Exhibit 99.2
MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Baytex Energy Corp. (the "Company") is responsible for establishing and maintaining adequate internal control over financial reporting. Under the supervision of our President and Chief Executive Officer and our Chief Financial Officer we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on our assessment, we have concluded that as of December 31, 2023, our internal control over financial reporting was effective. As permitted by applicable securities laws in Canada and the U.S., management excluded from its design and assessment the internal control over financial reporting for Ranger Oil Corporation ("Ranger"), which was acquired on June 20, 2023. The consolidated financial statements as at and for the year ended December 31, 2023 include $3.5 billion of total assets and $691.9 million of revenues, net of royalties from the acquired entity.
Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to the financial statement preparation and presentation.
The effectiveness of the Company's internal control over financial reporting as of December 31, 2023 has been audited by KPMG LLP, the Company's Independent Registered Public Accounting Firm, who also audited the Company's consolidated financial statements for the year ended December 31, 2023.
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS
Management, in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board, has prepared the accompanying consolidated financial statements of the Company. Financial and operating information presented throughout this Annual Report is consistent with that shown in the consolidated financial statements.
Management is responsible for the integrity of the financial information. Internal control systems are designed and maintained to provide reasonable assurance that assets are safeguarded from loss or unauthorized use and to produce reliable accounting records for financial reporting purposes.
KPMG LLP were appointed by the Company's Board of Directors to express an audit opinion on the consolidated financial statements. Their examination included such tests and procedures, as they considered necessary, to provide a reasonable assurance that the consolidated financial statements are presented fairly in accordance with IFRS.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board of Directors exercises this responsibility through the Audit Committee, with assistance from the Reserves Committee regarding the annual review of our petroleum and natural gas reserves. The Audit Committee meets regularly with management and the Independent Registered Public Accounting Firm to ensure that management's responsibilities are properly discharged, to review the consolidated financial statements and recommend that the consolidated financial statements be presented to the Board of Directors for approval. The Audit Committee also considers the independence of KPMG LLP and reviews their fees. The Independent Registered Public Accounting Firm has access to the Audit Committee without the presence of management.
| | | | | |
| /s/ Eric T. Greager | /s/ Chad L. Kalmakoff |
| |
| Eric T. Greager | Chad L. Kalmakoff |
| President and Chief Executive Officer | Chief Financial Officer |
| Baytex Energy Corp. | Baytex Energy Corp. |
| |
| February 28, 2024 | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Baytex Energy Corp.
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated statements of financial position of Baytex Energy Corp. (and subsidiaries) (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of income (loss) and comprehensive income (loss), changes in equity, and cash flows for the years then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and its financial performance and its cash flows for the years then ended, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 28, 2024 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Assessment of the recoverable amount of oil and gas properties
As discussed in note 7 to the consolidated financial statements, the Company identified indicators of impairment as of December 31, 2023 related to the Company’s Viking and Eagle Ford Non-op cash generating units (CGUs). The Company therefore determined the recoverable amount as of December 31, 2023 of each of the CGUs and recorded an impairment of $833.7 million. The determination of recoverable amount of a CGU involves numerous estimates, including cash flows associated with estimated proved and probable oil and gas reserves of the CGU (“CGU reserves cash flows”) and the discount rate. The estimation of CGU reserves cash flows in the reserve report involves the expertise of independent qualified reserve evaluators, who take into consideration assumptions related to forecasted production volumes, royalty obligations, operating and capital costs and commodity prices (collectively “CGU reserve report assumptions”). The Company engages independent qualified reserve evaluators to estimate CGU reserves cash flows.
We identified the assessment of the recoverable amount of the Viking and Eagle Ford Non-op CGUs as a critical audit matter. Changes in CGU reserve report assumptions and discount rates could have had a significant impact on the estimate of recoverable amounts and the resulting impairment in the carrying amount of oil and gas properties relating to the CGUs. A high degree of auditor judgment was required to evaluate the Company’s estimates of CGU reserves cash flows, and related CGU reserve report assumptions, and the discount rates, which were inputs into the calculation of recoverable amounts. Additionally, the evaluation of these recoverable amounts required involvement of valuation professionals with specialized skills and knowledge.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to:
•the Company’s determination of the recoverable amount of each of the CGUs, including the discount rate
•the Company’s determination of the CGU reserve report assumptions and resulting CGU reserves cash flows.
We evaluated the competence, capabilities and objectivity of the independent qualified reserve evaluators engaged by the Company, who estimated the CGU reserves cash flows. We evaluated the methodology used by the independent qualified reserves evaluators to estimate the CGU reserves cash flows for compliance with the applicable regulatory standards. We compared the current year actual CGU production volumes, royalty obligations, operating and capital costs to those estimates used in the prior year estimate of proved reserves by CGU to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices used in the estimate of the CGU reserves cash flows by comparing them to those published by other reserve engineering companies. We assessed the forecasted production volumes, royalty obligations, operating and capital costs assumptions used in the current year estimate of the CGU reserves cash flows by comparing them to historical results. We involved valuation professionals with specialized skills and knowledge, who assisted in:
•evaluating the Company’s determination of discount rates by comparing the inputs of the discount rates against publicly available market data for comparable assets and assessing the resulting discount rates
•evaluating the Company’s estimate of recoverable amount of the CGUs by comparing to publicly available market data and valuation metrics for comparable entities.
Fair value measurement of oil and gas properties in a business combination
As discussed in note 4 to the consolidated financial statements, the Company acquired Ranger Oil Corporation (“Ranger”) in a business combination that was completed on June 20, 2023 (the “acquisition-date”). As a result of the transaction, the Company acquired oil and gas properties with an acquisition-date fair value of $3,096.4 million, a portion of which related to oil and gas properties with proved and probable oil and gas reserves. The determination of the acquisition-date fair value of the oil and gas properties with proved and probable oil and gas reserves involves numerous estimates, including cash flows associated with estimated acquired proved and probable oil and gas reserves (“acquired reserves cash flows”) and the discount rate. The estimation of acquired reserves cash flows in the acquired reserve report involves the expertise of the independent qualified reserve evaluators, who take into consideration assumptions related to forecasted production volumes, royalty obligations, operating and capital costs and commodity prices (collectively “acquired reserve report assumptions”). The Company engages independent qualified reserve evaluators to estimate the acquired reserves cash flows.
We identified the determination of the acquisition-date fair value of the oil and gas properties acquired in the Ranger business combination as a critical audit matter. Changes in acquired reserve report assumptions and the discount rate could have had a significant impact on the determination of the acquisition-date fair value of the acquired oil and gas properties. A high degree of auditor judgment was required to evaluate the acquired reserve report assumptions and the discount rate, which were inputs into the determination of the acquisition-date fair value. Additionally, the evaluation of this fair value required involvement of valuation professionals with specialized skills and knowledge.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to this critical audit matter. This included controls related to:
•the Company’s determination of the fair value, including the discount rate
•the Company’s determination of the acquired reserve report assumptions and resulting acquired reserves cash flows.
We evaluated the competence, capabilities and objectivity of the independent qualified reserve evaluators engaged by the Company, who estimated the acquired reserves cash flows. We evaluated the methodology used by the independent qualified reserve evaluators to estimate the acquired reserves cash flows for compliance with the applicable regulatory standards. We assessed the forecasted commodity prices used in the acquired reserve report by comparing them to those published by other reserve engineering companies. We assessed the forecasted production volumes, royalty obligations, operating and capital costs assumptions used in the acquired reserve report by comparing them to 2023 historical results for the Ranger oil and gas properties post-acquisition and the Ranger reserve report assumptions.
We involved valuation professionals with specialized skills and knowledge, who assisted in:
•evaluating the Company’s determination of the discount rate by comparing the inputs of the discount rate against publicly available market data for comparable assets and assessed the resulting discount rate
•evaluating the Company’s estimate of the acquisition-date fair value of the acquired oil and gas properties by comparing to publicly available market data and valuation metrics for comparable entities.
Assessment of indicators of impairment related to the Eagle Ford Operated CGU
As discussed in notes 2 and 7 to the consolidated financial statements, the Company assesses its oil and gas properties by cash generating unit (“CGU”) for indicators of impairment and impairment reversal at the end of each reporting period. These indicators can be internal such as changes in estimated proved and probable oil and gas reserves (“CGU reserves cash flows”) and internally estimated oil and gas resources (“CGU resources cash flows”), or external such as market conditions impacting discount rates or market capitalization. The estimation of CGU reserves cash flows in the reserve report involves the expertise of independent qualified reserve evaluators, who take into consideration assumptions related to forecasted production volumes, royalty obligations, operating and capital costs and commodity prices (“CGU reserve report assumptions”). The estimation of CGU resources cash flows involves the expertise of internal qualified reserve evaluators, who take into consideration
assumptions related to forecasted production volumes, royalty obligations, operating and capital costs and commodity prices (collectively “CGU resource report assumptions”), in addition to the number and locations of development wells along with the annual drilling timeline and pace. Based on the Company’s assessment of internal and external indicators of impairment, the Company determined that impairment testing was not required for the Eagle Ford Operated CGU as of December 31, 2023.
We identified the assessment of indicators of impairment related to the Eagle Ford Operated CGU as a critical audit matter. Indicators of impairment and impairment reversal such as changes in estimated CGU reserves cash flows and CGU resources cash flows required the application of auditor judgement. A high degree of auditor judgment was required in evaluating the Eagle Ford Operated CGU reserve report assumptions and CGU resource report assumptions, which were used in the assessment of indicators of impairment. Additionally, the evaluation of the Company’s resource valuation metric derived from the CGU resources cash flows required the involvement of valuation professionals with specialized skills and knowledge.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to:
•the Company’s assessment of internal and external indicators of impairment for the Eagle Ford Operated CGU
•the Company’s estimation of the Eagle Ford Operated CGU reserves cash flows and CGU resources cash flows and related CGU reserve report assumptions and CGU resource report assumptions in addition to the number and locations of development wells along with the annual drilling timeline and pace.
We evaluated the Company’s assessment of internal and external indicators of impairment for the Eagle Ford Operated CGU by considering whether the quantitative and qualitative information in the analysis was consistent with external market and industry data and the estimate of Eagle Ford Operated CGU reserves cash flows and CGU resources cash flows.
We evaluated the competence, capabilities and objectivity of the independent qualified reserve evaluators engaged by the Company. We evaluated the methodology used by the independent qualified reserves evaluators to estimate Eagle Ford Operated CGU reserves cash flows for compliance with the applicable regulatory standards. We compared 2023 actual production volumes, royalty obligations, operating and capital costs to those assumptions used in the acquired reserve report estimate of proved and probable reserves for the Eagle Ford Operated CGU to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices used in the estimate of the Eagle Ford Operated CGU reserves cash flows by comparing them to those published by other reserve engineering companies. We assessed the forecasted production volumes, royalty obligations, operating and capital costs assumptions used in the estimate of Eagle Ford Operated CGU reserves cash flows by comparing them to historical results.
We evaluated the competence, capabilities and objectivity of the internal qualified reserve evaluators. We assessed the forecasted production volumes, royalty obligations, operating and capital costs and commodity price assumptions for development well locations in the Eagle Ford Operated CGU resource report by comparing to the CGU reserve report assumptions for similar well locations in the Eagle Ford Operated CGU reserve report. We assessed the number and locations of development wells in the Eagle Ford Operated CGU resource report by comparing to the number and locations of development wells in the Eagle Ford Operated CGU full field development plan. We assessed the annual drilling timeline and pace in the Eagle Ford Operated CGU resource report by comparing to the annual drilling timeline and pace in the Eagle Ford Operated CGU reserve report.
We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the Company’s resource valuation metric derived from the CGU resources cash flows by comparing to publicly available market data and valuation metrics for comparable entities.
Impact of estimated oil and gas reserves on depletion expense related to oil and gas properties
As discussed in note 3 to the consolidated financial statements, the Company depletes its oil and gas properties using the unit-of-production method by depletable area. Under such method, capitalized costs are depleted over estimated proved and probable oil and gas reserves by depletable area (“area reserves”). As discussed in note 7 to the consolidated financial statements, the Company recorded depletion expense related to oil and gas properties of $1,039.8 million for the year ended December 31, 2023. The estimation of area reserves requires the expertise of independent qualified reserve evaluators who take into consideration assumptions related to forecasted production volumes, royalty obligations, operating and capital costs and commodity prices (collectively “area reserve report assumptions”). The Company engages independent qualified reserve evaluators to estimate area reserves.
We identified the assessment of the impact of estimated area reserves on depletion expense related to oil and gas properties as a critical audit matter. Changes in area reserve report assumptions could have had a significant impact on the calculation of depletion expense of the depletable area. A high degree of auditor judgment was required in evaluating the area reserves, and related area reserve report assumptions, which were used in the calculation of depletion expense.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to:
•the Company’s calculation of depletion expense by depletable area
•the Company’s determination of area reserve report assumptions and resulting area reserves.
We assessed the calculation of depletion expense for compliance with International Financial Reporting Standards as issued by the International Accounting Standards Board. We evaluated the competence, capabilities and objectivity of the independent qualified reserve evaluators engaged by the Company. We evaluated the methodology used by the independent qualified reserve evaluators to estimate area reserves for compliance with the applicable regulatory standards. We compared the current year actual production volumes, royalty obligations, operating and capital costs to those estimates used in the prior year estimate of proved reserves to assess the Company’s ability to accurately forecast. We assessed the forecasted commodity prices used in the estimate of area reserves by comparing them to those published by other reserves engineering companies. We assessed the forecasted production volumes, royalty obligations, operating and capital costs assumptions used in the estimate of area reserves by comparing them to historical results.
/s/ KPMG LLP
Chartered Professional Accountants
We have served as the Company’s auditor since 2016.
Calgary, Canada
February 28, 2024
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of Baytex Energy Corp.
