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Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies Changes In Accounting Estimates And Errors [Abstract]

The Consolidated Financial Statements include the financial statements of the Company and its wholly-owned, controlled subsidiaries. Control exists when the Company has the power to govern the financial and operating policies of an entity, it is exposed to or has rights to variable returns associated with its involvement in the entity, and it has the ability to use that power to influence the amount of returns it is exposed to or has rights to. In assessing control, potential voting rights need to be considered. All subsidiaries of the Company are wholly-owned by the parent company, TransGlobe Energy Corporation.

All intra-company transactions, balances, income and expenses, unrealized gains and losses are eliminated on consolidation.

Foreign currency translation

The Consolidated Financial Statements are presented in U.S. dollars. The Company’s functional currency is the Canadian dollar, and the functional currency of all subsidiaries is the U.S. dollar. Foreign currency translations include the translation of foreign currency transactions and translation of the Canadian operations.

Foreign currency translations occur when translating transactions in foreign currencies to the applicable functional currency of TransGlobe Energy Corporation and its subsidiaries. Gains and losses from foreign currency transactions are recorded as foreign exchange gains or losses. Foreign currency transaction translations occur as follows:

•

Income and expenses are translated at the prevailing rates on the date of the transaction

•

Non-monetary

assets or liabilities are carried at the prevailing rates on the date of the transaction

•

Monetary items are translated at the prevailing rates at the balance sheet date

Translation gains and losses occur when translating the financial statements of

non-U.S.

functional currency operations to the U.S. dollar. These translation gains and losses are recorded as currency translation adjustments and presented as other comprehensive income on the Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss). Translations occur as follows:

•

Income and expenses are translated at the date of the transaction

•

Assets and liabilities are translated at the prevailing rates on the balance sheet date

Cash

Cash comprises cash on hand. As at December 31, 2021, all of the Company’s cash is on deposit with high credit-quality financial institutions.

Financial instruments

Financial instruments are measured at fair value on initial recognition. Measurement in subsequent periods depends on the classification of the financial instrument:

•

Fair value through profit or loss - subsequently carried at fair value with changes recognized in net earnings (loss). Financial instruments under this classification include cash

and derivative commodity contracts; and

•

Amortized cost - subsequently carried at amortized cost using the effective interest method. Financial instruments under this classification include accounts receivable, accounts payable and accrued liabilities and long-term debt.

The Company enters into certain financial derivative contracts from time to time in order to reduce its exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company does not designate financial derivative contracts as effective accounting hedges, and thus does not apply hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, the Company’s policy is to classify all financial derivative contracts at fair value through profit or loss and to record them on the Consolidated Balance Sheet at fair value with a corresponding gain or loss in net earnings (loss). Attributable transaction costs are recognized in net earnings (loss) when incurred. The estimated fair value of all derivative instruments is based on quoted market prices and/or third-party market indications and forecasts.

Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract when their economic characteristics and risks are not closely related to those of the host contract; when the terms of the embedded derivatives are the same as those of a freestanding derivative; and when the combined contract is not measured at fair value through profit or loss.

Refer to Note 5 for the classification and measurement of these financial instruments.

Share capital

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as a deduction from equity. Repurchase of the Company’s own equity instruments is recognized and deducted directly in equity. No gain or loss is recognized in profit or loss on the purchase, sale, issue or cancellation of the Company’s own equity instruments.

Leases

A contract is, or contains, a lease if the contract provides the right to control the use of an identified asset for a period of time in exchange for consideration. A lease obligation is recognized at the commencement of the lease term measured as the present value of the lease payments not already paid at that date. Interest expense is recognized on the lease obligations using the effective interest rate method and net payments are applied against the lease obligation. At the commencement date, a corresponding

right-of-use

asset is recognized at the amount of the lease obligation, adjusted for lease incentives received and initial direct costs. Depreciation is recognized on the

right-of-use

asset over the lease term.

Intangible exploration and evaluation assets

Exploration and evaluation assets

Exploration and evaluation (“E&E”) costs related to each license/prospect are initially capitalized within “intangible exploration and evaluation assets”. Such E&E costs may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, directly attributable expenses, including remuneration of production personnel and supervisory management, and the projected costs of retiring the assets (if any), but do not include

pre-licensing

costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to net earnings (loss) as they are incurred and presented as exploration expenses on the Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss).

Intangible exploration and evaluation assets are not depleted. They are carried forward until technical feasibility and commercial viability of extracting a mineral resource is determined, at which point they are transferred to petroleum and natural gas (“PNG”) assets. The technical feasibility and commercial viability is considered to be determined when proved and/or probable reserves are determined to exist or they can be empirically supported with actual production data or conclusive formation tests.

