tga-ex992_253.htm

The Consolidated Financial Statements of TransGlobe Energy Corporation were prepared by management within acceptable limits of materiality and are in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. Management is responsible for ensuring that the financial and operating information presented in this annual report is consistent with that shown in the Consolidated Financial Statements.

The Consolidated Financial Statements have been prepared by management in accordance with the accounting policies as described in the notes to the Consolidated Financial Statements. Timely release of financial information sometimes necessitates the use of estimates when transactions affecting the current accounting period cannot be finalized until future periods. When necessary, such estimates are based on informed judgments made by management.

To ensure the integrity of the Consolidated Financial Statements, we carefully select and train qualified personnel. We also ensure our organizational structure provides appropriate delegation of authority and division of responsibilities. Our policies and procedures are communicated throughout the organization and include a written Code of Conduct that applies to all employees, including the Chief Executive Officer and Chief Financial Officer.

Deloitte LLP, an independent registered public accounting firm appointed by the shareholders, has conducted an examination of the corporate and accounting records in order to express their opinion on the Consolidated Financial Statements. The Audit Committee, consisting of three independent directors, has met with representatives of Deloitte LLP and management in order to determine if management has fulfilled its responsibilities in the preparation of the Consolidated Financial Statements. The Board of Directors has approved the Consolidated Financial Statements.

Management has designed and maintains an appropriate system of internal controls to provide reasonable assurance that all assets are safeguarded and financial records are properly maintained to facilitate the preparation of Consolidated Financial Statements for reporting purposes. Management’s evaluation concluded that the internal control over financial reporting was effective as of December 31, 2019.

The effectiveness of TransGlobe’s internal controls over financial reporting as of December 31, 2019 has been audited by Deloitte LLP, the Company’s Independent Registered Public Accounting Firm, who also audited the Company’s Consolidated Financial Statements for the year ended December 31, 2019.

We have audited the accompanying consolidated balance sheets of TransGlobe Energy Corporation and subsidiaries (the "Company") as at December 31, 2019 and 2018, the related consolidated statements of earnings (loss) and comprehensive income (loss), changes in shareholders’ equity and cash flows, for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2019 and 2018, and its financial performance and its cash flows for each of the two years in the period ended December 31, 2019, in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 12, 2020, expressed an unqualified opinion on the Company's internal control over financial reporting.

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

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

We have audited the internal control over financial reporting of TransGlobe Energy Corporation and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2019, of the Company and our report dated March 12, 2020, expressed an unqualified opinion on those financial statements.

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

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

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

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

				Years Ended December 31
		Notes		2019			2018

REVENUE
	Petroleum and natural gas sales, net of royalties		25		140,096			176,227
	Finance revenue		6		471			570
					140,567			176,797

EXPENSES
	Production and operating	10,25			50,626			53,298
	Selling costs		7		1,287			2,103
	General and administrative				16,611			18,688
	Foreign exchange gain				(147	)		(289	)
	Finance costs		6		4,256			5,075
	Depletion, depreciation and amortization		13		34,948			34,291
	Asset retirement obligation accretion		14		215			270
	Loss on financial instruments		5		2,845			7,051
	Impairment loss		12		7,937			14,500
	Gain on disposition of assets				(114	)		(207	)
					118,464			134,780

Earnings before income taxes					22,103			42,017

Income tax expense - current			11		26,098			26,340
NET (LOSS) EARNINGS					(3,995	)		15,677

OTHER COMPREHENSIVE (LOSS) INCOME
	Currency translation adjustments				2,073			(3,732	)
COMPREHENSIVE (LOSS) INCOME					(1,922	)		11,945

Net (loss) earnings per share			21
	Basic				(0.06	)		0.22
	Diluted				(0.06	)		0.22

			As at		As at
		Notes	December 31, 2019		December 31, 2018

ASSETS
Current
	Cash and cash equivalents	8		33,251		51,705
	Accounts receivable	5,9		10,681		12,014
	Derivative commodity contracts	5		-		1,198
	Prepaids and other			4,338		5,385
	Product inventory	10		17,516		8,692
				65,786		78,994
Non-Current
	Derivative commodity contracts	5		-		171
	Intangible exploration and evaluation assets	12		33,706		36,266
	Property and equipment	13
	Petroleum and natural gas assets			196,150		195,263
	Other			4,296		3,079
	Deferred taxes	11		8,387		4,523
				308,325		318,296

LIABILITIES
Current
	Accounts payable and accrued liabilities	16		32,156		28,007
	Derivative commodity contracts	5		217		-
	Current portion of lease obligations	15		1,219		-
				33,592		28,007
Non-Current
	Long-term debt	17		37,041		52,355
	Asset retirement obligations	14		13,612		12,113
	Other long-term liabilities			614		1,007
	Lease obligations	15		589		-
	Deferred taxes	11		8,387		4,523
				93,835		98,005

SHAREHOLDERS’ EQUITY
	Share capital	19		152,805		152,084
	Accumulated other comprehensive income (loss)			1,134		(939	)
	Contributed surplus	20		24,673		24,195
	Retained earnings			35,878		44,951
				214,490		220,291
				308,325		318,296

			Years Ended December 31
		Notes	2019			2018

Share Capital
	Balance, beginning of year	19		152,084			152,084
	Stock options exercised	19		547			-
	Transfer from contributed surplus on exercise of options	19		174			-
	Balance, end of year			152,805			152,084

Accumulated Other Comprehensive Income (Loss)
	Balance, beginning of year			(939	)		2,793
	Currency translation adjustment			2,073			(3,732	)
	Balance, end of year			1,134			(939	)

Contributed Surplus
	Balance, beginning of year			24,195			23,329
	Share-based compensation expense	20		652			866
	Transfer to share capital on exercise of options	19		(174	)		-
	Balance, end of year			24,673			24,195

Retained Earnings
	Balance, beginning of year			44,951			31,801
	Net (loss) earnings			(3,995	)		15,677
	Dividends	22		(5,078	)		(2,527	)
	Balance, end of year			35,878			44,951

				Years Ended December 31
			Notes	2019			2018

OPERATING
	Net (loss) earnings				(3,995	)		15,677
	Adjustments for:
		Depletion, depreciation and amortization	13		34,948			34,291
		Asset retirement obligation accretion	14		215			270
		Deferred lease inducement			-			(90	)
		Impairment loss	12		7,937			14,500
		Share-based compensation	20		2,237			3,536
		Finance costs	6		4,256			5,075
		Unrealized loss (gain) on financial instruments	5		1,586			(9,335	)
		Unrealized gain on foreign currency translation			(153	)		(135	)
		Gain on asset dispositions			(114	)		(207	)
	Asset retirement obligations settled		14		(46	)		(300	)
	Changes in non-cash working capital		26		(2,035	)		5,910
Net cash generated by operating activities					44,836			69,192

