Cover
Cover | 12 Months Ended |
Dec. 31, 2023 shares | |
Document Information [Line Items] | |
Document Type | 40-F |
Document Registration Statement | false |
Document Annual Report | true |
Current Fiscal Year End Date | --12-31 |
Document Period End Date | Dec. 31, 2023 |
Entity File Number | 001-32754 |
Entity Registrant Name | BAYTEX ENERGY CORP. |
Entity Incorporation, State or Country Code | A0 |
Entity Address, Address Line One | 2800, 520 - 3rd Avenue S.W. |
Entity Address, City or Town | Calgary |
Entity Address, State or Province | AB |
Entity Address, Postal Zip Code | T2P 0R3 |
City Area Code | 587 |
Local Phone Number | 952-3000 |
Title of 12(b) Security | Common Shares |
Trading Symbol | BTE |
Security Exchange Name | NYSE |
Security Reporting Obligation | 15(d) |
Annual Information Form | true |
Audited Annual Financial Statements | true |
Entity Common Stock, Shares Outstanding | 821,680,619 |
Entity Current Reporting Status | Yes |
Entity Interactive Data Current | Yes |
Entity Emerging Growth Company | false |
Entity Central Index Key | 0001279495 |
Document Fiscal Year Focus | 2023 |
Document Fiscal Period Focus | FY |
Amendment Flag | false |
ICFR Auditor Attestation Flag | true |
Document Financial Statement Error Correction [Flag] | false |
Business Contact | |
Document Information [Line Items] | |
Entity Address, Address Line One | 16285 Park Ten Place |
Entity Address, Address Line Two | Ste 500 |
Entity Address, City or Town | Houston |
Entity Address, State or Province | TX |
Entity Address, Postal Zip Code | 77084 |
City Area Code | 713 |
Local Phone Number | 722-6500 |
Contact Personnel Name | Baytex Energy USA, Inc. |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2023 | |
Audit Information [Abstract] | |
Auditor Name | KPMG LLP |
Auditor Location | Calgary, Alberta, Canada |
Auditor Firm ID | 85 |
Consolidated Statements of Fina
Consolidated Statements of Financial Position - CAD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Current assets | ||
Cash | $ 55,815 | $ 5,464 |
Trade receivables | 339,405 | 222,108 |
Prepaids and other assets | 21,530 | 6,377 |
Financial derivatives | 23,274 | 10,105 |
Total current assets | 440,024 | 244,054 |
Non-current assets | ||
Exploration and evaluation assets | 90,919 | 168,684 |
Oil and gas properties | 6,619,033 | 4,620,766 |
Other plant and equipment | 7,936 | 6,568 |
Lease assets | 28,145 | 6,453 |
Prepaids and other assets | 61,729 | 0 |
Deferred income tax asset | 213,145 | 57,244 |
Total assets | 7,460,931 | 5,103,769 |
Current liabilities | ||
Trade payables | 477,295 | 227,332 |
Share-based compensation liability | 28,508 | 44,863 |
Dividends payable | 18,381 | 0 |
Lease obligations | 13,391 | 3,521 |
Asset retirement obligations | 20,448 | 12,813 |
Total current liabilities | 558,023 | 288,529 |
Non-current liabilities | ||
Other long-term liabilities | 19,147 | 0 |
Share-based compensation liability | 7,224 | 9,209 |
Credit facilities | 848,749 | 383,031 |
Long-term notes | 1,562,361 | 547,598 |
Lease obligations | 16,056 | 3,017 |
Asset retirement obligations | 602,951 | 576,110 |
Deferred income tax liability | 21,333 | 265,858 |
Total liabilities | 3,635,844 | 2,073,352 |
SHAREHOLDERS’ EQUITY | ||
Shareholders' capital | 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) |
Total shareholders' equity | 3,825,087 | 3,030,417 |
Total liabilities and shareholders' equity | $ 7,460,931 | $ 5,103,769 |
Consolidated Statements of Inco
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) - CAD ($) shares in Thousands, $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Revenue, net of royalties | ||
Petroleum and natural gas sales | $ 3,382,621 | $ 2,889,045 |
Royalties | (669,792) | (562,964) |
Revenue, net of royalties | 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 | 49,045 | 0 |
Exploration and evaluation | 8,896 | 30,239 |
Depletion and depreciation | 1,047,904 | 587,050 |
Impairment loss (reversal) | 833,662 | (267,744) |
Share-based compensation | 37,699 | 29,056 |
Financing and interest | 192,173 | 104,817 |
Financial derivatives (gain) loss | (24,695) | 199,010 |
Foreign exchange (gain) loss | (10,848) | 43,441 |
Loss (gain) on dispositions | 141,295 | (4,898) |
Other (income) expense | (456) | 3,244 |
Total expenses | 3,229,411 | 1,435,166 |
Net (loss) income before income taxes | (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 |
Income tax (recovery) expense | (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 | ||
Basic (in cad per share) | $ (0.33) | $ 1.53 |
Diluted (in cad per share) | $ (0.33) | $ 1.52 |
Weighted average common shares | ||
Basic (in shares) | 704,896 | 557,986 |
Diluted (in shares) | 704,896 | 563,835 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Equity - CAD ($) $ in Thousands | Total | Shareholders’ capital | Contributed surplus | Accumulated other comprehensive income | Deficit |
Beginning balance at Dec. 31, 2021 | $ 2,211,329 | $ 5,736,593 | $ 13,559 | $ 632,103 | $ (4,170,926) |
Vesting of share awards | 0 | 8,501 | (8,501) | ||
Share-based compensation | 3,159 | 8,501 | 3,159 | ||
Repurchase of common shares for cancellation | (158,977) | (245,430) | 86,453 | ||
Transfers for liability-classified awards | (4,791) | (4,791) | |||
Comprehensive income (loss) | 979,697 | 124,092 | 855,605 | ||
Ending balance at Dec. 31, 2022 | 3,030,417 | 5,499,664 | 89,879 | 756,195 | (3,315,321) |
Issued on corporate acquisition | 1,347,751 | 1,326,435 | 21,316 | ||
Vesting of share awards | (11,233) | 26,229 | (37,462) | ||
Share-based compensation | 16,237 | 16,237 | |||
Repurchase of common shares for cancellation | (221,932) | (325,039) | 103,107 | ||
Transfers for liability-classified awards | 0 | ||||
Dividends declared | (37,519) | (37,519) | |||
Comprehensive income (loss) | (298,634) | (65,278) | (233,356) | ||
Ending balance at Dec. 31, 2023 | $ 3,825,087 | $ 6,527,289 | $ 193,077 | $ 690,917 | $ (3,586,196) |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Operating activities | ||
Net (loss) income | $ (233,356) | $ 855,605 |
Adjustments for: | ||
Non-cash share-based compensation | 16,237 | 3,159 |
Unrealized foreign exchange (gain) loss | (14,300) | 45,073 |
Exploration and evaluation | 8,896 | 30,239 |
Depletion and depreciation | 1,047,904 | 587,050 |
Impairment loss (reversal) | 833,662 | (267,744) |
Non-cash financing and accretion | 32,350 | 24,431 |
Non-cash other income | (1,271) | (4,009) |
Unrealized financial derivatives loss (gain) | 11,517 | (135,471) |
Cash premiums on derivatives | (2,263) | 0 |
Loss (gain) on dispositions | 141,295 | (4,898) |
Deferred income tax (recovery) expense | (297,629) | 31,716 |
Asset retirement obligations settled | (26,416) | (18,351) |
Change in non-cash working capital | (220,895) | 26,072 |
Cash flows from operating activities | 1,295,731 | 1,172,872 |
Financing activities | ||
Increase (decrease) in credit facilities | 477,387 | (136,980) |
Decrease in acquired credit facilities | (373,608) | 0 |
Debt issuance costs | (40,424) | (2,138) |
Payments on lease obligations | (11,527) | (3,732) |
Net proceeds from issuance of long-term notes | 1,046,197 | 0 |
Redemption of long-term notes | 0 | (376,589) |
Redemption of acquired long-term notes | (569,256) | 0 |
Repurchase of common shares | (221,932) | (158,977) |
Dividends declared | (37,519) | 0 |
Change in non-cash working capital | (3,068) | 0 |
Cash flows from (used in) financing activities | 266,250 | (678,416) |
Investing activities | ||
Additions to exploration and evaluation assets | 0 | (6,359) |
Additions to oil and gas properties | (1,012,787) | (515,183) |
Additions to other plant and equipment | (4,416) | (1,148) |
Corporate acquisition, net of cash acquired | (662,579) | 0 |
Property acquisitions | (38,914) | (1,352) |
Proceeds from dispositions | 160,256 | 25,649 |
Change in non-cash working capital | 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 | 0 |
Cash, end of year | 55,815 | 5,464 |
Supplementary information | ||
Interest paid | 153,224 | 84,225 |
Income taxes paid | $ 3,603 | $ 2,303 |
Reporting Entity
Reporting Entity | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Reporting Entity | 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. |
Basis of Preparation
Basis of Preparation | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Basis of Preparation | 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. |
Material Accounting Policies
Material Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies, Changes In Accounting Policies And Errors [Abstract] | |
Material Accounting Policies | 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. |
Business Combination
Business Combination | 12 Months Ended |
Dec. 31, 2023 | |
Business Combinations1 [Abstract] | |
Business Combination | 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 base d 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. |
Segmented Financial Information
Segmented Financial Information | 12 Months Ended |
Dec. 31, 2023 | |
Operating Segments [Abstract] | |
Segmented Financial Information | 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 |
Exploration and Evaluation Asse
Exploration and Evaluation Assets | 12 Months Ended |
Dec. 31, 2023 | |
Exploration For And Evaluation Of Mineral Resources [Abstract] | |
Exploration and Evaluation Assets | EXPLORATION AND EVALUATION ASSETS 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. |
Oil and Gas Properties
Oil and Gas Properties | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of detailed information about property, plant and equipment [abstract] | |
Oil and gas properties | OIL AND GAS PROPERTIES Cost Accumulated 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 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 |
Credit Facilities
Credit Facilities | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Credit Facilities | 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. 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. |
Long-Term Notes
Long-Term Notes | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Long-Term Notes | 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. 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. |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2023 | |
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract] | |
Asset Retirement Obligations | 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. |
Shareholders' Capital
Shareholders' Capital | 12 Months Ended |
Dec. 31, 2023 | |
Share Capital, Reserves And Other Equity Interest [Abstract] | |
Shareholders' Capital | 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 |
Share-Based Compensation Plan
Share-Based Compensation Plan | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of share-based payment arrangements [Abstract] | |
Share-Based Compensation Plan | 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 Number of Total number of 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). |
Net (Loss) Income Per Share