Property and equipment

Petroleum and natural gas assets

PNG assets and other assets are

measured

at cost less accumulated depletion, depreciation and amortization, and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, including qualifying E&E costs on reclassification from intangible exploration and evaluation assets, and for qualifying assets, where applicable, borrowing costs. When significant parts of an item of property and equipment have different useful lives, they are accounted for as separate items.

Gains and losses on disposal of items of property and equipment, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property and equipment and are recognized in net earnings (loss) immediately.

Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property and equipment are recognized as petroleum properties or other assets only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized property and equipment generally

represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a well, field or geotechnical area basis, together with the discounted value of estimated future costs of asset retirement obligations.

When components of PNG assets are replaced, disposed of or no longer in use, the carrying amount is derecognized. The costs of the

day-to-day

servicing of property, plant and equipment are recognized in net earnings (loss) as incurred.

Depletion, depreciation and amortization

The depletion, depreciation and amortization of PNG assets and other assets are recognized in net earnings (loss).

The net carrying value of the PNG assets included in petroleum properties is depleted using the unit of production method by reference to the ratio of production to the related proved plus probable reserves using estimated future prices and costs. Costs subject to depletion include estimated future development costs necessary to bring those reserves into production. These estimates are reviewed by independent reserves engineers at least annually and determined in accordance with the standards set out in the Canadian Oil and Gas Evaluation Handbook (the “

COGE Handbook

“) and the reserves definitions contained in National Instrument

51-101

Standards of Disclosure of Oil and Gas Activities

. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.

Furniture and fixtures are depreciated at declining balance rates of 20% to 30%, whereas vehicles and leasehold improvements are depreciated on a straight-line basis over their estimated useful lives.

Depreciation methods, useful lives and residual values are reviewed at each reporting date.

Product inventory

Product inventory consists of the Company’s unsold Egypt entitlement crude oil barrels, valued at the lower of cost, using the

first-in,

first-out

method, or net realizable value. Cost includes operating expenses and depletion associated with the entitlement crude oil barrels as determined on a concession by concession basis.

Overlift liability

Overlift liability Overlift refers to a situation where the Company lifts barrels in excess of its entitlement crude oil inventory at the time of sale. An overlift liability represents an obligation for the Company to deliver the equivalent future entitlement production. Settlement of the overlift liability occurs when this entitlement production is delivered or when there is an agreement in place to offset amounts owed from the counterparty. At the time of an overlift, the Company recognizes the revenue from the cargo lifting, with an equivalent cost recorded to an expense resulting in no net earnings impact related to the overlifted barrels during the period. Overlift liabilities are valued based on the Dated Brent oil price, less Gharib quality differential, at the balance sheet date. A gain/loss on overlifted oil volumes is recorded on the difference between the original liability and the fair value of the liability at the balance sheet date.

Impairment

Financial assets carried at amortized cost

TransGlobe applies the simplified approach to providing for expected credit losses (“ECL”) prescribed by IFRS 9 Financial Instruments (“IFRS 9”) which permits the use of the lifetime expected loss provision for all trade receivables carried at amortized cost.

At each reporting date, the Company measures the lifetime expected loss provision taking into consideration TransGlobe’s historical credit loss experience as well as forward-looking information in order to establish loss rates. The amount recognized for ECL that is required to adjust the loss allowance at the reporting date to the amount that is required to be recognized is recognized in net earnings (loss).

Non-financial

assets

At each reporting date, the carrying amounts of the Company’s

non-financial

assets are reviewed to determine whether there is an indication of impairment, except for E&E assets, which are reviewed when circumstances indicate impairment may exist. If there is an indication of impairment, the asset’s recoverable amount is estimated and compared to its carrying value.

For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the cash-generating unit). The recoverable amount of an asset or a cash-generating unit (“CGU”) is the greater of its value in use and its fair value less costs to sell. The Company’s CGUs are not larger than a segment. In assessing both fair value less costs to sell and value in use, the estimated future cash flows are discounted to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in net earnings (loss).

For PNG assets, fair value less costs to sell and value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved plus probable reserves.

E&E assets are tested for impairment when they are transferred to petroleum properties and also if facts and circumstances suggest that the carrying amount of E&E assets may exceed the recoverable amount. Impairment indicators are evaluated at a CGU level. Indication of impairment includes:

Expiry or impending expiry of lease with no expectation of renewal;

Lack of budget or plans for substantive expenditures on further E&E;

Cessation of E&E activities due to a lack of commercially viable discoveries; and

Carrying amounts of E&E assets are unlikely to be recovered in full from a successful development project.