INVESTING
	Additions to intangible exploration and evaluation assets		12		(5,377	)		(9,288	)
	Additions to petroleum and natural gas assets		13		(30,626	)		(30,832	)
	Additions to other assets		13		(929	)		(586	)
	Proceeds from asset dispositions				114			207
	Changes in non-cash working capital		26		(291	)		251
Net cash used in investing activities					(37,109	)		(40,248	)

FINANCING
	Issue of common shares for cash		19		547			-
	Interest paid		6		(3,664	)		(4,767	)
	Increase in long-term debt		17		476			508
	Payments on lease obligations		15		(1,945	)		-
	Repayments of long-term debt		17		(16,523	)		(17,797	)
	Dividends paid		22		(5,078	)		(2,527	)
	Changes in non-cash working capital		26		(200	)		(3	)
Net cash used in financing activities					(26,387	)		(24,586	)

Currency translation differences relating to cash and cash equivalents					206			(102	)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS					(18,454	)		4,256
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR					51,705			47,449
CASH AND CASH EQUIVALENTS, END OF YEAR					33,251			51,705

TransGlobe Energy Corporation ("TransGlobe" or the "Company") and its subsidiaries are engaged in oil and natural gas exploration, development and production, and the acquisition of oil and natural gas properties. The Company's shares are traded on the Toronto Stock Exchange (“TSX”), the London Stock Exchange's Alternative Investment Market ("AIM") and the Global Select Market of the NASDAQ Stock Market (“NASDAQ”). TransGlobe is incorporated in Alberta, Canada and the address of its registered office is 2300, 250 – 5th Street SW, Calgary, Alberta, Canada, T2P 0R4.

The Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board. The accounting policies used in the preparation of the Consolidated Financial Statements are described in Note 3 Significant Accounting Policies.

The Company prepared the Consolidated Financial Statements on a going concern basis, which contemplates the realization of assets and liabilities in the normal course of business as they become due. Accordingly, the Consolidated Financial Statements have been prepared on a historical cost basis, except for cash and cash equivalents, derivative commodity contracts and other long-term liabilities that have been measured at fair value. The method used to measure fair value is discussed further in Notes 3 and 5.

The Consolidated Financial Statements are presented and expressed in United States dollars (“US$”), unless otherwise noted. All references to $ are to United States dollars and references to C$ are to Canadian dollars.

The Consolidated Financial Statements were authorized for issue by the Board of Directors on March 10, 2020.

The accounting policies set out below have been applied consistently to all subsidiaries and periods presented in these Consolidated Financial Statements.

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.

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:

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:

Cash and cash equivalents include cash and short-term investments that mature within one month of the date of their purchase.

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

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.

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.

In January 2016, the IASB issued IFRS 16 which replaced IAS 17 Leases and IFRIC 4 Determining Whether an Arrangement Contains a Lease. IFRS 16 requires the recognition of a right-of-use (“ROU”) asset and a lease liability on the balance sheet for most leases where the entity is acting as a lessee, as opposed to the dual classification model (operating and capital leases) under IAS 17. Lessors still apply the dual classification model to their recognized leases.

TransGlobe adopted IFRS 16 as of January 1, 2019 using the modified retrospective approach. The modified retrospective approach does not require a restatement of prior period financial information as the cumulative effect is recognized as an adjustment to opening retained earnings and the Company applies the standard prospectively. There was no effect on the Company's retained earnings or prior period amounts as a result of adopting this standard. The cumulative effect of initially applying the standard was recognized as a $3.5 million increase to ROU assets (included in Property and equipment - "Petroleum and natural gas assets" and "Other assets") with a corresponding increase recorded in "Lease obligations". The ROU assets recognized were measured at amounts equal to the lease obligations. The weighted average incremental borrowing rate used to determine the lease obligation at adoption was approximately 9.8%. The assets and lease obligations recognized largely relate to the Company's head office lease in Calgary and drilling rigs in Egypt.

As a result of this adoption, TransGlobe has revised the description of its accounting policy for leases as follows:

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.

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.

PNG assets and other assets are recognized 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.

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.

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 in the year to the related proved and 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 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 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.

At each reporting date, the Company assesses whether there is objective evidence that a financial asset carried at amortized cost is impaired. If such evidence exists, the Company recognizes an impairment loss in net earnings (loss). Impairment losses are reversed in subsequent periods if the impairment loss decrease can be related objectively to an event occurring after the impairment was recognized.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

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 and 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:

Impairment losses recognized in prior years 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.

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.

The expense related to the share units granted under these plans is measured at fair value using the lattice-based trinomial pricing model and 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 accounts payable, accrued liabilities and other long-term liabilities over the period that the employees become unconditionally entitled to the units. The amount recognized as an expense is adjusted to reflect the actual number of units for which the related service and non-market vesting conditions are met. Until the liability is ultimately settled, it is re-measured at each reporting date with changes to fair value recognized in net earnings (loss).

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, and title to fixed and movable assets is transferred to the respective government when its total cost has been recovered through cost recovery, or at the time of termination of the PSC. Since the Company will not hold title to the land or the assets at the termination of the PSC, the Company does not have a legal obligation, nor the legal ability to decommission the Egypt assets. Furthermore, there is no explicit contractual obligation under the Company's PSCs for the abandonment of assets or reclamation of lands upon termination of the PSCs.

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 25.

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

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 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 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.

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.

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 many 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.

Timely preparation of financial statements in conformity with IFRS as issued by the International Accounting Standards Board requires that management make estimates and assumptions and use judgments that affect the application of accounting policies and the reported amounts of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. The effect of these estimates, assumptions and the use of judgments are explained throughout the notes to the Consolidated Financial Statements. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected.

The key sources of estimation uncertainty that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities are discussed below.

The recoverability of PNG asset carrying values are assessed at the CGU level. Determination of what constitutes a CGU is subject to management judgment of the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets or properties. The factors used by TransGlobe to determine CGUs may vary by country due to unique operating and geographic circumstances in each country. In general, TransGlobe assesses the following factors in determining whether a group of assets generate largely independent cash inflows:

In Egypt, each PSC is considered a separate CGU. In Canada, CGUs are determined by regional geography and one CGU has been identified. The asset composition of a CGU can directly impact the recoverability of the assets included therein. In assessing the recoverability of the Company's petroleum properties, each CGU's carrying value is compared to its recoverable amount, defined as the greater of its fair value less costs to sell and value-in-use. As at December 31, 2019 and December 31, 2018, the recoverable amounts of the Company's CGUs were estimated as their fair value less costs to sell based on the net present value of the after-tax cash flows from the oil and natural gas reserves of each CGU based on reserves estimated by the Company's independent reserves evaluator.