Net (Loss) Income Per Share | 12 Months Ended |
Dec. 31, 2023 | |
Earnings per share [abstract] | |
Net (Loss) Income Per Share | 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. 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. |
Petroleum and Natural Gas Sales
Petroleum and Natural Gas Sales | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of revenue from contracts with customers [Abstract] | |
Petroleum and Natural Gas Sales | 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). |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Income Taxes [Abstract] | |
Income Taxes | 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 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. |
Financing and Interest
Financing and Interest | 12 Months Ended |
Dec. 31, 2023 | |
Analysis of income and expense [abstract] | |
Financing and Interest | 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 |
Foreign Exchange
Foreign Exchange | 12 Months Ended |
Dec. 31, 2023 | |
Effects Of Changes In Foreign Exchange Rates [Abstract] | |
Foreign Exchange | 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 |
Financial Instruments and Risk
Financial Instruments and Risk Management | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Financial Instruments and Risk Management | 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 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 (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 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. 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 |
Supplemental Information
Supplemental Information | 12 Months Ended |
Dec. 31, 2023 | |
Additional information [abstract] | |
Supplemental Information | 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. 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 |
Commitments
Commitments | 12 Months Ended |
Dec. 31, 2023 | |
Commitments And Contingencies [Abstract] | |
Commitments | 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. |
Related Parties
Related Parties | 12 Months Ended |
Dec. 31, 2023 | |
Related Party [Abstract] | |
Related Parties | 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 |
Capital Management
Capital Management | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Capital Management | 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 |
Material Accounting Policies (P
Material Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies, Changes In Accounting Policies And Errors [Abstract] | |
Measurement Uncertainty and Judgments | 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. |
Consolidation | 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 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 | 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 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 | 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 | 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. |
Asset Retirement Obligations | 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 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 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 | 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 | 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 | 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. |
Business Combination (Tables)
Business Combination (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Business Combinations1 [Abstract] | |
Estimates of fair value to assets acquired and liabilities assumed | 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 base d 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) |
Segmented Financial Informati_2
Segmented Financial Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Operating Segments [Abstract] | |
Information by reportable segment | 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) |
Assets by segment | 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 |
Exploration and Evaluation As_2
Exploration and Evaluation Assets (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Exploration For And Evaluation Of Mineral Resources [Abstract] | |
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 |
Oil and Gas Properties (Tables)
Oil and Gas Properties (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of detailed information about property, plant and equipment [abstract] | |
Plant and equipment | Cost Accumulated 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 |
Disclosure of recoverable amount of CGU benchmark reference prices | 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 |
Sensitivity of The Estimated Recoverable Amount of Changes in Assumptions | 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). 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 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) |
Credit Facilities (Tables)
Credit Facilities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Bank loans | 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. 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. 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. |
Long-Term Notes (Tables)
Long-Term Notes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Long-term notes | 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. 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. 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. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Other Provisions, Contingent Liabilities And Contingent Assets [Abstract] | |
Change in 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. |
Shareholders' Capital (Tables)
Shareholders' Capital (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Share Capital, Reserves And Other Equity Interest [Abstract] | |
Schedule of shareholders' capital | 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 |
Schedule of dividends | 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 |
Share-Based Compensation Plan (
Share-Based Compensation Plan (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of share-based payment arrangements [Abstract] | |
Number of share awards outstanding | The number of Share Awards outstanding is detailed below: (000s) Number of Number of Total number of 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. |
Net (Loss) Income Per Share (Ta
Net (Loss) Income Per Share (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Earnings per share [abstract] | |
Net income (loss) per share | 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 |
Petroleum and Natural Gas Sal_2
Petroleum and Natural Gas Sales (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure of revenue from contracts with customers [Abstract] | |
Disclosure of disaggregation of revenue from contracts with customers | 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 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Taxes [Abstract] | |
Provision for 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. |
Continuity of net deferred income tax liability | 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. |
Financing and Interest (Tables)
Financing and Interest (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Analysis of income and expense [abstract] | |
Schedule of 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 |
Foreign Exchange (Tables)
Foreign Exchange (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Effects Of Changes In Foreign Exchange Rates [Abstract] | |
Foreign exchange gains and losses | 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 |
Financial Instruments and Ris_2
Financial Instruments and Risk Management (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Financial Instruments [Abstract] | |
Disclosure of financial assets | 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 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) |
Disclosure of financial liabilities | 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 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) |
Carrying amounts of U.S. dollar denominated monetary assets and liabilities | 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 |
Disclosure of 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 (1) Based on the weighted average price per unit for the period. (2) Contracts entered subsequent to December 31, 2023. |
Disclosure of financial derivatives marked-to-market | 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 |
Disclosure of cash outflows relating to financial liabilities | 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. |
Trade and other receivables aging | The Company's trade receivables, net of the allowance for doubtful accounts, were aged as follows at December 31, 2023. 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 |
Supplemental Information (Table
Supplemental Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Additional information [abstract] | |
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 |
Employee compensation costs | The following table details the amount of total employee compensation costs included in the operating expense and general and administrative expense. Years Ended December 31 2023 2022 Operating $ 17,975 $ 11,814 General and administrative 49,633 35,935 Total employee compensation costs $ 67,608 $ 47,749 |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Commitments And Contingencies [Abstract] | |
Financial obligations and expected timing | 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 |
Related Parties (Tables)
Related Parties (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Related Party [Abstract] | |
Transactions with key management personnel | 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 |
Capital Management (Tables)
Capital Management (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Corporate information and statement of IFRS compliance [abstract] | |
Net Debt | 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 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 |
Business Combination - Addition
Business Combination - Additional Information (Details) $ / shares in Units, $ in Thousands, $ in Thousands, share in Millions | 1 Months Ended | 6 Months Ended | 12 Months Ended | ||||||||
Aug. 31, 2023 USD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2023 USD ($) | Jun. 20, 2023 CAD ($) share $ / shares | Jun. 20, 2023 USD ($) share | Jun. 20, 2023 uSDollarPerShare | Apr. 27, 2023 CAD ($) | Dec. 31, 2022 USD ($) | Apr. 01, 2022 USD ($) | |
Disclosure of detailed information about business combination [line items] | |||||||||||
Line of credit facility secured term | 2 years | ||||||||||
Transaction costs | $ 49,045 | $ 0 | |||||||||
Revolving Facilities | |||||||||||
Disclosure of detailed information about business combination [line items] | |||||||||||
Maximum borrowing capacity | $ 150,000 | $ 1,500,000 | 1,500,000 | $ 1,500,000 | $ 1,100,000 | $ 850,000 | |||||
Line of credit facility secured term | 2 years | ||||||||||
8.50% notes due April 1, 2030 | |||||||||||