Opinion on Internal Control Over Financial Reporting
We have audited Baytex Energy Corp.’s (and subsidiaries’) (the “Company”) 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. 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 Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated statements of financial position of the Company as at December 31, 2023 and 2022, the related consolidated statements of income (loss) and comprehensive income (loss), changes in equity, and cash flows for the years then ended, and the related notes (collectively, the consolidated financial statements), and our report dated February 28, 2024 expressed an unqualified opinion on those consolidated financial statements.
The Company acquired Ranger Oil Corporation during 2023, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2023, Ranger Oil Corporation’s internal control over financial reporting associated with total assets of $3.5 billion and total revenues, net of royalties, of $691.9 million included in the consolidated financial statements of the Company as of and for the year ended December 31, 2023. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Ranger Oil Corporation.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Chartered Professional Accountants
Calgary, Canada
February 28, 2024
Baytex Energy Corp.
Consolidated Statements of Financial Position
(thousands of Canadian dollars)
| | | | | | | | | | | |
| As at | Notes | December 31, 2023 | December 31, 2022 |
| | | |
| ASSETS | | | |
| Current assets | | | |
| Cash | | $ | 55,815 | | $ | 5,464 | |
| Trade receivables | 18 | 339,405 | | 222,108 | |
| Prepaids and other assets | | 21,530 | | 6,377 | |
| Financial derivatives | 18 | 23,274 | | 10,105 | |
| | 440,024 | | 244,054 | |
| Non-current assets | | | |
| | | |
| Exploration and evaluation assets | 6 | 90,919 | | 168,684 | |
| Oil and gas properties | 7 | 6,619,033 | | 4,620,766 | |
| Other plant and equipment | | 7,936 | | 6,568 | |
| Lease assets | | 28,145 | | 6,453 | |
| Prepaids and other assets | 15 | 61,729 | | — | |
| Deferred income tax asset | 15 | 213,145 | | 57,244 | |
| | $ | 7,460,931 | | $ | 5,103,769 | |
| | | |
| LIABILITIES | | | |
| Current liabilities | | | |
| Trade payables | | $ | 477,295 | | $ | 227,332 | |
| Share-based compensation liability | 12 | 28,508 | | 44,863 | |
| Dividends payable | 11,18 | 18,381 | | — | |
| | | |
| Lease obligations | | 13,391 | | 3,521 | |
| Asset retirement obligations | 10 | 20,448 | | 12,813 | |
| | 558,023 | | 288,529 | |
| Non-current liabilities | | | |
| Other long-term liabilities | | 19,147 | | — | |
| Share-based compensation liability | 12 | 7,224 | | 9,209 | |
| | | |
| Credit facilities | 8 | 848,749 | | 383,031 | |
| Long-term notes | 9 | 1,562,361 | | 547,598 | |
| Lease obligations | | 16,056 | | 3,017 | |
| Asset retirement obligations | 10 | 602,951 | | 576,110 | |
| Deferred income tax liability | 15 | 21,333 | | 265,858 | |
| | 3,635,844 | | 2,073,352 | |
| | | |
| SHAREHOLDERS’ EQUITY | | | |
| Shareholders' capital | 11 | 6,527,289 | | 5,499,664 | |
| Contributed surplus | | 193,077 | | 89,879 | |
| Accumulated other comprehensive income | | 690,917 | | 756,195 | |
| Deficit | | (3,586,196) | | (3,315,321) | |
| | 3,825,087 | | 3,030,417 | |
| | $ | 7,460,931 | | $ | 5,103,769 | |
Subsequent events (note 11 and note 18) and Commitments (note 20)
See accompanying notes to the consolidated financial statements.
| | | | | |
| /s/ Mark R. Bly | /s/ Jennifer A. Maki |
| |
| Mark R. Bly | Jennifer A. Maki |
| Director, Baytex Energy Corp. | Director, Baytex Energy Corp. |
Baytex Energy Corp.
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)
(thousands of Canadian dollars, except per common share amounts and weighted average common shares)
| | | | | | | | | | | |
| Years Ended December 31 | Notes | 2023 | | 2022 | |
| | | |
| Revenue, net of royalties | | | |
| Petroleum and natural gas sales | 14 | $ | 3,382,621 | | $ | 2,889,045 | |
| Royalties | | (669,792) | | (562,964) | |
| | 2,712,829 | | 2,326,081 | |
| | | |
| Expenses | | | |
| Operating | | 570,839 | | 422,666 | |
| Transportation | | 89,306 | | 48,561 | |
| Blending and other | | 224,802 | | 189,454 | |
| General and administrative | | 69,789 | | 50,270 | |
| Transaction costs | 4 | 49,045 | | — | |
| Exploration and evaluation | 6 | 8,896 | | 30,239 | |
| Depletion and depreciation | | 1,047,904 | | 587,050 | |
| Impairment loss (reversal) | 6, 7 | 833,662 | | (267,744) | |
| Share-based compensation | 12 | 37,699 | | 29,056 | |
| Financing and interest | 16 | 192,173 | | 104,817 | |
| Financial derivatives (gain) loss | 18 | (24,695) | | 199,010 | |
| Foreign exchange (gain) loss | 17 | (10,848) | | 43,441 | |
| Loss (gain) on dispositions | | 141,295 | | (4,898) | |
| Other (income) expense | | (456) | | 3,244 | |
| | 3,229,411 | | 1,435,166 | |
| Net (loss) income before income taxes | | (516,582) | | 890,915 | |
| Income tax (recovery) expense | 15 | | |
| Current income tax expense | | 14,403 | | 3,594 | |
| Deferred income tax (recovery) expense | | (297,629) | | 31,716 | |
| | (283,226) | | 35,310 | |
| Net (loss) income | | $ | (233,356) | | $ | 855,605 | |
| Other comprehensive (loss) income | | | |
| Foreign currency translation adjustment | | (65,278) | | 124,092 | |
| Comprehensive (loss) income | | $ | (298,634) | | $ | 979,697 | |
| | | |
| Net (loss) income per common share | 13 | | |
| Basic | | $ | (0.33) | | $ | 1.53 | |
| Diluted | | $ | (0.33) | | $ | 1.52 | |
| | | |
| Weighted average common shares | 13 | | |
| Basic | | 704,896 | | 557,986 | |
| Diluted | | 704,896 | | 563,835 | |
See accompanying notes to the consolidated financial statements.
Baytex Energy Corp.
Consolidated Statements of Changes in Equity
(thousands of Canadian dollars) | | | | | | | | | | | | | | | | | | | | |
| Notes | Shareholders’
capital | Contributed
surplus | Accumulated
other
comprehensive
income | Deficit | Total equity |
| Balance at December 31, 2021 | | $ | 5,736,593 | | $ | 13,559 | | $ | 632,103 | | $ | (4,170,926) | | $ | 2,211,329 | |
| Vesting of share awards | 11 | 8,501 | | (8,501) | | — | | — | | — | |
| Share-based compensation | 12 | — | | 3,159 | | — | | — | | 3,159 | |
| Repurchase of common shares for cancellation | | (245,430) | | 86,453 | | — | | — | | (158,977) | |
| Transfers for liability-classified awards | | — | | (4,791) | | — | | — | | (4,791) | |
| Comprehensive income | | — | | — | | 124,092 | | 855,605 | | 979,697 | |
| Balance at December 31, 2022 | | $ | 5,499,664 | | $ | 89,879 | | $ | 756,195 | | $ | (3,315,321) | | $ | 3,030,417 | |
| Issued on corporate acquisition | 4 | 1,326,435 | | 21,316 | | — | | — | | 1,347,751 | |
| Vesting of share awards | 11 | 26,229 | | (37,462) | | — | | — | | (11,233) | |
| Share-based compensation | 12 | — | | 16,237 | | — | | — | | 16,237 | |
| | | | | | |
| Repurchase of common shares for cancellation | 11 | (325,039) | | 103,107 | | — | | — | | (221,932) | |
| Dividends declared | 11 | — | | — | | — | | (37,519) | | (37,519) | |
| Comprehensive loss | | — | | — | | (65,278) | | (233,356) | | (298,634) | |
| Balance at December 31, 2023 | | $ | 6,527,289 | | $ | 193,077 | | $ | 690,917 | | $ | (3,586,196) | | $ | 3,825,087 | |
See accompanying notes to the consolidated financial statements.
Baytex Energy Corp.
Consolidated Statements of Cash Flows
(thousands of Canadian dollars)
| | | | | | | | | | | |
| Years Ended December 31 | Notes | 2023 | | 2022 | |
| | | |
| CASH PROVIDED BY (USED IN): | | | |
| Operating activities | | | |
| Net (loss) income | | $ | (233,356) | | $ | 855,605 | |
| Adjustments for: | | | |
| Non-cash share-based compensation | 12 | 16,237 | | 3,159 | |
| Unrealized foreign exchange (gain) loss | 17 | (14,300) | | 45,073 | |
| Exploration and evaluation | 6 | 8,896 | | 30,239 | |
| Depletion and depreciation | | 1,047,904 | | 587,050 | |
| Impairment loss (reversal) | 6, 7 | 833,662 | | (267,744) | |
| Non-cash financing and accretion | 16 | 32,350 | | 24,431 | |
| Non-cash other income | 10 | (1,271) | | (4,009) | |
| Unrealized financial derivatives loss (gain) | 18 | 11,517 | | (135,471) | |
| Cash premiums on derivatives | | (2,263) | | — | |
| Loss (gain) on dispositions | | 141,295 | | (4,898) | |
| Deferred income tax (recovery) expense | 15 | (297,629) | | 31,716 | |
| | | |
| Asset retirement obligations settled | 10 | (26,416) | | (18,351) | |
| Change in non-cash working capital | 19 | (220,895) | | 26,072 | |
| Cash flows from operating activities | | 1,295,731 | | 1,172,872 | |
| | | |
| Financing activities | | | |
| Increase (decrease) in credit facilities | 8 | 477,387 | | (136,980) | |
| | | |
| Decrease in acquired credit facilities | 4 | (373,608) | | — | |
| Debt issuance costs | | (40,424) | | (2,138) | |
| Payments on lease obligations | | (11,527) | | (3,732) | |
| Net proceeds from issuance of long-term notes | 9 | 1,046,197 | | — | |
| Redemption of long-term notes | 9 | — | | (376,589) | |
| Redemption of acquired long-term notes | 4 | (569,256) | | — | |
| Repurchase of common shares | 11 | (221,932) | | (158,977) | |
| Dividends declared | 11 | (37,519) | | — | |
| Change in non-cash working capital | 19 | (3,068) | | — | |
| Cash flows from (used in) financing activities | | 266,250 | | (678,416) | |
| | | |
| Investing activities | | | |
| Additions to exploration and evaluation assets | 6 | — | | (6,359) | |
| Additions to oil and gas properties | 7 | (1,012,787) | | (515,183) | |
| Additions to other plant and equipment | | (4,416) | | (1,148) | |
| Corporate acquisition, net of cash acquired | 4 | (662,579) | | — | |
| Property acquisitions | | (38,914) | | (1,352) | |
| | | |
| Proceeds from dispositions | | 160,256 | | 25,649 | |
| Change in non-cash working capital | 19 | 46,810 | | 9,401 | |
| Cash flows used in investing activities | | (1,511,630) | | (488,992) | |
| | | |
| Change in cash | | 50,351 | | 5,464 | |
| Cash, beginning of year | | 5,464 | | — | |
| Cash, end of year | | $ | 55,815 | | $ | 5,464 | |
| | | |
| Supplementary information | | | |
| Interest paid | | $ | 153,224 | | $ | 84,225 | |
| Income taxes paid | | $ | 3,603 | | $ | 2,303 | |
See accompanying notes to the consolidated financial statements.
Baytex Energy Corp.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2023 and 2022
(all tabular amounts in thousands of Canadian dollars, except per common share amounts)
1. REPORTING ENTITY
Baytex Energy Corp. (the “Company” or “Baytex”) is an energy company engaged in the acquisition, development and production of oil and natural gas in the Western Canadian Sedimentary Basin and in Texas, United States. The Company’s common shares are traded on the Toronto Stock Exchange and the New York Stock Exchange under the symbol BTE. The Company’s head and principal office is located at 2800, 520 – 3rd Avenue S.W., Calgary, Alberta, T2P 0R3, and its registered office is located at 2400, 525 – 8th Avenue S.W., Calgary, Alberta, T2P 1G1.
2. BASIS OF PREPARATION
The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board (the "IASB"). The material accounting policies set forth below were consistently applied to all periods presented.
The consolidated financial statements were approved by the Board of Directors of Baytex on February 28, 2024.
The consolidated financial statements have been prepared on a historical cost basis, with the exception of certain fair value measurements noted in the material accounting policies set forth below. The consolidated financial statements are presented in Canadian dollars which is the functional currency of the Company. References to “US$” are to United States ("U.S.") dollars. All financial information is rounded to the nearest thousand, except per share amounts or where otherwise indicated.
Certain prior year amounts have been reclassified to conform to current year presentation, including prepaids and other assets and share-based compensation liability.
Measurement Uncertainty and Judgments
Management makes judgements and assumptions about the future in deriving estimates used in preparation of these consolidated financial statements in accordance with IFRS. Sources of estimation uncertainty include estimates used to determine economically recoverable oil, natural gas, and natural gas liquids reserves, the recoverable amount of long-lived assets or cash generating units, the fair value of financial derivatives, the provision for asset retirement obligations and the provision for income taxes and the related deferred tax assets and liabilities.
The preparation of the consolidated financial statements in accordance with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets, liabilities, revenues and expenses. These judgments, estimates and assumptions are based on all relevant information available, including considerations related to various regulatory and legislative requirements, to the Company at the time of financial statement preparation. Actual results could be materially different from those estimates as the effect of future events cannot be determined with certainty. Revisions to estimates are recognized prospectively. The key areas of judgment or estimation uncertainty that have a significant risk of causing material adjustment to the reported amounts of assets, liabilities, revenues, and expenses are discussed below.
