income, assets and liabilities as a result of their impact on depletion, depreciation and amortization (“DD&A”), decommissioning liability, deferred taxes, asset impairments and impairment reversals, and business combinations. Independent petroleum reservoir engineers perform evaluations of the Company’s oil and gas reserves on an annual basis. The estimation of reserves is an inherently complex process requiring significant judgment. Estimates of economically recoverable oil and gas reserves are based upon a number of variables and assumptions such as production forecasts, commodity prices, costs and related future cash flows, all of which may vary considerably from actual results. These estimates are expected to be revised upward or downward over time, as additional information such as reservoir performance becomes available, or as economic conditions change.

For purposes of impairment testing, property, plant and equipment (“PP&E”) is aggregated into cash-generating units (“CGUs”), based on separately identifiable and largely independent cash inflows. The determination of the Company’s CGUs is subject to judgment. Factors considered in the classification of CGUs include the integration between assets, shared infrastructure, the existence of common sales points, geography, geologic structure and the manner in which management monitors and makes decisions regarding operations.

The determination of technical feasibility and commercial viability, based on the presence of reserves and which results in the transfer of assets from exploration and evaluation ("E&E") to PP&E, is subject to judgment.

Decommissioning liability

Upon retirement of its oil and gas assets, the Company anticipates incurring substantial costs associated with decommissioning. Estimates of these costs are subject to uncertainty associated with the method, timing and extent of future decommissioning activities. The liability, the related asset and the expense are impacted by estimates with respect to the cost and timing of decommissioning.

Business combinations

Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of PP&E and E&E assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, production forecasts, costs and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill. Future net earnings can be affected as a result of changes in future DD&A, asset impairment or goodwill impairment.

Fair value measurement

The estimated fair value of derivative instruments resulting in derivative assets and liabilities, by their very nature, are subject to measurement uncertainty. Estimates included in the determination of the fair value of derivative instruments include forward benchmark prices, discount rates, share price, forward foreign exchange rates and forward interest rates.

Joint control

Judgment is required to determine when the Company has joint control over an arrangement, which requires an assessment of the capital and operating activities of the projects it undertakes with partners and when the decisions in relation to those activities require unanimous consent.

Share-based compensation

Compensation costs recorded pursuant to share-based compensation plans are subject to estimated fair values, forfeiture rates and the future attainment of performance criteria.

Income taxes

Tax regulations and legislation and the interpretations thereof are subject to change. In addition, deferred income tax assets and liabilities recognize the extent that temporary differences will be receivable and payable in future periods. The calculation of the asset and liability involves a significant amount of estimation including an evaluation of when the temporary differences will reverse, an analysis of the amount of future taxable earnings, expected cash flows from estimated proved plus probable reserves and the application of tax laws. Changes in tax regulations and legislation and the other assumptions listed are subject to measurement uncertainty.

Principles of Consolidation

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries and any reference to the “Company” throughout these consolidated financial statements refers to the Company and its subsidiaries. All transactions between the Company and its subsidiaries have been eliminated.

The Company conducts some of its oil and gas production activities through jointly controlled operations and the financial statements reflect only the Company's proportionate interest in such activities. Joint control exists for contractual arrangements governing the Company's assets whereby the Company has less than 100 percent working interest, all the partners have control of the arrangement collectively, and share the associated risks. The Company does not have any joint arrangements that are material to the Company or that are structured through joint venture arrangements.

Property, Plant and Equipment

Property, Plant and Equipment

Items of PP&E, which primarily consist of oil and gas development and production assets, are measured at cost less accumulated depletion, depreciation and any accumulated impairment losses or impairment reversals. Development and production assets are accumulated into CGUs and account for the cost of developing the commercial reserves and initiating production.

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of PP&E are recognized as development and production assets only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in net income as incurred. Capitalized development and production assets generally represent costs incurred in developing reserves and initiating or enhancing production from such reserves. The carrying amount of any sold component is derecognized.

Depletion and Depreciation

Development and production assets are depleted using the unit-of-production method based on estimated proved plus probable oil and gas reserves before royalties, as determined by independent petroleum reservoir engineers. Natural gas reserves and production are converted to equivalent barrels of oil based upon the relative energy content (6:1). The depletion base includes capitalized costs, plus future costs to be incurred in developing proved plus probable oil and gas reserves.

Corporate assets are depreciated on a straight line basis over the estimated useful lives of the related assets, ranging from 5 to 16 years.

Impairment

The carrying amounts of PP&E, which takes into account the discounted abandonment and reclamation costs on proved plus probable undeveloped oil and gas reserves, are grouped into CGUs and reviewed quarterly for indicators of impairment. Indicators are events or changes in circumstances that indicate the carrying amount may not be recoverable. If indicators of impairment exist, the recoverable amount of the CGU is estimated. If the carrying amount of the CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income.

Assets are grouped into CGUs based on the integration between assets, shared infrastructure, the existence of common sales points, geography, geological structure and the manner in which management monitors and makes decisions regarding operations. Estimates of future cash flows used in the calculation of the recoverable amount are based on reserve evaluation reports prepared by independent petroleum reservoir engineers. The recoverable amount is the higher of fair value less costs of disposal and the value-in-use. Fair value less costs of disposal is derived by estimating the discounted after-tax future net cash flows from proved plus probable oil and gas reserves. Discounted future net cash flows are based on forecasted commodity prices and costs over the expected economic life of the reserves and discounted using market-based rates to reflect a market participant’s view of the risks associated with the assets. Value-in-use is assessed using the expected future cash flows from proved plus probable oil and gas reserves discounted at a pre-tax rate. The fair value less costs of disposal and value in use estimates are categorized as Level 3 according to the IFRS 13 fair value hierarchy.

Impairment losses recognized in prior periods, other than goodwill impairments, are assessed at each reporting date for any indicators that the impairment losses may no longer exist or may have decreased. In the event that an impairment loss reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount, but only to the extent that the carrying amount does not exceed the amount that would have been determined, net of depletion, had no impairment loss been recognized on the asset in prior periods. The amount of the reversal is recognized in net income.

Exploration and Evaluation

Exploration and Evaluation

Exploration and evaluation assets are comprised of the accumulated expenditures incurred in an area where technical feasibility and commercial viability has not yet been determined. Exploration and evaluation assets include undeveloped land and any drilling costs thereon.

Technical feasibility and commercial viability are considered to be determinable when reserves are discovered. Upon determination of reserves, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to PP&E.

Costs incurred prior to acquiring the legal rights to explore an area are expensed as incurred.

Amortization

Undeveloped land classified as E&E assets is amortized by major area over the average primary lease term and recognized in net income. Drilling costs classified as E&E assets are not amortized, but are subject to impairment.

Impairment

Exploration and evaluation assets are reviewed quarterly for indicators of impairment and upon reclassification from E&E assets to PP&E. Exploration and evaluation assets are tested for impairment at the operating segment level by combining E&E assets with PP&E. The recoverable amount is the greater of fair value less costs of disposal or value-in-use. Fair value less costs of disposal is derived by estimating the discounted after-tax future net cash flows from proved plus probable oil and gas reserves, plus the fair market value of undeveloped land. Value-in-use is assessed using the expected future cash flows from proved plus probable oil and gas reserves discounted at a pre-tax rate.

Impairments of E&E assets are reversed when there has been a subsequent increase in the recoverable amount, but only to the extent of what the carrying amount would have been, net of amortization, had no impairment been recognized.

Decommissioning Liability

Decommissioning Liability

The Company recognizes the present value of a decommissioning liability in the period in which it is incurred. The obligation is recorded as a liability on a discounted basis using the relevant risk free rate, with a corresponding increase to the carrying amount of the related asset. Over time, the liabilities are accreted for the change in their present value and the capitalized costs are depleted on a unit-of-production basis over the life of the underlying proved plus probable oil and gas reserves. Accretion expense is recognized in net income. Revisions to the discount rate, estimated timing or amount of future cash flows would also result in an increase or decrease to the decommissioning liability and related asset.

Goodwill

Goodwill

The Company records goodwill relating to business combinations when the purchase price exceeds the fair value of the net identifiable assets and liabilities of the acquired business. The goodwill balance is assessed for impairment annually or as events occur that could result in impairment. Goodwill is tested for impairment at an operating segment level by combining the carrying amounts of PP&E, E&E assets and goodwill and comparing this to the recoverable amount. Any excess of the carrying amount over the recoverable amount is the impairment amount. The recoverable amount estimates is categorized as Level 3 according to the IFRS 13 fair value hierarchy. Impairment charges, which are not tax affected, are recognized in net income. Goodwill is reported at cost less any accumulated impairment. Goodwill impairments are not reversed.

Share-based Compensation

Share-based Compensation

Restricted shares granted under the Restricted Share Bonus Plan are accounted for at fair value and vest on terms up to three years from the grant date determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of shares on the date of grant. Forfeitures are estimated at the grant date and recognized when they occur. The expense is recognized over the service period, with a corresponding increase to contributed surplus. The Company capitalizes the portion of share-based compensation directly attributable to development activities, with a corresponding decrease to share-based compensation expense. At the time the restricted shares vest, the issuance of shares is recorded as an increase to shareholders’ capital and a corresponding decrease to contributed surplus.

Employee Share Value Plan ("ESVP") awards are accounted for at fair value and vest on terms of up to three years from the grant date as determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of the ESVP awards on the date of grant and subsequently adjusted to reflect the fair value at each period end. The expense is recognized over the service period, with a corresponding increase to long-term compensation liability. ESVP awards are settled in cash upon vesting based on the prevailing Crescent Point share price and the aggregate amount of dividends paid from the grant date.

Performance share units ("PSUs") are accounted for at fair value and vest on terms of up to three years from the grant date as determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of the PSUs on the date of the grant and subsequently adjusted to reflect the fair value at each period end. Market performance conditions are factored into the fair value and the best estimate of non-market performance conditions is used to determine an estimate of the number of units that will vest. Fair value is based on the expected cash payment per PSU and the expected number of PSUs to vest, calculated from multipliers based on internal and external performance metrics. The expense is recognized over the service period, with a corresponding increase to long-term compensation liability. PSUs are settled in cash upon vesting based on the prevailing Crescent Point share price, performance multiplier, and factors in the aggregate amount of dividends paid over the vesting term.

Deferred share units (“DSUs”) are accounted for at fair value. Share-based compensation expense is determined based on the estimated fair value of the DSUs on the date of the grant and subsequently adjusted to reflect the fair value at each period end. Fair value is based on the prevailing Crescent Point share price.

Stock options are accounted for at fair value and have a maximum term of seven years and vest on terms as determined by the Board of Directors. Share-based compensation expense is determined based on the estimated fair value of the stock options on the date of the grant. Upon vesting, the stock option holder may either exercise their stock options to purchase one common share per option at the exercise price or, at the Company's discretion, surrender their stock options for a cash payment in an amount equal to the aggregate positive difference, if any, between the market price and the exercise price of the number of common shares associated with the stock options surrendered. Alternatively, the stock option holder may also, at the Company's discretion, surrender their stock options for common shares having a value equivalent to the cash payment.

Income taxes

Income Taxes

The Company follows the liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the estimated effect of any differences between the accounting and tax basis of assets and liabilities, using enacted or substantively enacted income tax rates expected to apply when the deferred tax asset or liability is settled. The effect of a change in income tax rates on deferred income taxes is recognized in net income in the period in which the change occurs.

The tax expense for the period comprises current and deferred tax. Tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in equity. In this case, the tax is also recognized in other comprehensive income or directly in equity, respectively.

The Company is able to deduct certain settlements under its Restricted Share Bonus Plan. To the extent the tax deduction exceeds the cumulative remuneration cost for a particular restricted share grant recorded in net income, the tax benefit related to the excess is recorded directly within equity.

A deferred tax asset is recognized to the extent that it is probable that future taxable income will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized. Deferred income tax assets and liabilities are presented as non-current.

Financial Instruments

Financial Instruments

The Company uses financial derivative instruments and physical delivery commodity contracts from time to time to reduce its exposure to fluctuations in commodity prices, share price, foreign exchange rates and interest rates. The Company also makes investments in companies from time to time in connection with the Company’s acquisition and divestiture activities.

Financial derivative instruments

Financial derivative instruments are included in current assets/liabilities except for those with maturities greater than 12 months after the end of the reporting period, which are classified as non-current assets/liabilities.

The Company has not designated any of its financial derivative contracts as effective accounting hedges and, accordingly, fair values its financial derivative contracts with the resulting gains and losses recorded in net income.

The fair value of a financial derivative instrument on initial recognition is normally the transaction price. Subsequent to initial recognition, the fair values are based on quoted market prices where available from active markets, otherwise fair values are estimated based on market prices at the reporting date for similar assets or liabilities with similar terms and conditions, or by discounting future payments of interest and principal at estimated interest rates that would be available to the Company at the reporting date.

Financial assets and liabilities

Financial assets and liabilities are measured at fair value on initial recognition. For non-equity instruments, measurement in subsequent periods depends on the classification of the financial asset or liability as “fair value through profit or loss” or “amortized cost”.

Financial assets and liabilities classified as fair value through profit or loss are subsequently carried at fair value, with changes recognized in net income.

Financial assets and liabilities classified as amortized cost are subsequently carried at amortized cost using the effective interest rate method.

Currently, the Company classifies all non-equity financial instruments which are not financial derivative instruments as amortized cost.

At each reporting date, the Company assesses whether there is objective evidence that a financial asset carried at amortized cost is impaired. If such evidence exists, the Company recognizes an impairment loss in net income. Impairment losses are reversed in subsequent periods if the impairment loss decrease can be related objectively to an event occurring after the impairment was recognized.

For investments in equity instruments, the subsequent measurement is dependent on the Company’s election to classify such instruments as fair value through profit or loss or fair value through other comprehensive income. Currently, the Company classifies all investments in equity instruments as fair value through profit or loss, whereby the Company recognizes movements in the fair value of the investment (adjusted for dividends) in net income. If the fair value through other comprehensive income classification is selected, the Company would recognize any dividends from the investment in net income and would recognize fair value re-measurements of the investment in other comprehensive income.

Impairment of financial assets

Impairment losses are recognized using an expected credit loss model. The Company has adopted the simplified expected credit loss model for its accounts receivable, which permits the use of the lifetime expected loss provision.

To measure the expected credit losses, accounts receivable have been grouped based on shared credit risk characteristics and days past due. The Company uses judgment in making these assumptions and selecting the inputs into the expected loss calculation based on past history, existing market conditions and forward looking estimates at the end of each reporting period.

Business Combinations

Business Combinations

Business combinations are accounted for using the acquisition method. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured at their fair values at the acquisition date. The acquisition is measured as the fair value of the acquired assets by estimating the discounted after-tax future net cash flows, the fair value of equity instruments issued and the fair value of liabilities incurred or assumed at the acquisition date. The excess of the cost of the acquisition over the fair value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of the acquisition is less than the fair value of the net assets acquired, the difference is recognized immediately in net income. Transaction costs associated with business combinations are expensed as incurred.

Foreign Currency Translation

Foreign Currency Translation

Foreign operations

The Company has operations in the U.S. transacted via U.S. subsidiaries. The assets and liabilities of foreign operations are translated to Canadian dollars at exchange rates in effect at the balance sheet date. The income and expenses of foreign operations are translated to Canadian dollars using average exchange rates for the period. The resulting unrealized gain or loss is included in other comprehensive income. The unrealized gain or loss is subsequently reclassified to profit and loss upon discontinuation of the foreign operations.

Foreign transactions

Transactions in foreign currencies not incurred by the Company’s U.S. subsidiaries are translated to Canadian dollars at exchange rates in effect at the transaction dates. Foreign currency assets and liabilities are translated to Canadian dollars at exchange rates in effect at the balance sheet date and income and expenses are translated to Canadian dollars using average exchange rates for the period. Both realized and unrealized gains and losses resulting from the settlement or restatement of foreign currency transactions are included in net income.

Revenue Recognition

Revenue Recognition

The Company’s major revenue sources are comprised of sales from the production of crude oil and condensate, natural gas liquids ("NGLs") and natural gas. Revenue is recognized when control of the product transfers to the customer and the collection is reasonably probable, generally upon delivery of the product. Sales of crude oil and condensate, NGLs and natural gas production are based on variable pricing as the transaction prices are based on benchmark commodity prices and other variable factors, including quality differentials and location.

Each contract is 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, revenue is recognized on a gross basis. Where the Company acts as agent, revenue is recognized on a net basis.

Cash and Cash Equivalents

Cash and Cash EquivalentsCash and cash equivalents include short-term investments with original maturities of three months or less.

Leases

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. At the commencement date, the lease liability is recognized at the present value of the future lease payments and discounted using the interest rate implicit in the lease or the Company's incremental borrowing rate. A corresponding right-of-use ("ROU") asset will be recognized at the amount of the lease liability, adjusted for any lease incentives received and initial direct costs incurred. Over the term of the lease, financing expense is recognized on the lease liability using the effective interest rate method and charged to net income, lease payments are applied against the lease liability and depreciation on the ROU asset is recorded by class of underlying asset.

The lease term is the non-cancellable period of a lease and includes periods covered by an optional lease extension option if reasonably certain the Company will exercise the option to extend. Conversely, periods covered by an option to terminate are included if the Company does not expect to end the lease during that time frame. Leases with a term of less than twelve months or leases for underlying low value assets are recognized as an expense in net income on a straight-line basis over the lease term.

A lease modification will be accounted for as a separate lease if it materially changes the scope of the lease. For a modification that is not a separate lease, on the effective date of the lease modification, the Company will remeasure the lease liability and corresponding ROU asset using the interest rate implicit in the lease or the Company's incremental borrowing rate. Any variance between the remeasured ROU asset and lease liability will be recognized as a gain or loss in net income to reflect the change in scope.

The Company also acts as an intermediate lessor for office space sub-leased to other companies. As a lessor, the Company will evaluate whether a lease is a finance or operating lease. Leases where the Company transfers substantially all the risks and rewards of ownership are classified as finance leases. Conversely, leases where the risks and rewards of ownership are retained by the Company are operating leases. The head lease between the Company and the building, and the sub-lease between the Company and tenants, are accounted for separately. The lease classification of the sub-lease is based upon the head lease and not the underlying asset.

Earnings Per Share

Earnings Per Share

Basic earnings per share (“EPS”) is calculated by dividing the net income for the period attributable to equity owners of the Company by the weighted average number of common shares outstanding during the period.

Diluted EPS is calculated by adjusting the weighted average number of common shares outstanding for dilutive instruments. The number of shares included with respect to dilutive instruments, being restricted shares issued under the Company’s Restricted Share Bonus Plan and stock options under the Company's Stock Option Plan, is computed using the treasury stock method. The treasury stock method assumes that the deemed proceeds related to unrecognized share-based compensation are used to repurchase shares at the average market price during the period.