Disclosure of detailed information about business combination [line items] | |||||||||||
Notional amount | $ 800,000 | $ 800,000 | $ 0 | ||||||||
Ranger Oil Corporation | |||||||||||
Disclosure of detailed information about business combination [line items] | |||||||||||
Total consideration | 2,085,913 | 1,574,453 | |||||||||
Cash transferred | $ 732,840 | $ 553,150 | |||||||||
Equity interests of acquirer | share | 311.4 | 311.4 | |||||||||
Equity interests of acquirer | $ 1,326,435 | $ 1,001,196 | |||||||||
Exercise price of outstanding share options | (per share) | $ 4.26 | uSDollarPerShare 13.31 | |||||||||
Closing price of common shares (in cad per share) | $ / shares | $ 7.49 | ||||||||||
Revenue of combined entity as if combination occurred at beginning of period | 939,400 | 1,700,000 | |||||||||
Profit (loss) of combined entity as if combination occurred at beginning of period | $ 165,100 | 366,700 | |||||||||
Transaction costs | 49,000 | ||||||||||
Other professional fees | 41,700 | ||||||||||
Post-employment benefit expense, defined contribution plans | $ 7,300 | ||||||||||
Ranger Oil Corporation | Discount rate, measurement input | |||||||||||
Disclosure of detailed information about business combination [line items] | |||||||||||
Fair value of oil and gas properties | 0.122 | 0.122 | |||||||||
Ranger Oil Corporation | Market rate, measurement input | |||||||||||
Disclosure of detailed information about business combination [line items] | |||||||||||
Market rate of interest | 9,000 | 9,000 |
Business Combination - Net Asse
Business Combination - Net Assets Acquired (Details) $ in Thousands, $ in Thousands | 12 Months Ended | |||||
Jun. 20, 2023 CAD ($) | Jun. 20, 2023 USD ($) | Dec. 31, 2023 CAD ($) | Jun. 20, 2023 USD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2021 CAD ($) | |
Fair value of net assets acquired | ||||||
Increase in deferred income tax asset | $ 100,852 | |||||
Cash | $ 55,815 | $ 5,464 | $ 0 | |||
Ranger Oil Corporation | ||||||
Consideration | ||||||
Cash | $ 732,840 | $ 553,150 | ||||
Common shares issued | 1,326,435 | 1,001,196 | ||||
Share based compensation | 26,638 | 20,107 | ||||
Total consideration | 2,085,913 | 1,574,453 | ||||
Fair value of net assets acquired | ||||||
Oil and gas properties | 3,096,404 | 2,337,173 | ||||
Working capital deficiency excluding bank debt and financial derivatives | (159,731) | (120,565) | ||||
Financial derivatives | 22,562 | 17,030 | ||||
Lease assets | 20,811 | 15,708 | ||||
Lease obligations | (20,811) | (15,708) | ||||
Credit facilities | (373,608) | (282,000) | ||||
Long-term notes | (569,256) | (429,676) | ||||
Asset retirement obligations | (31,310) | (23,632) | ||||
Deferred income tax asset | 100,852 | 76,123 | ||||
Net assets acquired | $ 2,085,913 | $ 1,574,453 | ||||
Closing foreign exchange rate | 1.32485 | 1.32485 | ||||
Working capital deficiency | $ 16,400 | $ 12,400 | ||||
Increase in deferred income tax asset | 1,600 | $ 1,200 | ||||
Cash | 70,300 | 53,000 | ||||
Provision for expected credit losses | 300 | |||||
Ranger Oil Corporation | Fully Vested Awards | ||||||
Consideration | ||||||
Share based compensation | 21,300 | 16,100 | ||||
Ranger Oil Corporation | Cash-Based Awards | ||||||
Consideration | ||||||
Share based compensation | $ 5,300 | $ 4,000 |
Segmented Financial Informati_3
Segmented Financial Information - Information By Reportable Segment (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Revenue, net of royalties | ||
Petroleum and natural gas sales | $ 3,382,621 | $ 2,889,045 |
Royalties | (669,792) | (562,964) |
Revenue, net of royalties | 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 | 49,045 | 0 |
Exploration and evaluation | 8,896 | 30,239 |
Depletion and depreciation | 1,047,904 | 587,050 |
Impairment loss (reversal) | 833,662 | (267,744) |
Share-based compensation | 16,237 | 3,159 |
Financing and interest | 192,173 | 104,817 |
Financial derivatives (gain) loss | (24,695) | 199,010 |
Foreign exchange (gain) loss | (10,848) | 43,441 |
Loss (gain) on dispositions | 141,295 | (4,898) |
Total expenses | 3,229,411 | 1,435,166 |
Net (loss) income before income taxes | (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 |
Income tax (recovery) expense | (283,226) | 35,310 |
Net (loss) income | (233,356) | 855,605 |
Additions to exploration and evaluation assets | 0 | (6,359) |
Additions to oil and gas properties | 1,012,787 | 515,183 |
Corporate acquisition, net of cash acquired | 662,579 | 0 |
Property acquisitions | 38,914 | 1,352 |
Proceeds from dispositions | (160,256) | (25,649) |
Operating segments | ||
Expenses | ||
Transaction costs | 49,045 | 0 |
Operating segments | Canada | ||
Revenue, net of royalties | ||
Petroleum and natural gas sales | 1,729,021 | 1,926,561 |
Royalties | (213,148) | (277,428) |
Revenue, net of royalties | 1,515,873 | 1,649,133 |
Expenses | ||
Operating | 368,605 | 327,894 |
Transportation | 64,325 | 48,561 |
Blending and other | 224,802 | 189,454 |
General and administrative | 0 | 0 |
Transaction costs | 0 | 0 |
Exploration and evaluation | 8,896 | 30,239 |
Depletion and depreciation | 484,232 | 409,286 |
Impairment loss (reversal) | 184,000 | (267,744) |
Share-based compensation | 0 | 0 |
Financing and interest | 0 | 0 |
Financial derivatives (gain) loss | 0 | 0 |
Foreign exchange (gain) loss | 0 | 0 |
Loss (gain) on dispositions | 141,295 | (4,898) |
Other (income) expense | (1,271) | (4,009) |
Total expenses | 1,474,884 | 728,783 |
Net (loss) income before income taxes | 40,989 | 920,350 |
Income tax (recovery) expense | ||
Net (loss) income | 40,989 | 920,350 |
Additions to exploration and evaluation assets | 0 | 6,359 |
Additions to oil and gas properties | 463,198 | 374,443 |
Corporate acquisition, net of cash acquired | 0 | 0 |
Property acquisitions | 20,023 | 1,352 |
Proceeds from dispositions | (160,256) | (25,649) |
Operating segments | U.S. | ||
Revenue, net of royalties | ||
Petroleum and natural gas sales | 1,653,600 | 962,484 |
Royalties | (456,644) | (285,536) |
Revenue, net of royalties | 1,196,956 | 676,948 |
Expenses | ||
Operating | 202,234 | 94,772 |
Transportation | 24,981 | 0 |
Blending and other | 0 | 0 |
General and administrative | 0 | 0 |
Transaction costs | 0 | 0 |
Exploration and evaluation | 0 | 0 |
Depletion and depreciation | 555,548 | 171,747 |
Impairment loss (reversal) | 649,662 | 0 |
Share-based compensation | 0 | 0 |
Financing and interest | 0 | 0 |
Financial derivatives (gain) loss | 0 | 0 |
Foreign exchange (gain) loss | 0 | 0 |
Loss (gain) on dispositions | 0 | 0 |
Other (income) expense | 0 | 0 |
Total expenses | 1,432,425 | 266,519 |
Net (loss) income before income taxes | (235,469) | 410,429 |
Income tax (recovery) expense | ||
Net (loss) income | (235,469) | 410,429 |
Additions to exploration and evaluation assets | 0 | 0 |
Additions to oil and gas properties | 549,589 | 140,740 |
Corporate acquisition, net of cash acquired | 662,579 | 0 |
Property acquisitions | 18,891 | 0 |
Proceeds from dispositions | 0 | 0 |
Operating segments | Corporate | ||
Revenue, net of royalties | ||
Petroleum and natural gas sales | 0 | 0 |
Royalties | 0 | 0 |
Revenue, net of royalties | 0 | 0 |
Expenses | ||
Operating | 0 | 0 |
Transportation | 0 | 0 |
Blending and other | 0 | 0 |
General and administrative | 69,789 | 50,270 |
Exploration and evaluation | 0 | 0 |
Depletion and depreciation | 8,124 | 6,017 |
Impairment loss (reversal) | 0 | 0 |
Share-based compensation | 37,699 | 29,056 |
Financing and interest | 192,173 | 104,817 |
Financial derivatives (gain) loss | (24,695) | 199,010 |
Foreign exchange (gain) loss | (10,848) | 43,441 |
Loss (gain) on dispositions | 0 | 0 |
Other (income) expense | 815 | 7,253 |
Total expenses | 322,102 | 439,864 |
Net (loss) income before income taxes | (322,102) | (439,864) |
Income tax (recovery) expense | ||
Net (loss) income | (322,102) | (439,864) |
Additions to exploration and evaluation assets | 0 | 0 |
Additions to oil and gas properties | 0 | 0 |
Corporate acquisition, net of cash acquired | 0 | 0 |
Property acquisitions | 0 | 0 |
Proceeds from dispositions | 0 | 0 |
Operating segments | Consolidated | ||
Revenue, net of royalties | ||
Petroleum and natural gas sales | 3,382,621 | 2,889,045 |
Royalties | (669,792) | (562,964) |
Revenue, net of royalties | 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 |
Exploration and evaluation | 8,896 | 30,239 |
Depletion and depreciation | 1,047,904 | 587,050 |
Impairment loss (reversal) | 833,662 | (267,744) |
Share-based compensation | 37,699 | 29,056 |
Financing and interest | 192,173 | 104,817 |
Financial derivatives (gain) loss | (24,695) | 199,010 |
Foreign exchange (gain) loss | (10,848) | 43,441 |
Loss (gain) on dispositions | 141,295 | (4,898) |
Other (income) expense | (456) | 3,244 |
Total expenses | 3,229,411 | 1,435,166 |
Net (loss) income before income taxes | (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 |
Income tax (recovery) expense | (283,226) | 35,310 |
Net (loss) income | (233,356) | 855,605 |
Additions to exploration and evaluation assets | 0 | 6,359 |
Additions to oil and gas properties | 1,012,787 | 515,183 |
Corporate acquisition, net of cash acquired | 662,579 | 0 |
Property acquisitions | 38,914 | 1,352 |
Proceeds from dispositions | $ (160,256) | $ (25,649) |
Segmented Financial Informati_4
Segmented Financial Information - Assets By Segment (Details) - CAD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure of operating segments [line items] | ||
Assets | $ 7,460,931 | $ 5,103,769 |
Operating segments | Canada | ||
Disclosure of operating segments [line items] | ||
Assets | 2,289,083 | 2,779,596 |
Operating segments | U.S. | ||
Disclosure of operating segments [line items] | ||
Assets | 5,112,493 | 2,301,047 |
Operating segments | Corporate | ||
Disclosure of operating segments [line items] | ||
Assets | $ 59,355 | $ 23,126 |
Exploration and Evaluation As_3
Exploration and Evaluation Assets - Schedule of Assets (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Reconciliation of changes in intangible assets other than goodwill [abstract] | ||
Exploration and evaluation assets, beginning of year | $ 168,684 | |
Exploration and evaluation expense | (8,896) | $ (30,239) |
Exploration and evaluation assets, end of year | 90,919 | 168,684 |
Impairment loss (reversal of impairment loss) | 833,700 | (245,200) |
Exploration and evaluation assets | ||
Reconciliation of changes in intangible assets other than goodwill [abstract] | ||
Impairment loss (reversal of impairment loss) | (22,500) | |
Exploration and evaluation assets | ||
Reconciliation of changes in intangible assets other than goodwill [abstract] | ||
Exploration and evaluation assets, beginning of year | 168,684 | 172,824 |
Capital expenditures | 0 | 6,359 |
Property acquisitions | 18,486 | 301 |
Divestitures | (2,965) | (498) |
Property swaps | 1,000 | 385 |
Impairment reversal | 0 | 22,503 |
Exploration and evaluation expense | (8,896) | (30,239) |
Transfers to oil and gas properties | (83,530) | (8,496) |