Impairment losses recognized in prior periods are assessed at each reporting date for indication that the loss has decreased or no longer exists. An impairment loss may be reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

Share-based payment transactions

Equity-settled transactions

The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which equity instruments are granted and is recognized as an expense over the vesting period, which ends on the date on which the relevant employees become fully entitled to the award. Fair value is determined by using the lattice-based trinomial option pricing model. An estimated forfeiture rate is taken into consideration when assigning a fair value to options granted such that no expense is recognized for awards that do not ultimately vest.

At each financial reporting date before vesting, the cumulative expense is calculated, which represents the extent to which the vesting period has expired and management’s best estimate of the number of equity instruments that will ultimately vest. The movement in cumulative expense since the previous financial reporting date is recognized in net earnings (loss), with a corresponding entry in contributed surplus in equity.

When the terms of an equity-settled award are modified or a new award is designated as replacing a canceled or settled award, the cost based on the original award terms continues to be recognized over the remainder of the new vesting period for the incremental fair value of any modification, based on the difference between the fair value of the original award and the fair value of the modified award, both as measured on the date of the modification. No reduction is recognized if this difference is negative.

Cash-settled transactions

The expense related to the share units granted under these plans is measured at fair value based on the estimated grant date share price fair value of the respective awards, net of estimated forfeitures. The expense is recognized over the vesting period, with a corresponding liability recognized on the Consolidated Balance Sheet.

The grant date fair value of cash-settled units granted to employees is recognized as compensation expense within general and administrative expenses, with a corresponding increase in share-based compensation liabilities over the period that the employees become unconditionally entitled to the units. The amount recognized as an expense over the related service period is adjusted to reflect the actual number of units that eventually vest and considers both

non-market

and market conditions. Until the liability is ultimately settled, it is

re-measured

at each reporting date with changes to fair value recognized in net earnings (loss).

Provisions and asset retirement obligations

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

The Company provides for asset retirement obligations on all of its Canadian operations based on current legislation and industry operating practices. The estimated present value of the asset retirement obligation is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. This increase is depleted with the related depletion unit and is allocated to a CGU for impairment testing. The liability is increased each reporting period to reflect the passage of time with a corresponding charge to accretion expense. The asset retirement obligation can also increase or decrease due to changes in the estimated timing of cash flows, changes in the discount rate and/or changes in the original estimated undiscounted costs. Increases or decreases in the obligation will result in a corresponding change in the carrying amount of the related asset. Actual costs incurred upon settlement of the asset retirement obligation are charged against the asset retirement obligation to the extent of the liability recorded. Asset retirement obligations are measured at each reporting period to reflect the discount rates in effect at that time. On an annual basis, the Company reviews its estimates of the expected costs to reclaim the net interest in its wells and facilities. Resulting changes are accounted for prospectively as a change in estimate.

In accordance with all of the Company’s Production Sharing Agreements and Production Sharing Concessions (collectively defined as “PSCs”), the Company does not, at any time, hold title to the lands on which it operates. In Egypt, under model concession agreements and the Fuel Material Law, liabilities in respect of decommissioning movable and immovable assets (other than wells) passes to the Egyptian Government through the transfer of ownership from the contractor to the government under the cost recovery process.

In relation to petroleum wells, under good oilfield practices, the contractor is responsible for decommissioning

non-producing

wells under a decommissioning plan approved by the Egyptian General Petroleum

Corporation (“EGPC”)

during the life of the concession agreement. If EGPC agrees that a producing well is not economic, then the contractor will be responsible for decommissioning the well under an EGPC approved decommissioning plan. EGPC, at its own discretion, may not require a well to be decommissioned if it wants to preserve the ability to use the well for other purposes. In accordance with the respective concession agreements, expenses approved by EGPC are recoverable through the cost recovery mechanism.

As at December 31, 2021 there is no ARO associated with the Egypt PSCs.

Revenue recognition

The Company’s revenue is derived exclusively from contracts with customers, except for immaterial amounts related to interest and other income. Royalties are considered to be part of the price of the sale transaction and are therefore presented as a reduction to revenue. Revenue associated with the sale of crude oil, natural gas and natural gas liquids (“NGLs”) is measured based on the consideration specified in contracts with customers. Revenue from contracts with customers is recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the customer and the customer taking physical possession. TransGlobe mainly satisfies

its performance obligations at a point in time and the amounts of revenue recognized relating to performance obligations satisfied over time are not significant.