Government Grants

Government Grants

The Company may receive government grants which provide immediate financial assistance as compensation for costs or expenditures to be incurred. Government grants are accounted for when there is reasonable assurance that conditions attached to the grants are met and that the grants will be received. The Company recognizes government grants in net income on a systematic basis and in line with recognition of the expense that the grants are intended to compensate.

Assets Held for Sale

Assets Held for SalePP&E and E&E assets are classified as held for sale if it is highly probable their carrying amounts will be recovered through a capital disposition rather than through future operating cash flows. Before PP&E and E&E assets are classified as held for sale, they are assessed for indicators of impairment or reversal of previously recorded impairments and are measured at the lower of their carrying amount and fair value less costs of disposal. Any impairment charges or reversals are recognized in net income. Assets held for sale are classified as current assets and are not subject to DD&A. Decommissioning liabilities associated with assets held for sale are classified as current liabilities.

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Other Current Assets (Tables)

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Schedule of Other Current Assets

($ millions)	2023	2022
Deferred consideration receivable	79.2	—
Deposit on acquisition	—	18.7
Other current assets	79.2	18.7

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Exploration and Evaluation Assets (Tables)

12 Months Ended

Dec. 31, 2023

Exploration For And Evaluation Of Mineral Resources [Abstract]

Schedule of Exploration and Evaluation Assets

($ millions)	2023	2022
Exploration and evaluation assets at cost	1,578.6	1,453.4
Accumulated amortization	(971.6)	(1,349.2)
Net carrying amount	607.0	104.2
Reconciliation of movements during the year
Cost, beginning of year	1,453.4	1,613.3
Accumulated amortization, beginning of year	(1,349.2)	(1,564.5)
Net carrying amount, beginning of year	104.2	48.8
Net carrying amount, beginning of year	104.2	48.8
Acquisitions through business combinations	515.2	28.0
Additions	224.8	134.2
Dispositions	(1.9)	(10.9)
Transfers to property, plant and equipment	(204.3)	(80.8)
Amortization	(30.9)	(15.2)
Foreign exchange	(0.1)	0.1
Net carrying amount, end of year	607.0	104.2

($ millions)	2023	2022
Development and production assets	24,580.6	22,340.0
Corporate assets	132.1	126.2
Property, plant and equipment at cost	24,712.7	22,466.2
Accumulated depletion, depreciation and impairment	(13,994.4)	(14,736.8)
Net carrying amount	10,718.3	7,729.4
Reconciliation of movements during the year
Development and production assets
Cost, beginning of year	22,340.0	23,402.9
Accumulated depletion and impairment, beginning of year	(14,651.8)	(15,762.6)
Net carrying amount, beginning of year	7,688.2	7,640.3
Net carrying amount, beginning of year	7,688.2	7,640.3
Acquisitions through business combinations	4,348.6	66.0
Additions	1,025.8	741.9
Dispositions	(657.7)	(285.8)
Transfers from exploration and evaluation assets	204.3	80.8
Reclassified as assets held for sale	(98.7)	(148.4)
Depletion	(1,009.3)	(911.4)
Impairment reversal (impairment)	(822.2)	428.6
Foreign exchange	0.2	76.2
Net carrying amount, end of year	10,679.2	7,688.2
Cost, end of year	24,580.6	22,340.0
Accumulated depletion and impairment, end of year	(13,901.4)	(14,651.8)
Net carrying amount, end of year	10,679.2	7,688.2
Corporate assets
Cost, beginning of year	126.2	123.2
Accumulated depreciation, beginning of year	(85.0)	(76.2)
Net carrying amount, beginning of year	41.2	47.0
Net carrying amount, beginning of year	41.2	47.0
Additions	5.9	2.6
Depreciation	(8.0)	(8.5)
Foreign exchange	—	0.1
Net carrying amount, end of year	39.1	41.2
Cost, end of year	132.1	126.2
Accumulated depreciation, end of year	(93.0)	(85.0)
Net carrying amount, end of year	39.1	41.2

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Capital Acquisitions and Dispositions (Tables)

12 Months Ended

Dec. 31, 2023

Business Combinations And Dispositions [Abstract]

Schedule of Capital Acquisitions and Dispositions

The following table summarizes the Company's capital acquisitions and dispositions:

($ millions)	Hammerhead Acquisition (1) (2)	Kaybob Duvernay Acquisition	Alberta Montney Acquisition	North Dakota Disposition (3) (4)	Other minor dispositions, net
Cash	(1,544.0)	(370.4)	(1,700.4)	504.6	17.3
Common shares	(493.0)	—	—	—	—
Deferred consideration receivable	—	—	—	81.2	—
Consideration (paid) received	(2,037.0)	(370.4)	(1,700.4)	585.8	17.3
Working capital	(116.7)	—	—	9.1	—
Derivative asset	12.3	—	—	—	—
Other long-term assets	—	—	0.1	—	—
Exploration and evaluation	354.8	52.1	108.3	(1.8)	(0.1)
Property, plant and equipment	2,406.6	323.7	1,616.6	(635.2)	(20.8)
Right-of-use asset	4.3	—	—	(1.0)	—
Goodwill	72.6	—	—	—	(0.6)
Long-term debt	(363.8)	—	—	—	—
Decommissioning liability	(9.9)	(5.4)	(24.6)	13.7	4.3
Derivative liability	(0.3)	—	—	19.0	—
Lease liability	(4.3)	—	—	1.1	—
Deferred income tax liability	(318.6)	—	—	—	—
Fair value of net assets acquired (Carrying value of net assets disposed)	2,037.0	370.4	1,700.4	(595.1)	(17.2)
Gain (loss) on capital dispositions	—	—	—	(9.3)	0.1

(1)Total net assets acquired excludes $696.6 million of commitments relating to transportation, $156.7 million related to gas processing and $4.8 million related to operating.

(2)Working capital includes $115.4 million of accounts receivable, $7.6 million of prepaids and deposits, and $239.7 million of accounts payable and accrued liabilities.

(3)Working capital includes $9.1 million of accounts payable and accrued liabilities.

(4)See Note 5 - "Other Current Assets" for additional information on deferred consideration receivable.

Assets Held for Sale

($ millions)	2023	2022
Assets held for sale - PP&E	247.1	148.4
Liabilities held for sale - Decommissioning liability	(132.4)	(28.4)

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Discontinued Operations (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of analysis of single amount of discontinued operations [abstract]

Summary of Discontinued Operations

The following table summarizes the Company's financial results from discontinued operations:

For the years ended December 31
(Cdn$ millions)	2023	2022
REVENUE AND OTHER INCOME
Oil and gas sales	612.9	646.1
Royalties	(155.9)	(165.4)
Oil and gas revenue	457.0	480.7
Commodity derivative losses	(23.4)	—
Other loss	(2.2)	(0.2)
	431.4	480.5
EXPENSES
Operating	80.0	84.9
Transportation	12.2	8.8
General and administrative	12.7	3.4
Foreign exchange gain	(621.7)	—
Share-based compensation	(0.4)	0.3
Depletion, depreciation and amortization	170.3	144.5
Impairment (impairment reversal)	728.4	(71.3)
Accretion and financing	0.4	0.4
	381.9	171.0
Net income before tax from discontinued operations	49.5	309.5
Tax expense (recovery)
Current	—	—
Deferred	278.6	(27.2)
Net income (loss) from discontinued operations	(229.1)	336.7

The following table summarizes cash flows from discontinued operations reported in the consolidated statements of cash flows:

For the years ended December 31
(Cdn$ millions)	2023	2022
Cash provided by (used in) discontinued operations
Operating activities	399.0	363.5
Investing activities	177.3	(252.3)
Increase in cash from discontinued operations	576.3	111.2

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2023

Property, plant and equipment [abstract]

Disclosure of property plant and equipment

($ millions)	2023	2022
Exploration and evaluation assets at cost	1,578.6	1,453.4
Accumulated amortization	(971.6)	(1,349.2)
Net carrying amount	607.0	104.2
Reconciliation of movements during the year
Cost, beginning of year	1,453.4	1,613.3
Accumulated amortization, beginning of year	(1,349.2)	(1,564.5)
Net carrying amount, beginning of year	104.2	48.8
Net carrying amount, beginning of year	104.2	48.8
Acquisitions through business combinations	515.2	28.0
Additions	224.8	134.2
Dispositions	(1.9)	(10.9)
Transfers to property, plant and equipment	(204.3)	(80.8)
Amortization	(30.9)	(15.2)
Foreign exchange	(0.1)	0.1
Net carrying amount, end of year	607.0	104.2

($ millions)	2023	2022
Development and production assets	24,580.6	22,340.0
Corporate assets	132.1	126.2
Property, plant and equipment at cost	24,712.7	22,466.2
Accumulated depletion, depreciation and impairment	(13,994.4)	(14,736.8)
Net carrying amount	10,718.3	7,729.4
Reconciliation of movements during the year
Development and production assets
Cost, beginning of year	22,340.0	23,402.9
Accumulated depletion and impairment, beginning of year	(14,651.8)	(15,762.6)
Net carrying amount, beginning of year	7,688.2	7,640.3
Net carrying amount, beginning of year	7,688.2	7,640.3
Acquisitions through business combinations	4,348.6	66.0
Additions	1,025.8	741.9
Dispositions	(657.7)	(285.8)
Transfers from exploration and evaluation assets	204.3	80.8
Reclassified as assets held for sale	(98.7)	(148.4)
Depletion	(1,009.3)	(911.4)
Impairment reversal (impairment)	(822.2)	428.6
Foreign exchange	0.2	76.2
Net carrying amount, end of year	10,679.2	7,688.2
Cost, end of year	24,580.6	22,340.0
Accumulated depletion and impairment, end of year	(13,901.4)	(14,651.8)
Net carrying amount, end of year	10,679.2	7,688.2
Corporate assets
Cost, beginning of year	126.2	123.2
Accumulated depreciation, beginning of year	(85.0)	(76.2)
Net carrying amount, beginning of year	41.2	47.0
Net carrying amount, beginning of year	41.2	47.0
Additions	5.9	2.6
Depreciation	(8.0)	(8.5)
Foreign exchange	—	0.1
Net carrying amount, end of year	39.1	41.2
Cost, end of year	132.1	126.2
Accumulated depreciation, end of year	(93.0)	(85.0)
Net carrying amount, end of year	39.1	41.2

Impairment test of property, plant and equipment

The following table summarizes the total impairment (impairment reversal) on the consolidated statements of comprehensive income:

($ millions)	2023	2022 (1)
Impairment reversal	—	(1,469.6)
Impairment	—	985.0
Impairment on assets held for sale	93.8	127.3
Impairment (impairment reversal)	93.8	(357.3)

(1)Comparative period revised to reflect current period presentation.

Schedule of Forecast Benchmark Commodity Prices And Exchange Rates for Impairment of Property, Plant and Equipment

The following table outlines the forecast benchmark commodity prices and the exchange rate used in the impairment calculation of PP&E at December 31, 2022:

	2023 (1)	2024	2025	2026	2027	2028	2029	2030	2031	2032	2033 (3)
WTI ($US/bbl) (2)	80.33	78.50	76.95	77.61	79.16	80.74	82.36	84.00	85.69	87.40	89.15
Exchange Rate ($US/$Cdn)	0.745	0.765	0.768	0.772	0.775	0.775	0.775	0.775	0.775	0.775	0.775
WTI ($Cdn/bbl)	107.83	102.61	100.20	100.53	102.14	104.18	106.27	108.39	110.57	112.77	115.03
AECO ($Cdn/mmbtu) (2)	4.23	4.40	4.21	4.27	4.34	4.43	4.51	4.60	4.69	4.79	4.88

(1)Effective January 1, 2023.

(2)The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, distance to market and other factors in performing the impairment tests.

(3)Forecast benchmark commodity prices are assumed to increase by 2.0% in each year after 2033 to the end of the reserve life. Exchange rates are assumed to be constant at 0.775.

The following table outlines the forecast benchmark commodity prices and the exchange rate used in the impairment calculation of PP&E at March 31, 2022:

	2022 (1)	2023	2024	2025	2026	2027	2028	2029	2030	2031	2032 (3)
WTI ($US/bbl) (2)	94.17	84.05	75.38	74.41	75.90	77.42	78.97	80.55	82.16	83.80	85.48
Exchange Rate ($US/$Cdn)	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800	0.800
WTI ($Cdn/bbl)	117.71	105.06	94.23	93.01	94.88	96.78	98.71	100.69	102.70	104.75	106.85
AECO ($Cdn/mmbtu) (2)	5.18	4.18	3.38	3.34	3.41	3.48	3.54	3.61	3.69	3.76	3.84

(1)Effective April 1, 2022.

(2)The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, distance to market and other factors in performing the impairment tests.

(3)Forecast benchmark commodity prices are assumed to increase by 2.0% in each year after 2032 to the end of the reserve life. Exchange rates are assumed to be constant at 0.800.

Schedule of Impairment Loss and Reversal of Impairment Loss

The following table summarizes the impairment expense for the year ended December 31, 2022 by CGU:

CGU ($ millions, except %)	Operating segment	Recoverable amount	Discount rate		Impairment	Impairment,  net of tax
Southeast Saskatchewan	Canada	2,868.3	15.00	%	564.5	424.4
Southwest Saskatchewan	Canada	1,356.6	15.00	%	420.5	316.1
Total impairment		4,224.9			985.0	740.5

The following table summarizes the impairment reversal for the three months ended March 31, 2022 by CGU:

CGU ($ millions, except %)	Operating segment	Recoverable amount	Discount rate		Impairment reversal	Impairment reversal, net of tax
Southeast Saskatchewan	Canada	3,413.8	15.00	%	806.0	605.3
Southwest Saskatchewan	Canada	1,715.0	15.00	%	419.4	315.0
Alberta	Canada	2,567.1	15.00	%	244.2	183.4
Total impairment reversal		7,695.9			1,469.6	1,103.7

Schedule of Impact on Income Before Tax For Changes in Discount Rate and Forecast Benchmark Commodity Price Estimates

CGU	Discount Rate		Commodity Prices		Operating Costs
($ millions)	Increase 1%	Decrease 1%	Increase 5%	Decrease 5%	Increase 5%	Decrease 5%
Southeast Saskatchewan	(167.8)	185.2	349.4	(348.3)	(117.7)	118.7
Southwest Saskatchewan	(88.0)	97.3	185.6	(185.3)	(64.8)	65.0
Increase (decrease)	(255.8)	282.5	535.0	(533.6)	(182.5)	183.7

The following sensitivities show the resulting impact on income before tax of the changes in discount rate and forecast benchmark commodity price estimates at March 31, 2022, with all other variables held constant:

CGU	Discount Rate		Commodity Prices
($ millions)	Increase 1%	Decrease 1%	Increase 5%	Decrease 5%
Southeast Saskatchewan	(186.2)	204.8	367.6	(366.6)
Southwest Saskatchewan	(95.0)	104.6	201.1	(201.1)
Alberta	—	—	—	—
Increase (decrease)	(281.2)	309.4	568.7	(567.7)

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Schedule of Goodwill Rollforward

($ millions)	2023	2022
Goodwill, beginning of year	203.9	211.5
Hammerhead acquisition	72.6	—
Saskatchewan Viking asset disposition	—	(6.8)
Other dispositions	(0.6)	(0.8)
Goodwill, end of year	275.9	203.9

Schedule of Forecast Benchmark Commodity Prices and Exchange Rates for Impairment of Goodwill

The following table outlines the forecast benchmark commodity prices and the exchange rate used in the impairment calculation of goodwill at December 31, 2023:

	2024 (1)	2025	2026	2027	2028	2029	2030	2031	2032	2033	2034 (3)
WTI ($US/bbl) (2)	73.67	74.98	76.14	77.66	79.22	80.80	82.42	84.06	85.74	87.46	89.21
Exchange Rate ($US/$Cdn)	0.752	0.752	0.755	0.755	0.755	0.755	0.755	0.755	0.755	0.755	0.755
WTI ($Cdn/bbl)	97.97	99.71	100.85	102.86	104.93	107.02	109.17	111.34	113.56	115.84	118.16
AECO ($Cdn/mmbtu) (2)	2.20	3.37	4.05	4.13	4.21	4.30	4.38	4.47	4.56	4.65	4.74

(1)Effective January 1, 2024.

(2)The forecast benchmark commodity prices listed above are adjusted for quality differentials, heat content, distance to market and other factors in performing the impairment tests.

(3)Forecast benchmark commodity prices are assumed to increase by 2.0% in each year after 2034 to the end of the reserve life. Exchange rates are assumed to be constant at 0.755.

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Other Current Liabilities (Tables)

12 Months Ended

Dec. 31, 2023

Subclassifications of assets, liabilities and equities [abstract]

Disclosure of Other Current Liabilities

($ millions)	2023	2022
Long-term compensation liability	37.5	49.1
Lease liability	40.5	24.9
Decommissioning liability	40.0	41.6
Other current liabilities	118.0	115.6

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Long-term Debt (Tables)

12 Months Ended

Dec. 31, 2023

Financial Instruments [Abstract]

Schedule of Long-term Debt

($ millions)	2023	2022
Revolving bank debt	1,932.9	—
Bank term loan	750.0	—
Senior guaranteed notes	883.4	1,441.5
Long-term debt	3,566.3	1,441.5
Long-term debt due within one year	380.0	538.7
Long-term debt due beyond one year	3,186.3	902.8

The following table summarizes the Company's senior guaranteed notes:

Principal ($ millions)	Coupon Rate		Hedged Principal (1) (Cdn$ millions)	Unhedged  Principal (2) (Cdn$ millions)	Interest Payment Dates	Maturity Date	Financial statement carrying value
							2023	2022
US$61.5	4.12	%	—	—	October 11 and April 11	April 11, 2023	—	83.2
Cdn$80.0	3.58	%	—	—	October 11 and April 11	April 11, 2023	—	80.0
Cdn$10.0	4.11	%	—	—	December 12 and June 12	June 12, 2023	—	10.0
US$270.0	3.78	%	—	—	December 12 and June 12	June 12, 2023	—	365.5
Cdn$40.0	3.85	%	40.0	—	December 20 and June 20	June 20, 2024	40.0	40.0
US$257.5	3.75	%	276.4	—	December 20 and June 20	June 20, 2024	340.0	348.5
US$82.0	4.30	%	67.9	39.6	October 11 and April 11	April 11, 2025	108.3	111.0
Cdn$65.0	3.94	%	65.0	—	October 22 and April 22	April 22, 2025	65.0	65.0
US$230.0	4.08	%	262.6	29.7	October 22 and April 22	April 22, 2025	303.7	311.3
US$20.0	4.18	%	—	26.4	October 22 and April 22	April 22, 2027	26.4	27.0
Senior guaranteed notes			711.9	95.7			883.4	1,441.5
Due within one year			316.4	—			380.0	538.7
Due beyond one year			395.5	95.7			503.4	902.8

(1)Includes underlying derivatives which fix the Company's foreign exchange exposure on its US dollar senior guaranteed notes or represents the Canadian dollar principal on Canadian dollar denominated senior guaranteed notes.