Foreign currency translation | (1,860) | 5,545 |
Exploration and evaluation assets, end of year | $ 90,919 | $ 168,684 |
Oil and Gas Properties - Schedu
Oil and Gas Properties - Schedule of PPE Activity, Oil and Gas (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Reconciliation of changes in property, plant and equipment [abstract] | ||
Impairment (loss) reversal | $ (833,700) | $ 245,200 |
Oil and gas assets | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Balance, beginning of year | 4,620,766 | 4,464,371 |
Capital expenditures | 1,012,787 | 515,183 |
Corporate acquisition | 3,096,404 | |
Property acquisitions | 20,263 | 1,173 |
Transfers from exploration and evaluation assets | 83,530 | 8,496 |
Transfers from lease assets | 7,611 | |
Change is asset retirement obligations | 54,166 | (147,020) |
Divestitures | (343,269) | (23,274) |
Property swaps | 781 | |
Impairment (loss) reversal | (833,662) | 245,241 |
Foreign currency translation | (60,564) | 137,629 |
Depletion | (1,039,780) | (581,033) |
Balance, end of year | 6,619,033 | 4,620,766 |
Oil and gas assets | Cost | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Balance, beginning of year | 12,042,216 | 11,633,517 |
Capital expenditures | 1,012,787 | 515,183 |
Corporate acquisition | 3,096,404 | |
Property acquisitions | 20,263 | 1,173 |
Transfers from exploration and evaluation assets | 83,530 | 8,496 |
Transfers from lease assets | 7,611 | |
Change is asset retirement obligations | 54,166 | (147,020) |
Divestitures | (660,920) | (265,166) |
Property swaps | (2,975) | |
Impairment (loss) reversal | 0 | 0 |
Foreign currency translation | (127,065) | 296,033 |
Depletion | 0 | 0 |
Balance, end of year | 15,526,017 | 12,042,216 |
Oil and gas assets | Accumulated depletion | ||
Reconciliation of changes in property, plant and equipment [abstract] | ||
Balance, beginning of year | (7,421,450) | (7,169,146) |
Capital expenditures | 0 | 0 |
Corporate acquisition | 0 | |
Property acquisitions | 0 | 0 |
Transfers from exploration and evaluation assets | 0 | 0 |
Transfers from lease assets | 0 | |
Change is asset retirement obligations | 0 | 0 |
Divestitures | 317,651 | 241,892 |
Property swaps | 3,756 | |
Impairment (loss) reversal | (833,662) | 245,241 |
Foreign currency translation | 66,501 | (158,404) |
Depletion | (1,039,780) | (581,033) |
Balance, end of year | $ (8,906,984) | $ (7,421,450) |
Oil and Gas Properties - Additi
Oil and Gas Properties - Additional Information (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 CAD ($) cashGeneratingUnit | Dec. 31, 2022 CAD ($) cashGeneratingUnit | |
Disclosure of detailed information about property, plant and equipment [line items] | ||
Number of cash generating units with no indicators of impairment | 5 | |
Number of cash generating units with indicators of impairment | 2 | |
Number of cash generating units, with recoverable amounts | 2 | 3 |
Impairment loss (reversal of impairment loss) | $ | $ 833,700 | $ (245,200) |
Adjusted inflation for prices and costs subsequent to 2023 | 0.020 | |
Oil and gas assets | ||
Disclosure of detailed information about property, plant and equipment [line items] | ||
Impairment loss (reversal of impairment loss) | $ | $ 833,662 | $ (245,241) |
Oil and gas assets | Minimum | ||
Disclosure of detailed information about property, plant and equipment [line items] | ||
Discount rate applied to cash flow projections | 12% | 12% |
Oil and gas assets | Maximum | ||
Disclosure of detailed information about property, plant and equipment [line items] | ||
Number of cash generating units with indicators of impairment | 2 | 5 |
Discount rate applied to cash flow projections | 14% | 23% |
Oil and Gas Properties - Recove
Oil and Gas Properties - Recoverable Amount Of Company CGUs (Details) - Company's CGUs | 12 Months Ended |
Dec. 31, 2023 $ / MMBTU usdPerBbl $ / $ cadPerBbl $ / MMBTU | |
Year 1 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Average foreign exchange rate (in dollars per share) | $ / $ | 0.75 |
Year 2 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Average foreign exchange rate (in dollars per share) | $ / $ | 0.75 |
Year 3 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Average foreign exchange rate (in dollars per share) | $ / $ | 0.76 |
Year 4 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Average foreign exchange rate (in dollars per share) | $ / $ | 0.76 |
Year 5 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Average foreign exchange rate (in dollars per share) | $ / $ | 0.76 |
Year 6 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Average foreign exchange rate (in dollars per share) | $ / $ | 0.76 |
Year 7 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Average foreign exchange rate (in dollars per share) | $ / $ | 0.76 |
Year 8 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Average foreign exchange rate (in dollars per share) | $ / $ | 0.76 |
Year 9 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Average foreign exchange rate (in dollars per share) | $ / $ | 0.76 |
Year 10 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Average foreign exchange rate (in dollars per share) | $ / $ | 0.76 |
WTI | Oil reserves | Year 1 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 73.67 |
WTI | Oil reserves | Year 2 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 74.98 |
WTI | Oil reserves | Year 3 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 76.14 |
WTI | Oil reserves | Year 4 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 77.66 |
WTI | Oil reserves | Year 5 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 79.22 |
WTI | Oil reserves | Year 6 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 80.80 |
WTI | Oil reserves | Year 7 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 82.42 |
WTI | Oil reserves | Year 8 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 84.06 |
WTI | Oil reserves | Year 9 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 85.74 |
WTI | Oil reserves | Year 10 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 87.46 |
LLS | Oil reserves | Year 1 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 76.49 |
LLS | Oil reserves | Year 2 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 77.80 |
LLS | Oil reserves | Year 3 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 78.95 |
LLS | Oil reserves | Year 4 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 80.35 |
LLS | Oil reserves | Year 5 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 81.95 |
LLS | Oil reserves | Year 6 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 83.59 |
LLS | Oil reserves | Year 7 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 85.27 |
LLS | Oil reserves | Year 8 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 86.97 |
LLS | Oil reserves | Year 9 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 88.71 |
LLS | Oil reserves | Year 10 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | usdPerBbl | 90.48 |
Edmonton Par | Oil reserves | Year 1 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | cadPerBbl | 92.91 |
Edmonton Par | Oil reserves | Year 2 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | cadPerBbl | 95.04 |
Edmonton Par | Oil reserves | Year 3 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | cadPerBbl | 96.07 |
Edmonton Par | Oil reserves | Year 4 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | cadPerBbl | 97.99 |
Edmonton Par | Oil reserves | Year 5 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | cadPerBbl | 99.95 |
Edmonton Par | Oil reserves | Year 6 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | cadPerBbl | 101.94 |
Edmonton Par | Oil reserves | Year 7 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | cadPerBbl | 103.98 |
Edmonton Par | Oil reserves | Year 8 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | cadPerBbl | 106.06 |
Edmonton Par | Oil reserves | Year 9 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | cadPerBbl | 108.18 |
Edmonton Par | Oil reserves | Year 10 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | cadPerBbl | 110.35 |
Henry Hub | Natural gas reserves | Year 1 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 2.75 |
Henry Hub | Natural gas reserves | Year 2 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 3.64 |
Henry Hub | Natural gas reserves | Year 3 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.02 |
Henry Hub | Natural gas reserves | Year 4 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.10 |
Henry Hub | Natural gas reserves | Year 5 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.18 |
Henry Hub | Natural gas reserves | Year 6 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.27 |
Henry Hub | Natural gas reserves | Year 7 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.35 |
Henry Hub | Natural gas reserves | Year 8 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.44 |
Henry Hub | Natural gas reserves | Year 9 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.53 |
Henry Hub | Natural gas reserves | Year 10 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.62 |
AECO | Natural gas reserves | Year 1 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 2.20 |
AECO | Natural gas reserves | Year 2 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 3.37 |
AECO | Natural gas reserves | Year 3 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.05 |
AECO | Natural gas reserves | Year 4 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.13 |
AECO | Natural gas reserves | Year 5 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.21 |
AECO | Natural gas reserves | Year 6 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.30 |
AECO | Natural gas reserves | Year 7 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.38 |
AECO | Natural gas reserves | Year 8 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.47 |
AECO | Natural gas reserves | Year 9 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.56 |
AECO | Natural gas reserves | Year 10 | |
Disclosure of detailed information about property, plant and equipment [line items] | |
Commodity sales price | $ / MMBTU | 4.65 |
Oil and Gas Properties - Sensit
Oil and Gas Properties - Sensitivity of the Estimated Recoverable Amount of Possible Changes (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 CAD ($) cadPerBbl cadPerMcf | Dec. 31, 2022 CAD ($) | |
Disclosure of detailed information about property, plant and equipment [line items] | ||
Discount rate | 1% | |
Oil price | cadPerBbl | 2.50 | |
Gas price | cadPerMcf | 0.25 | |
Impairment (loss) reversal | $ (833,700) | $ 245,200 |
Viking CGU | ||
Disclosure of detailed information about property, plant and equipment [line items] | ||
Recoverable amount | 606,290 | 1,322,193 |
Impairment (loss) reversal | 184,000 | 81,000 |
Change in discount rate of 1% | 26,500 | 39,500 |
Change in oil price of $2.50/bbl | 53,000 | 78,000 |
Change in gas price of $0.25/mcf | 3,500 | 4,000 |
Eagle Ford Non-op CGU | ||