Key input estimates used in the determination of cash flows from oil and natural gas reserves include the following:

Impairment tests were carried out at December 31, 2019 and were based on fair value less costs to sell calculations, using a discount rate of 15% for Egypt and 10% for Canada on future after-tax cash flows and the following commodity price estimates:

	Egypt¹			Canada¹
	Brent Blend Crude Oil	WTI Oil	AECO Gas	Edmonton Pentane	Edmonton Butane	Edmonton Propane	Spec Ethane	Exchange Rate
Year	$/Bbl	$/Bbl	$C/Mcf	$C/Bbl	$C/Bbl	$C/Bbl	$C/Bbl	USD/CAD
2020	67.00	61.00	2.08	77.80	48.76	28.68	6.42	0.760
2021	68.00	63.00	2.35	79.22	51.82	31.09	7.36	0.770
2022	71.00	66.00	2.55	83.33	54.62	34.62	8.05	0.780
2023	73.00	68.00	2.65	86.54	56.89	36.06	8.39	0.780
2024	75.00	70.00	2.75	89.10	58.71	37.21	8.73	0.780
2025	76.00	72.00	2.85	91.67	60.53	38.37	9.08	0.780
2026	78.00	74.00	2.91	94.23	62.35	39.52	9.29	0.780
2027	79.81	75.81	2.97	96.55	64.00	40.56	9.48	0.780
2028	81.33	77.33	3.03	98.50	65.38	41.44	9.69	0.780
2029	82.88	78.88	3.09	100.49	66.79	42.33	9.91	0.780
Thereafter²	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	0.780

Reserves and resources are used in the units of production calculation for depletion, depreciation and amortization. Depletion of petroleum properties is calculated based on total proved plus probable reserves as well as estimated future development costs associated with these reserves as determined by the Company's independent reserves evaluator. See above for discussion of estimates and judgments involved in reserves estimation.

Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the Consolidated Financial Statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly affect the amount of the deferred tax asset or liability calculated at a point in time. Tax interpretations, regulations and legislation in the various jurisdictions in which TransGlobe and its subsidiaries operate are subject to change and interpretation. Such changes can affect the timing of the reversal of temporary tax differences, the tax rates in effect when such differences reverse and TransGlobe's ability to use tax losses and other tax pools in the future. The Company’s income tax filings are subject to audit by taxation authorities in different jurisdictions and the results of such audits may increase or decrease the tax liability. The determination of current and deferred tax amounts recognized in the Consolidated Financial Statements are based on management’s assessment of the tax positions, which includes consideration of their technical merits, communications with tax authorities and management’s view of the most likely outcome. These differences could materially impact net earnings (loss).

The fair values of financial instruments are estimated based upon market and third-party inputs. These estimates are subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance risk.

The fair value estimates of equity-settled and cash-settled share-based payment awards depend on certain assumptions including share price volatility, risk-free interest rate, the term of the awards, and the forfeiture rate which, by their nature, are subject to measurement uncertainty.

The provision for site restoration and abandonment in Canada is based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, market conditions, discovery and analysis of site conditions and changes in technology.

The recoverability of accounts receivable due from the Egyptian General Petroleum Company ("EGPC") is assessed to determine the carrying value of accounts receivable on the Company's Consolidated Balance Sheets. Management judgment is required in performing the recoverability assessment. No material credit losses have been experienced to date, and the Company expects to collect the accounts receivable balance in full.

Management uses judgment to determine whether a sufficient amount of economically recoverable reserves have been discovered. This requires estimates of the quantity and realizable value of a discovery. E&E assets are subject to ongoing technical, commercial and management review to confirm the continued intent to establish the technical feasibility and commercial viability of the discovery.

Management uses judgement to determine the incremental borrowing rate and lease term related to the application of IFRS 16. Incremental borrowing rates are based on judgments including economic environment, term, currency, and the underlying risk inherent to the asset. The carrying amount of the right-of-use assets, lease obligations, and the resulting interest and depletion and depreciation expense, may differ due to changes in the market conditions and lease term. Lease terms are based on assumptions regarding extension terms that allow for operational flexibility and future market conditions.

Financial instruments include cash and cash equivalents, accounts receivable, derivative commodity contracts, accounts payable and accrued liabilities and long-term debt.

The Company has classified its cash and cash equivalents and derivative commodity contracts as fair value through profit or loss. Both are measured at fair value with subsequent changes recognized through net earnings (loss). Accounts receivable are classified as assets at amortized cost; accounts payable and accrued liabilities and long-term debt are classified as liabilities at amortized cost, all of which are measured initially at fair value, and subsequently at amortized cost. Transaction costs attributable to financial instruments carried at amortized cost are included in the initial measurement of the financial instrument and are subsequently amortized using the effective interest rate method.

Carrying value and fair value of financial assets and liabilities are summarized as follows:

Assets and liabilities as at December 31, 2019 that are measured at fair value are classified into levels reflecting the method used to make the measurements. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant inputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair value measurement.

The Company’s cash and cash equivalents and derivative commodity contracts are assessed on the fair value hierarchy described above. TransGlobe’s cash and cash equivalents are classified as Level 1. Derivative commodity contracts are classified as Level 2. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level. There were no transfers between levels in the fair value hierarchy in the period.

The nature of TransGlobe’s operations exposes it to fluctuations in commodity prices, interest rates and foreign currency exchange rates. TransGlobe monitors and, when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by TransGlobe are related to an underlying financial position or to future crude oil and natural gas production. TransGlobe does not use derivative financial instruments for speculative purposes. TransGlobe has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in net earnings (loss) at each reporting period. TransGlobe has not obtained collateral

or other security to support its financial derivatives as management reviews the creditworthiness of its counterparties prior to entering into derivative contracts. The derivative financial instruments are initiated within the guidelines of the Company's corporate hedging policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.

In conjunction with the prepayment agreement (see Note 17), TransGlobe has also entered into a marketing contract with Mercuria Energy Trading S.A. ("Mercuria") to market nine million barrels of TransGlobe's entitlement production. The pricing of the crude oil sales will be based on market prices at the time of sale.

The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at December 31, 2019, the fair values of which have been presented on the Consolidated Balance Sheet:

The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production and financing activities:

The Board of Directors and Audit Committee oversee management’s establishment and execution of the Company’s risk management framework. Management has implemented and monitors compliance with risk management policies. The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.