(2)Includes the principal balance translated at the period end foreign exchange rate on US dollar senior guaranteed notes that do not have underlying CCS

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Leases (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of leases [Abstract]

Disclosure of quantitative information about right-of-use assets

($ millions)	Office (1)	Fleet Vehicles	Equipment	Total
Right-of-use asset at cost	124.8	37.2	38.6	200.6
Accumulated depreciation	(65.1)	(23.0)	(9.7)	(97.8)
Net carrying amount	59.7	14.2	28.9	102.8
Reconciliation of movements during the year
Cost, beginning of year	121.9	28.5	11.1	161.5
Accumulated depreciation, beginning of year	(55.4)	(20.4)	(7.6)	(83.4)
Net carrying amount, beginning of year	66.5	8.1	3.5	78.1
Net carrying amount, beginning of year	66.5	8.1	3.5	78.1
Acquisitions through business combinations	3.0	0.6	0.7	4.3
Additions	0.8	10.6	26.8	38.2
Dispositions	(0.1)	(0.9)	—	(1.0)
Depreciation	(10.5)	(4.2)	(2.1)	(16.8)
Net carrying amount, end of year	59.7	14.2	28.9	102.8

(1)A portion of the Company's office space is subleased. During the year ended December 31, 2023, the Company recorded sublease income of $3.7 million (year ended December 31, 2022 - $3.6 million) as a component of other income.

Disclosure of additional information about leasing activities for lessee

($ millions)	2023	2022
Lease liability, beginning of year	124.1	141.4
Acquisitions through business combinations	4.3	—
Additions	38.2	3.8
Dispositions	(1.1)	—
Financing	5.2	5.7
Payments on lease liability	(26.0)	(26.1)
Other	—	(0.7)
Lease liability, end of year	144.7	124.1
Expected to be incurred within one year	40.5	24.9
Expected to be incurred beyond one year	104.2	99.2

Disclosure of maturity analysis of finance lease payments receivable

The undiscounted cash flows relating to the lease liability are as follows:

($ millions)	December 31, 2023
1 year	41.8
2 to 3 years	59.6
4 to 5 years	35.5
More than 5 years	25.2
Total (1)	162.1

(1)Includes both the principal and amounts representing interest.

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Decommissioning Liability (Tables)

12 Months Ended

Dec. 31, 2023

Other Provisions, Contingent Liabilities And Contingent Assets [Abstract]

Decommissioning Liability

($ millions)	2023	2022
Decommissioning liability, beginning of year	675.5	918.8
Liabilities incurred	19.8	21.6
Liabilities acquired through capital acquisitions	40.1	3.4
Liabilities disposed through capital dispositions	(18.2)	(46.7)
Liabilities settled (1)	(45.4)	(43.1)
Revaluation of acquired decommissioning liabilities (2)	38.5	3.8
Change in estimates	(3.0)	(11.4)
Change in discount and inflation rate estimates	(19.6)	(163.0)
Accretion	22.7	19.2
Reclassified as liabilities associated with assets held for sale	(104.0)	(28.4)
Foreign exchange	—	1.3
Decommissioning liability, end of year	606.4	675.5
Expected to be incurred within one year	40.0	41.6
Expected to be incurred beyond one year	566.4	633.9

(1)Includes $5.4 million received from government grant programs during the year ended December 31, 2023 (year ended December 31, 2022 - $23.0 million).

(2)These amounts relate to the revaluation of acquired decommissioning liabilities at the end of the period using a risk-free discount rate. At the date of acquisition, acquired decommissioning liabilities are fair valued.

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Shareholders' Capital (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of classes of share capital [abstract]

Disclosure of shareholders' capital

Crescent Point has an unlimited number of common shares authorized for issuance.

	2023		2022
	Number of shares	Amount ($ millions)	Number of shares	Amount ($ millions)
Common shares, beginning of year	550,888,983	16,675.8	579,484,032	16,963.4
Issued on capital acquisition	53,202,339	493.0	—	—
Issued for cash	48,550,000	500.1	—	—
Issued on redemption of restricted shares	1,436,017	4.9	1,713,730	5.2
Issued on exercise of stock options	464,051	0.7	1,038,321	1.4
Common shares repurchased for cancellation	(34,611,900)	(349.9)	(31,347,100)	(294.2)
Common shares, end of year	619,929,490	17,324.6	550,888,983	16,675.8
Cumulative share issue costs, net of tax	—	(271.9)	—	(256.5)
Total shareholders’ capital, end of year	619,929,490	17,052.7	550,888,983	16,419.3

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Deficit (Tables)

12 Months Ended

Dec. 31, 2023

Equity [abstract]

Schedule of Deficit

($ millions)	2023	2022
Accumulated earnings (deficit)	(2,130.3)	(2,700.6)
Accumulated gain on shares issued pursuant to DRIP (1) and SDP (2)	8.4	8.4
Accumulated tax effect on redemption of restricted shares	18.2	15.8
Accumulated dividends	(8,098.8)	(7,886.9)
Deficit	(10,202.5)	(10,563.3)

(1)Premium Dividend TM and Dividend Reinvestment Plan – suspended in 2015.

(2)Share Dividend Plan – suspended in 2015.

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Capital Management (Tables)

12 Months Ended

Dec. 31, 2023

Capital Management [Abstract]

Schedule of Capital Management

CAPITAL MANAGEMENT

($ millions)	2023	2022
Long-term debt (1)	3,566.3	1,441.5
Adjusted working capital (surplus) deficiency (2)	196.3	(95.1)
Unrealized foreign exchange on translation of hedged US dollar long-term debt	(24.5)	(191.7)
Net debt	3,738.1	1,154.7
Shareholders’ equity	6,867.5	6,493.4
Total capitalization	10,605.6	7,648.1

(1)Includes current portion of long-term debt.

(2)Adjusted working capital (surplus) deficiency is calculated as accounts payable and accrued liabilities, dividends payable and long-term compensation liability net of equity derivative contracts, less cash, accounts receivable, prepaids and deposits, and other current assets.

Schedule of Cash Flows from Operating Activities to Adjusted Funds

The following table reconciles cash flow from operating activities to adjusted funds flow from operations for the year ended December 31, 2023 and December 31, 2022:

($ millions)	2023	2022
Cash flow from operating activities	2,195.7	2,192.2
Changes in non-cash working capital	54.9	15.0
Transaction costs	48.5	5.1
Decommissioning expenditures	40.0	20.1
Adjusted funds flow from operations	2,339.1	2,232.4

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Commodity Derivative Gains (Losses) (Tables)

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Schedule of Derivative Instruments

($ millions)	2023	2022
Realized gains (losses)	15.5	(641.8)
Unrealized gains	148.3	168.4
Commodity derivative gains (losses)	163.8	(473.4)

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Other Income (Tables)

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Schedule of Other Income (Loss)

($ millions)	2023	2022 (1)
Gain (loss) on capital dispositions	(0.7)	26.1
Government grant for decommissioning expenditures	5.4	23.0
Sublease income	3.7	3.6
Other	5.0	6.3
Other income	13.4	59.0

(1)Comparative period revised to reflect current period presentation.

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Interest Expense (Tables)

12 Months Ended

Dec. 31, 2023

Analysis of income and expense [abstract]

Schedule of Interest Expense

($ millions)	2023	2022
Interest expense on long-term debt	126.0	64.7
Unrealized (gain) loss on interest derivative contracts	3.4	(1.1)
Interest expense	129.4	63.6

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Foreign Exchange Gain (Tables)

12 Months Ended

Dec. 31, 2023

Foreign exchange rates [abstract]

Foreign Exchange Gain (Loss)

($ millions)	2023	2022
Realized gain on CCS - principal	151.8	63.8
Translation of US dollar long-term debt	16.8	(94.3)
Unrealized gain (loss) on CCS - principal and foreign exchange swaps	(153.6)	4.4
Other	(5.0)	7.3
Foreign exchange gain (loss)	10.0	(18.8)

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Taxes [Abstract]

Disclosure of provision for income taxes

The provision for income taxes is as follows:

($ millions)		2023	2022 (1)
Current tax:
	Canada	(0.7)	—
Current tax recovery		(0.7)	—
Deferred tax expense:
	Canada	254.4	415.1
Deferred tax expense		254.4	415.1
Income tax expense		253.7	415.1

(1)Comparative period revised to reflect current period presentation.

Disclosure of reconciliation of income taxes calculated at the Canadian statutory rate with recorded income taxes

The following table reconciles income taxes calculated at the Canadian statutory rate with the recorded income taxes:

($ millions, except percentages)	2023		2022 (1)
Net income before tax from continuing operations	1,053.1		1,561.8
Statutory income tax rate	24.58	%	24.82	%
Expected provision for income taxes	258.9		387.6
Change in corporate tax rates and tax rate variance	(5.6)		1.6
Derecognition (recognition) of deferred tax assets	0.5		(0.7)
Non-deductible capital losses (non-taxable capital gains)	0.1		(0.2)
Non-deductible disposition of goodwill	0.1		1.9
Other (2)	(0.3)		24.9
Income tax expense	253.7		415.1

(1)Comparative period revised to reflect current period presentation.

(2)For the year ended December 31, 2022, there is an expense deducted in a foreign jurisdiction for which a tax benefit is not recognized.

Disclosure of deferred income tax asset (liability)

The composition of net deferred income tax asset (liability) is as follows:

($ millions)	2023	2022
Deferred income tax assets	—	278.8
Deferred income tax liabilities	(643.0)	(77.3)
Net deferred income tax asset (liability)	(643.0)	201.5

Disclosure of net deferred tax liabilities

The net deferred income tax assets (liabilities) are expected to be settled in the following periods:

($ millions)	2023	2022
Deferred income tax:
To be settled within one year	(1.7)	19.6
To be settled beyond one year	(641.3)	181.9
Deferred income tax	(643.0)	201.5

The movement in deferred income tax assets (liabilities) are as follows:

($ millions)	At January 1, 2023	(Charges) / credits due to acquisitions, discontinued operations & other	(Charged) / credited to earnings	At December 31, 2023
Deferred income tax assets:
Decommissioning liability	167.4	(1.6)	(19.2)	146.6
Income tax losses carried forward	744.6	(348.2)	(80.6)	315.8
Risk management contracts	2.1	—	11.3	13.4
Lease liabilities	30.7	0.6	3.7	35.0
Other	29.9	6.8	16.5	53.2
	974.7	(342.4)	(68.3)	564.0
Deferred income tax liabilities:
Property, plant and equipment	(743.1)	(244.2)	(139.9)	(1,127.2)
Risk management contracts	(10.8)	(2.9)	(41.3)	(55.0)
ROU asset	(19.3)	(0.6)	(4.9)	(24.8)
	(773.2)	(247.7)	(186.1)	(1,207.0)
Net deferred income tax assets (liabilities)	201.5	(590.1)	(254.4)	(643.0)

($ millions)	At January 1, 2022	Credits due to acquisitions & other	(Charged) / credited to earnings	At December 31, 2022
Deferred income tax assets:
Decommissioning liability	229.6	—	(62.2)	167.4
Income tax losses carried forward	814.2	—	(69.6)	744.6
Risk management contracts	41.1	—	(39.0)	2.1
Lease liabilities	35.3	—	(4.6)	30.7
Other	19.5	19.3	(8.9)	29.9
	1,139.7	19.3	(184.3)	974.7
Deferred income tax liabilities:
Property, plant and equipment	(533.4)	—	(209.7)	(743.1)
Risk management contracts	(13.4)	—	2.6	(10.8)
ROU asset	(22.8)	—	3.5	(19.3)
	(569.6)	—	(203.6)	(773.2)
Net deferred income tax assets (liabilities)	570.1	19.3	(387.9)	201.5

Disclosure of tax pools available

The approximate amounts of tax pools available as at December 31, 2023 and 2022 are as follows:

($ millions)	2023	2022
Tax pools:
Canada	8,281.0	5,685.8
United States	2,319.7	3,025.2
Total	10,600.7	8,711.0

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Share-based Compensation (Tables)

12 Months Ended

Dec. 31, 2023

Share-based Payment Arrangements [Abstract]

Schedule of restricted shares and DSU's rollforward

The following table reconciles the number of restricted shares, ESVP awards, PSUs and DSUs for the year ended December 31, 2023:

	Restricted Shares	ESVP	PSUs (1)	DSUs
Balance, beginning of year	2,244,738	5,274,478	2,713,176	1,745,879
Granted	718,566	1,626,590	888,834	231,464
Redeemed	(1,436,017)	(3,721,568)	(1,627,028)	(248,920)
Forfeited	(146,602)	(519,434)	(351,734)	—
Balance, end of year	1,380,685	2,660,066	1,623,248	1,728,423

(1)Based on underlying units before any effect of performance multipliers.

The following table reconciles the number of restricted shares, ESVP awards, PSUs and DSUs for the year ended December 31, 2022:

	Restricted Shares	ESVP	PSUs (1)	DSUs
Balance, beginning of year	3,267,717	8,329,291	3,214,620	1,556,780
Granted	710,819	1,288,598	904,469	208,693
Redeemed	(1,718,906)	(3,691,820)	(1,405,913)	(19,594)
Forfeited	(14,892)	(651,591)	—	—
Balance, end of year	2,244,738	5,274,478	2,713,176	1,745,879

(1)Based on underlying units before any effect of performance multipliers.

The following table provides summary information regarding stock options outstanding as at December 31, 2023:

	Stock options (number of units)	Weighted average exercise price ($)
Balance, beginning of year	3,889,130	4.43
Exercised	(629,013)	2.92
Forfeited	(35,857)	3.43
Balance, end of year	3,224,260	4.74

Summarized Information Regarding Stock Options Outstanding

The following table summarizes information regarding stock options outstanding as at December 31, 2023:

Range of exercise prices ($)	Number of stock options outstanding	Weighted average remaining term for stock options outstanding (years)	Weighted average exercise price per share for stock options outstanding ($)	Number of stock options exercisable	Weighted average exercise price per share for stock options exercisable ($)
1.09 - 1.65	1,541,362	3.25	1.09	505,996	1.09
1.66 - 5.16	254,950	2.27	3.94	245,820	3.99
5.17 - 9.86	438,417	3.70	6.01	177,060	7.15
9.87 - 10.06	989,531	1.02	10.06	989,531	10.06
	3,224,260	2.55	4.74	1,918,407	6.65

Disclosure of Number and Weighted Average Exercise Prices of Share Options

The following table provides summary information regarding stock options outstanding as at December 31, 2022:

	Stock options (number of units)	Weighted average exercise price ($)
Balance, beginning of year	5,839,464	4.04
Exercised	(1,446,571)	3.16
Forfeited	(398,610)	2.06
Expired	(105,153)	9.22
Balance, end of year	3,889,130	4.43

XML

Per Share Amounts (Tables)

12 Months Ended

Dec. 31, 2023

Earnings per share [abstract]

Disclosure of earnings per share

The following table summarizes the weighted average shares used in calculating net income (loss) per share:

	2023	2022
Weighted average shares – basic	545,644,234	566,710,644
Dilutive impact of share-based compensation	2,684,473	4,357,422
Weighted average shares – diluted	548,328,707	571,068,066

XML

Financial Instruments and Derivatives (Tables)

12 Months Ended

Dec. 31, 2023

Financial Instruments [Abstract]

Disclosure of financial assets

The following table summarizes the carrying value of the Company's remaining financial assets and liabilities as compared to their respective fair values as at December 31, 2023:

	2023 Carrying Value	2023 Fair Value	Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs  (Level 3)
($ millions)
Financial assets
Derivatives	255.0	255.0	—	255.0	—
	255.0	255.0	—	255.0	—
Financial liabilities
Derivatives	55.2	55.2	—	55.2	—
Senior guaranteed notes (1)	883.4	853.0	—	853.0	—
	938.6	908.2	—	908.2	—

(1)The senior guaranteed notes are classified as financial liabilities at amortized cost and are reported at amortized cost. The notes denominated in US dollars are translated to Canadian dollars at the period end exchange rate. The fair value of the notes is calculated based on current interest rates and is not recorded in the financial statements.

The following table summarizes the carrying value of the Company's remaining financial assets and liabilities as compared to their respective fair values as at December 31, 2022:

	2022 Carrying Value	2022 Fair Value	Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs  (Level 3)
($ millions)
Financial assets
Derivatives	235.3	235.3	—	235.3	—
	235.3	235.3	—	235.3	—
Financial liabilities
Derivatives	8.7	8.7	—	8.7	—
Senior guaranteed notes (1)	1,441.5	1,372.9	—	1,372.9	—
	1,450.2	1,381.6	—	1,381.6	—

(1)The senior guaranteed notes are classified as financial liabilities at amortized cost and are reported at amortized cost. The notes denominated in US dollars are translated to Canadian dollars at the period end exchange rate. The fair value of the notes is calculated based on current interest rates and is not recorded in the financial statements.

Disclosure of financial liabilities

The following table summarizes the carrying value of the Company's remaining financial assets and liabilities as compared to their respective fair values as at December 31, 2023:

	2023 Carrying Value	2023 Fair Value	Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs  (Level 3)
($ millions)
Financial assets
Derivatives	255.0	255.0	—	255.0	—
	255.0	255.0	—	255.0	—
Financial liabilities
Derivatives	55.2	55.2	—	55.2	—
Senior guaranteed notes (1)	883.4	853.0	—	853.0	—
	938.6	908.2	—	908.2	—

(1)The senior guaranteed notes are classified as financial liabilities at amortized cost and are reported at amortized cost. The notes denominated in US dollars are translated to Canadian dollars at the period end exchange rate. The fair value of the notes is calculated based on current interest rates and is not recorded in the financial statements.

The following table summarizes the carrying value of the Company's remaining financial assets and liabilities as compared to their respective fair values as at December 31, 2022:

	2022 Carrying Value	2022 Fair Value	Quoted prices in active markets for identical assets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs  (Level 3)
($ millions)
Financial assets
Derivatives	235.3	235.3	—	235.3	—
	235.3	235.3	—	235.3	—
Financial liabilities
Derivatives	8.7	8.7	—	8.7	—
Senior guaranteed notes (1)	1,441.5	1,372.9	—	1,372.9	—
	1,450.2	1,381.6	—	1,381.6	—

(1)The senior guaranteed notes are classified as financial liabilities at amortized cost and are reported at amortized cost. The notes denominated in US dollars are translated to Canadian dollars at the period end exchange rate. The fair value of the notes is calculated based on current interest rates and is not recorded in the financial statements.