Reserves
The Company uses estimates of oil, natural gas and natural gas liquids ("NGL") reserves in the calculation of depletion, evaluating the recoverability of deferred income tax assets and in the determination of recoverable value estimates for non-financial assets. The process to estimate reserves is complex and requires significant judgment. Estimates of the Company's reserves are evaluated annually by independent qualified reserves evaluators and represent the estimated recoverable quantities of oil, natural gas and NGL reserves and the related cash flows. This evaluation of reserves is prepared in accordance with the reserves definition contained in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook.
Estimates of economically recoverable oil, natural gas and NGL reserves and the related cash flows are based on a number of factors and assumptions. Changes to estimates and assumptions such as forecasted commodity prices, production volumes, capital and operating costs and royalty obligations could have a significant impact on reported reserves. Other estimates include ultimate reserve recovery, marketability of oil and natural gas and other geological, economic and technical factors. Changes in the Company's reserves estimates can have a significant impact on the calculation of depletion, the recoverability of deferred income tax assets and in the determination of recoverable value estimates for non-financial assets.
Business Combinations
Business combinations are accounted for using the acquisition method of accounting when the assets acquired meet the definition of a business in accordance with IFRS. The determination of the fair value assigned to assets acquired and liabilities assumed requires management to make assumptions and estimates. These assumptions or estimates used in determining the fair value of assets acquired and liabilities assumed could impact the amounts assigned to assets, liabilities and goodwill. The determination of the acquisition-date fair value measurement of oil and gas properties acquired represents the largest fair value estimate which is derived from the present value of expected cash flows associated with estimated acquired proved and probable oil and gas reserves prepared by an independent qualified reserve evaluator using assumptions as outlined under "reserves", on an after-tax basis and applying a discount rate. Assumptions used to arrive at the fair value of oil and gas properties are further verified by way of market comparisons and third party sources.
Cash-generating Units ("CGUs")
The Company's oil and gas properties are aggregated into CGUs which are the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. The aggregation of assets in CGUs requires management judgment and is based on geographical proximity, shared infrastructure and similar exposure to market risk.
Identification of Impairment and Impairment Reversal Indicators
Judgment is required to assess when indicators of impairment or impairment reversal exist and when a calculation of the recoverable amount is required. The CGUs comprising oil and gas properties are reviewed at each reporting date to assess whether there is any indication of impairment or impairment reversal. These indicators can be internal such as changes in estimated proved and probable oil and gas reserves ("CGU reserves") and internally estimated oil and gas resources, or external such as market conditions impacting discount rates or market capitalization. The assessment for each CGU considers significant changes in the forecasted cash flows including reservoir performance, the number of development locations and timing of development, forecasted commodity prices, production volumes, capital and operating costs and royalty obligations.
Measurement of Recoverable Amounts
If indicators of impairment or impairment reversal are determined to exist, the recoverable amount of an asset or CGU is calculated based on the higher of value-in-use ("VIU") and fair value less cost of disposal ("FVLCD"). These calculations require the use of estimates and assumptions including cash flows associated with proved and probable oil and gas reserves and the discount rate used to present value future cash flows. Any changes to these estimates and assumptions could impact the calculation of the recoverable amount and the carrying value of assets.
Asset Retirement Obligations
The Company's provision for asset retirement obligations is based on estimated costs to abandon and reclaim the wells and the facilities, the estimated time period during which these costs will be incurred in the future, and risk-free discount rates and inflation rates. The Company uses risk-free discount rates. The provision for asset retirement obligations represents management's best estimate of the present value of the future abandonment and reclamation costs required under current regulatory requirements.
Income Taxes
Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and there are differing interpretations requiring management judgment. Income tax filings are subject to audit and re-assessment and changes in facts, circumstances and interpretations of the applicable legislative requirements may result in a material change to the Company's provision for income taxes.
Environmental Reporting Regulations
Environmental reporting for public enterprises continues to evolve and the Company may be subject to additional future disclosure requirements. The International Sustainability Standards Board has issued an IFRS Sustainability Disclosure Standard with the objective to develop a global framework for environmental sustainability disclosure. The Canadian Securities Administrators have also issued a proposed National Instrument 51-107 Disclosure of Climate-related Matters which sets forth additional reporting requirements for Canadian Public Companies. Baytex continues to monitor developments on these reporting requirements and has not yet quantified the cost to comply with these regulations.
3. MATERIAL ACCOUNTING POLICIES
Consolidation
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies to obtain benefits from its activities. Significant subsidiaries included in the Company's accounts include Baytex Energy USA, Inc., Baytex Energy Ltd. and Baytex Energy Limited Partnership. Intercompany transactions are eliminated in preparation of the consolidated financial statements.
Many of the Company's exploration, development and production activities are conducted through jointly owned assets. The consolidated financial statements include the Company's proportionate share of the assets, liabilities, revenues and expenses generated by jointly owned assets.
Revenue Recognition
Revenue from the sale of light oil and condensate, heavy oil, natural gas liquids, and natural gas is recognized based on the consideration specified in contracts with customers. Baytex recognizes revenue by unit of production and when control of the product transfers to the customer and collection is reasonably assured. This is generally at the point in time when the customer obtains legal title to the product and it is physically transferred to the customer at the agreed upon delivery point.
The nature of the Company's performance obligations, including roles of third parties and partners, are evaluated to determine if the Company acts as a principal. Baytex recognizes revenue on a gross basis when it acts as the principal and has primary responsibility for the transaction. Revenue is recognized on a net basis when Baytex acts in the capacity of an agent rather than as a principal.
The transaction price for variable price contracts is based on a representative commodity price index, and typically includes adjustments for quality, location, delivery method, or other factors depending on the agreed upon terms of the contract. The amount of revenue recorded varies depending on the grade, quality and quantities of oil or natural gas transferred to customers. Market conditions, which impact the Company's ability to negotiate certain components of the transaction price, can also cause the amount of revenue recorded to fluctuate from period to period.
Tariffs, tolls and fees charged to other entities for the use of pipelines and facilities owned by Baytex are evaluated by management to determine if these originate from contracts with customers or from incidental or collaborative arrangements. Tariffs, tolls and fees charged to other entities that are from contracts with customers are recognized in revenue when the related services are provided.
Exploration and Evaluation ("E&E") Assets
Once the legal right to explore has been acquired, costs directly associated with an exploration program are capitalized as E&E assets until results of the exploration program have been evaluated. Costs capitalized as E&E assets include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing of initial production results.
E&E expenditures are costs incurred in an area where technical feasibility and commercial viability has not yet been determined. The technical feasibility and commercial viability is dependent on whether extracting petroleum and natural gas resources is demonstrable. If the asset is determined not to be technically feasible or commercially viable the accumulated E&E assets associated with the exploration project are charged to E&E expense in the period the determination is made.
Upon determination of technical feasibility and commercial viability, as evidenced by demonstrating the ability to extract mineral resources and management's intention to develop the E&E asset, the accumulated costs associated with the exploration project are tested for impairment and transferred to oil and gas properties.
Oil and Gas Properties
Oil and gas properties are initially recorded at cost and include the costs to acquire, develop, complete geological and geophysical surveys, drill and complete wells for production, and construct and install infrastructure including wellhead equipment and processing facilities.
Oil and gas properties includes costs related to planned major inspection, overhaul and turnaround activities to maintain items of oil and gas properties and benefit future years of operations. Replacements outside of a major inspection, overhaul or turnaround are recognized as oil and gas properties when it is probable the economic benefits of the replacement will be realized by the Company in the future. The carrying amount of any replaced or disposed item of oil and gas properties is derecognized. Repair and maintenance costs incurred for servicing an item of oil and gas properties is recorded as operating expense as incurred.
Depletion
The costs associated with oil and gas properties are depleted on a unit-of-production basis by depletable area over proved and probable reserves once commercial production has commenced. Forecasted capital costs required to bring proved and probable reserves into production are included in the depletable base. For purposes of the depletion calculation, petroleum and natural gas reserves are converted to a common unit of measurement on the basis of their relative energy content where six thousand cubic feet of natural gas equates to one barrel of oil equivalent.
Impairment and Impairment Reversals
Non-financial Assets
The Company reviews its oil and gas properties and E&E assets at a CGU level for indicators of impairment and impairment reversal at the end of each reporting period. E&E assets are also assessed for impairment upon transfer to oil and gas properties. The recoverable amount of the asset is estimated if indicators of impairment or impairment reversal exist.
When reviewing for indicators of impairment or impairment reversal, and testing for impairment or impairment reversal when indicators have been identified, assets are grouped together at a CGU level. The recoverable amount of an asset or CGU is the higher of its FVLCD and its VIU. The determination of recoverable amount includes estimates of proved and probable oil and gas reserves and the associated cash flows. Factors that impact these cash flows include forecasted CGU production volumes, royalty obligations, operating costs, capital costs, commodity prices, taxes, along with inflation and discount rates used to estimate present value. FVLCD is the amount that would be obtained from the sale of an asset or CGU in an arm's length transaction. In determining FVLCD, recent comparable market transactions are considered if available. In the absence of such transactions, an appropriate valuation model is used. VIU is assessed using the present value of the estimated future cash flows of the asset or CGU. The estimated future cash flows are adjusted for risks specific to the asset or CGU and are discounted using a discount rate based on the Company’s weighted average cost of capital adjusted for risks specific to the CGU.
Where the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. The impairment reduces the carrying amount of the individual assets in the CGU on a pro-rata basis.
Impairments may be reversed for all CGUs and individual assets when there is indication that a previously recognized impairment may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. An impairment may be reversed only to the extent that the CGU’s revised carrying amount does not exceed the carrying amount that would have been determined, net of depreciation and depletion, had no impairment been recognized.
Impairments and impairment reversals are recorded in net income or loss in the period the impairment or impairment reversal occurs.
Asset Retirement Obligations
The Company recognizes asset retirement obligations when it has a legal or constructive obligation as a result of past events, it is probable that an outflow of economic resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. The Company’s asset retirement obligations are based on its net ownership in wells and facilities. Management estimates the costs to abandon and reclaim the wells and the facilities using existing technology and the estimated time period during which these costs will be incurred in the future.
Asset retirement obligations are recognized for future asset retirement costs associated with the abandonment and reclamation of the Company's E&E assets and oil and gas properties. Asset retirement obligations are measured at the present value of management's best estimate of the future cash flows required to settle the present obligation, discounted using the risk-free interest rate. The present value of the liability is capitalized as part of the cost of the related asset and depleted over its useful life. The asset retirement obligation is accreted until the date of expected settlement of the retirement obligation and is recognized within financing and interest expense in net income or loss. Changes in the future cash flow estimates resulting from revisions to the estimated timing or amount of undiscounted cash flows or the discount rates are recognized as changes in the asset retirement obligation provision and related asset at each reporting date.
Foreign Currency Translation
Foreign Transactions
Transactions completed in currencies other than the functional currency are translated into the functional currency at the exchange rates prevailing at the time of the transactions. Foreign currency assets and liabilities are translated to functional currency at the period-end exchange rate. Revenue and expenses are translated to functional currency using the average exchange rate for the period. Realized and unrealized gains and losses resulting from the settlement or translation of foreign currency transactions are included in net income or loss.
Foreign Operations
The functional currency of the Company's subsidiaries is the currency of the primary economic environment in which the entity operates. The Company's U.S. operations are conducted in USD. Management judgement is required in the designation of a subsidiary's functional currency.
The financial statements of each entity are translated into Canadian dollars during the preparation of the Company's consolidated financial statements. Refer to the Consolidation section of Note 3 for a list of the Company's entities. The assets and liabilities of a foreign operation are translated to Canadian dollars at the period-end exchange rate. Revenues and expenses of foreign operations are translated to Canadian dollars using the average exchange rate for the period. Foreign exchange differences are recognized in other comprehensive income or loss.
If the Company or any of its entities disposes of its entire interest in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the accumulated foreign currency translation gains or losses related to the foreign operation are recognized in net income or loss.
Financial Instruments
Financial assets are initially classified into two categories: measured at amortized cost or fair value through profit or loss (“FVTPL”).
The measurement category for each class of financial asset and financial liability is set forth in the following table. | | | | | |
| Financial Instrument | Classification |
| Cash | Amortized cost |
| Trade receivables | Amortized cost |
| |
| Financial derivatives | Fair value through profit or loss |
| Trade payables | Amortized cost |
| Dividends payable | Amortized cost |
| Credit facilities | Amortized cost |
| Long-term notes | Amortized cost |
Debt issuance costs related to the amendment of the Company's credit facilities or the issuance of long-term notes are capitalized and amortized as financing costs over the term of the credit facilities or long-term notes. For a financial asset or a financial liability carried at amortized cost, transaction costs directly attributable to acquiring or issuing the asset or liability are added to, or deducted from, the fair value on initial recognition and amortized through net income or loss over the term of the financial instrument. Transaction costs that are directly attributable to the acquisition or issue of a financial asset or a financial liability classified as FVTPL are expensed at inception of the contract.
The Company formally documents its risk management objectives and strategies to manage exposures to fluctuations in commodity prices, interest rates and foreign currency exchange rates. The Company has not designated its financial derivative contracts as effective accounting hedges, and therefore has not applied hedge accounting. As a result, the Company applies the fair value method of accounting for all derivative instruments. The fair values of these instruments are based on quoted market prices or, in their absence, third-party market indications and forecasts. Attributable transaction costs are recognized in net income or loss when incurred.
The Company accounts for its physical delivery sales contracts as executory contracts. These contracts are entered into and held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements. As such, these contracts are not considered to be derivative financial instruments and are not recorded at fair value on the statements of financial position. Settlements on these physical delivery sales contracts are recognized in revenue in the period the product is delivered to the sales point.