Disclosure of detailed information about property, plant and equipment [line items] | ||
Recoverable amount | 1,429,658 | |
Impairment (loss) reversal | 649,662 | |
Change in discount rate of 1% | 71,300 | |
Change in oil price of $2.50/bbl | 107,600 | |
Change in gas price of $0.25/mcf | $ 25,700 | |
Conventional CGU | ||
Disclosure of detailed information about property, plant and equipment [line items] | ||
Recoverable amount | 119,031 | |
Impairment (loss) reversal | 23,707 | |
Change in discount rate of 1% | 0 | |
Change in oil price of $2.50/bbl | 0 | |
Change in gas price of $0.25/mcf | 0 | |
Peace River CGU | ||
Disclosure of detailed information about property, plant and equipment [line items] | ||
Recoverable amount | 676,939 | |
Impairment (loss) reversal | 140,534 | |
Change in discount rate of 1% | 0 | |
Change in oil price of $2.50/bbl | 0 | |
Change in gas price of $0.25/mcf | 0 | |
Lloydminster CGU | ||
Disclosure of detailed information about property, plant and equipment [line items] | ||
Recoverable amount | 449,250 | |
Impairment (loss) reversal | 0 | |
Change in discount rate of 1% | 11,500 | |
Change in oil price of $2.50/bbl | 53,000 | |
Change in gas price of $0.25/mcf | 0 | |
Eagle Ford Non-op CGU | ||
Disclosure of detailed information about property, plant and equipment [line items] | ||
Recoverable amount | 2,102,646 | |
Impairment (loss) reversal | 0 | |
Change in discount rate of 1% | 95,800 | |
Change in oil price of $2.50/bbl | 131,100 | |
Change in gas price of $0.25/mcf | $ 28,500 |
Credit Facilities - Bank Loan (
Credit Facilities - Bank Loan (Details) $ in Thousands, $ in Millions | 12 Months Ended | ||||
Dec. 31, 2023 CAD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2022 USD ($) | |
Disclosure of detailed information about borrowings [line items] | |||||
Secured bank loans received | $ 848,749 | $ 383,031 | |||
Principal | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Secured bank loans received | 864,736 | 385,394 | |||
Unamortized debt issuance costs | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Secured bank loans received | (15,987) | (2,363) | |||
Bank loan - U.S. dollar denominated | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Secured bank loans received | 311,980 | 30,394 | |||
Bank loan - U.S. dollar denominated | Principal | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Secured bank loans received | $ 236.3 | $ 22.5 | |||
Credit facilities - Canadian dollar denominated | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Secured bank loans received | 552,756 | $ 355,000 | |||
Credit facilities - Canadian dollar denominated | Principal | |||||
Disclosure of detailed information about borrowings [line items] | |||||
Net draws | $ 477,400 | $ 2 |
Credit Facilities - Additional
Credit Facilities - Additional Information (Details) $ in Thousands, $ in Millions | 1 Months Ended | |||||||
Aug. 31, 2023 USD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2023 CAD ($) | Jun. 20, 2023 USD ($) | Jun. 20, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Jul. 25, 2022 CAD ($) | Apr. 01, 2022 USD ($) | |
Disclosure of detailed information about borrowings [line items] | ||||||||
Line of credit facility secured term | 2 years | |||||||
Outstanding letters of credit | $ 15,700 | |||||||
Revolving Facilities | ||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||
Maximum borrowing capacity | $ 150 | $ 1,500,000 | $ 1,100 | $ 1,500,000 | $ 850 | |||
Line of credit facility secured term | 2 years | |||||||
Operating loan | ||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||
Maximum borrowing capacity | $ 50 | |||||||
Syndicated loan | ||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||
Maximum borrowing capacity | 750 | |||||||
Subsidiary operating loan | ||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||
Maximum borrowing capacity | 45 | |||||||
Subsidiary syndicated loan | ||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||
Maximum borrowing capacity | $ 255 | |||||||
Long-Term Notes And Credit Facilities | Weighted average | Effective Interest Rate | ||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||
Weighted average interest rate on Credit Facilities | 7.60% | 7.60% | 3.60% | |||||
Baytex | ||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||
Borrowings, outstanding letters of credit | $ 5,600 | |||||||
LC Facility | ||||||||
Disclosure of detailed information about borrowings [line items] | ||||||||
Borrowings, outstanding letters of credit | $ 4,700 | |||||||
Outstanding letters of credit | $ 20,000 |
Credit Facilities - Financial C
Credit Facilities - Financial Covenants (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 CAD ($) | Dec. 31, 2022 | |
Disclosure of detailed information about borrowings [line items] | ||
Total Debt to Bank EBITDA (Maximum Ratio) | 4 | |
Senior Secured Debt, as defined | $ 864.7 | |
Bank EBITDA, as defined | 2,200 | |
Financing and interest expenses, as defined | 195.2 | |
Principal amounts outstanding | $ 2,500 | |
Position as at December 31, 2023 | ||
Disclosure of detailed information about borrowings [line items] | ||
Senior Secured Debt to Bank EBITDA (Maximum Ratio) | 0.4 | |
Interest Coverage (Minimum Ratio) | 11.3 | 2 |
Total Debt to Bank EBITDA (Maximum Ratio) | 1.1 | |
Covenant | ||
Disclosure of detailed information about borrowings [line items] | ||
Senior Secured Debt to Bank EBITDA (Maximum Ratio) | 3.5 | |
Interest Coverage (Minimum Ratio) | 3.5 | |
Total Debt to Bank EBITDA (Maximum Ratio) | 4 |
Long-Term Notes (Details)
Long-Term Notes (Details) $ in Millions | 12 Months Ended | |||||
Apr. 27, 2023 CAD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Feb. 05, 2020 | |
Disclosure of detailed information about borrowings [line items] | ||||||
Long-term notes | $ 1,562,361,000 | $ 547,598,000 | ||||
Loan repayments | 1,100,000,000 | |||||
Changes in reported amount of U.S. denominated debt | 17,000,000 | |||||
Net proceeds from issuance of long-term notes | 1,046,197,000 | 0 | ||||
Unamortized debt issuance costs | 40,424,000 | 2,138,000 | ||||
Principal | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Long-term notes | 1,597,475,000 | 554,597,000 | ||||
Unamortized debt issuance costs | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Long-term notes | $ (35,114,000) | (6,999,000) | ||||
8.75% Notes Due April 1, 2027 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Notional amount | $ 409.8 | $ 409.8 | ||||
8.75% Notes Due April 1, 2027 | Fixed interest rate | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Borrowings, interest rate | 8.75% | 8.75% | 8.75% | |||
8.75% Notes Due April 1, 2027 | Principal | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Long-term notes | $ 541,114,000 | 554,597,000 | ||||
8.50% notes due April 1, 2030 | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Notional amount | $ 800,000,000 | $ 800 | $ 0 | |||
Borrowings, redeemable interest rate | 98.709% | |||||
Net proceeds from issuance of long-term notes | $ 1,000,000,000 | |||||
Unamortized debt issuance costs | 13,700,000 | |||||
Transaction costs | $ 18,500,000 | |||||
8.50% notes due April 1, 2030 | Fixed interest rate | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Borrowings, interest rate | 8.50% | 8.50% | 8.50% | |||
8.50% notes due April 1, 2030 | Principal | ||||||
Disclosure of detailed information about borrowings [line items] | ||||||
Long-term notes | $ 1,056,361,000 | $ 0 |
Asset Retirement Obligations -
Asset Retirement Obligations - Changes In Asset Retirement Obligations (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Reconciliation of changes in other provisions [Abstract] | ||
Accretion | $ 20,406 | $ 15,683 |
Government grants | (1,271) | (4,009) |
Less current portion of asset retirement obligations | 20,448 | 12,813 |
Non-current portion of asset retirement obligations | 602,951 | 576,110 |
Oil and gas assets | ||
Reconciliation of changes in other provisions [Abstract] | ||
Property swaps | (781) | |
Change is asset retirement obligations | 54,166 | (147,020) |
Asset retirement obligation | ||
Reconciliation of changes in other provisions [Abstract] | ||
Balance, beginning of the year | 588,923 | 743,683 |
Liabilities incurred | 24,185 | 19,942 |
Liabilities settled | (26,416) | (18,351) |
Liabilities acquired from property acquisitions | 11 | 950 |
Liabilities divested | (43,153) | (3,464) |
Property swaps | 76 | 0 |
Accretion | 20,406 | 15,683 |
Government grants | (1,271) | (4,009) |
Change in estimate | 17,067 | 6,124 |
Changes in discount rates and inflation rates | 12,914 | (173,086) |
Foreign currency translation | (653) | 1,451 |
Balance, end of the year | $ 623,399 | $ 588,923 |
Estimated risk free rate | 3.30% | |
Estimated inflation rate | 2.10% | |
Asset retirement obligation | Canada | ||
Reconciliation of changes in other provisions [Abstract] | ||
Estimated risk free rate | 3% | 3.30% |
Estimated inflation rate | 1.60% | 2.10% |
Asset retirement obligation | U.S. | ||
Reconciliation of changes in other provisions [Abstract] | ||
Estimated risk free rate | 4% | 3.30% |
Estimated inflation rate | 2.10% | |
Asset retirement obligation | Oil and gas assets | ||
Reconciliation of changes in other provisions [Abstract] | ||
Change is asset retirement obligations | $ 54,200 | $ (147,000) |
Asset retirement obligation | Aggregated individually immaterial business combinations | ||
Reconciliation of changes in other provisions [Abstract] | ||
Liabilities assumed from corporate acquisition | $ 31,310 | $ 0 |
Asset Retirement Obligations _2
Asset Retirement Obligations - Additional Information (Details) - Asset retirement obligation - CAD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Disclosure of other provisions [line items] | |||
Estimated cash flows, undiscounted amount | $ 795,500 | $ 724,800 | |
Estimated inflation rate | 2.10% | ||
Estimated risk free rate | 3.30% | ||
Other provisions | $ 623,399 | $ 588,923 | $ 743,683 |
Other provisions, period of costs being incurred | 60 years | ||
Canada | |||
Disclosure of other provisions [line items] | |||
Estimated inflation rate | 1.60% | 2.10% | |
Estimated risk free rate | 3% | 3.30% | |
U.S. | |||
Disclosure of other provisions [line items] | |||
Estimated inflation rate | 2.10% | ||
Estimated risk free rate | 4% | 3.30% |
Shareholders' Capital (Details)
Shareholders' Capital (Details) $ / shares in Units, $ in Thousands | 1 Months Ended | 12 Months Ended | |||||||
Feb. 28, 2024 $ / shares | Dec. 15, 2023 $ / shares | Sep. 15, 2023 $ / shares | Jun. 23, 2023 shares | Nov. 30, 2023 $ / shares | Dec. 31, 2023 CAD ($) vote $ / shares shares | Dec. 31, 2022 CAD ($) $ / shares shares | Jun. 21, 2023 shares | Dec. 31, 2021 shares | |
Shares repurchased and cancelled, average price (in dollars per share) | $ / shares | $ 5.48 | $ 6.54 | |||||||
Repurchase of common shares | $ | $ 221,932 | $ 158,977 | |||||||
Dividends declared (in dollars per share) | $ / shares | $ 0.0225 | $ 0.0225 | $ 0.0225 | ||||||