Disclosure of derivative assets and liabilities

The following table summarizes the fair value as at December 31, 2023 and the change in fair value for the year ended December 31, 2023:

($ millions)	Commodity (1)	Interest (2)	Foreign exchange (3)	Equity	Total
Derivative assets, beginning of year	14.0	6.7	175.0	30.9	226.6
Acquisitions through business combinations	12.0	—	—	—	12.0
Dispositions	19.0	—	—	—	19.0
Unrealized change in fair value	129.4	(3.4)	(153.6)	(29.3)	(56.9)
Foreign exchange	(0.9)	—	—	—	(0.9)
Derivative assets, end of year	173.5	3.3	21.4	1.6	199.8
Derivative assets, end of year	176.5	3.3	72.2	3.0	255.0
Derivative liabilities, end of year	(3.0)	—	(50.8)	(1.4)	(55.2)

(1)Includes crude oil, crude oil differentials, natural gas and natural gas differential contracts.

(2)Interest payments on CCS.

(3)Includes principal portion of CCS and foreign exchange contracts.

The following table summarizes the fair value as at December 31, 2022 and the change in fair value for the year ended December 31, 2022:

($ millions)	Commodity (1)	Interest (2)	Foreign exchange (3)	Equity	Total
Derivative assets (liabilities), beginning of year	(154.4)	5.6	170.6	33.8	55.6
Unrealized change in fair value	168.4	1.1	4.4	(2.9)	171.0
Derivative assets, end of year	14.0	6.7	175.0	30.9	226.6
Derivative assets, end of year	22.6	6.7	175.1	30.9	235.3
Derivative liabilities, end of year	(8.6)	—	(0.1)	—	(8.7)

(1)Includes crude oil, crude oil differentials, propane, natural gas and natural gas differential contracts.

(2)Interest payments on CCS.

(3)Includes principal portion of CCS and foreign exchange contracts.

Disclosure of offsetting of financial assets and liabilities

The following table summarizes the gross asset and liability positions of the Company's financial derivatives by contract that are offset on the balance sheet as at December 31, 2023 and December 31, 2022:

	2023			2022
($ millions)	Asset	Liability	Net	Asset	Liability	Net
Gross amount	258.4	(58.6)	199.8	246.3	(19.7)	226.6
Amount offset	(3.4)	3.4	—	(11.0)	11.0	—
Net amount	255.0	(55.2)	199.8	235.3	(8.7)	226.6

Sensitivity analysis for types of market risk

The following table summarizes the unrealized gains (losses) on the Company's commodity financial derivative contracts and the resulting impact on income before tax due to fluctuations in commodity prices or differentials, with all other variables held constant:

	Impact on Income Before Tax		Impact on Income Before Tax
($ millions)	Year ended December 31, 2023		Year ended December 31, 2022
	Increase 10%	Decrease 10%	Increase 10%	Decrease 10%
Commodity price
Crude oil	(134.4)	135.5	(40.3)	38.8
Natural gas	(25.4)	25.8	(3.1)	3.2
Differential
Natural gas	15.5	(15.5)	2.6	(2.6)

The following table summarizes the resulting unrealized gains (losses) impacting income before tax due to the respective changes in the period end and applicable foreign exchange rates, with all other variables held constant:

		Impact on Income Before Tax		Impact on Income Before Tax
($ millions)	Exchange Rate	Year ended December 31, 2023		Year ended December 31, 2022
Cdn$ relative to US$		Increase 10%	Decrease 10%	Increase 10%	Decrease 10%
US dollar long-term debt	Period End	265.1	(265.1)	124.6	(124.6)
Cross currency swaps	Forward	(254.8)	254.8	(123.7)	123.7
Foreign exchange swaps	Forward	14.1	(14.1)	4.3	(4.3)

The following table summarizes the unrealized gains (losses) on the Company's equity derivative contracts and the resulting impact on income before tax due to the respective changes in the applicable share price, with all other variables held constant:

	Impact on Income Before Tax		Impact on Income Before Tax
($ millions)	Year ended December 31, 2023		Year ended December 31, 2022
Share price	Increase 50%	Decrease 50%	Increase 50%	Decrease 50%
Total return swaps	12.7	(12.7)	26.8	(26.8)

Disclosure of undiscounted cash outflows to non-derivative financial liabilities

The timing of undiscounted cash outflows relating to the financial liabilities outstanding as at December 31, 2023, is outlined in the table below:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Accounts payable and accrued liabilities	634.9	—	—	—	634.9
Dividends payable	56.8	—	—	—	56.8
Derivative liabilities (1)	—	3.2	—	—	3.2
Senior guaranteed notes (2)	342.8	476.5	27.0	—	846.3
Bank debt (3)	236.3	3,118.8	—	—	3,355.1

(1)These amounts exclude undiscounted cash outflows pursuant to the CCS and foreign exchange swaps.

(2)These amounts include the notional principal and interest payments pursuant to the CCS related to the senior guaranteed notes, which fix the amounts due in Canadian dollars. US dollar senior guaranteed notes that do not have any underlying CCS are translated at the period end foreign exchange rate.

(3)These amounts include interest based on debt outstanding and interest rates effective as at December 31, 2023, and includes undiscounted cash outflows pursuant to the CCS related to Secured Overnight Financing Rate loans.

The timing of undiscounted cash outflows relating to the financial liabilities outstanding as at December 31, 2022, is outlined in the table below:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Accounts payable and accrued liabilities	448.2	—	—	—	448.2
Dividends payable	99.4	—	—	—	99.4
Derivative liabilities (1)	12.6	—	—	—	12.6
Senior guaranteed notes (2)	486.6	816.2	26.9	—	1,329.7

(1)These amounts exclude undiscounted cash outflows pursuant to the CCS and foreign exchange swaps.

(2)These amounts include the notional principal and interest payments pursuant to the CCS and foreign exchange swap related to the senior guaranteed notes, which fix the amounts due in Canadian dollars

Disclosure of undiscounted cash outflows to derivative financial liabilities

The timing of undiscounted cash outflows relating to the financial liabilities outstanding as at December 31, 2023, is outlined in the table below:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Accounts payable and accrued liabilities	634.9	—	—	—	634.9
Dividends payable	56.8	—	—	—	56.8
Derivative liabilities (1)	—	3.2	—	—	3.2
Senior guaranteed notes (2)	342.8	476.5	27.0	—	846.3
Bank debt (3)	236.3	3,118.8	—	—	3,355.1

(1)These amounts exclude undiscounted cash outflows pursuant to the CCS and foreign exchange swaps.

(2)These amounts include the notional principal and interest payments pursuant to the CCS related to the senior guaranteed notes, which fix the amounts due in Canadian dollars. US dollar senior guaranteed notes that do not have any underlying CCS are translated at the period end foreign exchange rate.

(3)These amounts include interest based on debt outstanding and interest rates effective as at December 31, 2023, and includes undiscounted cash outflows pursuant to the CCS related to Secured Overnight Financing Rate loans.

The timing of undiscounted cash outflows relating to the financial liabilities outstanding as at December 31, 2022, is outlined in the table below:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Accounts payable and accrued liabilities	448.2	—	—	—	448.2
Dividends payable	99.4	—	—	—	99.4
Derivative liabilities (1)	12.6	—	—	—	12.6
Senior guaranteed notes (2)	486.6	816.2	26.9	—	1,329.7

(1)These amounts exclude undiscounted cash outflows pursuant to the CCS and foreign exchange swaps.

(2)These amounts include the notional principal and interest payments pursuant to the CCS and foreign exchange swap related to the senior guaranteed notes, which fix the amounts due in Canadian dollars

Disclosure of derivative contracts

The following is a summary of the derivative contracts in place as at December 31, 2023:

Financial WTI Crude Oil Derivative Contracts – Canadian Dollar (1)
	Swap		Collar
Term	Volume (bbls/d)	Average Price ($/bbl)	Volumes (bbls/d)	Average Sold Call Price ($/bbl)	Average Bought Put Price ($/bbl)
January 2024 - December 2024 (2)	15,414	102.02	28,488	114.40	97.52
January 2025 - December 2025	1,513	95.13	—	—	—

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

(2)Includes 5,000 bbls/d in the first half of 2024, which can be extended at the option of the counterparty for the second half of 2024 at an average swap price of $102.68/bbl.

Financial WTI Crude Oil Derivative Contracts – US Dollar (1)
	Swap
	Volume (bbls/d)	Average Price (US$/bbl)
Term
January 2024 - March 2024	10,050	82.44

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

Financial AECO Natural Gas Derivative Contracts – Canadian Dollar (1)
	Swap
	Volume (GJ/d)	Average Price ($/GJ)
Term
January 2024 - October 2024	31,403	3.33

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

Financial NYMEX Natural Gas Derivative Contracts – US Dollar (1)
	Swap		Collar
Term	Volume (mmbtu/d)	Average Price (US$/mmbtu)	Volume (mmbtu/d)	Average Sold Call Price (US$/mmbtu)	Average Bought Put Price (US$/mmbtu)
January 2024 - December 2024	31,027	3.44	60,000	4.21	3.14
January 2025 - December 2025	51,000	3.43	45,000	4.01	3.33

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

Financial NYMEX Natural Gas Differential Derivative Contracts – US Dollar (1)
Term	Volume (mmbtu/d)	Contract	Basis	Fixed Differential (US$/mmbtu)
January 2024 - December 2024	151,257	Basis Swap	AECO	(1.10)
January 2025 - December 2025	150,000	Basis Swap	AECO	(1.12)

(1)The volumes and prices reported are the weighted average volumes and prices for the period.

Financial Cross Currency Derivative Contracts
Term	Contract	Receive Notional Principal (US$ millions)	Fixed Rate (US%)	Pay Notional Principal (Cdn$ millions)	Fixed Rate (Cdn%)
January 2024	Swap	783.0	7.18	1,075.6	6.69
January 2024 - March 2024	Swap	635.0	7.17	847.6	6.78
January 2024 - June 2024	Swap	257.5	3.75	276.4	4.03
January 2024 - April 2025	Swap	52.0	4.30	67.9	3.98
January 2024 - April 2025	Swap	207.5	4.08	262.6	4.13

Financial Foreign Exchange Forward Derivative Contracts
Settlement Date	Contract	Receive Currency	Receive Notional Principal ($ millions)	Pay Currency	Pay Notional Principal ($ millions)
January 2024	Swap (1)	Cdn$	64.1	US$	48.0
June 2024	Swap	Cdn$	40.5	US$	30.0
December 2024	Swap	Cdn$	40.5	US$	30.0

(1)Based on an average floating exchange rate.

Financial Equity Derivative Contracts		Notional Principal ($ millions)	Number of shares
Term	Contract
January 2024 - March 2024	Swap	11.8	1,549,947
January 2024 - March 2025	Swap	12.0	1,207,754

XML

Commitments (Tables)

12 Months Ended

Dec. 31, 2023

Capital commitments [abstract]

Schedule of Gain Contingencies by Contingency

At December 31, 2023, the Company had contractual obligations and commitments as follows:

($ millions)	1 year	2 to 3 years	4 to 5 years	More than 5 years	Total
Operating (1)	15.8	19.7	11.5	7.9	54.9
Gas processing	115.6	193.4	147.9	280.8	737.7
Transportation	186.1	361.5	276.5	524.5	1,348.6
Total contractual commitments (2)	317.5	574.6	435.9	813.2	2,141.2

(1)Includes operating costs on the Company's office space, net of $16.7 million recoveries from subleases.

(2)Excludes contracts accounted for under IFRS 16. See Note 14 - "Leases" for additional information.

XML

Significant Subsidiaries (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of subsidiaries [abstract]

Schedule of Significant Subsidiaries Owned

The Company has the following significant subsidiaries, each owned 100% directly and indirectly, at December 31, 2023:

Subsidiary Name	Country of Formation
Crescent Point Resources Partnership	Canada
Crescent Point Holdings Ltd.	Canada
Hammerhead Resources ULC	Canada
Crescent Point Energy U.S. Corp.	United States of America

XML

Supplemental Disclosures (Tables)

12 Months Ended

Dec. 31, 2023

Supplemental Disclosures [Abstract]

Income statement presentation

The Company’s statements of comprehensive income are prepared primarily by nature of expense, with the exception of compensation expenses which are included in the operating, general and administrative and share-based compensation line items, as follows:

($ millions)	2023	2022 (1)
Operating	64.0	56.3
General and administrative	66.8	58.7
Share-based compensation	9.4	35.9
Total compensation expenses	140.2	150.9

(1)Comparative period revised to reflect current period presentation.

Cash flow statement presentation

Cash flow statement presentation

($ millions)	2023	2022
Operating activities
Changes in non-cash working capital:
Accounts receivable	66.7	(11.3)
Prepaids and deposits	(2.2)	(13.9)
Accounts payable and accrued liabilities	(97.8)	(3.5)
Other current liabilities	(11.8)	8.6
Other long-term liabilities	(9.8)	5.1
	(54.9)	(15.0)
Investing activities
Changes in non-cash working capital:
Accounts receivable	—	0.2
Other current assets	(60.5)	(18.7)
Accounts payable and accrued liabilities	56.3	(7.6)
	(4.2)	(26.1)
Financing activities
Changes in non-cash working capital:
Prepaids and deposits	(12.6)	(44.2)
Accounts payable and accrued liabilities	(2.0)	4.0
Dividends payable	(42.6)	55.9
	(57.2)	15.7

The Company's reconciliation of cash flow from financing activities is outlined in the table below:

($ millions)	Dividends payable	Long-term debt (1)	Lease liability (2)
December 31, 2021	43.5	1,970.2	141.4
Changes from cash flow from financing activities:
Decrease in bank debt, net		(338.5)
Repayment of senior guaranteed notes		(281.8)
Realized gain on cross currency swap maturity		63.8
Dividends paid	(144.7)
Payments on principal portion of lease liability			(20.4)
Non-cash changes:
Dividends declared	200.6
Additions			3.8
Other			(0.7)
Foreign exchange		27.8
December 31, 2022	99.4	1,441.5	124.1
Changes from cash flow from financing activities:
Increase in bank debt, net		2,675.1
Repayment of senior guaranteed notes and acquired long-term debt		(897.9)
Realized gain on cross currency swap maturity		147.7
Dividends paid	(254.5)
Payments on principal portion of lease liability			(20.8)
Non-cash changes:
Dividends declared	211.9
Acquisitions through business combinations		363.8	4.3
Additions			38.2
Dispositions			(1.1)
Foreign exchange		(163.9)
December 31, 2023	56.8	3,566.3	144.7

(1)Includes current portion of long-term debt.

(2)Includes current portion of lease liability.

XML

Oil and Gas Sales (Tables)

12 Months Ended

Dec. 31, 2023

Disclosure of geographical areas [abstract]

Disclosure of disaggregation of revenue from contracts with customers

The following table reconciles oil and gas sales by country:

($ millions) (1)	2023	2022
Canada
Crude oil and condensate sales	3,082.5	3,319.1
NGL sales	180.2	224.8
Natural gas sales	236.3	303.1
Total Canada	3,499.0	3,847.0
U.S.
Crude oil and condensate sales	569.6	553.3
NGL sales	27.0	55.2
Natural gas sales	16.3	37.6
Total U.S. (2)	612.9	646.1
Total oil and gas sales	4,111.9	4,493.1

(1)Oil and gas sales are reported before realized derivatives.

(2)Discontinued operations.

XML

Material Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2023
Restricted Share Bonus Plan
Disclosure of detailed information about property, plant and equipment [line items]
Award vesting (in years)	3 years
Employee Share Value Plan
Disclosure of detailed information about property, plant and equipment [line items]
Award vesting (in years)	3 years
Performance Share Units
Disclosure of detailed information about property, plant and equipment [line items]
Award vesting (in years)	3 years
Minimum
Disclosure of detailed information about property, plant and equipment [line items]
Estimated useful lives	5 years
Maximum
Disclosure of detailed information about property, plant and equipment [line items]
Estimated useful lives	16 years
Maximum | Deferred Share Units
Disclosure of detailed information about property, plant and equipment [line items]
Award vesting (in years)	7 years

XML

Other Current Assets (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Deferred consideration receivable	$ 79.2	$ 0.0
Deposit on acquisition	0.0	18.7
Other current assets	$ 79.2	$ 18.7

XML

Other Current Assets - Narrative (Details) - North Dakota Disposition $ in Millions	Dec. 31, 2023 USD ($) installment
Disclosure of impairment loss and reversal of impairment loss [line items]
Deferred consideration receivable | $	$ 60.0
Number of installments | installment	2

XML

Other Long-term Assets (Details) - CAD ($)	Dec. 31, 2023	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Non-current receivables from taxes other than income tax	$ 7,200,000	$ 6,400,000
Other non-current receivables	$ 200,000	$ 0

XML

Exploration and Evaluation Assets (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2023	Dec. 31, 2022
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of period		$ 7,729.4
End of period		10,718.3	$ 7,729.4
Impairment reversal	$ 1,469.6
Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of period		22,466.2
End of period		24,712.7	22,466.2
Exploration and evaluation assets
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of period	48.8	104.2	48.8
Acquisitions through business combinations		515.2	28.0
Additions		224.8	134.2
Dispositions		(1.9)	(10.9)
Transfers to property, plant and equipment		(204.3)	(80.8)
Amortization		(30.9)	(15.2)
Foreign exchange		(0.1)	0.1
End of period		607.0	104.2
Exploration and evaluation assets | Gross carrying amount
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of period	1,613.3	1,453.4	1,613.3
End of period		1,578.6	1,453.4
Exploration and evaluation assets | Accumulated depreciation and amortisation
Disclosure of detailed information about property, plant and equipment [line items]
Beginning of period	$ (1,564.5)	(1,349.2)	(1,564.5)
End of period		$ (971.6)	$ (1,349.2)