Income Taxes
Current and deferred income taxes are recognized in net income or loss, except when they relate to items that are recognized directly in equity, in which case the current and deferred taxes are also recognized directly in equity.
Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates enacted at the end of the reporting period. The Company recognizes the financial statement impact of a tax filing position when it is probable that the position will be upheld. The asset or liability is measured based on an assessment of probable outcomes and their associated probabilities.
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and the corresponding tax basis used in the computation of taxable income. Deferred income tax liabilities are generally recognized for all taxable temporary differences. Deferred income tax assets are recognized for all deductible temporary differences to the extent future recovery is probable. The carrying amount of deferred income tax assets is reviewed at the end of each reporting period and reduced or increased to the extent that it is no longer probable or becomes probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. Deferred income taxes are calculated using enacted or substantively enacted tax rates. Deferred income tax balances are adjusted for any changes in the enacted or substantively enacted tax rates and the adjustment is recognized in the period that the rate change occurs.
Tax regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and there are differing interpretations requiring management judgment. Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in future periods, which requires management judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future periods, which requires management judgment. Income tax filings are subject to audit and re-assessment and changes in facts, circumstances and interpretations of the standards may result in a material change to the Company's provision for income taxes.
New Accounting Standards Adopted
In 2023, Baytex adopted amendments to IAS 12 Income Taxes regarding relief from deferred tax accounting for top-up tax under Pillar Two. Pillar Two refers to a minimum 15% tax rate on the income generated by multinational corporations in the jurisdictions in which they operate. Baytex applies the exception to recognizing and disclosing information about deferred taxes related to Pillar Two income taxes, as provided in the amendments to IAS 12 issued in May 2023. This amendment did not have a material impact on our consolidated financial statements.
Baytex has adopted amendments to IAS 1 Presentation of Financial Statements regarding the disclosure of material accounting policies, effective January 1, 2023. This amendment was disclosure related and did not impact the Company's accounting policies.
Future Accounting Pronouncements
Effective January 1, 2024, Baytex plans to adopt amendments to IAS 1 Presentation of Financial Statements which was issued by the IASB in January 2020. The amendments further clarify the requirements for the presentation of liabilities as current or non-current in the consolidated statements of financial position.
In October 2022, the IASB issued Non-current Liabilities with Covenants which amended IAS 1 Presentation of Financial Statements. The amendments specify the classification and disclosure of a liability with covenants and is effective January 1, 2024.
These amendments are not expected to have a material impact on our consolidated financial statements.
4.BUSINESS COMBINATION
On June 20, 2023, Baytex closed the acquisition of Ranger Oil Corporation (“Ranger”), a publicly traded oil and gas exploration and production company with operations in the Eagle Ford. Baytex acquired all of the issued and outstanding common shares of Ranger and is treated as the acquirer for accounting purposes. The acquisition increases Baytex's Eagle Ford scale and provides an operating platform to effectively allocate capital across the Western Canadian Sedimentary Basin and the Eagle Ford.
The acquisition was accounted for as a business combination with the net assets and liabilities recorded at fair value at the acquisition date. The total consideration of US$1.6 billion ($2.1 billion) consisted of $732.8 million of cash consideration and 311.4 million Baytex common shares valued at approximately $1.3 billion (based on the closing price of Baytex’s common shares of $4.26 per share on the Toronto Stock Exchange on June 20, 2023). Under the terms of the agreement, Ranger shareholders received 7.49 Baytex shares plus US$13.31 cash for each share of Ranger common stock.
The fair value of oil and gas properties acquired is primarily based on estimated cash flows associated with proved and probable oil and gas reserves acquired and the discount rate. Factors that impact these reserves cash flows include forecasted production volumes, royalty obligations, operating and capital costs, taxes and commodity prices. The estimation of reserves cash flows involves the expertise of the independent qualified reserve evaluators. Any changes to these estimates and assumptions could impact the calculation of the recoverable amount and the carrying value of assets. The fair value of the acquired oil and gas properties were determined using a discount rate of 12.2%.
Asset retirement obligations were determined using internal estimates of the timing and estimated costs associated with the abandonment and reclamation of the wells and facilities acquired using a market rate of interest of 9.0%.
The total consideration paid and estimates of the fair value of the assets and liabilities acquired as at the date of the acquisition are set forth in the table below. The preliminary purchase price equation is based on Management's best estimate of the assets acquired and liabilities assumed. Adjustments to these initial estimates may be required upon finalizing the value of net assets acquired.
| | | | | | | | |
| USD | CAD (1) |
| Consideration | | |
| Cash | $ | 553,150 | | $ | 732,840 | |
| Common shares issued | 1,001,196 | | 1,326,435 | |
Share based compensation (2) | 20,107 | | 26,638 | |
| Total consideration | $ | 1,574,453 | | $ | 2,085,913 | |
| | |
| Fair value of net assets acquired | | |
Oil and gas properties (3) | $ | 2,337,173 | | $ | 3,096,404 | |
Working capital deficiency excluding bank debt and financial derivatives (3)(4) | (120,565) | | (159,731) | |
| Financial derivatives | 17,030 | | 22,562 | |
| Lease assets | 15,708 | | 20,811 | |
| Lease obligations | (15,708) | | (20,811) | |
| Credit facilities | (282,000) | | (373,608) | |
| Long-term notes | (429,676) | | (569,256) | |
| Asset retirement obligations | (23,632) | | (31,310) | |
Deferred income tax asset (3) | 76,123 | | 100,852 | |
| Net assets acquired | $ | 1,574,453 | | $ | 2,085,913 | |
(1)Exchange rate used to translate the U.S. denominated values above is the rate as at the closing date being CAD/USD 1.32485.
(2)Following closing of the transaction, holders of awards outstanding under Ranger's share based compensation plans are entitled to Baytex common shares rather than Ranger common shares with adjustment to the quantity outstanding based on the exchange ratio for Ranger shares. The fair value of share awards allocated to consideration was based on the service period that had occurred prior to the acquisition date while the remaining fair value of the share awards assumed by Baytex will be recognized over the remaining future service periods (note 12). Included in this balance is $21.3 million (US$16.1 million) of awards that were fully vested at close of the Ranger acquisition and $5.3 million (US$4.0 million) of cash-based awards included in share-based compensation liability.
(3)Adjustments were recorded to the preliminary fair value to reflect circumstances that existed as at the acquisition date. These adjustments relate to an update in operating results which increased our working capital deficiency by $16.4 million (US$12.4 million) with an offset to oil and gas properties and an increase in the deferred income tax asset of $1.6 million (US$1.2 million) as a result.
(4)Includes $70.3 million (US$53.0 million) of cash. Trade receivables acquired is net of a provision for expected credit losses of approximately $0.3 million.
The cash portion of the transaction was funded with Baytex’s expanded credit facility which increased to US$1.1 billion at close of the transaction, US$150 million from a two-year term loan facility, and the net proceeds from the issuance of US$800 million senior unsecured notes due 2030. Baytex closed the US$800 million, senior unsecured note offering on April 27, 2023 and the net proceeds were released from escrow on June 20, 2023.
These consolidated financial statements include the results of operations of Ranger for the period following closing of the transaction on June 20, 2023. For the year ended December 31, 2023, the acquisition contributed revenues and net income before income taxes of $939.4 million and $165.1 million, respectively. Had the acquisition occurred on January 1, 2023, revenues and net income before income taxes would have increased by approximately $1.7 billion and $366.7 million, respectively, for the year ended December 31, 2023. This pro-forma information is not necessarily indicative of the results of operations that would have resulted had the acquisition been reflected on the dates indicated, or that may be obtained in the future.
During the year ended December 31, 2023, Baytex incurred transaction costs of $49.0 million. Transaction costs include consulting, advisory fees, legal fees, tax fees and other professional fees of $41.7 million, as well as post-combination employee-related costs of $7.3 million.
5. SEGMENTED FINANCIAL INFORMATION
Baytex's reportable segments are determined based on the geographic location and nature of the underlying operations:
•Canada includes the exploration for, and the development and production of, crude oil and natural gas in Western Canada;
•U.S. includes the exploration for, and the development and production of, crude oil and natural gas in the U.S.; and
•Corporate includes corporate activities and items not allocated between operating segments.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Canada | U.S. | Corporate | Consolidated |
| Years Ended December 31 | 2023 | | 2022 | 2023 | | 2022 | 2023 | | 2022 | 2023 | | 2022 |
| | | | | | | | |
| Revenue, net of royalties | | | | | | | | |
| Petroleum and natural gas sales | $ | 1,729,021 | | $ | 1,926,561 | | $ | 1,653,600 | | $ | 962,484 | | $ | — | | $ | — | | $ | 3,382,621 | | $ | 2,889,045 | |
| Royalties | (213,148) | | (277,428) | | (456,644) | | (285,536) | | — | | — | | (669,792) | | (562,964) | |
| 1,515,873 | | 1,649,133 | | 1,196,956 | | 676,948 | | — | | — | | 2,712,829 | | 2,326,081 | |
| | | | | | | | |
| Expenses | | | | | | | | |
| Operating | 368,605 | | 327,894 | | 202,234 | | 94,772 | | — | | — | | 570,839 | | 422,666 | |
| Transportation | 64,325 | | 48,561 | | 24,981 | | — | | — | | — | | 89,306 | | 48,561 | |
| Blending and other | 224,802 | | 189,454 | | — | | — | | — | | — | | 224,802 | | 189,454 | |
| General and administrative | — | | — | | — | | — | | 69,789 | | 50,270 | | 69,789 | | 50,270 | |
| Transaction costs | — | | — | | — | | — | | 49,045 | | — | | 49,045 | | — | |
| Exploration and evaluation | 8,896 | | 30,239 | | — | | — | | — | | — | | 8,896 | | 30,239 | |
| Depletion and depreciation | 484,232 | | 409,286 | | 555,548 | | 171,747 | | 8,124 | | 6,017 | | 1,047,904 | | 587,050 | |
| Impairment loss (reversal) | 184,000 | | (267,744) | | 649,662 | | — | | — | | — | | 833,662 | | (267,744) | |
| Share-based compensation | — | | — | | — | | — | | 37,699 | | 29,056 | | 37,699 | | 29,056 | |
| Financing and interest | — | | — | | — | | — | | 192,173 | | 104,817 | | 192,173 | | 104,817 | |
| Financial derivatives (gain) loss | — | | — | | — | | — | | (24,695) | | 199,010 | | (24,695) | | 199,010 | |
| Foreign exchange (gain) loss | — | | — | | — | | — | | (10,848) | | 43,441 | | (10,848) | | 43,441 | |
| Loss (gain) on dispositions | 141,295 | | (4,898) | | — | | — | | — | | — | | 141,295 | | (4,898) | |
| Other (income) expense | (1,271) | | (4,009) | | — | | — | | 815 | | 7,253 | | (456) | | 3,244 | |
| 1,474,884 | | 728,783 | | 1,432,425 | | 266,519 | | 322,102 | | 439,864 | | 3,229,411 | | 1,435,166 | |
| Net income (loss) before income taxes | 40,989 | | 920,350 | | (235,469) | | 410,429 | | (322,102) | | (439,864) | | (516,582) | | 890,915 | |
| Income tax (recovery) expense | | | | | | | | |
| Current income tax expense | | | | | | | 14,403 | | 3,594 | |
| Deferred income tax (recovery) expense | | | | | | | (297,629) | | 31,716 | |
| | | | | | | (283,226) | | 35,310 | |
| Net income (loss) | $ | 40,989 | | $ | 920,350 | | $ | (235,469) | | $ | 410,429 | | $ | (322,102) | | $ | (439,864) | | $ | (233,356) | | $ | 855,605 | |
| | | | | | | | |
| Additions to exploration and evaluation assets | — | | 6,359 | | — | | — | | — | | — | | — | | 6,359 | |
| Additions to oil and gas properties | 463,198 | | 374,443 | | 549,589 | | 140,740 | | — | | — | | 1,012,787 | | 515,183 | |
| Corporate acquisition, net of cash acquired | — | | — | | 662,579 | | — | | — | | — | | 662,579 | | — | |
| Property acquisitions | 20,023 | | 1,352 | | 18,891 | | — | | — | | — | | 38,914 | | 1,352 | |
| Proceeds from dispositions | (160,256) | | (25,649) | | — | | — | | — | | — | | (160,256) | | (25,649) | |
| | | | | | | | |
| As at | December 31, 2023 | December 31, 2022 |
| Canadian assets | $ | 2,289,083 | | $ | 2,779,596 | |
| U.S. assets | 5,112,493 | | 2,301,047 | |
| Corporate assets | 59,355 | | 23,126 | |
| Total consolidated assets | $ | 7,460,931 | | $ | 5,103,769 | |
6. EXPLORATION AND EVALUATION ASSETS
| | | | | | | | |
| December 31, 2023 | December 31, 2022 |
| Balance, beginning of year | $ | 168,684 | | $ | 172,824 | |
| Capital expenditures | — | | 6,359 | |
| | |
| Property acquisitions | 18,486 | | 301 | |
| Divestitures | (2,965) | | (498) | |
| Property swaps | 1,000 | | 385 | |
| Impairment reversal | — | | 22,503 | |
| Exploration and evaluation expense | (8,896) | | (30,239) | |
| Transfers to oil and gas properties (note 7) | (83,530) | | (8,496) | |
| Foreign currency translation | (1,860) | | 5,545 | |
| Balance, end of year | $ | 90,919 | | $ | 168,684 | |
At December 31, 2023, there were no indicators of impairment or impairment reversal for exploration and evaluation assets in any of the Company's CGUs.
At December 31, 2022, the Company identified indicators of impairment reversal for the exploration and evaluation assets within the Peace River CGU due to an increase in land sale values. The recoverable amount for the Peace River CGU exceeded its carrying value and an impairment reversal of $22.5 million was recorded at December 31, 2022. The recoverable amount was based on the CGUs FVLCD and was estimated with reference to arm's length transactions in comparable locations.