Dividend Transactions | |||||||||
Dividends declared (in dollars per share) | $ / shares | $ 0.0225 | ||||||||
Shareholders’ capital | |||||||||
Shares authorized for repurchase and cancellation (in shares) | 68,400,000 | ||||||||
Number of shares authorized for repurchase as percentage of public float (in shares) | 10% | ||||||||
Number of shares outstanding | 821,681,000 | 544,930,000 | 856,900,000 | 564,213,000 | |||||
Common shares repurchased and cancelled (in shares) | 40,511,000 | 24,318,000 | |||||||
Preference shares | |||||||||
Preferred shares without nominal or par value (in shares) | 10,000,000 | ||||||||
Issued on corporate acquisition (in shares) | 0 | ||||||||
Ordinary shares | |||||||||
Voting rights, votes per share | vote | 1 |
Shareholders' Capital - Common
Shareholders' Capital - Common Shares at an Average Price (Details) shares in Thousands, $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 CAD ($) shares | Dec. 31, 2022 CAD ($) shares | |
Number of Common Shares | ||
Vesting of share awards (in shares) | shares | 13,069 | 5,007 |
Amount | ||
Beginning balance | $ 3,030,417 | $ 2,211,329 |
Issued on corporate acquisition | 1,347,751 | |
Vesting of share awards | 16,237 | 3,159 |
Repurchase of common shares for cancellation | (221,932) | (158,977) |
Ending balance | $ 3,825,087 | $ 3,030,417 |
Shareholders’ capital | ||
Number of Common Shares | ||
Beginning balance (in shares) | shares | 544,930 | 564,213 |
Issued on corporate acquisition (in shares) | shares | 311,370 | |
Vesting of share awards (in shares) | shares | 5,892 | 5,035 |
Common shares repurchased and cancelled (in shares) | shares | (40,511) | (24,318) |
Ending balance (in shares) | shares | 821,681 | 544,930 |
Amount | ||
Beginning balance | $ 5,499,664 | $ 5,736,593 |
Issued on corporate acquisition | 1,326,435 | |
Vesting of share awards | 8,501 | |
Repurchase of common shares for cancellation | (325,039) | (245,430) |
Ending balance | $ 6,527,289 | $ 5,499,664 |
Shareholders' Capital - Schedul
Shareholders' Capital - Schedule of dividends (Details) - CAD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Dec. 15, 2023 | Sep. 15, 2023 | Nov. 30, 2023 | Dec. 31, 2023 | |
Share Capital, Reserves And Other Equity Interest [Abstract] | ||||
Dividends declared (in dollars per share) | $ 0.0225 | $ 0.0225 | $ 0.0225 | |
Dividends declared | $ 18,381 | $ 19,138 | $ 37,519 |
Share-Based Compensation Plan -
Share-Based Compensation Plan - Additional Information (Details) $ / shares in Units, shares in Thousands | 12 Months Ended | ||
Dec. 31, 2023 CAD ($) share shares $ / shares | Dec. 31, 2022 CAD ($) shares share $ / shares | Dec. 31, 2021 shares | |
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Compensation expense related to share awards | $ | $ 37,699,000 | $ 29,056,000 | |
Share-based compensation | $ | 16,237,000 | 3,159,000 | |
Cash compensation expense related to share awards | $ | $ 21,500,000 | $ 25,900,000 | |
Closing share price (in dollars per share) | $ / shares | $ 4.38 | $ 6.08 | |
Maximum percentage of issuable awards to outstanding common stock | 3.80% | ||
Granted (in shares) | shares | 2,682 | 1,459 | |
Number of other equity instruments outstanding in share-based payment arrangement | shares | 5,634 | 5,558 | 9,474 |
Minimum | |||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Payout multiplier | 0% | ||
Maximum | |||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Payout multiplier | 200% | ||
Incentive Award Plan | |||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Granted (in shares) | share | 2,600,000 | 1,400,000 | |
Weighted average fair value of share awards (in cad per share) | $ | $ 5.35 | $ 5.70 | |
Number of other equity instruments outstanding in share-based payment arrangement | share | 4,500,000 | 5,100,000 | |
Deferred Share Unit Plan | |||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Granted (in shares) | share | 300,000 | 200,000 | |
Weighted average fair value of share awards (in cad per share) | $ | $ 5.15 | $ 5.68 | |
Number of other equity instruments outstanding in share-based payment arrangement | share | 1,200,000 | 1,000,000 | |
Incentive Award Plan And DSU Plan | |||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Current derivative financial assets, realized portion of swap | $ | $ 1,000,000 | $ 21,200,000 | |
Restricted awards | |||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Number of common shares entitled by restricted award | share | 1 | ||
Granted (in shares) | shares | 41 | 68 | |
Weighted average fair value of share awards (in cad per share) | $ | $ 5.40 | $ 6.08 | |
Number of other equity instruments outstanding in share-based payment arrangement | shares | 2,279 | 762 | 2,093 |
Performance awards | |||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Granted (in shares) | shares | 2,641 | 1,391 | |
Number of other equity instruments outstanding in share-based payment arrangement | shares | 3,355 | 4,796 | 7,381 |
Performance awards | Minimum | |||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Number of common shares entitled by restricted award | share | 0 | ||
Performance awards | Maximum | |||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||
Number of common shares entitled by restricted award | share | 2 |
Share-Based Compensation Plan_2
Share-Based Compensation Plan - Shares Outstanding (Details) shares in Thousands, share in Thousands | 12 Months Ended | |
Dec. 31, 2023 shares share | Dec. 31, 2022 shares | |
Total number of Share Awards | ||
Beginning balance (in shares) | 5,558 | 9,474 |
Granted (in shares) | 2,682 | 1,459 |
Assumed on corporate acquisition (in shares) | share | 10,789 | |
Vested and converted to common shares (in shares) | (13,069) | (5,007) |
Forfeited (in shares) | (326) | (368) |
Ending balance (in shares) | 5,634 | 5,558 |
Restricted awards | ||
Total number of Share Awards | ||
Beginning balance (in shares) | 762 | 2,093 |
Granted (in shares) | 41 | 68 |
Assumed on corporate acquisition (in shares) | share | 10,789 | |
Vested and converted to common shares (in shares) | (9,302) | (1,377) |
Forfeited (in shares) | (11) | (22) |
Ending balance (in shares) | 2,279 | 762 |
Performance awards | ||
Total number of Share Awards | ||
Beginning balance (in shares) | 4,796 | 7,381 |
Granted (in shares) | 2,641 | 1,391 |
Assumed on corporate acquisition (in shares) | share | 0 | |
Vested and converted to common shares (in shares) | (3,767) | (3,630) |
Forfeited (in shares) | (315) | (346) |
Ending balance (in shares) | 3,355 | 4,796 |
Net (Loss) Income Per Share (De
Net (Loss) Income Per Share (Details) - CAD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Net (loss) income | ||
Net (loss) income - basic | $ (233,356) | $ 855,605 |
Net (loss) income - diluted | $ (233,356) | $ 855,605 |
Weighted average common shares (000's) | ||
Weighted average common shares - basic (in shares) | 704,896,000 | 557,986,000 |
Dilutive effect of share awards (in shares) | 0 | 5,849,000 |
Weighted average common shares - diluted (in shares) | 704,896,000 | 563,835,000 |
Net (loss) income per share | ||
Basic (in cad per share) | $ (0.33) | $ 1.53 |
Diluted (in cad per share) | $ (0.33) | $ 1.52 |
Instruments with potential future dilutive effect not included in calculation of diluted earnings per share | 300,000 |
Petroleum and Natural Gas Sal_3
Petroleum and Natural Gas Sales (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | $ 3,382,621 | $ 2,889,045 |
Trade receivable, accrued petroleum and natural gas sales | ||
Disclosure of operating segments [line items] | ||
Included in accounts receivable | 271,100 | 180,300 |
Canada | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 1,729,021 | 1,926,561 |
U.S. | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 1,653,600 | 962,484 |
Light oil and condensate | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 2,029,123 | 1,470,549 |
Light oil and condensate | Canada | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 574,910 | 693,043 |
Light oil and condensate | U.S. | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 1,454,213 | 777,506 |
Heavy oil | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 1,081,549 | 1,102,076 |
Heavy oil | Canada | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 1,081,549 | 1,102,076 |
Heavy oil | U.S. | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 0 | 0 |
NGL | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 145,997 | 120,505 |
NGL | Canada | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 23,174 | 30,847 |
NGL | U.S. | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 122,823 | 89,658 |
Natural gas | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 125,952 | 195,915 |
Natural gas | Canada | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | 49,388 | 100,595 |
Natural gas | U.S. | ||
Disclosure of operating segments [line items] | ||
Petroleum and natural gas sales | $ 76,564 | $ 95,320 |
Income Taxes - Provision For In
Income Taxes - Provision For Income Taxes (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Income Taxes [Abstract] | ||
Net (loss) income before income taxes | $ (516,582) | $ 890,915 |
Expected income taxes at the statutory rate | $ (127,286) | $ 220,947 |
Tax rate | 24.64% | 24.80% |
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 | 6,347 | (129,931) |
Effect of internal debt restructuring | (186,460) | (44,762) |
Repatriation and related taxes | 13,565 | 0 |
Adjustments, assessments and other | 7,635 | 9,602 |
Income tax (recovery) expense | (283,226) | 35,310 |
Deferred tax assets, unrecognized | 40,400 | $ 14,400 |
Unrecognized deferred tax assets, capital losses | 101,800 | |
Unrecognized deferred tax assets. non-capital losses | $ 113,000 |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Details) - Tax Litigation With Canada Revenue Agency - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||
Estimated length of time to receive judgment on potential appeal | 2 years | |
Insurance coverage purchased | $ 272.5 | |
Costs incurred to purchase insurance coverage | 50.3 | |
Tax reassessment issued, amount of possible loss, amount owed by trusts | 244.8 | |
Tax reassessment issued, amount of possible loss, late payment interest | 166.6 | |
Tax reassessment issued, amount of possible loss, late filing penalty | $ 4.1 | |
Accumulated non-capital losses | $ 591 | |
Minimum | ||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||
Estimated length of time to receive judgment | 2 years | |
Maximum | ||
Disclosure of temporary difference, unused tax losses and unused tax credits [line items] | ||
Estimated length of time to receive judgment | 3 years |
Income Taxes - Continuity of Ne
Income Taxes - Continuity of Net Deferred Income Tax Liability (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Changes in deferred tax liability (asset) [abstract] | ||
Beginning balance | $ (208,614) | $ (167,456) |
Recognized in Net Income | 297,629 | 31,716 |
Business Combination | 100,852 | |