XML

Capital Acquisitions and Dispositions - Narrative (Details) shares in Millions, $ in Millions, $ in Millions						12 Months Ended
	Dec. 21, 2023 CAD ($) shares	Oct. 24, 2023 CAD ($)	Oct. 24, 2023 USD ($)	May 10, 2023 CAD ($)	Jan. 11, 2023 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Disclosure of impairment loss and reversal of impairment loss [line items]
Disposition transaction cost						$ 48.5	$ 5.1
Acquisition-related costs recognised as expense for transaction recognised separately from acquisition of assets and assumption of liabilities in business combination						39.8	4.6
Gain (loss) on capital dispositions						(0.7)	$ 26.1
North Dakota Disposition
Disclosure of impairment loss and reversal of impairment loss [line items]
Consideration (paid) received		$ 585.8
Cash		504.6	$ 372.7
Repaid debt		0.0
Deferred consideration receivable		(81.2)	$ 60.0
Carrying value		(595.1)
Gain (loss) on capital dispositions		$ 9.3
Hammerhead Acquisition
Disclosure of impairment loss and reversal of impairment loss [line items]
Consideration (paid) received	$ (2,037.0)
Cash	$ (1,544.0)
Equity consideration (in shares) | shares	53.2
Repaid debt	$ 363.8
Revenue of acquiree since acquisition date						24.7
Profit (loss) of acquiree since acquisition date						(14.8)
Revenue of combined entity as if combination occurred at beginning of period						833.3
Profit (loss) of combined entity as if combination occurred at beginning of period						527.6
Deferred consideration receivable	0.0
Carrying value	2,037.0
Gain (loss) on capital dispositions	$ 0.0
Kaybob Duvernay Acquisition
Disclosure of impairment loss and reversal of impairment loss [line items]
Consideration (paid) received					$ (370.4)
Cash					(370.4)
Repaid debt					0.0
Revenue of acquiree since acquisition date						56.4
Profit (loss) of acquiree since acquisition date						(37.0)
Revenue of combined entity as if combination occurred at beginning of period						58.8
Profit (loss) of combined entity as if combination occurred at beginning of period						38.7
Deferred consideration receivable					0.0
Carrying value					370.4
Gain (loss) on capital dispositions					$ 0.0
Alberta Montney Acquisition
Disclosure of impairment loss and reversal of impairment loss [line items]
Consideration (paid) received				$ (1,700.4)
Cash				(1,700.4)
Repaid debt				0.0
Revenue of acquiree since acquisition date						505.1
Profit (loss) of acquiree since acquisition date						329.4
Revenue of combined entity as if combination occurred at beginning of period						755.7
Profit (loss) of combined entity as if combination occurred at beginning of period						512.6
Deferred consideration receivable				0.0
Carrying value				1,700.4
Gain (loss) on capital dispositions				$ 0.0
Other minor dispositions, net
Disclosure of impairment loss and reversal of impairment loss [line items]
Consideration (paid) received						17.3
Cash						17.3
Repaid debt						0.0
Deferred consideration receivable						0.0
Carrying value						(17.2)
Gain (loss) on capital dispositions						$ (0.1)

XML

Capital Acquisitions and Dispositions - Schedule of Minor Acquisitions and Dispositions (Details) $ in Millions, $ in Millions						12 Months Ended
	Dec. 21, 2023 CAD ($)	Oct. 24, 2023 CAD ($)	Oct. 24, 2023 USD ($)	May 10, 2023 CAD ($)	Jan. 11, 2023 CAD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)
Disclosure of impairment loss and reversal of impairment loss [line items]
Gain (loss) on capital dispositions						$ 0.7	$ (26.1)
North Dakota Disposition
Disclosure of impairment loss and reversal of impairment loss [line items]
Cash		$ 504.6	$ 372.7
Common shares		0.0
Deferred consideration receivable		81.2	$ (60.0)
Consideration (paid) received		585.8
Working capital		9.1
Derivative asset		0.0
Other long-term assets		0.0
Exploration and evaluation		(1.8)
Property, plant and equipment		(635.2)
Right-of-use asset		(1.0)
Goodwill		0.0
Long-term debt		0.0
Decommissioning liability		13.7
Derivative liability		19.0
Lease liability		1.1
Deferred income tax liability		0.0
Fair value of net assets acquired (Carrying value of net assets disposed)		(595.1)
Gain (loss) on capital dispositions		(9.3)
North Dakota Disposition | Accounts Payable and Accrued Liabilities
Disclosure of impairment loss and reversal of impairment loss [line items]
Working capital		$ 9.1
Hammerhead Acquisition
Disclosure of impairment loss and reversal of impairment loss [line items]
Cash	$ (1,544.0)
Common shares	493.0
Deferred consideration receivable	0.0
Consideration (paid) received	(2,037.0)
Working capital	(116.7)
Derivative asset	12.3
Other long-term assets	0.0
Exploration and evaluation	354.8
Property, plant and equipment	2,406.6
Right-of-use asset	4.3
Goodwill	72.6
Long-term debt	(363.8)
Decommissioning liability	(9.9)
Derivative liability	(0.3)
Lease liability	(4.3)
Deferred income tax liability	(318.6)
Fair value of net assets acquired (Carrying value of net assets disposed)	2,037.0
Gain (loss) on capital dispositions	0.0
Assets acquired, excluding commitments relating to transportation	696.6
Assets acquired, excluding commitments relating to gas processing	156.7
Assets acquired, excluding commitments relating to operation	4.8
Hammerhead Acquisition | Accounts Receivable
Disclosure of impairment loss and reversal of impairment loss [line items]
Working capital	115.4
Hammerhead Acquisition | Prepaids and Deposits
Disclosure of impairment loss and reversal of impairment loss [line items]
Working capital	7.6
Hammerhead Acquisition | Accounts Payable and Accrued Liabilities
Disclosure of impairment loss and reversal of impairment loss [line items]
Working capital	$ 239.7
Kaybob Duvernay Acquisition
Disclosure of impairment loss and reversal of impairment loss [line items]
Cash					$ (370.4)
Common shares					0.0
Deferred consideration receivable					0.0
Consideration (paid) received					(370.4)
Working capital					0.0
Derivative asset					0.0
Other long-term assets					0.0
Exploration and evaluation					52.1
Property, plant and equipment					323.7
Right-of-use asset					0.0
Goodwill					0.0
Long-term debt					0.0
Decommissioning liability					(5.4)
Derivative liability					0.0
Lease liability					0.0
Deferred income tax liability					0.0
Fair value of net assets acquired (Carrying value of net assets disposed)					370.4
Gain (loss) on capital dispositions					$ 0.0
Alberta Montney Acquisition
Disclosure of impairment loss and reversal of impairment loss [line items]
Cash				$ (1,700.4)
Common shares				0.0
Deferred consideration receivable				0.0
Consideration (paid) received				(1,700.4)
Working capital				0.0
Derivative asset				0.0
Other long-term assets				0.1
Exploration and evaluation				108.3
Property, plant and equipment				1,616.6
Right-of-use asset				0.0
Goodwill				0.0
Long-term debt				0.0
Decommissioning liability				(24.6)
Derivative liability				0.0
Lease liability				0.0
Deferred income tax liability				0.0
Fair value of net assets acquired (Carrying value of net assets disposed)				1,700.4
Gain (loss) on capital dispositions				$ 0.0
Other minor dispositions, net
Disclosure of impairment loss and reversal of impairment loss [line items]
Cash						17.3
Common shares						0.0
Deferred consideration receivable						0.0
Consideration (paid) received						17.3
Working capital						0.0
Derivative asset						0.0
Other long-term assets						0.0
Exploration and evaluation						(0.1)
Property, plant and equipment						(20.8)
Right-of-use asset						0.0
Goodwill						(0.6)
Long-term debt						0.0
Decommissioning liability						4.3
Derivative liability						0.0
Lease liability						0.0
Deferred income tax liability						0.0
Fair value of net assets acquired (Carrying value of net assets disposed)						(17.2)
Gain (loss) on capital dispositions						$ 0.1

XML

Capital Acquisitions and Dispositions - Assets Held for Sale (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Business Combinations And Dispositions [Abstract]
Assets held for sale - PP&E	$ 247.1	$ 148.4
Liabilities held for sale - Decommissioning liability	$ (132.4)	$ (28.4)

XML

Discontinued Operations (Details) - CAD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Dec. 31, 2023	Dec. 31, 2022
REVENUE AND OTHER INCOME
Revenue from contracts with customers			$ 3,189.9	$ 3,512.3	[1]
Commodity derivative gains (losses)			163.8	(473.4)	[1]
Other income			13.4	59.0	[1]
Revenue and other income			3,367.1	3,097.9	[1]
EXPENSES
Operating			770.5	628.2	[1]
Transportation			174.3	131.0	[1]
General and administrative			126.5	78.4	[1]
Foreign exchange gain			10.0	(18.8)	[1]
Share-based compensation			38.7	38.8	[1]
Depletion, depreciation and amortization			894.7	807.2	[1]
Impairment (impairment reversal)	$ 6.2	$ 45.4	42.2	71.3
Accretion and financing			27.5	24.5	[1]
Total Expenses			2,314.0	1,536.1	[1]
Tax expense (recovery)
Current			(0.7)	0.0	[1]
Deferred			254.4	415.1	[1]
Net income (loss) from discontinued operations			(229.1)	336.7	[1]
Cash provided by (used in) discontinued operations
Operating activities			399.0	363.5
Investing activities			177.3	(252.3)
Increase in cash from discontinued operations			576.3	111.2
Oil and gas sales
REVENUE AND OTHER INCOME
Revenue from contracts with customers			3,499.0	3,847.0	[1]
Royalties
REVENUE AND OTHER INCOME
Revenue from contracts with customers			(375.3)	(435.5)	[1]
Discontinued operations
Disclosure of analysis of single amount of discontinued operations [line items]
Foreign exchange gain			621.7
REVENUE AND OTHER INCOME
Revenue from contracts with customers			457.0	480.7
Commodity derivative gains (losses)			(23.4)	0.0
Other income			(2.2)	(0.2)
Revenue and other income			431.4	480.5
EXPENSES
Operating			80.0	84.9
Transportation			12.2	8.8
General and administrative			12.7	3.4
Foreign exchange gain			(621.7)	0.0
Share-based compensation			(0.4)	0.3
Depletion, depreciation and amortization			170.3	144.5
Impairment (impairment reversal)			728.4	(71.3)
Accretion and financing			0.4	0.4
Total Expenses			381.9	171.0
Net income before tax from discontinued operations			49.5	309.5
Tax expense (recovery)
Current			0.0	0.0
Deferred			278.6	(27.2)
Net income (loss) from discontinued operations			(229.1)	336.7
Discontinued operations | Oil and gas sales
REVENUE AND OTHER INCOME
Revenue from contracts with customers			612.9	646.1
Discontinued operations | Royalties
REVENUE AND OTHER INCOME
Revenue from contracts with customers			$ (155.9)	$ (165.4)

[1] Comparative period revised to reflect current period presentation. See Note 9 - "Discontinued Operations" for additional information.

XML

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of changes in property, plant and equipment [abstract]
Beginning of period	$ 7,729.4
End of period	10,718.3	$ 7,729.4
General and administrative costs capitalized	42.4	49.7
Share-based compensation expense capitalized	5.7	14.7
Gross carrying amount
Reconciliation of changes in property, plant and equipment [abstract]
Beginning of period	22,466.2
End of period	24,712.7	22,466.2
Accumulated depreciation, amortization and impairment
Reconciliation of changes in property, plant and equipment [abstract]
Beginning of period	(14,736.8)
End of period	(13,994.4)	(14,736.8)
Development And Production Assets
Reconciliation of changes in property, plant and equipment [abstract]
Beginning of period	7,688.2	7,640.3
Acquisitions through business combinations	4,348.6	66.0
Additions	1,025.8	741.9
Dispositions	(657.7)	(285.8)
Transfers from exploration and evaluation assets	204.3	80.8
Reclassified as assets held for sale	(98.7)	(148.4)
Depletion	(1,009.3)	(911.4)
Impairment reversal (impairment)	(822.2)	428.6
Foreign exchange	0.2	76.2
End of period	10,679.2	7,688.2
Development And Production Assets | Gross carrying amount
Reconciliation of changes in property, plant and equipment [abstract]
Beginning of period	22,340.0	23,402.9
End of period	24,580.6	22,340.0
Development And Production Assets | Accumulated depreciation, amortization and impairment
Reconciliation of changes in property, plant and equipment [abstract]
Beginning of period	(14,651.8)	(15,762.6)
End of period	(13,901.4)	(14,651.8)
Corporate Assets
Reconciliation of changes in property, plant and equipment [abstract]
Beginning of period	41.2	47.0
Additions	5.9	2.6
Depletion	(8.0)	(8.5)
Foreign exchange	0.0	0.1
End of period	39.1	41.2
Corporate Assets | Gross carrying amount
Reconciliation of changes in property, plant and equipment [abstract]
Beginning of period	126.2	123.2
End of period	132.1	126.2
Corporate Assets | Accumulated depreciation, amortization and impairment
Reconciliation of changes in property, plant and equipment [abstract]
Beginning of period	(85.0)	(76.2)
End of period	(93.0)	(85.0)
Future Development Costs
Reconciliation of changes in property, plant and equipment [abstract]
Beginning of period	5,160.0
End of period	$ 9,080.0	$ 5,160.0

XML

Property, Plant and Equipment - Impairment Reversal (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Property, plant and equipment [abstract]
Impairment reversal	$ 0.0	$ (1,469.6)
Impairment	0.0	985.0
Impairment on assets held for sale	93.8	127.3
Impairment (impairment reversal)	$ 93.8	$ (357.3)

XML

Property, Plant and Equipment - Assets Held for Sale (Details) - CAD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2023	Sep. 30, 2023	Dec. 31, 2023	Dec. 31, 2022
Property, plant and equipment [abstract]
Impairment (impairment reversal)	$ 6.2	$ 45.4	$ 42.2	$ 71.3

XML

Property, Plant and Equipment - Impairment Test of Property, Plant and Equipment (Details)	Dec. 31, 2022 $ / bbl	Dec. 31, 2022 $ / $	Dec. 31, 2022 $ / bbl	Dec. 31, 2022 $ / MMbtu	Dec. 31, 2022	Mar. 31, 2022 $ / bbl	Mar. 31, 2022 $ / $	Mar. 31, 2022 $ / bbl	Mar. 31, 2022 $ / MMbtu
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark commodity price, assumed annual increase, percent					2.00%
2022 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices						94.17		117.71
Closing foreign exchange rate | $ / $							0.800
2022 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu									5.18
2023 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices	80.33		107.83			84.05		105.06
Closing foreign exchange rate | $ / $		0.745					0.800
2023 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.23					4.18
2024 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices	78.50		102.61			75.38		94.23
Closing foreign exchange rate | $ / $		0.765					0.800
2024 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.40					3.38
2025 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices	76.95		100.20			74.41		93.01
Closing foreign exchange rate | $ / $		0.768					0.800
2025 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.21					3.34
2026 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices	77.61		100.53			75.90		94.88
Closing foreign exchange rate | $ / $		0.772					0.800
2026 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.27					3.41
2027 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices	79.16		102.14			77.42		96.78
Closing foreign exchange rate | $ / $		0.775					0.800
2027 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.34					3.48
2028 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices	80.74		104.18			78.97		98.71
Closing foreign exchange rate | $ / $		0.775					0.800
2028 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.43					3.54
2029 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices	82.36		106.27			80.55		100.69
Closing foreign exchange rate | $ / $		0.775					0.800
2029 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.51					3.61
2030 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices	84.00		108.39			82.16		102.70
Closing foreign exchange rate | $ / $		0.775					0.800
2030 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.60					3.69
2031 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices	85.69		110.57			83.80		104.75
Closing foreign exchange rate | $ / $		0.775					0.800
2031 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.69					3.76
2032 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices	87.40		112.77			85.48		106.85
Closing foreign exchange rate | $ / $		0.775					0.800
2032 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.79					3.84
2033 | WTI Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices	89.15		115.03
Closing foreign exchange rate | $ / $		0.775
2033 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of detailed information about property, plant and equipment [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.88

XML

Property, Plant and Equipment - Impairment Loss and Recovery (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2022
Disclosure of impairment loss and reversal of impairment loss [line items]
Recoverable amount	$ 7,695.9
Impairment reversal	1,469.6
Impairment reversal, net of tax	1,103.7
Canada
Disclosure of impairment loss and reversal of impairment loss [line items]
Recoverable amount		$ 4,224.9
Impairment reversal		985.0
Impairment reversal, net of tax		740.5
Alberta Montney Acquisition | Canada
Disclosure of impairment loss and reversal of impairment loss [line items]
Recoverable amount	$ 3,413.8	$ 2,868.3
Discount rate	15.00%	15.00%
Impairment reversal	$ 806.0	$ 564.5
Impairment reversal, net of tax	605.3	424.4
Southwest Saskatchewan | Canada
Disclosure of impairment loss and reversal of impairment loss [line items]
Recoverable amount	$ 1,715.0	$ 1,356.6
Discount rate	15.00%	15.00%
Impairment reversal	$ 419.4	$ 420.5
Impairment reversal, net of tax	315.0	$ 316.1
Alberta | Canada
Disclosure of impairment loss and reversal of impairment loss [line items]
Recoverable amount	$ 2,567.1
Discount rate	15.00%
Impairment reversal	$ 244.2
Impairment reversal, net of tax	$ 183.4

XML

Property, Plant and Equipment - Market Risk (Details) - CAD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2022
Discount Rate Increase 1%
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	$ (281.2)	$ (255.8)
Discount Rate Increase 1% | Alberta Montney Acquisition
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	(186.2)	(167.8)
Discount Rate Increase 1% | Southwest Saskatchewan
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	(95.0)	(88.0)
Discount Rate Increase 1% | Alberta
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	0.0
Discount Rate Decrease 1%
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	309.4	282.5
Discount Rate Decrease 1% | Alberta Montney Acquisition
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	204.8	185.2
Discount Rate Decrease 1% | Southwest Saskatchewan
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	104.6	97.3
Discount Rate Decrease 1% | Alberta
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	0.0
Commodity Prices Increase 5%
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	568.7	535.0
Commodity Prices Increase 5% | Alberta Montney Acquisition
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	367.6	349.4
Commodity Prices Increase 5% | Southwest Saskatchewan
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	201.1	185.6
Commodity Prices Increase 5% | Alberta
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	0.0
Commodity Prices Decrease 5%
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	(567.7)	(533.6)
Commodity Prices Decrease 5% | Alberta Montney Acquisition
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	(366.6)	(348.3)
Commodity Prices Decrease 5% | Southwest Saskatchewan
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	(201.1)	(185.3)
Commodity Prices Decrease 5% | Alberta
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings	$ 0.0
Operating Costs Increases 5%
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings		(182.5)
Operating Costs Increases 5% | Alberta Montney Acquisition
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings		(117.7)
Operating Costs Increases 5% | Southwest Saskatchewan
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings		(64.8)
Operating Costs Decreases 5%
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings		183.7
Operating Costs Decreases 5% | Alberta Montney Acquisition
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings		118.7
Operating Costs Decreases 5% | Southwest Saskatchewan
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable, impact on pre-tax earnings		$ 65.0