Credit risk is the risk of financial loss if a customer or counterparty to a financial instrument fails to fulfill their contractual obligations. The Company’s exposure to credit risk primarily relates to cash equivalents and accounts receivable, the majority of which are in respect of oil and natural gas operations. The Company generally extends unsecured credit to these parties and therefore the collection of these amounts may be affected by changes in economic or other conditions. The Company has not experienced any material credit losses in its cash investments or in the collection of accounts receivable to date.

TransGlobe's accounts receivable related to the Canadian operations are with customers and joint interest partners in the petroleum and natural gas industry, and are subject to normal industry credit risks. Receivables from petroleum and natural gas marketers are normally collected in due course. The Company currently sells its production to several purchasers under standard industry sale and payment terms. Purchasers of TransGlobe's natural gas, crude oil and natural gas liquids are subject to a periodic internal credit review to minimize the risk of non-payment. The Company has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions.

The Company completed two direct crude sale shipments in Egypt to third-party buyers during 2019. Depending on the Company's assessment of the credit of crude purchasers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. During 2019, the Company also completed two sales of inventoried entitlement crude oil to EGPC for a total of 869.6 mbbls with total proceeds of $49.9 million. As at December 31, 2019, $5.7 million (December 31, 2018 – $7.2 million) of the total accounts receivable balance of $10.7 million (December 31, 2018 - $12.0 million) is due from EGPC. All accounts receivable are in good standing and collection is not considered to be at risk.

The Company manages its credit risk on cash equivalents by investing only in term deposits with reputable banking institutions.

Market risk is the risk or uncertainty arising from possible market price movements and the associated impact on future performance of the business. The market price movements that the Company is exposed to include commodity prices, foreign currency exchange rates and interest rates, all of which could adversely affect the value of the Company’s financial assets, liabilities and financial results.

The Company’s operational results and financial condition are partially dependent on the commodity prices received for its production of oil, natural gas and NGLs. The Company is exposed to commodity price risk on its derivative assets and liabilities which are used as part of the Company's risk management program to mitigate the effects of changes in commodity prices on future cash flows. While transactions of this nature relate to forecasted future petroleum and natural gas production, TransGlobe does not designate these derivative assets and liabilities as accounting hedges. As such, changes in commodity prices impact the fair value of derivative instruments and the corresponding gains or losses on derivative instruments. The estimated fair value of unrealized commodity contracts is reported on the Consolidated Balance Sheets, with any change in the unrealized positions recorded to net earnings (loss). The Company assesses these instruments on the fair value hierarchy and has classified the determination of fair value of these instruments as Level 2, as the fair values of these transactions are based on an approximation of the amounts that would have been received from counterparties to settle the transactions outstanding as at the date of the Consolidated Balance Sheets with reference to forward prices and market values provided by independent sources. The actual amounts realized may differ from these estimates.

As the Company’s business is conducted primarily in U.S. dollars and its financial instruments are primarily denominated in U.S. dollars, the Company’s exposure to foreign currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, long-term debt, lease obligations and accounts payable and accrued liabilities denominated in Canadian dollars. When assessing the potential impact of foreign currency exchange risk, the Company believes that 10% volatility is a reasonable measure. The Company estimates that a 10% increase in the value of the Canadian dollar against the U.S. dollar would increase net loss for the year ended December 31, 2019 by approximately $1.3 million and conversely, a 10% decrease in the value of the Canadian dollar against the U.S. dollar would decrease net loss by $1.4 million for the same period. The Company does not utilize derivative instruments to manage this risk.

The Company is also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds and British Pounds sterling. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while the Company is generally able to spend the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates, the average Egyptian pound cash balance for 2019 was $2.3 million (2018 - $2.0 million) in equivalent U.S. dollars. The Company estimates that a 10% increase in the value of the Egyptian pound against the U.S. dollar would increase net loss for the year ended December 31, 2019 by approximately $0.2 million and conversely a 10% decrease in the value of the Egyptian pound against the U.S. dollar would decrease net loss by $0.2 million for the same period. The Company does not currently utilize derivative instruments to manage foreign currency exchange risk.

The Company maintains nominal balances of British Pounds sterling to pay in-country costs incurred in operating its London office. Foreign exchange risk on these funds is not considered material.

Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable interest debt. No derivative contracts were entered into during 2019 to mitigate interest rate risk. When assessing interest rate risk applicable to the Company’s variable interest debt, the Company believes 1% volatility is a reasonable measure. The effect of interest rates increasing by 1% would increase the Company’s net loss, for the year ended December 31, 2019, by $0.5 million and conversely, the effect of interest rates decreasing by 1% would decrease the Company’s net loss, for the year ended December 31, 2019, by $0.5 million.

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity describes a company’s ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs necessary to maintain and increase production and proved reserves, to acquire strategic oil and gas assets and to repay debt.

The Company actively maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. The following are the contractual maturities of financial liabilities at December 31, 2019:

As at December 31, 2019, the Company had $94.2 million of revolving credit facilities with $37.5 million drawn and $56.7 million available. The Company has a prepayment agreement with Mercuria that allows for a revolving balance of up to $75.0 million, of which $30.0 million is drawn. During 2019, the Company repaid $15.0 million of this facility. The Company also had a revolving Canadian reserves-based lending facility with ATB Financial (“ATB”) totaling C$25.0 million ($19.2 million), of which C$9.8 million ($7.5 million) was drawn. During 2019, the Company had drawings of C$0.6 million ($0.5 million) and repayments of C$2.0 million ($1.5 million) on this facility (See Note 17).

The Company actively monitors its liquidity to ensure that its cash flows, credit facilities and working capital are adequate to support these financial liabilities, as well as the Company’s capital programs.

To date, the Company has experienced no difficulties with transferring funds abroad.

The Company’s objective when managing capital is to ensure the Company will have the financial capacity, liquidity and flexibility to fund the ongoing exploration and development of its petroleum assets. The Company’s financial objectives and strategy have remained substantially unchanged over the last two completed fiscal years. These objectives and strategy are reviewed on an annual basis. TransGlobe remains in a relatively strong financial position, and will continue to focus on cost reductions and prudent stewardship of capital with the objective of maintaining a strong balance sheet. The Company was subject to financial covenants with the prepayment agreement and the reserves-based lending facility as at December 31, 2019 and 2018. The Company was in compliance with all financial covenants at December 31, 2019 and 2018 (see Note 17).

Finance revenue relates to interest earned on the Company’s bank account balances and term deposits.