7. OIL AND GAS PROPERTIES
| | | | | | | | | | | |
| Cost | Accumulated
depletion | Net book value |
| Balance, December 31, 2021 | $ | 11,633,517 | | $ | (7,169,146) | | $ | 4,464,371 | |
| Capital expenditures | 515,183 | | — | | 515,183 | |
| | | |
| Property acquisitions | 1,173 | | — | | 1,173 | |
| Transfers from exploration and evaluation assets (note 6) | 8,496 | | — | | 8,496 | |
| Change in asset retirement obligations (note 10) | (147,020) | | — | | (147,020) | |
| Divestitures | (265,166) | | 241,892 | | (23,274) | |
| | | |
| Impairment reversal | — | | 245,241 | | 245,241 | |
| Foreign currency translation | 296,033 | | (158,404) | | 137,629 | |
| Depletion | — | | (581,033) | | (581,033) | |
| Balance, December 31, 2022 | $ | 12,042,216 | | $ | (7,421,450) | | $ | 4,620,766 | |
| Capital expenditures | 1,012,787 | | — | | 1,012,787 | |
| Corporate acquisition (note 4) | 3,096,404 | | — | | 3,096,404 | |
| Property acquisitions | 20,263 | | — | | 20,263 | |
| Transfers from exploration and evaluation assets (note 6) | 83,530 | | — | | 83,530 | |
| Transfers from lease assets | 7,611 | | — | | 7,611 | |
| Change in asset retirement obligations (note 10) | 54,166 | | — | | 54,166 | |
| Divestitures | (660,920) | | 317,651 | | (343,269) | |
| Property swaps | (2,975) | | 3,756 | | 781 | |
| Impairment loss | — | | (833,662) | | (833,662) | |
| Foreign currency translation | (127,065) | | 66,501 | | (60,564) | |
| Depletion | — | | (1,039,780) | | (1,039,780) | |
| Balance, December 31, 2023 | $ | 15,526,017 | | $ | (8,906,984) | | $ | 6,619,033 | |
At December 31, 2023, there were no indicators of impairment or impairment reversal for oil and gas properties in five CGUs and no impairment testing was required, including for the Eagle Ford Operated CGU which includes the assets acquired from Ranger (note 4).
2023 Impairment
At December 31, 2023, the Company identified indicators of impairment for oil and gas properties in two CGUs due to changes in reserves volumes and a loss recorded on a disposition of an asset within an existing CGU. The recoverable amounts for the two CGUs were not sufficient to support their carrying values which resulted in an impairment of $833.7 million recorded at December 31, 2023. The recoverable amount for each CGU is based on estimated cash flows associated with proved and probable oil and gas reserves from an independent reserve report prepared as at December 31, 2023 utilizing a discount rate based on Baytex's corporate weighted average cost of capital adjusted for asset specific factors. The after-tax discount rates applied to the cash flows were between 12% and 14%.
At December 31, 2023, the recoverable amounts of the two CGUs were calculated using the following benchmark reference prices for the years 2024 to 2033 adjusted for commodity differentials specific to the CGU. The prices and costs subsequent to 2033 have been adjusted for inflation at an annual rate of 2.0%.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2024 | 2025 | 2026 | 2027 | 2028 | 2029 | 2030 | 2031 | 2032 | 2033 |
| WTI crude oil (US$/bbl) | 73.67 | | 74.98 | | 76.14 | | 77.66 | | 79.22 | | 80.80 | | 82.42 | | 84.06 | | 85.74 | | 87.46 | |
| | | | | | | | | | |
| LLS crude oil (US$/bbl) | 76.49 | | 77.80 | | 78.95 | | 80.35 | | 81.95 | | 83.59 | | 85.27 | | 86.97 | | 88.71 | | 90.48 | |
| Edmonton par oil ($/bbl) | 92.91 | | 95.04 | | 96.07 | | 97.99 | | 99.95 | | 101.94 | | 103.98 | | 106.06 | | 108.18 | | 110.35 | |
| NYMEX Henry Hub gas (US$/mmbtu) | 2.75 | | 3.64 | | 4.02 | | 4.10 | | 4.18 | | 4.27 | | 4.35 | | 4.44 | | 4.53 | | 4.62 | |
| AECO gas ($/mmbtu) | 2.20 | | 3.37 | | 4.05 | | 4.13 | | 4.21 | | 4.30 | | 4.38 | | 4.47 | | 4.56 | | 4.65 | |
| Exchange rate (CAD/USD) | 0.75 | | 0.75 | | 0.76 | | 0.76 | | 0.76 | | 0.76 | | 0.76 | | 0.76 | | 0.76 | | 0.76 | |
The following table summarizes the recoverable amount and impairment for each of the two CGUs at December 31, 2023 and demonstrates the sensitivity of the impairment to reasonably possible changes in key assumptions inherent in the calculation.
| | | | | | | | | | | | | | | | | |
| Recoverable amount | Impairment loss | Change in discount rate of 1% | Change in oil price of $2.50/bbl | Change in gas price of $0.25/mcf |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Viking CGU | $ | 606,290 | | $ | 184,000 | | $ | 26,500 | | $ | 53,000 | | $ | 3,500 | |
Eagle Ford Non-op CGU (1) | 1,429,658 | | 649,662 | | 71,300 | | 107,600 | | 25,700 | |
| | | | | |
(1)There were no indicators of impairment identified for the Eagle Ford Operated CGU which includes the assets acquired from Ranger (note 4).
2022 Impairment Reversal
At December 31, 2022, indicators of impairment reversal were identified for oil and gas properties in five CGUs due to the increase in forecasted commodity prices in addition to changes in reserves volumes. The recoverable amount for three CGUs exceeded their carrying values which resulted in an impairment reversal of $245.2 million recorded at December 31, 2022. The recoverable amount for each CGU is based on estimated cash flows associated with proved and probable oil and gas reserves from an independent reserve report prepared as at December 31, 2022 with a discount rate based on Baytex's corporate weighted average cost of capital adjusted for asset specific factors. The after-tax discount rates applied to the cash flows were between 12% and 23%.
The following table summarizes the recoverable amount and impairment reversal for each of the five CGUs at December 31, 2022 and demonstrates the sensitivity of the impairment reversal to reasonably possible changes in key assumptions inherent in the calculation.
| | | | | | | | | | | | | | | | | |
| Recoverable amount | Impairment
reversal | Change in discount rate of 1% | Change in oil price of $2.50/bbl | Change in gas price of $0.25/mcf |
Conventional CGU (1) | $ | 119,031 | | $ | 23,707 | | $ | — | | $ | — | | $ | — | |
Peace River CGU (1) | 676,939 | | 140,534 | | — | | — | | — | |
| Lloydminster CGU | 449,250 | | — | | 11,500 | | 53,000 | | — | |
| | | | | |
| Viking CGU | 1,322,193 | | 81,000 | | 39,500 | | 78,000 | | 4,000 | |
| Eagle Ford Non-op CGU | 2,102,646 | | — | | 95,800 | | 131,100 | | 28,500 | |
| | | | | |
(1)The impairment reversals for the Conventional and Peace River CGUs were limited to the total accumulated impairments less subsequent depletion of $23.7 million and $140.5 million, respectively. As a result, changes in the key assumptions presented in the table above have no impact on the amount of the impairment reversal as at December 31, 2022.
8. CREDIT FACILITIES
| | | | | | | | |
| December 31, 2023 | December 31, 2022 |
Credit facilities - U.S. dollar denominated (1) | $ | 311,980 | | $ | 30,394 | |
| Credit facilities - Canadian dollar denominated | 552,756 | | 355,000 | |
Credit facilities - principal (2) | $ | 864,736 | | $ | 385,394 | |
| Unamortized debt issuance costs | (15,987) | | (2,363) | |
| Credit facilities | $ | 848,749 | | $ | 383,031 | |
(1)U.S. dollar denominated credit facilities balance was US$236.3 million as at December 31, 2023 (December 31, 2022 - US$22.5 million).
(2)The increase in the principal amount of the credit facilities outstanding from December 31, 2022 to December 31, 2023 is the result of net draws of $477.4 million along with an increase in the reported amount of U.S. denominated debt of $2.0 million due to foreign exchange.
At December 31, 2023, Baytex had US$1.1 billion ($1.5 billion) of revolving credit facilities (the "Credit Facilities"). On June 20, 2023, in connection with the acquisition of Ranger, Baytex amended its Credit Facilities to increase the committed amount to $1.1 billion ($1.5 billion) (previously US$850 million in aggregate as of April 1, 2022). The maturity date of the Credit Facilities is April 1, 2026. Baytex also entered into a secured two-year term loan of US$150 million that was repaid and cancelled in August 2023.
The Credit Facilities are secured and are comprised of a US$50 million operating loan and a US$750 million syndicated revolving loan for Baytex and a US$45 million operating loan and a US$255 million syndicated revolving loan for Baytex's wholly-owned subsidiary, Baytex Energy USA, Inc. The amended Credit Facilities contain an additional financial covenant of a maximum Total Debt to Bank EBITDA ratio of 4.0:1.0 and increased the Interest Coverage minimum ratio to 3.5:1.0 (from 2.0:1.0).
The Credit Facilities contain standard commercial covenants in addition to the financial covenants detailed below. There are no mandatory principal payments required prior to maturity which could be extended by Baytex. Advances under the Credit Facilities can be drawn in either Canadian or U.S. funds and bear interest at the bank’s prime lending rate, bankers’ acceptance discount rates or secured overnight financing rates ("SOFR"), plus applicable margins.
The weighted average interest rate on the Credit Facilities was 7.6% for the year ended December 31, 2023 (3.6% for the year ended December 31, 2022).
The following table summarizes the financial covenants applicable to the Credit Facilities and the Company's compliance therewith at December 31, 2023.
| | | | | | | | |
| Covenant Description | Position as at December 31, 2023 | Covenant |
Senior Secured Debt (1) to Bank EBITDA (2) (Maximum Ratio) | 0.4:1.0 | 3.5:1.0 |
Interest Coverage (3) (Minimum Ratio) | 11.3:1.0 | 3.5:1.0 |
Total Debt (4) to Bank EBITDA (2) (Maximum Ratio) | 1.1:1.0 | 4.0:1.0 |
(1)"Senior Secured Debt" is calculated in accordance with the credit facility agreement and is defined as the principal amount of the Credit Facilities and other secured obligations identified in the credit facility agreement. As at December 31, 2023, the Company's Senior Secured Debt totaled $864.7 million.
(2)"Bank EBITDA" is calculated based on terms and definitions set out in the credit facility agreement which adjusts net income or loss for financing and interest expenses, income tax, non-recurring losses, certain specific unrealized and non-cash transactions and is calculated based on a trailing twelve-month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Bank EBITDA for the year ended December 31, 2023 was $2.2 billion.
(3)"Interest coverage" is calculated in accordance with the credit facility agreement and is computed as the ratio of Bank EBITDA to financing and interest expenses, excluding certain non-cash transactions, and is calculated on a trailing twelve-month basis including the impact of material acquisitions as if they had occurred at the beginning of the twelve month period. Financing and interest expenses for the year ended December 31, 2023 was $195.2 million.
(4)"Total Debt" is calculated in accordance with the credit facility agreement and is defined as all obligations, liabilities, and indebtedness of Baytex excluding trade payables, share-based compensation liability, dividends payable, asset retirement obligations, leases, deferred income tax liabilities, other long-term liabilities and financial derivative liabilities. As at December 31, 2023, the Company's Total Debt totaled $2.5 billion of principal amounts outstanding.
At December 31, 2023, Baytex had $5.6 million of outstanding letters of credit, $4.7 million of which is under a $20 million uncommitted unsecured demand revolving letter of credit facility (December 31, 2022 - $15.7 million outstanding). Letters of credit under this facility are guaranteed by Export Development Canada and do not use capacity available under the Credit Facilities.
9. LONG-TERM NOTES | | | | | | | | |
| December 31, 2023 | December 31, 2022 |
8.75% notes due April 1, 2027 (1) | $ | 541,114 | | $ | 554,597 | |
8.50% notes due April 30, 2030 (2) | 1,056,361 | | — | |
Total long-term notes - principal (3) | $ | 1,597,475 | | $ | 554,597 | |
| Unamortized debt issuance costs | (35,114) | | (6,999) | |
| Total long-term notes - net of unamortized debt issuance costs | $ | 1,562,361 | | $ | 547,598 | |
(1)The U.S. dollar denominated principal outstanding of the 8.75% notes was US$409.8 million at December 31, 2023 (December 31, 2022 - US$409.8 million).
(2)The U.S. dollar denominated principal outstanding of the 8.50% notes was US$800.0 million at December 31, 2023 (December 31, 2022 - nil).
(3)The increase in the principal amount of long-term notes outstanding from December 31, 2022 to December 31, 2023 is the result of the issuance of the 8.50% notes for $1.1 billion and includes changes in the reported amount of U.S. denominated debt of $17.0 million due to changes in the CAD/USD exchange rate used to translate the U.S. denominated amount of long-term notes outstanding.
On April 27, 2023, we issued US$800 million aggregate principal amount of senior unsecured notes due April 30, 2030 bearing interest at a rate of 8.50% per annum semi-annually (the "8.50% Senior Notes"). The 8.50% Senior Notes were issued at 98.709% of par and are redeemable at our option, in whole or in part, at specified redemption prices after April 30, 2026 and will be redeemable at par from April 30, 2028 to maturity. Net proceeds of $1.0 billion reflects $13.7 million for the original issue discount and Baytex also incurred transaction costs of $18.5 million in conjunction with the issuance.
The long-term notes do not contain any significant financial maintenance covenants but do contain standard commercial covenants for debt incurrence and restricted payments.