Foreign Currency Translation Adjustment | 1,945 | (9,442) |
Ending balance | 191,812 | (208,614) |
Non-capital loss carry-forwards | 3,200,000 | 1,800,000 |
Non-capital loss carry-forwards that will expire | 2,600,000 | |
Non-capital loss carry-forwards with no expiration date | 575,700 | |
Deferred income tax asset | 213,145 | 57,244 |
Deferred income tax liability | 21,333 | 265,858 |
Petroleum and natural gas properties | ||
Changes in deferred tax liability (asset) [abstract] | ||
Beginning balance | (807,514) | (760,579) |
Recognized in Net Income | 200,623 | 18,081 |
Business Combination | (111,131) | |
Foreign Currency Translation Adjustment | 11,921 | (28,854) |
Ending balance | (706,101) | (807,514) |
Financial derivatives | ||
Changes in deferred tax liability (asset) [abstract] | ||
Beginning balance | (2,506) | 0 |
Recognized in Net Income | 4,506 | 2,506 |
Business Combination | (4,738) | |
Ending balance | (2,738) | (2,506) |
Other | ||
Changes in deferred tax liability (asset) [abstract] | ||
Beginning balance | (20,951) | (21,616) |
Recognized in Net Income | 8,225 | 1,137 |
Foreign Currency Translation Adjustment | (320) | 1,802 |
Ending balance | (13,046) | (20,951) |
Asset retirement obligations | ||
Changes in deferred tax liability (asset) [abstract] | ||
Beginning balance | 145,275 | 185,336 |
Recognized in Net Income | (873) | 40,693 |
Business Combination | 6,575 | |
Foreign Currency Translation Adjustment | (121) | 632 |
Ending balance | 150,856 | 145,275 |
Financial derivatives | ||
Changes in deferred tax liability (asset) [abstract] | ||
Beginning balance | 0 | 31,492 |
Recognized in Net Income | 31,492 | |
Ending balance | 0 | |
Non-capital losses | ||
Changes in deferred tax liability (asset) [abstract] | ||
Beginning balance | 416,131 | 342,884 |
Recognized in Net Income | 79,343 | (61,005) |
Business Combination | 156,385 | |
Foreign Currency Translation Adjustment | (4,298) | 12,242 |
Ending balance | 647,561 | 416,131 |
Finance costs | ||
Changes in deferred tax liability (asset) [abstract] | ||
Beginning balance | 60,951 | 55,027 |
Recognized in Net Income | 5,805 | (1,188) |
Business Combination | 53,761 | |
Foreign Currency Translation Adjustment | (5,237) | 4,736 |
Ending balance | $ 115,280 | $ 60,951 |
Financing and Interest (Details
Financing and Interest (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Analysis of income and expense [abstract] | ||
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 on asset retirement obligations | 20,406 | 15,683 |
Early redemption expense | 0 | 2,462 |
Financing and interest | $ 192,173 | $ 104,817 |
Foreign Exchange (Details)
Foreign Exchange (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Effects Of Changes In Foreign Exchange Rates [Abstract] | ||
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 |
Financial Instruments and Ris_3
Financial Instruments and Risk Management - Carrying Value and Fair Value of Financial Instruments (Details) - CAD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Amortized cost | ||
Disclosure Of Financial Assets And Liabilities [Line Items] | ||
Financial liabilities, carrying value | $ (2,906,786) | $ (1,157,961) |
Liabilities, at fair value | (3,013,530) | (1,176,018) |
Amortized cost | Trade payables | Level 1 | ||
Disclosure Of Financial Assets And Liabilities [Line Items] | ||
Financial liabilities, carrying value | (477,295) | (227,332) |
Liabilities, at fair value | (477,295) | (227,332) |
Amortized cost | Dividends payable | Level 1 | ||
Disclosure Of Financial Assets And Liabilities [Line Items] | ||
Financial liabilities, carrying value | (18,381) | 0 |
Liabilities, at fair value | (18,381) | 0 |
Amortized cost | Credit Facilities | Level 1 | ||
Disclosure Of Financial Assets And Liabilities [Line Items] | ||
Financial liabilities, carrying value | (848,749) | (383,031) |
Liabilities, at fair value | (864,736) | (385,394) |
Amortized cost | Long-term notes | Level 1 | ||
Disclosure Of Financial Assets And Liabilities [Line Items] | ||
Financial liabilities, carrying value | (1,562,361) | (547,598) |
Liabilities, at fair value | (1,653,118) | (563,292) |
FVTPL | ||
Disclosure Of Financial Assets And Liabilities [Line Items] | ||
Financial assets, carrying value | 23,274 | 10,105 |
Financial assets, at fair value | 23,274 | 10,105 |
FVTPL | Level 2 | ||
Disclosure Of Financial Assets And Liabilities [Line Items] | ||
Financial assets, carrying value | 23,274 | 10,105 |
Financial assets, at fair value | 23,274 | 10,105 |
Amortized cost | ||
Disclosure Of Financial Assets And Liabilities [Line Items] | ||
Financial assets, carrying value | 395,220 | 227,572 |
Financial assets, at fair value | 395,220 | 227,572 |
Amortized cost | Level 1 | ||
Disclosure Of Financial Assets And Liabilities [Line Items] | ||
Financial assets, carrying value | 55,815 | 5,464 |
Financial assets, at fair value | 55,815 | 5,464 |
Amortized cost | Trade receivables | Level 1 | ||
Disclosure Of Financial Assets And Liabilities [Line Items] | ||
Financial assets, carrying value | 339,405 | 222,108 |
Financial assets, at fair value | $ 339,405 | $ 222,108 |
Financial Instruments and Ris_4
Financial Instruments and Risk Management - Foreign Currency Risk, Interest Rate Risk, Interest Rate Swaps and Commodity Price Risk (Details) $ in Thousands | Dec. 31, 2023 CAD ($) usdBbl usdPerBbl | Dec. 31, 2023 USD ($) usdBbl usdPerBbl | Dec. 31, 2022 USD ($) |
Currency risk | |||
Disclosure of nature and extent of risks arising from financial instruments [line items] | |||
Increase/decrease risk in foreign exchange rate | $ 0.01 | ||
Effect on net income | 12,300,000 | ||
Currency risk | U.S. dollar denominated, liabilities | |||
Disclosure of nature and extent of risks arising from financial instruments [line items] | |||
U.S. dollar denominated | $ 1,249,725 | $ 430,171 | |
Currency risk | U.S. dollar denominated, assets | |||
Disclosure of nature and extent of risks arising from financial instruments [line items] | |||
U.S. dollar denominated | $ 17,923 | $ 6,980 | |
Interest rate risk | |||
Disclosure of nature and extent of risks arising from financial instruments [line items] | |||
Effect on net income | $ 8,600,000 | ||
Impact of base point change on interest rates | 100% | 100% | |
Commodity price risk | |||
Disclosure of nature and extent of risks arising from financial instruments [line items] | |||
Effect on net income | $ 4,700,000 | ||
Commodity price risk | Oil Price | |||
Disclosure of nature and extent of risks arising from financial instruments [line items] | |||
Potential impact of crude oil price changes | usdPerBbl | 1 | 1 | |
Potential impact of natural gas price changes | $ 13,400,000 | ||
Commodity price risk | Natural Gas and Natural Gas Liquids | |||
Disclosure of nature and extent of risks arising from financial instruments [line items] | |||
Potential impact of crude oil price changes | usdBbl | 0.25 | 0.25 |
Financial Instruments and Ris_5
Financial Instruments and Risk Management - Financial Derivative Contracts (Details) | Dec. 31, 2023 usdPerBbl bblPerDay |
Oil Basis Differential Jan 2024 To Jun 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 4,000 |
Derivative price/unit | 8.10 |
Oil Basis Differential July 2024 To Dec 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 4,000 |
Derivative price/unit | 8.40 |
Oil Basis Differential July 2024 To Dec 2024 one | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 5,000 |
Derivative price/unit | 8.18 |
Oil Basis Differential Apr 2024 To Dec 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 3,000 |
Derivative price/unit | 8.27 |
Oil Basis Differential July 2024 To Dec 2024 Two | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 3,000 |
Derivative price/unit | 13.70 |
Oil Basis Differential Jan 2024 To Dec 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 1,500 |
Derivative price/unit | 2.65 |
Oil Basis Differential Apr 2024 To Dec 2024 One | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 1,250 |
Derivative price/unit | 3.40 |
Oil Basis Differential July 2024 To Dec 2024 Three | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 2,500 |
Derivative price/unit | 2.85 |
Oil Collar Jan 2024 To Mar 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 10,400 |
Oil Collar Jan 2024 To Mar 2024 | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 60 |
Oil Collar Jan 2024 To Mar 2024 | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 100 |
Oil Collar Jan 2024 To Jun 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 24,500 |
Oil Collar Jan 2024 To Jun 2024 | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 60 |
Oil Collar Jan 2024 To Jun 2024 | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 100 |
Oil Collar July 2024 To Dec 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 2,500 |
Oil Collar July 2024 To Dec 2024 | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 60 |
Oil Collar July 2024 To Dec 2024 | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 90.21 |
Oil Collar Apr 2024 To Jun 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 11,750 |
Oil Collar Apr 2024 To Jun 2024 | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 60 |
Oil Collar Apr 2024 To Jun 2024 | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 100 |
Oil Collar July 2024 To Dec 2024 One | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 2,500 |
Oil Collar July 2024 To Dec 2024 One | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 60 |
Oil Collar July 2024 To Dec 2024 One | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 94.15 |
Oil Collar July 2024 To Dec 2024 Two | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 10,000 |
Oil Collar July 2024 To Dec 2024 Two | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 60 |
Oil Collar July 2024 To Dec 2024 Two | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 100 |
Oil Collar July 2024 To Sep 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 10,000 |
Oil Collar July 2024 To Sep 2024 | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 60 |
Oil Collar July 2024 To Sep 2024 | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 100 |
Oil Collar Oct 2024 To Dec 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 2,500 |
Oil Collar Oct 2024 To Dec 2024 | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 60 |
Oil Collar Oct 2024 To Dec 2024 | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 100 |
Oil Collar July 2024 To Dec 2024 Three | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 9,000 |
Oil Collar July 2024 To Dec 2024 Three | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 60 |
Oil Collar July 2024 To Dec 2024 Three | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 84.58 |
Oil Collar Oct 2024 To Dec 2024 One | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 7,000 |
Oil Collar Oct 2024 To Dec 2024 One | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 60 |
Oil Collar Oct 2024 To Dec 2024 One | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 86.43 |