Revenues associated with the sales of the Company’s crude oil in Egypt are recognized by reference to actual volumes sold and quoted market prices in active markets (Dated Brent), adjusted according to specific terms and conditions as applicable per the sales contracts. Revenue is measured at the fair value of the consideration received or receivable. For reporting purposes, the Company records the government’s share of production as royalties and taxes as all royalties and taxes are paid out of the government’s share of production.

Revenues from the sale of crude oil, natural gas, condensate and NGLs in Canada are recognized by reference to actual volumes delivered at contracted delivery points and prices. Prices are determined by reference to quoted market prices in active markets (crude oil - NYMEX WTI, natural gas - AECO C, condensate - NYMEX WTI, and NGLs - various based on product), adjusted according to specific terms and conditions applicable per the sales contracts. Revenues are recognized prior to the deduction of transportation costs. Revenues are measured at the fair value of the consideration received. TransGlobe pays royalties to the Alberta provincial government and other mineral rights owners in accordance with the established royalty regime.

Revenue segregated by product type and geographical market is disclosed in Note 2

Finance revenue and costs

Finance revenue comprises interest income on funds invested. Interest income is recognized as it accrues in net earnings (loss), using the effective interest method.

Finance costs comprise interest expense on borrowings.

Borrowing costs incurred for qualifying assets are capitalized during the period of time that is required to complete and prepare the assets for their intended use or sale. Qualifying assets are comprised of those significant assets that require a period greater than one year to be available for their intended use. All other borrowing costs are recognized in net earnings (loss).

Income tax

Income tax expense is comprised of current and deferred tax. TransGlobe is subject to income taxes based on the tax legislation of each respective country in which TransGlobe conducts business.

Current tax

Current tax assets and liabilities for the current and prior periods are measured as the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted by the date of the Consolidated Financial Statements.

The Company’s contractual arrangements in Egypt stipulate that income taxes are paid by the government out of its entitlement share of production sharing oil. Such amounts are included in current income tax expense at the statutory rate in effect at the time of production.

Deferred tax

The Company determines the amount of deferred income tax assets and liabilities based on the difference between the carrying amounts of the assets and liabilities reported for financial accounting purposes from those reported for tax. Deferred income tax assets and liabilities are measured using the substantively enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. Deferred income tax assets are recognized to the extent it is probable the Company will have sufficient future taxable earnings available against which the unused tax losses can be utilized.

Joint arrangements

A joint arrangement involves joint control and offers joint ownership by the Company and other joint interest partners of the financial and operating policies, and of the assets associated with the arrangement. Joint arrangements are classified into one of two categories: joint operations or joint ventures.

A joint operation is a joint arrangement whereby the Company and the other parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities relating to the arrangement. Parties involved in joint operations must recognize in relation to their interests in the joint operation their proportionate share of the revenues, expenses, assets and liabilities. A joint venture is a joint arrangement whereby the Company and the other parties that have joint control of the arrangement have rights to the net assets of the arrangement. Parties involved in joint ventures must recognize their interests in joint ventures as investments and must account for that investment using the equity method.

In Canada, the Company conducts some of its oil and gas production activities through joint operations and the Consolidated Financial Statements reflect only the Company’s proportionate interest in such activities. Joint control exists for contractual agreements governing TransGlobe’s assets whereby TransGlobe has less than 100% working interest, all of the partners have control of the arrangement collectively, and spending on the project requires the unanimous consent of all parties that collectively control the arrangement and share the associated risks. TransGlobe does not have any joint arrangements that are individually material to the Company or that are structured through joint venture arrangements.

In Egypt, joint arrangements in which the

Company

is involved are conducted pursuant to PSCs. Given the nature and contractual terms associated with the PSCs, the Company has determined that it has rights to the assets and obligations for the liabilities in all of its joint arrangements and that there are no joint arrangements where the Company has rights to the net assets. Accordingly, all joint arrangements have been classified as joint operations, and the Company has recognized its share of all revenues, expenses, assets and liabilities in accordance with the PSCs in the Consolidated Financial Statements.

Future accounting pronouncements

Future Accounting PronouncementsTransGlobe plans to adopt the following amendment to accounting standards, issued by the IASB that is effective for the annual periods beginning on or after January 1, 2022. The pronouncement will be adopted on its respective effective date, however; is not expected to have a material impact on the financial statements.

Amendments to IAS 1 presentation of financial statements

Amendments to IAS 1 Presentation of Financial Statements In January 2020, the IASB issued amendments to IAS 1 Presentation of Financial Statements, to clarify its requirements for the presentation of liabilities as current or non-current in the statement of financial position. This will be effective on January 1, 2023.