Selling costs include transportation and marketing costs associated with the sale of the Company's Egyptian crude oil production to third-party buyers and EGPC. The Company completed two direct crude oil sales to third-party buyers during the year ended December 31, 2019 (2018 - four). The Company also completed two sales of inventoried entitlement crude oil to EGPC in 2019.

As at December 31, 2019 the Company's cash equivalents balance consisted of short-term deposits with an original term to maturity at purchase of three months or less. All of the Company's cash and cash equivalents are on deposit with high credit-quality financial institutions.

Accounts receivable are comprised principally of amounts owed from EGPC. There were no amounts due from related parties and no loans to management or employees as at December 31, 2019 or December 31, 2018.

As at December 31, 2018, the Company utilized $5.1 million of its accounts receivable from EGPC as a guarantee to support work commitments on the North West Sitra concession (see Note 18). These commitments were met as of December 31, 2018. No amounts of accounts receivable were utilized as a guarantee to support work commitments as at December 31, 2019.

Product inventory consists of the Company's entitlement crude oil barrels, which are valued at the lower of cost or net realizable value. Costs include operating expenses and depletion associated with crude oil entitlement barrels and are determined on a concession by concession basis. These amounts are initially capitalized and expensed when sold.

As at December 31, 2019, the Company held 964.5 mbbls of entitlement crude oil in inventory valued at approximately $18.16/bbl (December 31, 2018 - 568.1 mbbls valued at approximately $15.30/bbl). During 2019, product inventory of $8.8 million was capitalized (2018 - $2.8 million expensed).

The Company has non-capital losses of $97.6 million (2018 - $84.3 million) that expire between 2027 and 2039. A deferred tax asset of $8.4 million (2018 - $4.5 million) was recognized in respect of unused tax losses in West Gharib. The Company has an additional $16.8 million (2018 - $14.2 million) in unrecognized tax benefits arising in foreign jurisdictions.

Current income taxes represent income taxes incurred and paid under the laws of Egypt pursuant to the PSCs on the West Gharib, West Bakr and NW Gharib concessions.

Income taxes vary from the amount that would be computed by applying the average Canadian statutory income tax rate of 26.5% (2018 - 27.0%) to income before taxes as follows:

The Company's consolidated effective income tax rate for 2019 was 118.1% (2018 - 62.7%).

The following table reconciles the changes in TransGlobe's exploration and evaluation assets:

For the year ended December 31, 2019, the Company recorded a non-cash impairment loss of $7.9 million on its exploration and evaluation assets, which included an $8.3 million impairment loss on the South Alamein concession and $0.4 million of impairment recovery on the North West Sitra concession.

The Company was unsuccessful in its attempts to secure military approval to access its desired drilling location in South Alamein. Based on the 2017 well results in the Boraq area, the limited commerciality of the original Boraq 2 discovery (2009) and continued access restrictions in the eastern area of the concession, the Company had fully impaired the remaining carrying value of South Alamein of $8.3 million and relinquished the concession in 2019.

In 2018 the Company recorded an impairment loss of $14.5 million on its exploration and evaluation assets which was fully related to the North West Sitra concession. During the third quarter of 2019, the Company received a final settlement report from EGPC regarding the relinquished North West Sitra concession. The final settlement report resulted in a reduction of the original impairment loss recognized by $0.4 million.

Exploration and evaluation assets as at December 31, 2019 includes $29.2 million in South Ghazalat (December 31, 2018 - $23.2 million), $nil in South Alamein (December 31, 2018 - $12.5 million), $4.0 million in Northwest Gharib (December 31, 2018 - $nil) and $0.5 million in Canada (2018 - $0.5 million).

The following table reconciles the changes in TransGlobe's property and equipment assets:

($000s)	PNG Assets			Other Assets		Total
Cost
Balance at December 31, 2017		648,229			15,525		663,754
Additions		30,832			586		31,418
Changes in estimate for asset retirement obligations		844			-		844
Balance at December 31, 2018		679,905			16,111		696,016
Increase in right-of-use assets (Note 3)		1,275			2,227		3,502
Additions		30,626			929		31,555
Change in estimate for asset retirement obligations (Note 14)		746			-		746
Balance at December 31, 2019		712,552			19,267		731,819

Accumulated depreciation, depletion, amortization and impairment losses
Balance at December 31, 2017		451,850			12,040		463,890
Depletion, depreciation and amortization for the year¹		31,422			992		32,414
Balance at December 31, 2018		483,272			13,032		496,304
Depletion, depreciation and amortization for the year¹		35,136			1,939		37,075
Balance at December 31, 2019		518,408			14,971		533,379

Foreign Exchange
Balance at December 31, 2017		4,602			-		4,602
Currency translation adjustments		(5,972	)		-		(5,972	)
Balance at December 31, 2018		(1,370	)		-		(1,370	)
Currency translation adjustments		3,376			-		3,376
Balance at December 31, 2019		2,006			-		2,006

Net book value
At December 31, 2018		195,263			3,079		198,342
At December 31, 2019		196,150			4,296		200,446

At December 31, 2019, the Company's market capitalization was less than its net asset value. Negative revisions due to economic factors were also noted in the Canadian CGU. These factors were identified as indicators of impairment and as a result, the Company completed impairment tests on all of its CGUs in accordance with IAS 36. It was determined that the carrying amounts of the CGUs did not exceed their fair value less costs to sell.

Neither a 5% increase in the discount rate, nor a 5% decrease in the forward price estimates used in the impairment assessments would result in an impairment loss on the West Gharib, West Bakr, North West Gharib or Canadian CGUs.

The following table discloses the carrying amount and depreciation charge for right-of-use assets by the class of underlying asset as at and for the year ended December 31, 2019:

The following table reconciles the change in TransGlobe's asset retirement obligation:

As at December 31, 2019, the entire asset retirement obligation balance related to the Company's Canadian operations. TransGlobe has estimated the net present value of its asset retirement obligation to be $13.6 million as at December 31, 2019 (2018 - $12.1 million) based on a total undiscounted future liability of $18.9 million (2018 - $18.3 million). These payments are expected to be made between 2020 and 2066. TransGlobe calculated the present value of the obligations using discount rates between 1.68% and 1.76% (2018 – 1.86% and 2.18%) to reflect the market

assessment of the time value of money as well as risks specific to liabilities that have not been included in the cash flow estimates. The inflation rate used in determining the cash flow estimate was 2% per annum (2018 – 2% per annum).

During the year ended December 31, 2019, the Company spent $0.3 million (2018 - $nil) on interest expense and paid a total cash outflow of $1.9 million (2018 - $nil) relating to lease obligations.

Accounts payable and accrued liabilities are comprised of current trade payables and accrued expenses due to third-parties. There were no amounts due to related parties as at December 31, 2019 or December 31, 2018.