XML

Goodwill - Schedule of Goodwill (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Schedule of Goodwill [Roll Forward]
Goodwill, beginning of year	$ 203.9	$ 211.5
Goodwill	(0.6)	(0.8)
Goodwill, end of year	275.9	203.9
Hammerhead Acquisition
Schedule of Goodwill [Roll Forward]
Acquisition	72.6	0.0
Saskatchewan, Gas Infrastructure Assets
Schedule of Goodwill [Roll Forward]
Asset dispositions	$ 0.0	$ (6.8)

XML

Goodwill - Schedule of Forecast Benchmark Commodity Prices and Exchange Rates for Impairment (Details) - Dec. 31, 2023	$ / bbl	$ / $	$ / bbl	$ / MMbtu	Total
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark commodity price, assumed annual increase, percent					2.00%
2024 | WTI Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices	73.67		97.97
Closing foreign exchange rate | $ / $		75.20%
2024 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices | $ / MMbtu				2.20
2025 | WTI Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices	74.98		99.71
Closing foreign exchange rate | $ / $		75.20%
2025 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices | $ / MMbtu				3.37
2026 | WTI Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices	76.14		100.85
Closing foreign exchange rate | $ / $		75.50%
2026 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.05
2027 | WTI Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices	77.66		102.86
Closing foreign exchange rate | $ / $		75.50%
2027 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.13
2028 | WTI Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices	79.22		104.93
Closing foreign exchange rate | $ / $		75.50%
2028 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.21
2029 | WTI Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices	80.80		107.02
Closing foreign exchange rate | $ / $		75.50%
2029 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.30
2030 | WTI Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices	82.42		109.17
Closing foreign exchange rate | $ / $		75.50%
2030 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.38
2031 | WTI Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices	84.06		111.34
Closing foreign exchange rate | $ / $		75.50%
2031 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.47
2032 | WTI Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices	85.74		113.56
Closing foreign exchange rate | $ / $		75.50%
2032 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.56
2033 | WTI Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices	87.46		115.84
Closing foreign exchange rate | $ / $		75.50%
2033 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.65
2034 | WTI Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices	89.21		118.16
Closing foreign exchange rate | $ / $		75.50%
2034 | AECO Natural Gas Derivative Contracts – Canadian Dollar
Disclosure of reconciliation of changes in goodwill [line items]
Forecast benchmark, commodity prices | $ / MMbtu				4.74

XML

Other Current Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Long-term compensation liability	$ 37.5	$ 49.1
Lease liability	40.5	24.9
Decommissioning liability	40.0	41.6
Other current liabilities	$ 118.0	$ 115.6

XML

Long-term Debt - Reconciliation Long Term Debt (Details) $ in Millions, $ in Millions	Dec. 31, 2023 CAD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Disclosure of detailed information about borrowings [line items]
Long-term debt	$ 3,566.3		$ 1,441.5	$ 1,970.2
Long-term debt due within one year	380.0		538.7
Long-term debt due beyond one year	3,186.3		902.8
Revolving bank debt
Disclosure of detailed information about borrowings [line items]
Bank debt	1,932.9		0.0
Term Loan
Disclosure of detailed information about borrowings [line items]
Senior guaranteed notes	750.0		0.0
Senior guaranteed notes
Disclosure of detailed information about borrowings [line items]
Senior guaranteed notes	883.4		$ 1,441.5
Long-term debt due beyond one year	$ 105.0	$ 589.5

XML

Long-term Debt - Bank Debt (Details) $ in Millions	Dec. 31, 2023 CAD ($) bank	Dec. 21, 2023 CAD ($) bank	May 10, 2023 CAD ($) bank	Dec. 31, 2022 CAD ($)
Disclosure of detailed information about borrowings [line items]
Credit facility, maximum borrowing capacity	$ 2,760.0
Maximum ratio of senior debt to EBITDA	3.5
Maximum ratio of total debt to EBITDA	4.0
Maximum ratio of senior debt to adjusted capital	0.55
Letter of credit amount outstanding	$ 26.2			$ 1.8
Syndicated Unsecured Credit Facility
Disclosure of detailed information about borrowings [line items]
Credit facility, maximum borrowing capacity	$ 2,260.0		$ 400.0
Number of banks | bank	11
Unsecured Operating Credit Facility
Disclosure of detailed information about borrowings [line items]
Credit facility, maximum borrowing capacity	$ 100.0
Number of banks | bank	1		10
Term Loan
Disclosure of detailed information about borrowings [line items]
Number of banks | bank		12
Non-current debt instruments issued		$ 750.0

XML

Long-term Debt - Senior Guaranteed Noted (Details)	Dec. 31, 2023 USD ($)	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Disclosure of detailed information about borrowings [line items]
Long-term debt		$ 3,186,300,000	$ 902,800,000
Borrowings		3,566,300,000	1,441,500,000	$ 1,970,200,000
Senior guaranteed notes, Hedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		711,900,000
Due within one year		316,400,000
Due beyond one year		395,500,000
Senior guaranteed notes, Unhedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		95,700,000
Due within one year		0
Due beyond one year		95,700,000
Senior guaranteed notes
Disclosure of detailed information about borrowings [line items]
Long-term debt	$ 589,500,000	105,000,000
Senior guaranteed notes		883,400,000	1,441,500,000
Current notes and debentures issued and current portion of non-current notes and debentures issued		380,000,000.0	538,700,000
Non-current portion of non-current notes and debentures issued		503,400,000	902,800,000
Senior guaranteed notes | Cross Currency Derivative Contract Swap 2018
Disclosure of detailed information about borrowings [line items]
Borrowings	517,000,000
Principal		$ 606,900,000
4.12% Interest, Maturing 4/11/2023
Disclosure of detailed information about borrowings [line items]
Principal	$ 61,500,000
Borrowings, interest rate	4.12%	4.12%
Senior guaranteed notes		$ 0	83,200,000
4.12% Interest, Maturing 4/11/2023 | Senior guaranteed notes, Hedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		0
4.12% Interest, Maturing 4/11/2023 | Senior guaranteed notes, Unhedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		0
3.58% Interest, Maturing 4/11/2023
Disclosure of detailed information about borrowings [line items]
Principal		$ 80,000,000.0
Borrowings, interest rate	3.58%	3.58%
Senior guaranteed notes		$ 0	80,000,000.0
3.58% Interest, Maturing 4/11/2023 | Senior guaranteed notes, Hedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		0
3.58% Interest, Maturing 4/11/2023 | Senior guaranteed notes, Unhedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		0
4.11% Interest, Maturing 6/12/2023
Disclosure of detailed information about borrowings [line items]
Principal		$ 10,000,000.0
Borrowings, interest rate	4.11%	4.11%
Senior guaranteed notes		$ 0	10,000,000.0
4.11% Interest, Maturing 6/12/2023 | Senior guaranteed notes, Hedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		0
4.11% Interest, Maturing 6/12/2023 | Senior guaranteed notes, Unhedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		$ 0
3.78% Interest, Maturing 6/12/2023
Disclosure of detailed information about borrowings [line items]
Principal	$ 270,000,000.0
Borrowings, interest rate	3.78%	3.78%
Senior guaranteed notes		$ 0	365,500,000
3.78% Interest, Maturing 6/12/2023 | Senior guaranteed notes, Hedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		0
3.78% Interest, Maturing 6/12/2023 | Senior guaranteed notes, Unhedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		0
3.85% Interest, Maturing 6/20/2024
Disclosure of detailed information about borrowings [line items]
Principal		$ 40,000,000.0
Borrowings, interest rate	3.85%	3.85%
Senior guaranteed notes		$ 40,000,000.0	40,000,000.0
3.85% Interest, Maturing 6/20/2024 | Senior guaranteed notes, Hedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		40,000,000.0
3.85% Interest, Maturing 6/20/2024 | Senior guaranteed notes, Unhedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		$ 0
3.75% Interest, Maturing 6/20/2024
Disclosure of detailed information about borrowings [line items]
Principal	$ 257,500,000
Borrowings, interest rate	3.75%	3.75%
Senior guaranteed notes		$ 340,000,000.0	348,500,000
3.75% Interest, Maturing 6/20/2024 | Senior guaranteed notes, Hedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		276,400,000
3.75% Interest, Maturing 6/20/2024 | Senior guaranteed notes, Unhedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		$ 0
4.30% Interest, Maturing 4/11/2025
Disclosure of detailed information about borrowings [line items]
Principal	$ 82,000,000.0
Borrowings, interest rate	4.30%	4.30%
Senior guaranteed notes		$ 108,300,000	111,000,000.0
4.30% Interest, Maturing 4/11/2025 | Senior guaranteed notes, Hedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		67,900,000
4.30% Interest, Maturing 4/11/2025 | Senior guaranteed notes, Unhedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		39,600,000
3.94% Interest, Maturing 4/22/2025
Disclosure of detailed information about borrowings [line items]
Principal		$ 65,000,000.0
Borrowings, interest rate	3.94%	3.94%
Senior guaranteed notes		$ 65,000,000.0	65,000,000.0
3.94% Interest, Maturing 4/22/2025 | Senior guaranteed notes, Hedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		65,000,000.0
3.94% Interest, Maturing 4/22/2025 | Senior guaranteed notes, Unhedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		$ 0
4.08% Interest, Maturing 4/22/2025
Disclosure of detailed information about borrowings [line items]
Principal	$ 230,000,000.0
Borrowings, interest rate	4.08%	4.08%
Senior guaranteed notes		$ 303,700,000	311,300,000
4.08% Interest, Maturing 4/22/2025 | Senior guaranteed notes, Hedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		262,600,000
4.08% Interest, Maturing 4/22/2025 | Senior guaranteed notes, Unhedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		$ 29,700,000
4.18% Interest, Maturing 4/22/2027
Disclosure of detailed information about borrowings [line items]
Principal	$ 20,000,000.0
Borrowings, interest rate	4.18%	4.18%
Senior guaranteed notes		$ 26,400,000	$ 27,000,000.0
4.18% Interest, Maturing 4/22/2027 | Senior guaranteed notes, Hedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		0
4.18% Interest, Maturing 4/22/2027 | Senior guaranteed notes, Unhedged
Disclosure of detailed information about borrowings [line items]
Principal due on maturity		$ 26,400,000

XML

Leases - Right-of-Use Assets (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use asset at cost	$ 200.6	$ 161.5
Accumulated depreciation	(97.8)	(83.4)
Right-of-use asset	102.8	78.1
Right-Of-Use Assets, Net Carrying Amount Rollforward [Roll Forward]
Net carrying amount, beginning of year	78.1
Acquisitions through business combinations	4.3
Additions	38.2
Dispositions	(1.0)
Depreciation	(16.8)
Net carrying amount, end of year	102.8	78.1
Sublease income	3.7	3.6
Other Income (Loss)
Right-Of-Use Assets, Net Carrying Amount Rollforward [Roll Forward]
Sublease income	3.7
Office
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use asset at cost	124.8	121.9
Accumulated depreciation	(65.1)	(55.4)
Right-of-use asset	59.7	66.5
Right-Of-Use Assets, Net Carrying Amount Rollforward [Roll Forward]
Net carrying amount, beginning of year	66.5
Acquisitions through business combinations	3.0
Additions	0.8
Dispositions	(0.1)
Depreciation	(10.5)
Net carrying amount, end of year	59.7	66.5
Fleet Vehicles
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use asset at cost	37.2	28.5
Accumulated depreciation	(23.0)	(20.4)
Right-of-use asset	14.2	8.1
Right-Of-Use Assets, Net Carrying Amount Rollforward [Roll Forward]
Net carrying amount, beginning of year	8.1
Acquisitions through business combinations	0.6
Additions	10.6
Dispositions	(0.9)
Depreciation	(4.2)
Net carrying amount, end of year	14.2	8.1
Other
Disclosure of quantitative information about right-of-use assets [line items]
Right-of-use asset at cost	38.6	11.1
Accumulated depreciation	(9.7)	(7.6)
Right-of-use asset	28.9	3.5
Right-Of-Use Assets, Net Carrying Amount Rollforward [Roll Forward]
Net carrying amount, beginning of year	3.5
Acquisitions through business combinations	0.7
Additions	26.8
Dispositions	0.0
Depreciation	(2.1)
Net carrying amount, end of year	$ 28.9	$ 3.5

XML

Leases - Lease Liability (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Lease Liability, Period Increase (Decrease) Rollforward [Roll Forward]
Additions	$ 38.2	$ 3.8
Lease liability, beginning of year	124.1	141.4
Acquisitions through business combinations	4.3	0.0
Dispositions	(1.1)	0.0
Financing	5.2	5.7
Payments on lease liability	(26.0)	(26.1)
Other	0.0	(0.7)
Lease liability, end of year	144.7	124.1
Expected to be incurred within one year	40.5	24.9
Expected to be incurred beyond one year	104.2	99.2
Expense relating to variable lease payments not included in measurement of lease liabilities	1.7	1.5
Expense relating to short-term leases for which recognition exemption has been used	$ 0.8	$ 0.8

XML

Leases - Undiscounted Lease Payments Maturity Schedule (Details) $ in Millions	Dec. 31, 2023 CAD ($)
Disclosure of maturity analysis of finance lease payments receivable [line items]
Undiscounted cash flows related to lease liability	$ 162.1
1 year
Disclosure of maturity analysis of finance lease payments receivable [line items]
Undiscounted cash flows related to lease liability	41.8
2 to 3 years
Disclosure of maturity analysis of finance lease payments receivable [line items]
Undiscounted cash flows related to lease liability	59.6
4 to 5 years
Disclosure of maturity analysis of finance lease payments receivable [line items]
Undiscounted cash flows related to lease liability	35.5
More than 5 years
Disclosure of maturity analysis of finance lease payments receivable [line items]
Undiscounted cash flows related to lease liability	$ 25.2

XML

Other Long-term Liabilities (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Subclassifications of assets, liabilities and equities [abstract]
Non-current Liabilities From Share-based Payment Transactions	$ (31.0)	$ (40.8)

XML

Decommissioning Liability (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Provisions for Changes in Decommissioning Liability [Roll Forward]
Expected to be incurred within one year	$ (40.0)	$ (41.6)
Decommissioning liability	566.4	633.9
Decommissioning liability, undiscounted cash flows	$ 847.7	$ 894.9
Discount rate applied to cash flow projections	3.02%	3.28%
Inflation rate used to extrapolate cash flow projections	1.62%	2.09%
Decommissioning liability
Provisions for Changes in Decommissioning Liability [Roll Forward]
Decommissioning liability, beginning of year	$ 675.5	$ 918.8
Liabilities incurred	19.8	21.6
Liabilities acquired through capital acquisitions	40.1	3.4
Liabilities disposed through capital dispositions	(18.2)	(46.7)
Liabilities settled	(45.4)	(43.1)
Revaluation of acquired decommissioning liabilities	38.5	3.8
Change in estimates	(3.0)	(11.4)
Change in discount and inflation rate estimates	(19.6)	(163.0)
Accretion	22.7	19.2
Reclassified as liabilities associated with assets held for sale	(104.0)	(28.4)
Foreign exchange	0.0	1.3
Decommissioning liability, end of year	606.4	675.5
Expected to be incurred within one year	(40.0)	(41.6)
Decommissioning liability		633.9
Proceeds from government subsidy programs	5.4	23.0
Provision for decommissioning, restoration and rehabilitation costs	$ 606.4	$ 675.5

XML

Shareholders' Capital (Details) - CAD ($) $ in Millions		12 Months Ended
	Mar. 07, 2023	Dec. 31, 2023	Dec. 31, 2022
Amount
Redemption of restricted shares		$ 2.4	$ 2.6
Common shares repurchased for cancellation		(349.9)	(294.2)
Shareholders’ capital		$ 17,052.7	$ 16,419.3
Percent of public float	10.00%
Shareholders’ capital
Number of shares
Common shares, beginning of year (in shares)		550,888,983	579,484,032
Issued on corporate acquisitions (in shares)		53,202,339	0
Issued for cash (in shares)		48,550,000	0
Issued on redemption of restricted stock (in shares)		1,436,017	1,713,730
Issued on exercise of stock options (in shares)		464,051	1,038,321
Common shares repurchased (in shares)	(54,605,659)	(34,611,900)	(31,347,100)
Common shares, end of year (in shares)		619,929,490	550,888,983
Amount
Common shares, beginning of year		$ 16,675.8	$ 16,963.4
Issued on capital acquisition		493.0	0.0
Issued for cash		500.1	0.0
Redemption of restricted shares		4.9	5.2
Issued on exercise of stock options		0.7	1.4
Common shares repurchased for cancellation		349.9	294.2
Common shares, end of year		17,324.6	16,675.8
Cumulative share issue costs, net of tax		(271.9)	(256.5)
Shareholders’ capital		$ 17,052.7	$ 16,419.3

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Deficit (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure of reserves within equity [line items]
Deficit	$ (10,202.5)	$ (10,563.3)
Accumulated earnings (deficit)
Disclosure of reserves within equity [line items]
Deficit	(2,130.3)	(2,700.6)
Accumulated gain on shares issued pursuant to DRIP and SDP
Disclosure of reserves within equity [line items]
Deficit	8.4	8.4
Accumulated tax effect on redemption of restricted shares
Disclosure of reserves within equity [line items]
Deficit	18.2	15.8
Accumulated dividends
Disclosure of reserves within equity [line items]
Deficit	$ (8,098.8)	$ (7,886.9)

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Capital Management (Details) $ in Millions	Dec. 31, 2023 CAD ($)	Dec. 31, 2022 CAD ($)	Dec. 31, 2021 CAD ($)
Capital Management [Abstract]
Long-term debt	$ 3,566.3	$ 1,441.5	$ 1,970.2
Adjusted working capital (surplus) deficiency	196.3	(95.1)
Unrealized foreign exchange on translation of hedged US dollar long-term debt	(24.5)	(191.7)
Net debt	3,738.1	1,154.7
Shareholders’ equity	6,867.5	6,493.4	$ 5,405.3
Total capitalization	$ 10,605.6	$ 7,648.1
Net debt to adjusted cash flow from operations ratio	1.6	0.5

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Capital Management - Cash Flows to Adjusted Funds Flow from Operations (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Capital Management [Abstract]
Cash flow from operating activities	$ 2,195.7	$ 2,192.2
Changes in non-cash working capital	54.9	15.0
Transaction costs	48.5	5.1
Decommissioning expenditures	40.0	20.1
Adjusted funds flow from operations	$ 2,339.1	$ 2,232.4

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Commodity Derivative Gains (Losses) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure Of Maturity Analysis For Derivative And Non-derivative Financial Liabilities [Line Items]
Unrealized gains	$ (56.9)	$ 171.0
Commodity derivative gains (losses)	163.8	(473.4)	[1]
Commodity Contract
Disclosure Of Maturity Analysis For Derivative And Non-derivative Financial Liabilities [Line Items]
Realized gains (losses)	15.5	(641.8)
Unrealized gains	148.3	168.4
Commodity derivative gains (losses)	$ 163.8	$ (473.4)

[1] Comparative period revised to reflect current period presentation. See Note 9 - "Discontinued Operations" for additional information.