10. ASSET RETIREMENT OBLIGATIONS
| | | | | | | | |
| December 31, 2023 | December 31, 2022 |
| Balance, beginning of year | $ | 588,923 | | $ | 743,683 | |
Liabilities incurred (1) | 24,185 | | 19,942 | |
| Liabilities settled | (26,416) | | (18,351) | |
| Liabilities assumed from corporate acquisition (note 4) | 31,310 | | — | |
| Liabilities acquired from property acquisitions | 11 | | 950 | |
| Liabilities divested | (43,153) | | (3,464) | |
| Property swaps | 76 | | — | |
| Accretion (note 16) | 20,406 | | 15,683 | |
Government grants (2) | (1,271) | | (4,009) | |
Change in estimate (1) | 17,067 | | 6,124 | |
Changes in discount rates and inflation rates (1)(3) | 12,914 | | (173,086) | |
| Foreign currency translation | (653) | | 1,451 | |
| Balance, end of year | $ | 623,399 | | $ | 588,923 | |
| Less current portion of asset retirement obligations | 20,448 | | 12,813 | |
| Non-current portion of asset retirement obligations | $ | 602,951 | | $ | 576,110 | |
(1)The total of these items reflects the total change in asset retirement obligations of $54.2 million per Note 7 - Oil and Gas Properties ($147 million decrease in 2022).
(2)During 2023, Baytex recognized $1.3 million of non-cash other income and a reduction in asset retirement obligations related to government grants provided by the Government of Alberta and the Government of Saskatchewan ($4.0 million in 2022).
(3)The discount and inflation rates used to calculate the liability for our Canadian operations at December 31, 2023 were 3.0% and 1.6% respectively (December 31, 2022 - 3.3% and 2.1%). The discount and inflation rates used to calculate the liability for our U.S. operations at December 31, 2023 were 4.0% and 2.1%, respectively (December 31, 2022 - 3.3% and 2.1%). The changes in discount rates also includes the remeasurement of the liability acquired from Ranger from a market rate of interest on the date of acquisition to a risk-free rate at period end.
At December 31, 2023, the undiscounted, uninflated amount of estimated cash flows required to settle the asset retirement obligations is $795.5 million (December 31, 2022 - $724.8 million). The discounted amount of estimated cash flow required to settle the asset retirement obligations at December 31, 2023 is $623.4 million (December 31, 2022 - $588.9 million). This was calculated using an estimated inflation rate of 1.6% and 2.1% for Canadian and U.S. operations, respectively (December 31, 2022 - 2.1%) and a risk-free discount rate of 3.0% and 4.0% for Canadian and U.S. operations, respectively (December 31, 2022 - 3.3%). These costs are expected to be incurred over the next 60 years.
11. SHAREHOLDERS' CAPITAL
The authorized capital of Baytex consists of an unlimited number of common shares without nominal or par value and 10.0 million preferred shares without nominal or par value, issuable in series. Baytex establishes the rights and terms of the preferred shares upon issuance. As at December 31, 2023, no preferred shares have been issued by the Company and all common shares issued were fully paid. The holders of common shares may receive dividends as declared from time to time and are entitled to one vote per share at any meeting of the holders of common shares. All common shares rank equally with regard to the Company's net assets in the event the Company is wound-up or terminated.
| | | | | | | | |
| Number of Common Shares (000s) | Amount |
| Balance, December 31, 2021 | 564,213 | | $ | 5,736,593 | |
| Vesting of share awards | 5,035 | | 8,501 | |
| Common shares repurchased and cancelled | (24,318) | | (245,430) | |
| | |
| | |
| Balance, December 31, 2022 | 544,930 | | $ | 5,499,664 | |
| Issued on corporate acquisition (note 4) | 311,370 | | 1,326,435 | |
| Vesting of share awards | 5,892 | | 26,229 | |
| Common shares repurchased and cancelled | (40,511) | | (325,039) | |
| | |
| Balance, December 31, 2023 | 821,681 | | $ | 6,527,289 | |
Normal Course Issuer Bid ("NCIB") Share Repurchases
On June 23, 2023, Baytex announced the acceptance from the Toronto Stock Exchange ("TSX") for renewal of the NCIB under which Baytex is permitted to purchase for cancellation 68.4 million common shares over the 12-month period commencing June 29, 2023. The number of shares authorized for repurchase represents 10% of the Company's 856.9 million common shares outstanding as at June 21, 2023.
Purchases are made on the open market at prices prevailing at the time of the transaction. During the year ended December 31, 2023, Baytex repurchased and cancelled 40.5 million common shares at an average price of $5.48 per share for total consideration of $221.9 million. During 2022, Baytex repurchased and cancelled 24.3 million common shares at an average price of $6.54 per share for total consideration of $159.0 million. The total consideration paid includes the commissions and fees paid as part of the transaction and is recorded as a reduction to shareholders' equity. The shares repurchased and cancelled are accounted for as a reduction in shareholders' capital at historical cost, with any discount paid recorded to contributed surplus and any premium paid recorded to retained earnings.
Dividends
In November 2023, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share which was paid on January 2, 2024 for shareholders of record as at December 15, 2023. On February 28, 2024, the Company's Board of Directors declared a quarterly cash dividend of $0.0225 per share to be paid on April 1, 2024 for shareholders on record as at March 15, 2024.
The following dividends were declared by Baytex during the year ended December 31, 2023:
| | | | | | | | | | | |
| Record Date | Payable Date | Per Share Amount | Dividend Amount |
| September 15, 2023 | October 2, 2023 | $0.0225 | $ | 19,138 | |
| December 15, 2023 | January 2, 2024 | $0.0225 | 18,381 | |
| Total dividends declared | $ | 37,519 | |
12. SHARE-BASED COMPENSATION PLAN
For the year ended December 31, 2023, the Company recorded total share-based compensation expense of $37.7 million ($29.1 million for the year ended December 31, 2022) which is comprised of $16.2 million of non-cash expense related to awards assumed in the acquisition of Ranger which were settled with Baytex common shares after closing of the business combination. Total share-based compensation expense for the year ended December 31, 2023 also includes the $21.5 million related to cash-settled awards and the associated equity total return swaps ($25.9 million for the year ended December 31, 2022).
The Company's closing share price on December 31, 2023 was $4.38 (December 31, 2022 - $6.08).
Share Award Incentive Plan
The Company has a full-value award plan (the "Share Award Incentive Plan") pursuant to which restricted awards and performance awards (collectively, "Share Awards") may be granted to directors, officers and employees of the Company and its subsidiaries. Pursuant to the Share Award Incentive Plan, Baytex has the option to settle amounts payable related to Share Awards in cash on the settlement date. The maximum number of common shares issuable under the Share Award Incentive Plan (and any other long-term incentive plans of the Company) shall not exceed 3.8% of the then-issued and outstanding common shares.
A restricted award entitles the holder of each award to receive one common share of Baytex or the equivalent cash value at the time of vesting. A performance award entitles the holder of each award to receive between zero and two common shares or the cash equivalent value on vesting; the number of common shares issued is determined by a performance multiplier. The multiplier can range between zero and two and is calculated based on a number of factors determined and approved by the Board of Directors on an annual basis. The multiplier is dependent on the performance of the Company relative to predefined corporate performance measures for a particular period. The number Share Awards is adjusted to account for the payment of dividends from the grant date to the applicable issue date. The Share Awards vest in equal tranches on the first, second and third anniversaries of the grant date. The cumulative expense is recognized at fair value at each period end and is included in share-based compensation liability.
When Share Awards are accounted for as equity-settled, share-based compensation expense is determined using the fair value of the Share Awards on the grant date which is based on quoted market prices for the Company's common shares. Share Awards vest in equal tranches on the first, second and third anniversaries of the grant date and are expensed over the vesting period using the graded vesting method, with a corresponding increase to contributed surplus. On the vest date, the associated contributed surplus is recognized in shareholders' capital.
In 2022, the Company received approval from its Board of Directors to settle the existing Share Awards with cash under the terms of the Share Award Incentive Plan. As a result, Baytex recognized the fair value of the liability for amortized unvested Share Awards in share-based compensation liability. For the year-ended December 31, 2022, the fair value of the liability recognized exceeded the amount previously recognized in contributed surplus of $4.8 million and the excess was recognized as share-based compensation expense in the period.
Liabilities associated with cash-settled awards are determined based on the fair value of the award at grant date and are subsequently revalued at each period end until the date of settlement. This valuation incorporates the period-end share price, the number of awards outstanding at each period end, and certain management estimates, such as estimated forfeitures and performance multiplier, if applicable. Share-based compensation expense related to cash-settled awards is recognized in the consolidated statements of income (loss) and comprehensive income (loss) over the relevant service period with a corresponding increase or decrease in share-based compensation liability. Classification of the associated short-term and long-term liabilities is dependent on the expected payout dates of the individual awards.
On June 20, 2023, Baytex became the successor to Ranger's Share Award Plan (note 4). Although no new grants will be made under the Ranger Share Award Plan, awards that were outstanding at June 20, 2023 were converted to restricted awards that will be settled in shares of Baytex or with cash, with the quantity outstanding adjusted based on the exchange ratio for the business combination with Ranger.
The weighted average fair value of Share Awards granted during the year ended December 31, 2023 was $5.40 per restricted and performance award ($6.08 for the year ended December 31, 2022).
The number of Share Awards outstanding is detailed below: | | | | | | | | | | | |
| (000s) | Number of
restricted awards | Number of
performance awards | Total number of
Share Awards |
| Balance, December 31, 2021 | 2,093 | | 7,381 | | 9,474 | |
| Granted | 68 | | 1,391 | | 1,459 | |
| | | |
| Vested | (1,377) | | (3,630) | | (5,007) | |
| Forfeited | (22) | | (346) | | (368) | |
| Balance, December 31, 2022 | 762 | | 4,796 | | 5,558 | |
| Granted | 41 | | 2,641 | | 2,682 | |
| | | |
Assumed on corporate acquisition (1) | 10,789 | | — | | 10,789 | |
| Vested | (9,302) | | (3,767) | | (13,069) | |
| Forfeited | (11) | | (315) | | (326) | |
| Balance, December 31, 2023 | 2,279 | | 3,355 | | 5,634 | |
(1)Following the closing of the transaction, holders of awards outstanding under Ranger's Share Award Plan were entitled to Baytex common shares rather than Ranger common shares with adjustment to the quantity outstanding based on the exchange ratio for Ranger shares. The fair value of share awards allocated to consideration was based on the service period that had occurred prior to the acquisition date (note 4) while the remaining fair value of the share awards assumed by Baytex will be recognized over the remaining future service periods.
Incentive Award Plan
Baytex has an Incentive Award Plan whereby the participants of the plan are entitled to receive a cash payment equal to the value of one Baytex common share per incentive award at the time of vesting. The incentive awards vest in equal tranches on the first, second and third anniversaries of the grant date using the graded vesting method. The cumulative expense is recognized at fair value at each period end and is included in share-based compensation liability.
During the year ended December 31, 2023, Baytex granted 2.6 million awards under the Incentive Award Plan at a fair value of $5.35 per award (1.4 million awards at $5.70 per award for the year ended December 31, 2022). At December 31, 2023 there were 4.5 million awards outstanding under the Incentive Award Plan (December 31, 2022 - 5.1 million).
Deferred Share Unit Plan ("DSU Plan")
Baytex has a DSU Plan whereby each independent director of Baytex is entitled to receive a cash payment equal to the value of one Baytex common share per DSU award on the date at which they cease to be a member of the Board. The awards vest immediately upon being granted and are expensed in full on the grant date. The units are recognized at fair value at each period end and are included in share-based compensation liability.
During the year ended December 31, 2023, Baytex granted 0.3 million awards under the DSU Plan at a fair value of $5.15 per award (0.2 million awards at $5.68 per award for the year ended December 31, 2022). At December 31, 2023, there were 1.2 million awards outstanding under the DSU Plan (December 31, 2022 - 1.0 million).
Equity Total Return Swaps
The Company uses equity total return swaps on the equivalent number of Baytex common shares in order to fix a portion of the aggregate cost of the Company's cash-settled plans including the Incentive Award Plan, the DSU Plan and the Share Award Incentive Plan, at the fair value determined on the grant date.
At December 31, 2023, an asset of $1.0 million associated with the equity total return swap was included in trade receivables (December 31, 2022 - $21.2 million).
13. NET (LOSS) INCOME PER SHARE
Baytex calculates basic income or loss per share based on the net income or loss attributable to shareholders using the weighted average number of shares outstanding during the period. Diluted income per share amounts reflect the potential dilution that could occur if share awards were converted to common shares. The treasury stock method is used to determine the dilutive effect of share awards whereby the potential conversion of share awards and the amount of compensation expense, if any, attributed to future services are assumed to be used to purchase common shares at the average market price during the year.
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| Years Ended December 31 |
| 2023 | 2022 |
| Net (loss) income | Weighted average common shares (000's) | Net (loss) income per share | Net income | Weighted average common shares (000's) | Net income per share |
| Net (loss) income - basic | $ | (233,356) | | 704,896 | | $ | (0.33) | | $ | 855,605 | | 557,986 | | $ | 1.53 | |
| Dilutive effect of share awards | — | | — | | — | | — | | 5,849 | | — | |
| Net (loss) income - diluted | $ | (233,356) | | 704,896 | | $ | (0.33) | | $ | 855,605 | | 563,835 | | $ | 1.52 | |
For the year ended December 31, 2023, all share awards were excluded from the calculation of diluted loss per share as their effect was anti-dilutive given the Company recorded a loss. For the year ended December 31, 2022, 0.3 million share awards were excluded from the calculation of diluted income per share as their effect was anti-dilutive.