The following table reconciles the changes in TransGlobe's long-term debt: ($000s)

The Company's interest-bearing loans and borrowings are measured at amortized cost.

Based on the Company's current forecast of future production and prices the estimated future debt payments on long-term debt as of December 31, 2019 are as follows:

On February 10, 2017, the Company completed a $75 million crude oil prepayment agreement between its wholly-owned subsidiary, TransGlobe Petroleum International Inc. ("TPI") and Mercuria.

TPI's obligations under the prepayment agreement are guaranteed by the Company and the subsidiaries of TPI (the "Guarantors"). The obligations of TPI and the Guarantors will be supported by, among other things, a pledge of equity held by the Company in TPI and a pledge of equity held by TPI in its subsidiaries. The funding arrangement has a term of four years, maturing March 31, 2021, and advances bear interest at a rate of LIBOR plus 6.0%. The funding arrangement is revolving with each advance to be satisfied through the delivery of crude oil to Mercuria. Further advances become available upon delivery of crude oil to Mercuria up to a maximum of $75.0 million and subject to compliance with the other terms and conditions of the prepayment agreement. The prepayment agreement was initially recognized at fair value, net of financing costs, and has

subsequently been measured at amortized cost. Financing costs of $1.5 million are being amortized over the term of the prepayment agreement using the effective interest rate method.

The Company is subject to certain financial covenants in accordance with the terms of the prepayment agreement. These covenants are tested on June 30 and December 31 of each year for the life of the prepayment agreement. The financial covenants include financial measures defined within the prepayment agreement that are not defined under IFRS. These financial measures are defined by the prepayment agreement as follows:

As at December 31, 2019 and 2018, the Company was in compliance with all the financial covenants under the prepayment agreement.

The Company is also subject to a cover ratio provision. The cover ratio, defined as the value of the Company's Egyptian forecasted entitlement crude oil production on a forward 12-month basis to the prepayment service obligations, must not be less than 1.25:1.00. Prepayment service obligations include the principal outstanding of the advances at the time and any costs, fees, expenses, interest and other amounts outstanding or forecasted to be due during the applicable prepayment period. In the event the cover ratio falls below 1.25:1.00, TransGlobe must:

The cover ratio as at December 31, 2019 is 2.73:1.00 (2018 - 2.21:1.00); the Company is in compliance with the cover ratio provision under the prepayment agreement.

As at December 31, 2019, the Company had in place a revolving Canadian reserves-based lending facility with ATB totaling C$25.0 million ($19.2 million), of which C$9.8 million ($7.5 million) was drawn. During 2019, the Company drew C$0.6 million ($0.5 million) and repaid C$2.0 million ($1.5 million) on this facility.

The facility borrowing base is re-calculated no less frequently than on a semi-annual basis of May 31 and November 30 of each year, or as requested by the lender. Lender shall notify the Company of each change in the amount of the borrowing base. In the event that the lender re-calculates the borrowing base to be an amount that is less than the borrowings outstanding under the facility, the Company shall repay the difference between such borrowings outstanding and the new borrowing base within 45 days of receiving notice of the new borrowing base.

The Company may request an extension of the term date by no later than 90 days prior to the then-current term date, and the lender may in its sole discretion agree to extend the term date for a further period of 364 days. Unless extended, before May 31, 2020, any unutilized amount of the facility will be canceled, and the amount of the facility will be reduced to the aggregate borrowings outstanding on that date. The balance of all amounts owing under the facility are due and payable in full on the date falling one year after the term date. If no extension is granted by the lender, the amounts owing pursuant to the facility are due at the maturity date. The facility bears interest at a rate of either ATB Prime or CDOR (Canadian Dollar Offered Rate) plus applicable margins that vary from 1.25% to 3.25% depending on the Company's net debt to trailing cash flow ratio. The revolving reserve-based lending facility was initially recognized at fair value, net of financing costs, and has subsequently been measured at amortized cost. Financing costs of $0.1 million were amortized over the initial term of the agreement using the effective interest rate method. The Company is subject to certain financial covenants in accordance with the terms of the agreement. These financial measures are defined by the agreement as follows:

As at December 31, 2019 and 2018, the Company was in compliance with all the financial covenants under the reserves-based lending facility.

As part of its principle business, the Company entered into arrangements and incurred obligations that will impact the Company’s future operations and liquidity. The principal commitments of the Company are as follows:

Pursuant to the PSC for North West Sitra in Egypt, the Company had a minimum financial commitment of $10.0 million and a work commitment for two wells and 300 square kilometers of 3-D seismic during the initial three-and-a-half-year exploration period, which commenced on January 8, 2015. The Company requested and received a six-month extension of the initial exploration period to January 7, 2019. The Company met its financial and operating commitments and based on well results did not elect to enter the second exploration phase. The concession was relinquished on January 7, 2019.

Pursuant to the approved South Ghazalat development lease, the Company is committed to drill one exploration well during the initial four year period of the 20 year development lease. The Company has issued a production guarantee in the amount of $1.0 million which will be released when the commitment well has been drilled.

In the normal course of its operations, the Company may be subject to litigation and claims. Although it is not possible to estimate the extent of potential costs, if any, management believes that the ultimate resolution of such contingencies would not have a material adverse impact on the results of operations, financial position or liquidity of the Company.

The Company is not aware of any material provisions or other contingent liabilities as at December 31, 2019.

The Company is authorized to issue an unlimited number of common shares with no par value. Shares in issue as at December 31, 2019 and December 31, 2018 are outlined below:

The Company operates a stock option plan (the "Plan") to provide equity-settled share-based remuneration to directors, officers and employees. The number of common shares that may be issued pursuant to the exercise of options awarded under the Plan and all other Security-Based Compensation Arrangements of the Company is 10% of the common shares outstanding from time to time. All incentive stock options granted under the Plan have a per-share exercise price equal to the weighted average trading price of the common shares for the five trading days prior to the date of grant. Each tranche of an award with different vesting dates is considered a separate grant for the calculation of fair value and the resulting fair value is amortized over the vesting period of the respective tranche.

The following tables summarize information about the stock options outstanding and exercisable at the dates indicated:

Compensation expense of $0.7 million was recorded during the year ended December 31, 2019 (2018 - $0.9 million) in general and administrative expenses in the Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss) and Changes in Shareholders’ Equity in respect of stock options. The fair value of all common stock options granted is estimated on the date of grant using the lattice-based trinomial option pricing model.