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Other Income (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Analysis of income and expense [abstract]
Gain (loss) on capital dispositions	$ (0.7)	$ 26.1
Government grant for decommissioning expenditures	5.4	23.0
Sublease income	3.7	3.6
Other	5.0	6.3
Other income	$ 13.4	$ 59.0	[1]

[1] Comparative period revised to reflect current period presentation. See Note 9 - "Discontinued Operations" for additional information.

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Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Analysis of income and expense [abstract]
Interest	$ 126.0	$ 64.7
Unrealized (gain) loss on interest derivative contracts	3.4	(1.1)
Interest expense	$ 129.4	$ 63.6

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Foreign Exchange Gain (Loss) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Foreign exchange gain (loss)	$ 10.0	$ (18.8)	[1]
CCS - Principal and foreign exchange swaps
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Realized gain (loss)	151.8	63.8
CCS - US Dollar Long-term Debt Maturities And Interest Payments
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Realized gain (loss)	16.8	(94.3)
US Dollar Long-Term Debt Maturities
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Unrealized gain (loss)	(153.6)	4.4
Other Foreign Currency Translation
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Unrealized gain (loss)	$ (5.0)	$ 7.3

[1] Comparative period revised to reflect current period presentation. See Note 9 - "Discontinued Operations" for additional information.

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Income Taxes - Provision for income taxes (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Current tax:
Canada	$ (0.7)	$ 0.0
Current tax recovery	(0.7)	0.0	[1]
Deferred tax expense:
Canada	254.4	415.1
Deferred	254.4	415.1	[1]
Income tax expense	$ 253.7	$ 415.1

[1] Comparative period revised to reflect current period presentation. See Note 9 - "Discontinued Operations" for additional information.

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Income Taxes - Income Tax Rate Reconciliation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Income Taxes [Abstract]
Net income before tax from continuing operations	$ 1,053.1	$ 1,561.8
Statutory income tax rate	24.58%	24.82%
Expected provision for income taxes	$ 258.9	$ 387.6
Change in corporate tax rates and tax rate variance	(5.6)	1.6
Derecognition (recognition) of deferred tax assets	0.5	(0.7)
Non-deductible capital losses (non-taxable capital gains)	0.1	(0.2)
Non-deductible disposition of goodwill	0.1	1.9
Other	(0.3)	24.9
Income tax expense	$ 253.7	$ 415.1

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Income Taxes - Deferred Income Tax Asset (liability) (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Taxes [Abstract]
Deferred income tax assets	$ 0.0	$ 278.8
Deferred income tax liabilities	(643.0)	(77.3)
Net deferred income tax asset (liability)	$ (643.0)	$ 201.5	$ 570.1

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Income Taxes - Deferred Tax Assets and Liabilities, Net (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset (liability)	$ (643.0)	$ 201.5	$ 570.1
To be settled within one year
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset (liability)	(1.7)	19.6
To be settled beyond one year
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax asset (liability)	$ (641.3)	$ 181.9

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Income Taxes - Deferred Tax Rollforward (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax liabilities at the beginning of the period	$ 643.0	$ (201.5)
Changes in deferred tax liability (asset) [abstract]
(Charges) / credits due to acquisitions & other	(590.1)	19.3
(Charged) / credited to earnings	(254.4)	(387.9)
Net deferred income tax liabilities at the end of the period	(201.5)	(570.1)
Deferred income tax assets:
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax liabilities at the beginning of the period	(564.0)	(974.7)
Changes in deferred tax liability (asset) [abstract]
(Charges) / credits due to acquisitions & other	(342.4)	19.3
(Charged) / credited to earnings	(68.3)	(184.3)
Net deferred income tax liabilities at the end of the period	(974.7)	(1,139.7)
Decommissioning liability
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax liabilities at the beginning of the period	(146.6)	(167.4)
Changes in deferred tax liability (asset) [abstract]
(Charges) / credits due to acquisitions & other	(1.6)	0.0
(Charged) / credited to earnings	(19.2)	(62.2)
Net deferred income tax liabilities at the end of the period	(167.4)	(229.6)
Income tax losses carried forward
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax liabilities at the beginning of the period	(315.8)	(744.6)
Changes in deferred tax liability (asset) [abstract]
(Charges) / credits due to acquisitions & other	(348.2)	0.0
(Charged) / credited to earnings	(80.6)	(69.6)
Net deferred income tax liabilities at the end of the period	(744.6)	(814.2)
Risk management contracts
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax liabilities at the beginning of the period	(13.4)	(2.1)
Changes in deferred tax liability (asset) [abstract]
(Charges) / credits due to acquisitions & other	0.0	0.0
(Charged) / credited to earnings	11.3	(39.0)
Net deferred income tax liabilities at the end of the period	(2.1)	(41.1)
Lease liabilities
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax liabilities at the beginning of the period	(35.0)	(30.7)
Changes in deferred tax liability (asset) [abstract]
(Charges) / credits due to acquisitions & other	0.6	0.0
(Charged) / credited to earnings	3.7	(4.6)
Net deferred income tax liabilities at the end of the period	(30.7)	(35.3)
Other
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax liabilities at the beginning of the period	(53.2)	(29.9)
Changes in deferred tax liability (asset) [abstract]
(Charges) / credits due to acquisitions & other	6.8	19.3
(Charged) / credited to earnings	16.5	(8.9)
Net deferred income tax liabilities at the end of the period	(29.9)	(19.5)
Deferred income tax liabilities:
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax liabilities at the beginning of the period	1,207.0	773.2
Changes in deferred tax liability (asset) [abstract]
(Charges) / credits due to acquisitions & other	(247.7)	0.0
(Charged) / credited to earnings	(186.1)	(203.6)
Net deferred income tax liabilities at the end of the period	773.2	569.6
Property, plant and equipment
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax liabilities at the beginning of the period	1,127.2	743.1
Changes in deferred tax liability (asset) [abstract]
(Charges) / credits due to acquisitions & other	(244.2)	0.0
(Charged) / credited to earnings	(139.9)	(209.7)
Net deferred income tax liabilities at the end of the period	743.1	533.4
Risk management contracts
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax liabilities at the beginning of the period	55.0	10.8
Changes in deferred tax liability (asset) [abstract]
(Charges) / credits due to acquisitions & other	(2.9)	0.0
(Charged) / credited to earnings	(41.3)	2.6
Net deferred income tax liabilities at the end of the period	10.8	13.4
ROU asset
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Net deferred income tax liabilities at the beginning of the period	24.8	19.3
Changes in deferred tax liability (asset) [abstract]
(Charges) / credits due to acquisitions & other	(0.6)	0.0
(Charged) / credited to earnings	(4.9)	3.5
Net deferred income tax liabilities at the end of the period	$ 19.3	$ 22.8

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Income Taxes - Tax Pools (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Tax pools	$ 10,600.7	$ 8,711.0
Operating loss carryforward	1,310.0	1,360.0
Operating loss carryforwards that will expire in the years 2026 through 2039	2,320.0	2,300.0
Operating loss carryforwards that will expire in the years 2029 through 2037	1,520.0
Operating loss carryforwards that will not expire	802.2
Unrealized losses	2,320.0	507.2
Other temporary differences	69.0	69.0
Canada
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Tax pools	8,281.0	5,685.8
United States
Disclosure of temporary difference, unused tax losses and unused tax credits [line items]
Tax pools	$ 2,319.7	$ 3,025.2

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Share-based Compensation - Schedule of Shares Activitiy (Details)	12 Months Ended
	Dec. 31, 2023 shares $ / shares	Dec. 31, 2022 shares $ / shares
Share-based Payment Arrangements [Roll Forward]
Redeemed (in shares)	(1,918,407)
Balance, end of year (in shares)	3,224,260
Share Based Payment Arrangements, Weighted Average Exercise Price [Roll Forward]
Exercised, Weighted average exercise price (in dollars per share) | $ / shares	$ 4.74
Restricted Shares
Share-based Payment Arrangements [Roll Forward]
Balance, beginning of year (in shares)	2,244,738	3,267,717
Granted (in shares)	718,566	710,819
Redeemed (in shares)	(1,436,017)	(1,718,906)
Forfeited (in shares)	(146,602)	(14,892)
Balance, end of year (in shares)	1,380,685	2,244,738
Employee Share Value Plan
Share-based Payment Arrangements [Roll Forward]
Balance, beginning of year (in shares)	5,274,478	8,329,291
Granted (in shares)	1,626,590	1,288,598
Redeemed (in shares)	(3,721,568)	(3,691,820)
Forfeited (in shares)	(519,434)	(651,591)
Balance, end of year (in shares)	2,660,066	5,274,478
Performance Stock Units
Share-based Payment Arrangements [Roll Forward]
Balance, beginning of year (in shares)	2,713,176	3,214,620
Granted (in shares)	888,834	904,469
Redeemed (in shares)	(1,627,028)	(1,405,913)
Forfeited (in shares)	(351,734)	0
Balance, end of year (in shares)	1,623,248	2,713,176
Deferred Share Units
Share-based Payment Arrangements [Roll Forward]
Balance, beginning of year (in shares)	1,745,879	1,556,780
Granted (in shares)	231,464	208,693
Redeemed (in shares)	(248,920)	(19,594)
Forfeited (in shares)	0	0
Balance, end of year (in shares)	1,728,423	1,745,879
Stock Option Plan
Share-based Payment Arrangements [Roll Forward]
Balance, beginning of year (in shares)	3,889,130
Redeemed (in shares)	(629,013)
Forfeited (in shares)	(35,857)
Balance, end of year (in shares)	3,224,260	3,889,130
Share Based Payment Arrangements, Weighted Average Exercise Price [Roll Forward]
Beginning Balance, Weighted average exercise price (in dollars per share) | $ / shares	$ 4.43
Exercised, Weighted average exercise price (in dollars per share) | $ / shares	2.92
Forfeited, Weighted average exercise price (in dollars per share) | $ / shares	3.43
Ending Balance, Weighted average exercise price (in dollars per share) | $ / shares	$ 4.74	$ 4.43

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Share-based Compensation - Schedule of Summarized Information on Options Outstanding (Details)	12 Months Ended
	Dec. 31, 2023 shares $ / shares	Dec. 31, 2022 shares
Disclosure of classes of share capital [line items]
Weighted average exercise price per share for options outstanding (in dollars per share)	3,224,260
Weighted average remaining term (in years)	2 years 6 months 18 days
Exercised, Weighted average exercise price (in dollars per share) | $ / shares	$ 4.74
Number of stock options exercisable (in shares)	1,918,407
Weighted average exercise price per share for options exercisable (in dollars per share) | $ / shares	$ 6.65
Stock Option Plan
Disclosure of classes of share capital [line items]
Weighted average exercise price per share for options outstanding (in dollars per share)	3,224,260	3,889,130
Exercised, Weighted average exercise price (in dollars per share) | $ / shares	$ 2.92
Number of stock options exercisable (in shares)	629,013
Stock Option Plan | 1.09 - 1.65
Disclosure of classes of share capital [line items]
Weighted average exercise price per share for options outstanding (in dollars per share)	1,541,362
Weighted average remaining term (in years)	3 years 3 months
Exercised, Weighted average exercise price (in dollars per share) | $ / shares	$ 1.09
Number of stock options exercisable (in shares)	505,996
Weighted average exercise price per share for options exercisable (in dollars per share) | $ / shares	$ 1.09
Stock Option Plan | 1.66 - 5.16
Disclosure of classes of share capital [line items]
Weighted average exercise price per share for options outstanding (in dollars per share)	254,950
Weighted average remaining term (in years)	2 years 3 months 7 days
Exercised, Weighted average exercise price (in dollars per share) | $ / shares	$ 3.94
Number of stock options exercisable (in shares)	245,820
Weighted average exercise price per share for options exercisable (in dollars per share) | $ / shares	$ 3.99
Stock Option Plan | 5.17 - 9.86
Disclosure of classes of share capital [line items]
Weighted average exercise price per share for options outstanding (in dollars per share)	438,417
Weighted average remaining term (in years)	3 years 8 months 12 days
Exercised, Weighted average exercise price (in dollars per share) | $ / shares	$ 6.01
Number of stock options exercisable (in shares)	177,060
Weighted average exercise price per share for options exercisable (in dollars per share) | $ / shares	$ 7.15
Stock Option Plan | 9.87 - 10.06
Disclosure of classes of share capital [line items]
Weighted average exercise price per share for options outstanding (in dollars per share)	989,531
Weighted average remaining term (in years)	1 year 7 days
Exercised, Weighted average exercise price (in dollars per share) | $ / shares	$ 10.06
Number of stock options exercisable (in shares)	989,531
Weighted average exercise price per share for options exercisable (in dollars per share) | $ / shares	$ 10.06

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Share-based Compensation - Stock Options Outstanding (Details)	12 Months Ended
	Dec. 31, 2022 shares $ / shares
Share-based Payment Arrangements [Abstract]
Stock Options Balance, beginning of year (in shares) | shares	5,839,464
Stock Options Exercised (in shares) | shares	(1,446,571)
Stock Options Forfeited (in shares) | shares	(398,610)
Stock Options Expired (in shares) | shares	(105,153)
Stock Options Balance, end of year (in shares) | shares	3,889,130
Weighted average exercise price Balance, beginning of year (in dollars per share) | $ / shares	$ 4.04
Weighted average exercise price Exercised (in dollars per share) | $ / shares	3.16
Weighted average exercise price Forfeited (in dollars per share) | $ / shares	2.06
Weighted average exercise price Expired (in dollars per share) | $ / shares	9.22
Weighted average exercise price Balance, end of year (in dollars per share) | $ / shares	$ 4.43

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Share-based Compensation - Narrative (Details) - CAD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Share-based Payment Arrangements [Abstract]
Weighted average share price	$ 9.73	$ 9.52
Share-based compensation	$ 40.4	$ 75.6
Share-based compensation expense capitalized from continuing operations	5.4	13.3
Share-based compensation expense capitalized	(5.7)	(14.7)
Current portion of long-term compensation liability	(37.5)	(49.1)
Non-current Liabilities From Share-based Payment Transactions	$ (31.0)	$ (40.8)

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Per Share Amounts (Details) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Earnings per share [abstract]
Weighted average shares – basic (in shares)	545,644,234	566,710,644
Dilutive impact of share-based compensation (in shares)	2,684,473	4,357,422
Weighted average shares – diluted (in shares)	548,328,707	571,068,066

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Financial Instruments and Derivatives - Carrying Amount and Fair Value of Financial Instruments (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets, carrying value	$ 255.0	$ 235.3
Financial assets, at fair value	255.0	235.3
Financial liabilities, carrying value	938.6	1,450.2
Financial liabilities, at fair value	908.2	1,381.6
Quoted prices in active markets for identical assets (Level 1)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets, at fair value	0.0	0.0
Financial liabilities, at fair value	0.0	0.0
Significant other observable inputs (Level 2)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets, at fair value	255.0	235.3
Financial liabilities, at fair value	908.2	1,381.6
Significant unobservable inputs (Level 3)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets, at fair value	0.0	0.0
Financial liabilities, at fair value	0.0	0.0
Derivatives
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities, carrying value	55.2	8.7
Financial liabilities, at fair value	55.2	8.7
Derivatives | Quoted prices in active markets for identical assets (Level 1)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities, at fair value	0.0	0.0
Derivatives | Significant other observable inputs (Level 2)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities, at fair value	55.2	8.7
Derivatives | Significant unobservable inputs (Level 3)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities, at fair value	0.0	0.0
Senior guaranteed notes
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities, carrying value	883.4	1,441.5
Financial liabilities, at fair value	853.0	1,372.9
Senior guaranteed notes | Quoted prices in active markets for identical assets (Level 1)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities, at fair value	0.0	0.0
Senior guaranteed notes | Significant other observable inputs (Level 2)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities, at fair value	853.0	1,372.9
Senior guaranteed notes | Significant unobservable inputs (Level 3)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial liabilities, at fair value	0.0	0.0
Derivatives
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets, carrying value	255.0	235.3
Financial assets, at fair value	255.0	235.3
Derivatives | Quoted prices in active markets for identical assets (Level 1)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets, at fair value	0.0	0.0
Derivatives | Significant other observable inputs (Level 2)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets, at fair value	255.0	235.3
Derivatives | Significant unobservable inputs (Level 3)
Disclosure Of Fair Value Measurement Of Assets And Liabilities [Line Items]
Financial assets, at fair value	$ 0.0	$ 0.0

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Financial Instruments and Derivatives - Derivatives Assets and Liabilities (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Derivative Assets and Liabilities, At Fair Value [Roll Forward]
Derivative assets, beginning of year	$ 226.6	$ 55.6
Acquisitions through business combinations	12.0
Dispositions	19.0
Unrealized change in fair value	(56.9)	171.0
Foreign exchange	(0.9)
Derivative assets, end of year	199.8	226.6
Derivative assets, end of year	255.0	235.3
Derivative liabilities, end of year	(55.2)	(8.7)
Commodity contracts
Derivative Assets and Liabilities, At Fair Value [Roll Forward]
Derivative assets, beginning of year	14.0	(154.4)
Acquisitions through business combinations	12.0
Dispositions	19.0
Unrealized change in fair value	129.4	168.4
Foreign exchange	(0.9)
Derivative assets, end of year	173.5	14.0
Derivative assets, end of year	176.5	22.6
Derivative liabilities, end of year	(3.0)	(8.6)
Interest rate swap contract
Derivative Assets and Liabilities, At Fair Value [Roll Forward]
Derivative assets, beginning of year	6.7	5.6
Acquisitions through business combinations	0.0
Dispositions	0.0
Unrealized change in fair value	(3.4)	1.1
Foreign exchange	0.0
Derivative assets, end of year	3.3	6.7
Derivative assets, end of year	3.3	6.7
Derivative liabilities, end of year	0.0	0.0
Foreign exchange
Derivative Assets and Liabilities, At Fair Value [Roll Forward]
Derivative assets, beginning of year	175.0	170.6
Acquisitions through business combinations	0.0
Dispositions	0.0
Unrealized change in fair value	(153.6)	4.4
Foreign exchange	0.0
Derivative assets, end of year	21.4	175.0
Derivative assets, end of year	72.2	175.1
Derivative liabilities, end of year	(50.8)	(0.1)
Equity Contracts
Derivative Assets and Liabilities, At Fair Value [Roll Forward]
Derivative assets, beginning of year	30.9	33.8
Acquisitions through business combinations	0.0
Dispositions	0.0
Unrealized change in fair value	(29.3)	(2.9)
Foreign exchange	0.0
Derivative assets, end of year	1.6	30.9
Derivative assets, end of year	3.0	30.9
Derivative liabilities, end of year	$ (1.4)	$ 0.0