14. PETROLEUM AND NATURAL GAS SALES
Petroleum and natural gas sales from contracts with customers for the Company's Canadian and U.S. operating segments is set forth in the following table.
| | | | | | | | | | | | | | | | | | | | |
| Years Ended December 31 |
| 2023 | 2022 |
| Canada | U.S. | Total | Canada | U.S. | Total |
| Light oil and condensate | $ | 574,910 | | $ | 1,454,213 | | $ | 2,029,123 | | $ | 693,043 | | $ | 777,506 | | $ | 1,470,549 | |
| Heavy oil | 1,081,549 | | — | | 1,081,549 | | 1,102,076 | | — | | 1,102,076 | |
| NGL | 23,174 | | 122,823 | | 145,997 | | 30,847 | | 89,658 | | 120,505 | |
| Natural gas | 49,388 | | 76,564 | | 125,952 | | 100,595 | | 95,320 | | 195,915 | |
| Total petroleum and natural gas sales | $ | 1,729,021 | | $ | 1,653,600 | | $ | 3,382,621 | | $ | 1,926,561 | | $ | 962,484 | | $ | 2,889,045 | |
Included in trade receivables at December 31, 2023 is $271.1 million of accrued receivables related to delivered volumes (December 31, 2022 - $180.3 million).
15. INCOME TAXES
The provision for income taxes has been computed as follows: | | | | | | | | |
| Years Ended December 31 |
| 2023 | | 2022 | |
| Net (loss) income before income taxes | $ | (516,582) | | $ | 890,915 | |
Expected income taxes at the statutory rate of 24.64% (2022 – 24.80%) (1) | (127,286) | | 220,947 | |
| Increase (decrease) in income taxes resulting from: | | |
| Effect of foreign exchange | (2,089) | | 4,976 | |
| | |
| Effect of rate adjustments for foreign jurisdictions | 5,062 | | (25,522) | |
| | |
Effect of change in deferred tax benefit not recognized (2) | 6,347 | | (129,931) | |
Effect of internal debt restructuring (3) | (186,460) | | (44,762) | |
| Repatriation and related taxes | 13,565 | | — | |
| Adjustments, assessments and other | 7,635 | | 9,602 | |
| Income tax (recovery) expense | $ | (283,226) | | $ | 35,310 | |
(1)The expected income tax rate decreased due to changes in the provincial apportionment of Canadian income.
(2)A deferred tax asset of $40.4 million remains unrecognized due to uncertainty surrounding future commodity prices and future capital gains (December 31, 2022 - $14.4 million). These deferred income tax assets relate to capital losses of $101.8 million and non-capital losses of $113.0 million.
(3)A deferred income tax asset has been recognized immediately after the closing of the Ranger acquisition due to effects of the transaction structuring.
In June 2016, certain indirect subsidiary entities received reassessments from the Canada Revenue Agency ("CRA") that deny non-capital loss deductions relevant to the calculation of income taxes for the years 2011 through 2015. Following objections and submissions, in November 2023 the CRA issued notices of confirmation regarding their prior reassessments. In February 2024, Baytex filed notices of appeal with the Tax Court of Canada and we estimate it could take between two and three years to receive a judgment. The reassessments do not require us to pay any amounts in order to participate in the appeals process. Should we be unsuccessful at the Tax Court of Canada, additional appeals are available; a process that we estimate could take another two years and potentially longer.
We remain confident that the tax filings of the affected entities are correct and are vigorously defending our tax filing positions. In addition, we have purchased $272.5 million of insurance coverage for a premium of $50.3 million to help manage the litigation risk associated with this matter. The most recent reassessments issued by the CRA assert taxes owing by the trusts (described below) of $244.8 million, late payment interest of $166.6 million as of the date of the reassessments, and a late filing penalty in respect of the 2011 tax year of $4.1 million.
By way of background, we acquired several privately held commercial trusts in 2010 with accumulated non-capital losses of $591.0 million (the "Losses"). The Losses were subsequently deducted in computing the taxable income of those trusts. The reassessments, as confirmed in November 2023, disallow the deduction of the Losses for two reasons. Firstly, the reassessments allege that (i) the trusts were resettled, and (ii) the resulting successor trusts were not able to access the losses of the predecessor trusts. Secondly, the reassessments allege that the general anti-avoidance rule of the Income Tax Act (Canada) operates to deny the deduction of the losses. If, after exhausting available appeals, the deduction of Losses continues to be disallowed, either the trusts or their corporate beneficiary will owe cash taxes, late payment interest and potentially penalties. The amount of cash taxes owing, late payment interest and potential penalties are dependent upon the taxpayer(s) ultimately liable (the trusts or their corporate beneficiary) and the amount of unused tax shelter available to those/that taxpayer(s) to offset the reassessed income, including tax shelter from future years that may be carried back and applied to prior years.
For the year-ended December 31, 2023, Baytex forecasts effective tax rates will exceed 15% in all jurisdictions in which we operate and therefore does not anticipate owing any top-up taxes under Pillar Two legislation.
A continuity of the net deferred income tax liability is detailed in the following tables:
| | | | | | | | | | | | | | | | | | |
| As at | January 1, 2023 | Recognized in Net Income | | Business Combination | Foreign Currency Translation Adjustment | December 31, 2023 |
| Taxable temporary differences: | | | | | | |
| Petroleum and natural gas properties | $ | (807,514) | | $ | 200,623 | | | $ | (111,131) | | $ | 11,921 | | $ | (706,101) | |
| Financial derivatives | (2,506) | | 4,506 | | | (4,738) | | — | | (2,738) | |
| Other | (20,951) | | 8,225 | | | — | | (320) | | (13,046) | |
| Deductible temporary differences: | | | | | | |
| Asset retirement obligations | 145,275 | | (873) | | | 6,575 | | (121) | | 150,856 | |
| | | | | | |
Non-capital losses (1)(2) | 416,131 | | 79,343 | | | 156,385 | | (4,298) | | 647,561 | |
| Finance costs | 60,951 | | 5,805 | | | 53,761 | | (5,237) | | 115,280 | |
Net deferred income tax (liability) asset (3) | $ | (208,614) | | $ | 297,629 | | | $ | 100,852 | | $ | 1,945 | | $ | 191,812 | |
(1)Non-capital loss carry-forwards at December 31, 2023 totaled $3.2 billion, of which $2.6 billion will expire from 2033 to 2040, and $575.7 million does not have an expiry date.
(2)A deferred income tax asset of $213.1 million has been recognized in respect of non-capital losses of a wholly owned financing subsidiary of Baytex; which losses will be offset against future interest income to be earned as a result of an internal debt restructuring.
(3)The net deferred income tax asset is comprised of a deferred income tax asset of $213.1 million and a deferred income tax liability of $21.3 million.
| | | | | | | | | | | | | | | | |
| As at | January 1, 2022 | Recognized in Net Loss | | | Foreign Currency Translation Adjustment | December 31, 2022 |
| Taxable temporary differences: | | | | | | |
| Petroleum and natural gas properties | $ | (760,579) | | $ | (18,081) | | | | $ | (28,854) | | $ | (807,514) | |
| Financial derivatives | — | | (2,506) | | | | — | | (2,506) | |
| | | | | | |
| Other | (21,616) | | (1,137) | | | | 1,802 | | (20,951) | |
| Deductible temporary differences: | | | | | | |
| Asset retirement obligations | 185,336 | | (40,693) | | | | 632 | | 145,275 | |
| Financial derivatives | 31,492 | | (31,492) | | | | — | | — | |
Non-capital losses (1) | 342,884 | | 61,005 | | | | 12,242 | | 416,131 | |
| Finance costs | 55,027 | | 1,188 | | | | 4,736 | | 60,951 | |
| Net deferred income tax liability | $ | (167,456) | | $ | (31,716) | | | | $ | (9,442) | | $ | (208,614) | |
(1)Non-capital loss carry-forwards at December 31, 2022 totaled $1.8 billion and will expire from 2033 to 2040.
16. FINANCING AND INTEREST | | | | | | | | |
| Years Ended December 31 |
| 2023 | | 2022 | |
| Interest on Credit Facilities | $ | 56,713 | | $ | 19,550 | |
| Interest on long-term notes | 102,426 | | 60,643 | |
| Interest on lease obligations | 684 | | 193 | |
| Cash interest | $ | 159,823 | | $ | 80,386 | |
| Amortization of debt issue costs | 11,944 | | 6,286 | |
| Accretion of asset retirement obligations (note 10) | 20,406 | | 15,683 | |
| Early redemption expense | — | | 2,462 | |
| Financing and interest | $ | 192,173 | | $ | 104,817 | |
17. FOREIGN EXCHANGE
| | | | | | | | |
| Years Ended December 31 |
| 2023 | | 2022 | |
| | |
| Unrealized foreign exchange (gain) loss | $ | (14,300) | | $ | 45,073 | |
| Realized foreign exchange loss (gain) | 3,452 | | (1,632) | |
| Foreign exchange (gain) loss | $ | (10,848) | | $ | 43,441 | |
18. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company's financial assets and liabilities are comprised of cash, trade receivables, trade payables, financial derivatives, Credit Facilities and long-term notes. The fair value of cash, trade receivables, trade payables and dividends payable approximates carrying value due to the short term to maturity. The fair value of the Credit Facilities is equal to the principal amount outstanding as the Credit Facilities bear interest at floating rates and credit spreads that are indicative of market rates. The fair value of the long-term notes is determined based on market prices.
The carrying value and fair value of the Company's financial instruments carried on the consolidated statements of financial position are classified into the following categories:
| | | | | | | | | | | | | | | | | |
| December 31, 2023 | December 31, 2022 | |
| Carrying value | Fair value | Carrying value | Fair value | Fair Value Measurement Hierarchy |
| Financial Assets | | | | | |
| FVTPL | | | | | |
| Financial Derivatives | $ | 23,274 | | $ | 23,274 | | $ | 10,105 | | $ | 10,105 | | Level 2 |
| Total | $ | 23,274 | | $ | 23,274 | | $ | 10,105 | | $ | 10,105 | | |
| | | | | |
| Amortized cost | | | | | |
| Cash | $ | 55,815 | | $ | 55,815 | | $ | 5,464 | | $ | 5,464 | | — | |
| Trade receivables | 339,405 | | 339,405 | | 222,108 | | 222,108 | | |
| Total | $ | 395,220 | | $ | 395,220 | | $ | 227,572 | | $ | 227,572 | | |
| | | | | |
| Financial Liabilities | | | | | |
| | | | | |
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| | | | | |
| Amortized cost | | | | | |
| Trade payables | $ | (477,295) | | $ | (477,295) | | $ | (227,332) | | $ | (227,332) | | — | |
| Dividends payable | (18,381) | | (18,381) | | — | | — | | — | |
| Credit Facilities | (848,749) | | (864,736) | | (383,031) | | (385,394) | | — | |
| Long-term notes | (1,562,361) | | (1,653,118) | | (547,598) | | (563,292) | | Level 1 |
| Total | $ | (2,906,786) | | $ | (3,013,530) | | $ | (1,157,961) | | $ | (1,176,018) | | |
Baytex classifies the fair value of financial instruments according to the following hierarchy based on the number of observable inputs used to value the instruments:
•Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.
•Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.
•Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.
There were no transfers between Level 1 and Level 2 during the years ended December 31, 2023 or 2022.
Foreign Currency Risk
In entities with a Canadian dollar functional currency, Baytex is exposed to fluctuations in foreign exchange rates as a result of the U.S. dollar portion of its Credit Facilities, long-term notes and crude oil sales based on U.S. dollar benchmark prices. The Company's net income or loss, comprehensive income or loss and cash flow will therefore be impacted by fluctuations in foreign exchange rates.
A $0.01 increase or decrease in the CAD/USD foreign exchange rate on the revaluation of outstanding U.S. dollar denominated assets and liabilities would impact net income or loss before income taxes by approximately $12.3 million.
The carrying amounts of the Company’s U.S. dollar denominated monetary assets and liabilities recorded in entities with a Canadian dollar functional currency at the reporting date are as follows:
| | | | | | | | | | | | | | |
| Assets | Liabilities |
| December 31, 2023 | December 31, 2022 | December 31, 2023 | December 31, 2022 |
| U.S. dollar denominated | US$17,923 | | US$6,980 | | US$1,249,725 | | US$430,171 | |
Interest Rate Risk
The Company's interest rate risk arises from borrowing at floating rates under the Credit Facilities (note 8). Based on the principal outstanding on the Credit Facilities as at December 31, 2023, a 100 basis points change in interest rates would impact net income or loss before income taxes by approximately $8.6 million for an annual period.
Commodity Price Risk
Baytex utilizes financial derivative contracts or physical delivery contracts to manage the risk associated with changes in commodity prices. The use of derivatives is governed by a Risk Management Policy approved by the Board of Directors of Baytex which sets out limits on the use of derivatives. Baytex does not use financial derivatives for speculative purposes.
The reported value of commodity financial derivatives is sensitive to changes in forecasted commodity prices. For crude oil contracts outstanding as at December 31, 2023, a US$1.00/bbl change in the underlying benchmark crude oil prices would impact net income before income taxes by approximately $13.4 million. For natural gas and natural gas liquids contracts outstanding as at December 31, 2023, a US$0.25 change in the underlying benchmark natural gas or natural gas liquids prices would impact net income or loss before income taxes by approximately $4.7 million.