Natural Gas Fixed Sell Jan 2024 To Mar 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 3,500 |
Derivative price/unit | 3.5025 |
Natural Gas Collar Jan 2024 To March 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 11,538 |
Natural Gas Collar Jan 2024 To March 2024 | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 2.50 |
Natural Gas Collar Jan 2024 To March 2024 | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 3.65 |
Natural Gas Collar Apr 2024 To Jun 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 11,538 |
Natural Gas Collar Apr 2024 To Jun 2024 | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 2.33 |
Natural Gas Collar Apr 2024 To Jun 2024 | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 3 |
Natural Gas Collar Jan 2024 To Dec 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 2,500 |
Natural Gas Collar Jan 2024 To Dec 2024 | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 3 |
Natural Gas Collar Jan 2024 To Dec 2024 | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 4.06 |
Natural Gas Collar Jan 2024 To Dec 2024 One | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 2,500 |
Natural Gas Collar Jan 2024 To Dec 2024 One | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 3 |
Natural Gas Collar Jan 2024 To Dec 2024 One | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 4.09 |
Natural Gas Collar Jan 2024 To Dec 2024 Two | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 5,000 |
Natural Gas Collar Jan 2024 To Dec 2024 Two | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 3 |
Natural Gas Collar Jan 2024 To Dec 2024 Two | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 4.10 |
Natural Gas Collar Jan 2024 To Dec 2024 Three | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 8,500 |
Natural Gas Collar Jan 2024 To Dec 2024 Three | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 3 |
Natural Gas Collar Jan 2024 To Dec 2024 Three | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 4.15 |
Natural Gas Collar Jan 2024 To Dec 2024 Four | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 5,000 |
Natural Gas Collar Jan 2024 To Dec 2024 Four | Price One | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 3 |
Natural Gas Collar Jan 2024 To Dec 2024 Four | Price Two | |
Disclosure of detailed information about financial instruments [line items] | |
Derivative price/unit | 4.19 |
Natural Gas Liquids Fixed Sell Jan 2024 To Mar 2024 | |
Disclosure of detailed information about financial instruments [line items] | |
Volume | bblPerDay | 34,364 |
Derivative price/unit | 0.2280 |
Financial Instruments and Ris_6
Financial Instruments and Risk Management - Financial Derivatives Marked-To-Market (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Financial Instruments [Abstract] | ||
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 |
Financial Instruments and Ris_7
Financial Instruments and Risk Management - Liquidity Risk (Details) $ in Thousands, $ in Millions | Dec. 31, 2023 CAD ($) | Dec. 31, 2023 USD ($) | Apr. 27, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2022 USD ($) | Feb. 05, 2020 |
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||||||
Trade payables | $ 477,295 | $ 227,332 | ||||
Credit facilities | 848,749 | 383,031 | ||||
Long-term notes | $ 1,562,361 | $ 547,598 | ||||
8.75% Notes Due April 1, 2027 | ||||||
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||||||
Notional amount | $ 409.8 | $ 409.8 | ||||
8.75% Notes Due April 1, 2027 | Fixed interest rate | ||||||
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||||||
Borrowings, interest rate | 8.75% | 8.75% | 8.75% | |||
8.50% notes due April 1, 2030 | ||||||
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||||||
Notional amount | $ 800 | $ 800,000 | $ 0 | |||
8.50% notes due April 1, 2030 | Fixed interest rate | ||||||
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||||||
Borrowings, interest rate | 8.50% | 8.50% | 8.50% | |||
Liquidity risk | ||||||
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||||||
Trade payables | $ 477,295 | |||||
Credit facilities | 864,736 | |||||
Long-term notes | 1,597,475 | |||||
Interest on long-term notes | 722,732 | |||||
Financial liabilities | 3,662,238 | |||||
2024 | Liquidity risk | ||||||
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||||||
Trade payables | 477,295 | |||||
Credit facilities | 0 | |||||
Long-term notes | 0 | |||||
Interest on long-term notes | 137,138 | |||||
Financial liabilities | 614,433 | |||||
2025-2026 | Liquidity risk | ||||||
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||||||
Trade payables | 0 | |||||
Credit facilities | 864,736 | |||||
Long-term notes | 0 | |||||
Interest on long-term notes | 274,276 | |||||
Financial liabilities | 1,139,012 | |||||
2027-2028 | Liquidity risk | ||||||
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||||||
Trade payables | 0 | |||||
Credit facilities | 0 | |||||
Long-term notes | 541,114 | |||||
Interest on long-term notes | 191,515 | |||||
Financial liabilities | 732,629 | |||||
2029 and beyond | Liquidity risk | ||||||
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||||||
Trade payables | 0 | |||||
Credit facilities | 0 | |||||
Long-term notes | 1,056,361 | |||||
Interest on long-term notes | 119,803 | |||||
Financial liabilities | $ 1,176,164 |
Financial Instruments and Ris_8
Financial Instruments and Risk Management - Credit Risk (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure of financial assets [line items] | ||
Current trade receivables | $ 339,405 | $ 222,108 |
Financial assets neither past due nor impaired | Current (less than 30 days) | ||
Disclosure of financial assets [line items] | ||
Current trade receivables | 321,450 | 216,345 |
Financial assets neither past due nor impaired | 31-60 days | ||
Disclosure of financial assets [line items] | ||
Current trade receivables | 14,836 | 1,993 |
Financial assets neither past due nor impaired | 61-90 days | ||
Disclosure of financial assets [line items] | ||
Current trade receivables | 461 | 766 |
Financial assets past due but not impaired | Past due (more than 90 days) | ||
Disclosure of financial assets [line items] | ||
Current trade receivables | $ 2,658 | 3,005 |
Trade receivable, purchasers of petroleum and natural gas | ||
Disclosure of financial assets [line items] | ||
Trade receivable typical collection period | 25 days | |
Trade receivables | ||
Disclosure of financial assets [line items] | ||
Allowance for doubtful accounts | $ 1,500 | $ 2,500 |
Minimum | Trade receivable, joint interest receivable | ||
Disclosure of financial assets [line items] | ||
Trade receivable typical collection period | 1 month | |
Maximum | Trade receivable, joint interest receivable | ||
Disclosure of financial assets [line items] | ||
Trade receivable typical collection period | 3 months |
Supplemental Information - Chan
Supplemental Information - Change in Non-Cash Working Capital Items (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Additional information [abstract] | ||
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 | 0 |
Non-cash working capital acquired | (230,012) | 0 |
Trade and other receivables/payables | (187,590) | 35,636 |
Changes in non-cash working capital related to: | ||
Change in non-cash working capital | (220,895) | 26,072 |
Financing activities | (3,068) | 0 |
Investing activities | 46,810 | 9,401 |
Transfers from equity | 0 | 4,791 |
Foreign currency translation on non-cash working capital | (10,437) | (4,628) |
Changes in non-cash working capital | $ (187,590) | $ 35,636 |
Supplemental Information - Empl
Supplemental Information - Employee Compensation Costs (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disclosure Of Employee Compensation [Line Items] | ||
Employee compensation costs | $ 67,608 | $ 47,749 |
Operating | ||
Disclosure Of Employee Compensation [Line Items] | ||
Employee compensation costs | 17,975 | 11,814 |
General and administrative | ||
Disclosure Of Employee Compensation [Line Items] | ||
Employee compensation costs | $ 49,633 | $ 35,935 |
Commitments (Details)
Commitments (Details) $ in Thousands | Dec. 31, 2023 CAD ($) |
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items] | |
Processing agreements | $ 5,642 |
Transportation agreements | 212,400 |
Total | 218,042 |
2024 | |
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items] | |
Processing agreements | 618 |
Transportation agreements | 52,691 |
Total | 53,309 |
2025-2026 | |
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items] | |
Processing agreements | 1,003 |
Transportation agreements | 94,866 |
Total | 95,869 |
2027-2028 | |
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items] | |
Processing agreements | 563 |
Transportation agreements | 47,601 |
Total | 48,164 |
2029 and beyond | |
Disclosure Of Maturity Analysis Of Lease And Other Payments [Line Items] | |
Processing agreements | 3,458 |
Transportation agreements | 17,242 |
Total | $ 20,700 |
Related Parties (Details)
Related Parties (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Related Party [Abstract] | ||
Short-term employee benefits | $ 7,753 | $ 6,868 |
Share-based compensation | 9,924 | 9,043 |
Termination payments | 0 | 1,758 |
Total compensation for key management personnel | $ 17,677 | $ 17,669 |
Capital Management - Net Debt (
Capital Management - Net Debt (Details) - CAD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Disclosure of detailed information about borrowings [line items] | |||
Trade payables | $ 477,295 | $ 227,332 | |
Dividends payable | 18,381 | 0 | |
Share-based compensation liability | 35,732 | 54,072 | |
Other long-term liabilities | 19,147 | 0 | |
Cash | (55,815) | (5,464) | $ 0 |
Trade receivables | (339,405) | (222,108) | |
Prepaids and other assets | (83,259) | (6,377) | |
Net Debt | 2,534,287 | 987,446 | |
Cost | Credit Facilities | |||
Disclosure of detailed information about borrowings [line items] | |||
Borrowings | 848,749 | 383,031 | |
Cost | Long-term notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Borrowings | 1,562,361 | 547,598 | |
Unamortized debt issuance costs | Credit Facilities | |||
Disclosure of detailed information about borrowings [line items] | |||
Borrowings | 15,987 | 2,363 | |
Unamortized debt issuance costs | Long-term notes | |||
Disclosure of detailed information about borrowings [line items] | |||
Borrowings | $ 35,114 | $ 6,999 |
Capital Management - Adjusted F
Capital Management - Adjusted Funds Flow (Details) - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Corporate information and statement of IFRS compliance [abstract] | ||
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 | 0 |
Cash premiums on derivatives | 2,263 | 0 |
Adjusted Funds Flow | $ 1,594,350 | $ 1,165,151 |
Uncategorized Items - _IXDS
Label | Element | Value |
Additional paid-in capital [member] | ||
Increase (Decrease) Through Settlement Of Share-Based Compensation Awards | bte_IncreaseDecreaseThroughSettlementOfShareBasedCompensationAwards | $ 4,800,000 |