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Financial Instruments and Derivatives - Offsetting (Details) - Derivatives - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Offsetting Financial Assets
Gross amount	$ 258.4	$ 246.3
Amount offset	(3.4)	(11.0)
Net amount	255.0	235.3
Offsetting Financial Liabilities
Gross amount	(58.6)	(19.7)
Amount offset	3.4	11.0
Net amount	(55.2)	(8.7)
Gross amount assets (liabilities)	199.8	226.6
Net amount assets (liabilities)	$ 199.8	$ 226.6

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Financial Instruments and Derivatives - Commodity Price Risk (Details) - Commodity price risk - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable percent	10.00%	10.00%
Commodity Price, Crude Oil
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible increase in risk variable, impact on pre-tax earnings	$ (134.4)	$ (40.3)
Possible decrease in risk variable, impact on pre-tax earnings	135.5	38.8
Commodity Price, Natural Gas
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible increase in risk variable, impact on pre-tax earnings	(25.4)	(3.1)
Possible decrease in risk variable, impact on pre-tax earnings	25.8	3.2
Differential, Natural Gas
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible increase in risk variable, impact on pre-tax earnings	15.5	2.6
Possible decrease in risk variable, impact on pre-tax earnings	$ (15.5)	$ (2.6)

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Financial Instruments and Derivatives - Interest Rate Risk (Details) - Interest rate risk - CAD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable percent	1.00%
Possible change in risk variable, impact on pre-tax earnings	$ 26,800,000	$ 0

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Financial Instruments and Derivatives - Foreign Exchange Risk (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Currency risk | US dollar long-term debt
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible increase in risk variable, impact on pre-tax earnings	$ 265.1	$ 124.6
Possible decrease in risk variable, impact on pre-tax earnings	(265.1)	(124.6)
Currency risk | Currency swap contract
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible increase in risk variable, impact on pre-tax earnings	(254.8)	(123.7)
Possible decrease in risk variable, impact on pre-tax earnings	254.8	123.7
Currency risk | Foreign exchange
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible increase in risk variable, impact on pre-tax earnings	14.1	4.3
Possible decrease in risk variable, impact on pre-tax earnings	$ (14.1)	$ (4.3)
Foreign exchange
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable percent	10.00%	10.00%

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Financial Instruments and Derivatives - Equity Contract Risk (Details) - Equity price risk - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible change in risk variable percent	50.00%	50.00%
Equity Contracts
Disclosure of nature and extent of risks arising from financial instruments [line items]
Possible increase in risk variable, impact on pre-tax earnings	$ 12.7	$ 26.8
Possible decrease in risk variable, impact on pre-tax earnings	$ (12.7)	$ (26.8)

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Financial Instruments and Derivatives - Credit Risk (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of credit risk exposure [line items]
Expected credit loss, percent	0.83%	0.93%
Credit risk | Investment grade
Disclosure of credit risk exposure [line items]
Concentration percentage	98.00%
Credit risk | More than 90 days | Trade receivables
Disclosure of credit risk exposure [line items]
Concentration percentage	4.00%	4.00%

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Financial Instruments and Derivatives - Liquidity Risk (Details) - CAD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure Of Maturity Analysis For Derivative And Non-derivative Financial Liabilities [Line Items]
Letter of credit amount outstanding	$ 26.2	$ 1.8
Cash	17.3	289.9	$ 13.5
Liquidity risk
Disclosure Of Maturity Analysis For Derivative And Non-derivative Financial Liabilities [Line Items]
Undrawn borrowing facilities	801.1
Accounts payable and accrued liabilities	634.9	448.2
Dividends payable	56.8	99.4
Derivative liabilities	3.2	12.6
Senior guaranteed notes	846.3	1,329.7
Bank debt	3,355.1
Liquidity risk | 1 year
Disclosure Of Maturity Analysis For Derivative And Non-derivative Financial Liabilities [Line Items]
Accounts payable and accrued liabilities	634.9	448.2
Dividends payable	56.8	99.4
Derivative liabilities	0.0	12.6
Senior guaranteed notes	342.8	486.6
Bank debt	236.3
Liquidity risk | 2 to 3 years
Disclosure Of Maturity Analysis For Derivative And Non-derivative Financial Liabilities [Line Items]
Accounts payable and accrued liabilities	0.0	0.0
Dividends payable	0.0	0.0
Derivative liabilities	3.2	0.0
Senior guaranteed notes	476.5	816.2
Bank debt	3,118.8
Liquidity risk | 4 to 5 years
Disclosure Of Maturity Analysis For Derivative And Non-derivative Financial Liabilities [Line Items]
Accounts payable and accrued liabilities	0.0	0.0
Dividends payable	0.0	0.0
Derivative liabilities	0.0	0.0
Senior guaranteed notes	27.0	26.9
Bank debt	0.0
Liquidity risk | More than 5 years
Disclosure Of Maturity Analysis For Derivative And Non-derivative Financial Liabilities [Line Items]
Accounts payable and accrued liabilities	0.0	0.0
Dividends payable	0.0	0.0
Derivative liabilities	0.0	0.0
Senior guaranteed notes	0.0	$ 0.0
Bank debt	$ 0.0

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Financial Instruments and Derivatives - Financial Derivatives (Details) $ in Millions, $ in Millions	Dec. 31, 2023 USD ($) $ / bbl bbl / d $ / MMBTU shares $ / bbl $ / GJ MMBTU / d GJ / d	Dec. 31, 2023 CAD ($) $ / bbl bbl / d $ / MMBTU shares $ / bbl $ / GJ MMBTU / d GJ / d	Dec. 31, 2022 shares	Dec. 31, 2021 shares
Disclosure of detailed information about financial instruments [line items]
Number of shares | shares			3,889,130	5,839,464
WTI Crude Oil Derivative Contracts – Canadian Dollar 2024 | Forward contract
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | bbl / d	15,414	15,414
Average swap price | $ / bbl	102.02	102.02
WTI Crude Oil Derivative Contracts – Canadian Dollar 2024 | Forward contract | Collar, Sold Call Price
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | bbl / d	28,488	28,488
Average swap price | $ / bbl	114.40	114.40
WTI Crude Oil Derivative Contracts – Canadian Dollar 2024 | Forward contract | Collar, Bought Put Price
Disclosure of detailed information about financial instruments [line items]
Average swap price | $ / bbl	97.52	97.52
WTI Crude Oil Derivative Contracts – Canadian Dollar 2025 | Forward contract
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | bbl / d	1,513	1,513
Average swap price | $ / bbl	95.13	95.13
WTI Crude Oil Derivative Contracts – Canadian Dollar 2025 | Forward contract | Collar, Sold Call Price
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | bbl / d	0	0
Average swap price | $ / bbl	0	0
WTI Crude Oil Derivative Contracts – Canadian Dollar 2025 | Forward contract | Collar, Bought Put Price
Disclosure of detailed information about financial instruments [line items]
Average swap price | $ / bbl	0	0
WTI Crude Oil Derivative Contracts – Canadian Dollar Jan 2024 to June 2024 | Forward contract
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | bbl / d	5,000	5,000
WTI Crude Oil Derivative Contracts – Canadian Dollar July 2024 to December 2024 | Forward contract
Disclosure of detailed information about financial instruments [line items]
Average swap price | $ / bbl	102.68	102.68
WTI Crude Oil Derivative Contracts – US Dollar January 2024 - March 2024 | Forward contract
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | bbl / d	10,050	10,050
Average swap price | $ / bbl	82.44	82.44
AECO Natural Gas Derivative Contracts – Canadian Dollar January 2024 - October 2024 | Forward contract
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | GJ / d	31,403	31,403
Average swap price | $ / GJ	3.33	3.33
NYMEX Natural Gas Derivative Contracts – US Dollar One | Forward contract
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | MMBTU / d	31,027	31,027
Average swap price | $ / MMBTU	3.44	3.44
NYMEX Natural Gas Derivative Contracts – US Dollar One | Sold Call Price | Forward contract
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | MMBTU / d	60,000	60,000
Average swap price | $ / MMBTU	4.21	4.21
NYMEX Natural Gas Derivative Contracts – US Dollar One | Bought Put Price | Forward contract
Disclosure of detailed information about financial instruments [line items]
Average swap price | $ / MMBTU	3.14	3.14
NYMEX Natural Gas Derivative Contracts – US Dollar Two | Forward contract
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | MMBTU / d	51,000	51,000
Average swap price | $ / MMBTU	3.43	3.43
NYMEX Natural Gas Derivative Contracts – US Dollar Two | Sold Call Price | Forward contract
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | MMBTU / d	45,000	45,000
Average swap price | $ / MMBTU	4.01	4.01
NYMEX Natural Gas Derivative Contracts – US Dollar Two | Bought Put Price | Forward contract
Disclosure of detailed information about financial instruments [line items]
Average swap price | $ / MMBTU	3.33	3.33
WTI Crude Oil Differential Derivative Contracts – Canadian Dollar | Interest Rate Derivative Contracts Swap - One
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | MMBTU / d	151,257	151,257
Average swap price | $ / MMBTU	(1.10)	(1.10)
WTI Crude Oil Differential Derivative Contracts – Canadian Dollar | Interest Rate Derivative Contracts Swap - Two
Disclosure of detailed information about financial instruments [line items]
Nominal amount of hedging instrument | MMBTU / d	150,000	150,000
Average swap price | $ / MMBTU	(1.12)	(1.12)
January 2024 | Receive
Disclosure of detailed information about financial instruments [line items]
Notional amount	$ 783.0
Fixed annual rate	7.18%	7.18%
January 2024 | Pay
Disclosure of detailed information about financial instruments [line items]
Notional amount		$ 1,075.6
Fixed annual rate	6.69%	6.69%
January 2024 - March 2024 | Receive
Disclosure of detailed information about financial instruments [line items]
Notional amount	$ 635.0
Fixed annual rate	7.17%	7.17%
January 2024 - March 2024 | Pay
Disclosure of detailed information about financial instruments [line items]
Notional amount		$ 847.6
Fixed annual rate	6.78%	6.78%
January 2024 - June 2024 | Receive
Disclosure of detailed information about financial instruments [line items]
Notional amount	$ 257.5
Fixed annual rate	3.75%	3.75%
January 2024 - June 2024 | Pay
Disclosure of detailed information about financial instruments [line items]
Notional amount		$ 276.4
Fixed annual rate	4.03%	4.03%
January 2024 - April 2025 | Receive
Disclosure of detailed information about financial instruments [line items]
Notional amount	$ 52.0
Fixed annual rate	4.30%	4.30%
January 2024 - April 2025 | Pay
Disclosure of detailed information about financial instruments [line items]
Notional amount		$ 67.9
Fixed annual rate	3.98%	3.98%
January 2024 - April 2025 | Receive
Disclosure of detailed information about financial instruments [line items]
Notional amount	$ 207.5
Fixed annual rate	4.08%	4.08%
January 2024 - April 2025 | Pay
Disclosure of detailed information about financial instruments [line items]
Notional amount		$ 262.6
Fixed annual rate	4.13%	4.13%
January 2024 | Receive
Disclosure of detailed information about financial instruments [line items]
Notional amount		$ 64.1
January 2024 | Pay
Disclosure of detailed information about financial instruments [line items]
Notional amount	$ 48.0
June 2024 | Receive
Disclosure of detailed information about financial instruments [line items]
Notional amount		40.5
June 2024 | Pay
Disclosure of detailed information about financial instruments [line items]
Notional amount	30.0
December 2024 | Receive
Disclosure of detailed information about financial instruments [line items]
Notional amount		40.5
December 2024 | Pay
Disclosure of detailed information about financial instruments [line items]
Notional amount	$ 30.0
January 2024 - March 2024
Disclosure of detailed information about financial instruments [line items]
Notional amount		$ 11.8
Number of shares | shares	1,549,947	1,549,947
January 2024 - March 2025
Disclosure of detailed information about financial instruments [line items]
Notional amount		$ 12.0
Number of shares | shares	1,207,754	1,207,754

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Related Party Transactions (Details) - Key management personnel of entity or parent - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of transactions between related parties [line items]
Key management personnel compensation, short-term benefits	$ 7.3	$ 6.1
Key management personnel compensation, share-based	$ 19.4	$ 24.2

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Commitments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 CAD ($)
Disclosure of maturity analysis of operating lease payments [line items]
Operating	$ 54.9
Gas processing	737.7
Transportation	1,348.6
Total contractual commitments	2,141.2
Sublease income	(16.7)
1 year
Disclosure of maturity analysis of operating lease payments [line items]
Operating	15.8
Gas processing	115.6
Transportation	186.1
Total contractual commitments	317.5
2 to 3 years
Disclosure of maturity analysis of operating lease payments [line items]
Operating	19.7
Gas processing	193.4
Transportation	361.5
Total contractual commitments	574.6
4 to 5 years
Disclosure of maturity analysis of operating lease payments [line items]
Operating	11.5
Gas processing	147.9
Transportation	276.5
Total contractual commitments	435.9
More than 5 years
Disclosure of maturity analysis of operating lease payments [line items]
Operating	7.9
Gas processing	280.8
Transportation	524.5
Total contractual commitments	$ 813.2

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Significant Subsidiaries (Details)	12 Months Ended
	Dec. 31, 2023
Disclosure of subsidiaries [line items]
Proportion of ownership interest in subsidiary	100.00%
Crescent Point Resources Partnership
Disclosure of subsidiaries [line items]
Name of subsidiary	Crescent Point Resources Partnership
Country of incorporation of subsidiary	Canada
Crescent Point Holdings Ltd.
Disclosure of subsidiaries [line items]
Name of subsidiary	Crescent Point Holdings Ltd.
Country of incorporation of subsidiary	Canada
Hammerhead Resources ULC
Disclosure of subsidiaries [line items]
Name of subsidiary	Hammerhead Resources ULC
Country of incorporation of subsidiary	Canada
Crescent Point Energy U.S. Corp.
Disclosure of subsidiaries [line items]
Name of subsidiary	Crescent Point Energy U.S. Corp.
Country of incorporation of subsidiary	United States of America

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Supplemental Disclosures - Comprehensive Income Statement Presentation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of analysis of other comprehensive income by item [line items]
Total compensation expense	$ 140.2	$ 150.9
Operating
Disclosure of analysis of other comprehensive income by item [line items]
Total compensation expense	64.0	56.3
General and administrative
Disclosure of analysis of other comprehensive income by item [line items]
Total compensation expense	66.8	58.7
Share-based compensation
Disclosure of analysis of other comprehensive income by item [line items]
Total compensation expense	$ 9.4	$ 35.9

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Supplemental Disclosures - Cash Flow Statement Presentation (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Operating activities
Accounts receivable	$ 66.7	$ (11.3)
Prepaids and deposits	(2.2)	(13.9)
Accounts payable and accrued liabilities	(97.8)	(3.5)
Other current liabilities	(11.8)	8.6
Other long-term liabilities	(9.8)	5.1
Changes in non-cash working capital:	(54.9)	(15.0)
Investing activities
Accounts receivable	0.0	0.2
Other current assets	(60.5)	(18.7)
Accounts payable and accrued liabilities	56.3	(7.6)
Changes in non-cash working capital:	(4.2)	(26.1)
Financing activities
Prepaids and deposits	(12.6)	(44.2)
Accounts payable and accrued liabilities	(2.0)	4.0
Dividends declared	(42.6)	55.9
Change in non-cash working capital	$ (57.2)	$ 15.7

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Supplemental Disclosures - Cash Flow Supplemental Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Dividends Payable [Roll Forward]
Dividends payable at the beginning of the period	$ 99.4	$ 43.5
Dividends paid	(254.5)	(144.7)
Dividends declared	211.9	200.6
Dividends payable at the end of the period	56.8	99.4
Long-term Debt [Roll Forward]
Long-term debt beginning of the period	1,441.5	1,970.2
Increase in bank debt, net	2,675.1	(338.5)
Repayment of senior guaranteed notes and acquired long-term debt	(897.9)	(281.8)
Realized gain on cross currency swap maturity	147.7	63.8
Acquisitions through business combinations	363.8
Foreign exchange	(163.9)	27.8
Long-term debt end of the period	3,566.3	1,441.5
Lease Liability [Roll Forward]
Lease liability, beginning of year	124.1	141.4
Payments of lease liabilities	(20.8)	(20.4)
Additions	38.2	3.8
Other	0.0	(0.7)
Acquisitions through business combinations	4.3	0.0
Dispositions	(1.1)	0.0
Lease liability, end of year	$ 144.7	$ 124.1

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Oil and Gas Sales (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Disclosure of geographical areas [line items]
Revenue from contracts with customers	$ 3,189.9	$ 3,512.3	[1]
Oil and gas sales
Disclosure of geographical areas [line items]
Revenue from contracts with customers	3,499.0	3,847.0	[1]
Oil and gas sales | Canada
Disclosure of geographical areas [line items]
Revenue from contracts with customers	3,499.0	3,847.0
Oil and gas sales | U.S.
Disclosure of geographical areas [line items]
Revenue from contracts with customers	612.9	646.1
Oil and gas sales | Canada and United States
Disclosure of geographical areas [line items]
Revenue from contracts with customers	4,111.9	4,493.1
Crude oil sales | Canada
Disclosure of geographical areas [line items]
Revenue from contracts with customers	3,082.5	3,319.1
Crude oil sales | U.S.
Disclosure of geographical areas [line items]
Revenue from contracts with customers	569.6	553.3
NGL sales | Canada
Disclosure of geographical areas [line items]
Revenue from contracts with customers	180.2	224.8
NGL sales | U.S.
Disclosure of geographical areas [line items]
Revenue from contracts with customers	27.0	55.2
Natural gas sales | Canada
Disclosure of geographical areas [line items]
Revenue from contracts with customers	236.3	303.1
Natural gas sales | U.S.
Disclosure of geographical areas [line items]
Revenue from contracts with customers	$ 16.3	$ 37.6

[1] Comparative period revised to reflect current period presentation. See Note 9 - "Discontinued Operations" for additional information.

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Subsequent Events (Details) - CAD ($) $ in Millions	Jan. 26, 2024	Dec. 31, 2023	Dec. 31, 2022
Disclosure of non-adjusting events after reporting period [line items]
Decommissioning liability		$ 566.4	$ 633.9
Southern Alberta Assets | Other disposals of assets
Disclosure of non-adjusting events after reporting period [line items]
Consideration, net	$ (38.1)
Deferred consideration receivable	25.0
Decommissioning liability	$ 92.4