Financial Derivative Contracts
Baytex had the following commodity financial derivative contracts outstanding as at February 28, 2024. | | | | | | | | | | | | | | |
| Period | Volume | Price/Unit (1) | Index |
| Oil | | | | |
| Basis differential | Jan 2024 to Jun 2024 | 4,000 bbl/d | Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.10/bbl | WCS |
| Basis differential | July 2024 to Dec 2024 | 4,000 bbl/d | Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.40/bbl | WCS |
Basis differential (2) | July 2024 to Dec 2024 | 5,000 bbl/d | Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.18/bbl | WCS |
Basis differential (2) | Apr 2024 to Dec 2024 | 3,000 bbl/d | Baytex pays: WCS differential at Hardisty Baytex receives: WCS differential at Houston less US$8.27/bbl | WCS |
Basis differential (2) | July 2024 to Dec 2024 | 3,000 bbl/d | WTI less US$13.70/bbl | WCS |
| Basis differential | Jan 2024 to Dec 2024 | 1,500 bbl/d | WTI less US$2.65/bbl | MSW |
Basis differential (2) | Apr 2024 to Dec 2024 | 1,250 bbl/d | WTI less US$3.40/bbl | MSW |
Basis differential (2) | July 2024 to Dec 2024 | 2,500 bbl/d | WTI less US$2.85/bbl | MSW |
| Collar | Jan 2024 to Mar 2024 | 10,400 bbl/d | US$60.00/US$100.00 | WTI |
| Collar | Jan 2024 to Jun 2024 | 24,500 bbl/d | US$60.00/US$100.00 | WTI |
| Collar | July 2024 to Dec 2024 | 2,500 bbl/d | US$60.00/US$90.21 | WTI |
| Collar | Apr 2024 to Jun 2024 | 11,750 bbl/d | US$60.00/US$100.00 | WTI |
| Collar | July 2024 to Dec 2024 | 2,500 bbl/d | US$60.00/US$94.15 | WTI |
| Collar | July 2024 to Dec 2024 | 10,000 bbl/d | US$60.00/US$100.00 | WTI |
| Collar | July 2024 to Sep 2024 | 10,000 bbl/d | US$60.00/US$100.00 | WTI |
| Collar | Oct 2024 to Dec 2024 | 2,500 bbl/d | US$60.00/US$100.00 | WTI |
Collar (2) | July 2024 to Dec 2024 | 9,000 bbl/d | US$60.00/US$84.58 | WTI |
Collar (2) | Oct 2024 to Dec 2024 | 7,000 bbl/d | US$60.00/US$86.43 | WTI |
| | | | |
| Natural Gas | | | | |
| Fixed Sell | Jan 2024 to Mar 2024 | 3,500 mmbtu/d | US$3.5025 | NYMEX |
| Collar | Jan 2024 to Mar 2024 | 11,538 mmbtu/d | US$2.50/US$3.65 | NYMEX |
| Collar | Apr 2024 to Jun 2024 | 11,538 mmbtu/d | US$2.33/US$3.00 | NYMEX |
| Collar | Jan 2024 to Dec 2024 | 2,500 mmbtu/d | US$3.00/US$4.06 | NYMEX |
| Collar | Jan 2024 to Dec 2024 | 2,500 mmbtu/d | US$3.00/US$4.09 | NYMEX |
| Collar | Jan 2024 to Dec 2024 | 5,000 mmbtu/d | US$3.00/US$4.10 | NYMEX |
| Collar | Jan 2024 to Dec 2024 | 8,500 mmbtu/d | US$3.00/US$4.15 | NYMEX |
| Collar | Jan 2024 to Dec 2024 | 5,000 mmbtu/d | US$3.00/US$4.19 | NYMEX |
| | | | |
| Natural Gas Liquids | | | |
| Fixed Sell | Jan 2024 to Mar 2024 | 34,364 gallon/d | US$0.2280/gallon | Mt. Belvieu Non-TET Ethane |
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(1)Based on the weighted average price per unit for the period.
(2)Contracts entered subsequent to December 31, 2023.
The following table sets forth the realized and unrealized gains and losses recorded on financial derivatives. | | | | | | | | |
| Years Ended December 31 |
| 2023 | | 2022 | |
| Realized financial derivatives (gain) loss | $ | (36,212) | | $ | 334,481 | |
| Unrealized financial derivatives loss (gain) | 11,517 | | (135,471) | |
| Financial derivatives (gain) loss | $ | (24,695) | | $ | 199,010 | |
Liquidity Risk
Liquidity risk is the risk that Baytex will encounter difficulty in meeting obligations associated with financial liabilities. Baytex manages its liquidity risk through cash and debt management. Such strategies include management of forecasted and actual cash flows from operating, financing and investing activities, available capacity under existing credit facility arrangements, and opportunities to issue additional common shares.
The timing of cash outflows relating to financial liabilities as at December 31, 2023 is outlined in the table below:
| | | | | | | | | | | | | | | | | |
| Total | 2024 | 2025-2026 | 2027-2028 | 2029 and beyond |
| Trade payables | $ | 477,295 | | $ | 477,295 | | $ | — | | $ | — | | $ | — | |
| | | | | |
| Credit Facilities - principal | 864,736 | | — | | 864,736 | | — | | — | |
Long-term notes - principal (1) | 1,597,475 | | — | | — | | 541,114 | | 1,056,361 | |
Interest on long-term notes (2) | 722,732 | | 137,138 | | 274,276 | | 191,515 | | 119,803 | |
| $ | 3,662,238 | | $ | 614,433 | | $ | 1,139,012 | | $ | 732,629 | | $ | 1,176,164 | |
(1)The US$409.8 million principal amount of 8.75% senior unsecured notes is due April 1, 2027 and the US$800.0 million principal amount of 8.50% senior unsecured notes is due April 30, 2030.
(2)Excludes interest on Credit Facilities as interest payments on Credit Facilities fluctuate based on amounts outstanding and the prevailing interest rate at the time of borrowing.
Credit Risk
Credit risk is the risk that a counterparty to a financial asset will default resulting in Baytex incurring a loss. As at December 31, 2023, the Company is exposed to credit risk with respect to its cash, trade receivables and financial derivatives. Baytex manages these risks through the selection and monitoring of credit-worthy counterparties.
Most of the Company's trade receivables relate to petroleum and natural gas sales. Baytex reviews its exposure to individual entities on a regular basis and manages its credit risk by entering into sales contracts after reviewing the creditworthiness of the entity. Letters of credit or parental guarantees may be obtained prior to the commencement of business with certain counterparties. Credit risk may also arise from financial derivative instruments. Baytex's financial derivative contracts are subject to master netting agreements that create a legally enforceable right to offset by the counterparty the related financial assets and financial liabilities. The maximum exposure to credit risk is equal to the carrying value of the financial assets. The Company considers all financial assets that are not impaired or past due to be of good credit quality.
The majority of the Company's credit exposure on trade receivables at December 31, 2023 relates to accrued revenues. Accounts receivable from purchasers of the Company's petroleum and natural gas sales are typically collected on the 25th day of the month following production. Joint interest receivables are typically collected within one to three months following production.
Should the Company determine that the ultimate collection of a receivable is in doubt, the carrying amount of trade receivables is reduced by adjusting the allowance for doubtful accounts and recording a charge to net income or loss. If the Company subsequently determines the accounts receivable is uncollectible, the receivable and allowance for doubtful accounts are adjusted accordingly. As at December 31, 2023, allowance for doubtful accounts was $1.5 million (December 31, 2022 - $2.5 million).
In determining whether amounts past due are collectible, the Company will assess the nature of the past due amounts as well as the credit worthiness and past payment history of the counterparty. Baytex has estimated the lifetime expected credit loss as at and for the year ended December 31, 2023 to be nominal.
The Company's trade receivables, net of the allowance for doubtful accounts, were aged as follows at December 31, 2023.
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| Trade Receivables Aging | December 31, 2023 | December 31, 2022 |
| Current (less than 30 days) | $ | 321,450 | | $ | 216,345 | |
| 31-60 days | 14,836 | | 1,993 | |
| 61-90 days | 461 | | 766 | |
| Past due (more than 90 days) | 2,658 | | 3,005 | |
| $ | 339,405 | | $ | 222,108 | |
19. SUPPLEMENTAL INFORMATION
Changes in Non-Cash Working Capital Items | | | | | | | | |
| Years Ended December 31 |
| 2023 | | 2022 | |
| Trade receivables | $ | (117,297) | | $ | (54,963) | |
| Prepaids and other assets | (76,882) | | (113) | |
| Trade payables | 236,560 | | 42,337 | |
| Share-based compensation liability | (18,340) | | 48,375 | |
| Dividends payable | 18,381 | | — | |
| Non-cash working capital acquired (note 4) | (230,012) | | — | |
| $ | (187,590) | | $ | 35,636 | |
| Changes in non-cash working capital related to: | | |
| Operating activities | $ | (220,895) | | $ | 26,072 | |
| Financing activities | (3,068) | | — | |
| Investing activities | 46,810 | | 9,401 | |
| Transfers from equity | — | | 4,791 | |
| Foreign currency translation on non-cash working capital | (10,437) | | (4,628) | |
| $ | (187,590) | | $ | 35,636 | |
Income Statement Presentation
Baytex's consolidated statements of income (loss) and comprehensive income (loss) are prepared according to the nature of expense, with the exception of employee compensation costs which are included in both operating expense and general and administrative expense line items.
The following table details the amount of total employee compensation costs included in the operating expense and general and administrative expense.
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| Years Ended December 31 |
| 2023 | | 2022 | |
| Operating | $ | 17,975 | | $ | 11,814 | |
| General and administrative | 49,633 | | 35,935 | |
| Total employee compensation costs | $ | 67,608 | | $ | 47,749 | |
20. COMMITMENTS
Baytex has a number of financial obligations that are incurred in the ordinary course of business. These obligations are of a recurring nature and impact the Company’s cash flow from operations in an ongoing manner. A significant portion of these obligations will be funded by adjusted funds flow (note 22). These obligations as of December 31, 2023 and the expected timing of funding of these obligations, are noted in the table below.
| | | | | | | | | | | | | | | | | |
| Total | 2024 | 2025-2026 | 2027-2028 | 2029 and beyond |
| Processing agreements | $ | 5,642 | | $ | 618 | | $ | 1,003 | | $ | 563 | | $ | 3,458 | |
| Transportation agreements | 212,400 | | 52,691 | | 94,866 | | 47,601 | | 17,242 | |
| Total | $ | 218,042 | | $ | 53,309 | | $ | 95,869 | | $ | 48,164 | | $ | 20,700 | |
Baytex also has ongoing obligations related to the abandonment and reclamation of well sites and facilities which have reached the end of their economic lives (note 10). The present value of the future estimated abandonment and reclamation costs are included in the asset retirement obligations presented in the statement of financial position. Programs to abandon and reclaim wellsites and facilities are undertaken regularly in accordance with applicable legislative requirements.
21. RELATED PARTIES
Transactions with key management personnel and directors are noted in the table below.
| | | | | | | | |
| Years Ended December 31 |
| 2023 | 2022 |
| Short-term employee benefits | $ | 7,753 | | $ | 6,868 | |
| Share-based compensation | 9,924 | | 9,043 | |
| Termination payments | — | | 1,758 | |
| Total compensation for key management personnel | $ | 17,677 | | $ | 17,669 | |
22. CAPITAL MANAGEMENT
The Company's capital management objective is to maintain a strong balance sheet that provides financial flexibility to execute its development programs, provide returns to shareholders and optimize its portfolio through strategic acquisitions. Baytex strives to actively manage its capital structure in response to changes in economic conditions. At December 31, 2023, the Company's capital structure was comprised of shareholders' capital, long-term notes, trade receivables, prepaids and other assets, trade payables, share-based compensation liability, dividends payable, cash and the Credit Facilities.
In order to manage its capital structure and liquidity, Baytex may from time-to-time issue equity or debt securities, enter into business transactions including the sale of assets or adjust capital spending to manage current and projected debt levels. There is no certainty that any of these additional sources of capital would be available if required.
The capital-intensive nature of Baytex's operations requires the maintenance of adequate sources of liquidity to fund ongoing exploration and development. Baytex's capital resources consist primarily of adjusted funds flow, available Credit Facilities and proceeds received from the divestiture of oil and gas properties. The following capital management measures and ratios are used to monitor current and projected sources of liquidity.
Net Debt
The Company uses net debt to monitor its current financial position and to evaluate existing sources of liquidity. The Company defines net debt to be the sum of our Credit Facilities and long-term notes outstanding adjusted for unamortized debt issuance costs, trade payables, dividends payable, share-based compensation liability, other long-term liabilities, cash, trade receivables and prepaids and other assets. Baytex also uses net debt projections to estimate future liquidity and whether additional sources of capital are required to fund ongoing operations.
The following table reconciles net debt to amounts disclosed in the primary financial statements.
| | | | | | | | |
| December 31, 2023 | December 31, 2022 |
| Credit Facilities | $ | 848,749 | | $ | 383,031 | |
| Unamortized debt issuance costs - Credit Facilities (note 8) | 15,987 | | 2,363 | |
| Long-term notes | 1,562,361 | | 547,598 | |
| Unamortized debt issuance costs - Long-term notes (note 9) | 35,114 | | 6,999 | |
| Trade payables | 477,295 | | 227,332 | |
| | |
| Dividends payable | 18,381 | | — | |
| Share-based compensation liability | 35,732 | | 54,072 | |
| Other long-term liabilities | 19,147 | | — | |
| Cash | (55,815) | | (5,464) | |
| Trade receivables | (339,405) | | (222,108) | |
| Prepaids and other assets | (83,259) | | (6,377) | |
| Net Debt | $ | 2,534,287 | | $ | 987,446 | |
| | |
Adjusted Funds Flow
Adjusted funds flow is used to monitor operating performance and the Company's ability to generate funds for exploration and development expenditures and settlement of abandonment obligations. Adjusted funds flow is comprised of cash flows from operating activities adjusted for changes in non-cash working capital, asset retirements obligations settled during the applicable period, transaction costs and cash premiums on derivatives.
Adjusted funds flow is reconciled to amounts disclosed in the primary financial statements in the following table.
| | | | | | | | |
| Years Ended December 31 |
| 2023 | 2022 |
| Cash flows from operating activities | $ | 1,295,731 | | $ | 1,172,872 | |
| Change in non-cash working capital | 220,895 | | (26,072) | |
| Asset retirement obligations settled | 26,416 | | 18,351 | |
| Transaction costs | 49,045 | | — | |
| Cash premiums on derivatives | 2,263 | | — | |
| | |
| Adjusted Funds Flow | $ | 1,594,350 | | $ | 1,165,151 | |