The weighted average fair value of options granted during the period and the assumptions used in their determination are noted below:

All options granted vest annually over a three-year period and expire five years after the grant date. During the year ended December 31, 2019, 0.3 million employee stock options valued at $0.5 million were exercised (2018 – nil). As at December 31, 2019 and December 31, 2018, the entire balance in contributed surplus was related to previously recognized share-based compensation expense on equity-settled stock options.

In May 2014, the Company implemented a restricted share unit ("RSU") plan, a performance share unit ("PSU") plan and a deferred share unit ("DSU") plan.

RSUs may be issued to directors, officers and employees of the Company, and each RSU entitles the holder to a cash payment equal to the fair market value of a TransGlobe common share on the vesting date of the RSU. All RSUs granted vest annually over a three-year period, and all must be settled within 30 days of their respective vesting dates.

PSUs are similar to RSUs, except that the number of PSUs that ultimately vest is dependent on achieving certain performance targets and objectives as set by the Board of Directors. Depending on performance, PSUs can vest between 0% to 200% of the original PSU grant. All PSUs granted vest on the third anniversary of their grant date, and all must be settled within 60 days of their vesting dates.

DSUs are similar to RSUs, except that they become fully vested on the date of grant and are only issued to directors of the Company. Distributions under the DSU plan do not occur until the retirement of the DSU holder from the Company's Board of Directors.

The number of RSUs, PSUs and DSUs outstanding as at December 31, 2019 are as follows:

Compensation expense of $1.6 million was recorded in general and administrative expenses in the Consolidated Statement of Earnings (Loss) and Comprehensive Income (Loss) during the year ended December 31, 2019 in respect of share units granted under the three plans described above (2018 - $2.7 million).

The weighted-average number of common shares outstanding (basic and diluted) for the year ended December 31, 2019 was 72,513,657 (2018 - basic 72,205,369; and diluted 72,631,320). These outstanding share amounts were used to calculate net earnings (loss) per share in the respective periods.

In determining diluted net earnings (loss) per share, the Company assumes that the proceeds received from the exercise of “in-the-money” stock options are used to repurchase common shares at the average market price. In calculating the weighted-average number of diluted common shares outstanding for the year ended December 31, 2019, the Company excluded 4,480,935 stock options (2018 – 1,640,000) as their exercise price was greater than the average common share market price in the year.

During the year ended December 31, 2019, the Company paid the following dividends on its common shares:

Details of controlled and consolidated entities active as at December 31, 2019 are as follows:

Key management personnel have been identified as the Board of Directors and the four executive officers of the Company.

The Company has two reportable segments for the years ended December 31, 2019 and December 31, 2018: the Arab Republic of Egypt and Canada. The Company, through its operating segments, is engaged primarily in oil exploration, development and production and the acquisition of oil and gas properties. In presenting information on the basis of operating segments, segment revenue is based on the geographical location of assets which is also consistent with the location of the segment customers. Segmented assets are also based on the geographical location of the assets. There are no inter-segment sales. The accounting policies of the operating segments are the same as the Company’s accounting policies.

	Years ended December 31
	2019			2018			2019			2018			2019			2018			2019			2018
($000s)	Egypt						Canada						Corporate						Total
Revenue
Oil sales		256,193			278,111			15,159			10,666			-			-			271,352			288,777
Natural gas sales		-			-			2,705			2,632			-			-			2,705			2,632
Natural gas liquids sales		-			-			4,872			7,735			-			-			4,872			7,735
Less: royalties		(136,616	)		(120,271	)		(2,217	)		(2,646	)		-			-			(138,833	)		(122,917	)
Petroleum and natural gas sales, net of royalties		119,577			157,840			20,519			18,387			-			-			140,096			176,227
Finance revenue		45			87			-			-			426			483			471			570
Total segmented revenue		119,622			157,927			20,519			18,387			426			483			140,567			176,797

Segmented expenses
Production and operating		43,252			45,562			7,374			7,736			-			-			50,626			53,298
Selling costs		1,287			2,103			-			-			-			-			1,287			2,103
General and administrative		6,491			4,798			901			1,134			9,219			12,756			16,611			18,688
Foreign exchange gain		-			-			-			-			(147	)		(289	)		(147	)		(289	)
Finance costs		3,767			4,635			456			440			33			-			4,256			5,075
Depletion, depreciation and amortization		26,345			26,271			7,790			7,711			813			309			34,948			34,291
Asset retirement obligation accretion		-			-			215			270			-			-			215			270
Loss on financial instruments		2,845			6,755			-			296			-			-			2,845			7,051
Impairment loss		7,937			14,500			-			-			-			-			7,937			14,500
Gain on disposition of assets		-			-			(114	)		(207	)		-			-			(114	)		(207	)
Income tax expense		26,098			26,340			-			-			-			-			26,098			26,340
Segmented net earnings (loss)		1,600			26,963			3,897			1,007			(9,492	)		(12,293	)		(3,995	)		15,677

Capital expenditures
Exploration and development		27,239			28,673			9,525			11,965			-			-			36,764			40,638
Corporate		-			-			-			-			168			68			168			68
Total capital expenditures		27,239			28,673			9,525			11,965			168			68			36,932			40,706

The carrying amounts of reportable segment assets and liabilities are as follows:

	As at December 31, 2019						As at December 31, 2018
($000s)	Egypt		Canada		Total		Egypt		Canada		Total
Assets
Accounts receivable		6,266		3,874		10,140		9,031		2,525		11,556
Derivative commodity contracts		-		-		-		1,369		-		1,369
Intangible exploration and evaluation assets		33,176		530		33,706		35,735		531		36,266
Property and equipment
Petroleum and natural gas assets		117,591		78,559		196,150		123,043		72,220		195,263
Other assets		2,847		15		2,862		2,222		22		2,244
Other		48,652		2,269		50,921		58,518		1,296		59,814
Deferred taxes		8,387		-		8,387		4,523		-		4,523
Segmented assets		216,919		85,247		302,166		234,441		76,594		311,035
Non-segmented assets						6,159						7,261
Total assets						308,325						318,296

Liabilities
Accounts payable and accrued liabilities		19,459		6,798		26,257		13,407		8,010		21,417
Derivative commodity contracts		217		-		217		-		-		-
Long-term debt		29,502		7,539		37,041		44,134		8,221		52,355
Asset retirement obligation		-		13,612		13,612		-		12,113		12,113
Lease obligation		718		276		994		-		-		-
Deferred taxes		8,387		-		8,387		4,523		-		4,523
Segmented liabilities		58,283		28,225		86,508		62,064		28,344		90,408
Non-segmented liabilities						7,327						7,597
Total liabilities						93,835						98,005

	Years ended December 31
($000s)	2019			2018
Operating activities
(Increase) decrease in current assets
Accounts receivable		1,333			6,076
Prepaids and other		637			97
Product inventory¹		(6,698	)		905
(Decrease) increase in current liabilities
Accounts payable and accrued liabilities		2,886			(1,975	)
Other long-term liabilities		(193	)		807
Total changes in non-cash working capital		(2,035	)		5,910

Investing activities
Increase (decrease) in current assets
Prepaids and other		4			(4	)
(Decrease) increase in current liabilities
Accounts payable and accrued liabilities		(295	)		255
Total changes in non-cash working capital		(291	)		251

Financing activities
Decrease in current liabilities
Other liabilities		(200	)		(3	)
Total changes in non-cash working capital		(200	)		(3	)

Signed by:

“Randy C. Neely”	“Edward D. Ok”

Randy C. Neely	Edward D. Ok
President & Chief Executive Officer	Vice President, Finance & Chief Financial Officer

March 12, 2020

“Randy C. Neely”		“Steven Sinclair”

Randy C. Neely		Steven Sinclair
President & CEO Director		Director

	December 31, 2019				December 31, 2018
Classification ($000s)	Carrying Value		Fair Value		Carrying Value		Fair Value
Financial assets at fair value through profit or loss		33,251		33,251		53,074		53,074
Financial assets at amortized cost		10,681		10,681		12,014		12,014
Financial liabilities at fair value through profit or loss		217		217		-		-
Financial liabilities at amortized cost		69,197		69,695		80,362		81,228

Financial Brent crude oil contracts
Period Hedged	Contract	Remaining Volume (bbl)		Monthly Volume (bbl)		Bought Put US$/bbl		Sold Call US$/bbl		Sold Put US$/bbl
Jul 2020 - Dec 2020	3-Way Collar		300,000		50,000		54.00		70.00		45.00
Jan 2020 - Jun 2020	3-Way Collar		300,000		50,000		54.00		70.00		46.50
Jan 2020 - Jun 2020	3-Way Collar		150,000		25,000		55.00		72.70		45.00

($000s)	December 31, 2019		December 31, 2018
Neither impaired nor past due		3,636		5,540
Not impaired and past due in the following period:
Within 30 days		226		829
31-60 days		131		212
61-90 days		5,672		102
Over 90 days		1,016		5,331
Accounts receivable		10,681		12,014

		Payment Due by Period^1,2
($000s)	Recognized in Financial Statements	Contractual Cash Flows		Less than 1 year		1-3 years		4-5 years		More than 5 years
Accounts payable and accrued liabilities	Yes-Liability		32,156		32,156		-		-		-
Long-term debt³	Yes-Liability		37,539		-		37,539		-		-
Other long-term liabilities	Yes-Liability		614		-		614		-		-
Derivative commodity contracts	Yes-Liability		217		217		-		-		-
Total			70,526		32,373		38,153		-		-

($000s)	At December 31, 2019
Less than 1 year		1,479
1 - 3 years		631
Total lease payments		2,110
Amounts representing interest		302
Present value of net lease payments		1,808
Current portion of lease obligations		1,219
Non-current portion of lease obligations		589

($000s)	Prepayment Agreement		Reserves Based Lending Facility		Total
2020		-		-		-
2021		29,502		7,539		37,041
		29,502		7,539		37,041

	2019				2018
(000s)	Shares		Amount ($)		Shares		Amount ($)
Balance, beginning of year		72,206		152,084		72,206		152,084
Stock options exercised		337		547		-		-
Contributed surplus re-class on exercise		-		174		-		-
Balance, end of year		72,543		152,805		72,206		152,084

	Options Outstanding						Options Exercisable
Exercise Price (C$)	Number Outstanding at December 31, 2019 (000s)		Weighted-Average Remaining Contractual Life (Years)		Weighted-Average Exercise price (C$)		Number Exercisable at December 31, 2019 (000s)		Weighted-Average Remaining Contractual Life (Years)		Weighted-Average Exercise price (C$)
2.16 - 2.17		826		2.4		2.16		550		2.4		2.16
2.18 - 2.41		1,002		1.2		2.19		1,002		1.2		2.19
2.42 - 3.73		966		3.4		2.62		322		3.4		2.62
3.74 - 3.91		976		4.2		2.83		-		-		-
3.92 - 4.99		711		0.4		4.99		711		0.4		4.99
		4,481		2.4		2.86		2,585		1.5		3.01

	2019			2018
Weighted average fair market value per option (C$)		0.88			0.88
Risk free interest rate		1.54	%		2.14	%
Expected volatility (based on actual historical volatility)		54.74	%		49.45	%
Dividend rate		3.30	%		-
Expected forfeiture rate (non-executive employees)		-			-
Suboptimal exercise factor		1.25			1.25

(000s)	RSUs			PSUs			DSUs
Units outstanding, December 31, 2017		970			1,376			595
Granted		410			678			225
Exercised		(361	)		(316	)		-
Forfeited		(163	)		(71	)		-
Reinvested		8			16			8
Units outstanding, December 31, 2018		864			1,683			828
Granted		400			529			190
Exercised		(381	)		(636	)		(454	)
Forfeited		(70	)		(13	)		-
Expired		(15	)		-			-
Reinvested		41			77			25
Units outstanding, December 31, 2019		839			1,640			589

Ex-dividend date	Record date	Payment date	Per share amount
March 28, 2019	March 29, 2019	April 18, 2019	$	0.035
August 29, 2019	August 30, 2019	September 13, 2019	$	0.035

	Country of Incorporation	Ownership Interest 2019	Ownership Interest 2018
TG Energy UK Ltd	United Kingdom	100%	100%
TransGlobe Petroleum International Inc.	Turks & Caicos	100%	100%
TG Holdings Yemen Inc.	Turks & Caicos	100%	100%
TransGlobe West Bakr Inc.	Turks & Caicos	100%	100%
TransGlobe West Gharib Inc.	Turks & Caicos	100%	100%
TG Holdings Egypt Inc.	Turks & Caicos	100%	100%
TG South Alamein Inc.	Turks & Caicos	100%	100%
TG South Mariut Inc.	Turks & Caicos	100%	100%
TG South Alamein II Inc.	Turks & Caicos	100%	100%
TG Energy Marketing Inc.	Turks & Caicos	100%	100%
TG NW Gharib Inc.	Turks & Caicos	100%	100%
TG SW Gharib Inc.	Turks & Caicos	100%	100%
TG SE Gharib Inc.	Turks & Caicos	100%	100%
TG S Ghazalat Inc.	Turks & Caicos	100%	100%
TransGlobe Petroleum Egypt Inc.	Turks & Caicos	100%	100%