EXHIBIT 99.2

MANAGEMENT'S REPORT

Management’s Responsibility on Financial Statements

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’s Report On Internal Control Over Financial Reporting

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, 2017.

Signed by:
“Ross G. Clarkson”	“Edward D. Ok”
Ross G. Clarkson	Edward D. Ok
Chief Executive Officer	Vice President, Finance & Chief Financial Officer
March 5, 2018

2017 1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of TransGlobe Energy Corporation

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated financial statements of TransGlobe Energy Corporation and subsidiaries (the “Company”), which comprise the consolidated balance sheets as at December 31, 2017 and December 31, 2016, the consolidated statements of loss and comprehensive loss, consolidated statements of changes in shareholders’ equity and consolidated statements of cash flows for the years then ended, and the related notes, including a summary of significant accounting policies and other explanatory information (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, 2017 and December 31, 2016, and its financial performance and its cash flows for the years then endedin accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Report on Internal Control over Financial Reporting

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, 2017, 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 5, 2018expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and 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 from material misstatement, whether due to fraud or error. Those standards also require that we comply with ethical requirements. 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. Further, we are required to be independent of the Company in accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada and to fulfill our other ethical responsibilities in accordance with these requirements.

An audit includes performing procedures to assess the risks of material misstatement of the financial statements, whether due to fraud or error, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies and principles used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a reasonable basis for our audit opinion.

/s/ Deloitte LLP

Chartered Professional Accountants

Calgary, Canada

March 5, 2018

We have served as the Company's auditor since 1999.

2 2017

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of TransGlobe Energy Corporation

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of TransGlobe Energy Corporationand subsidiaries (the “Company”) as of December 31, 2017, 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, 2017,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) and Canadian generally accepted auditing standards, the consolidated financial statements as at and for the year ended December 31, 2017, of the Company and our report dated March 5, 2018, expressed an unmodified/unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s 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.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. 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 International Financial Reporting Standards as issued by the International Accounting Standards Board, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ Deloitte LLP

Chartered Professional Accountants

Calgary, Canada

March 5, 2018

2017 3

Consolidated Statements of Loss and Comprehensive Loss

(Expressed in thousands of U.S. Dollars, except per share amounts)

	Notes	2017			2016
REVENUE
Petroleum and natural gas sales, net of royalties	8	$	148,464		$	63,134
Finance revenue	9	108			673
		148,572			63,807
EXPENSES
Production and operating	14	50,212			40,323
Transportation costs		793			12
Selling costs	10	2,495			875
General and administrative		15,253			17,555
Foreign exchange loss		194			3,607
Finance costs	9	6,233			6,068
Depletion, depreciation and amortization	17	40,036			29,177
Accretion	18	256			—
Loss on financial instruments	7, 21	10,992			7,983
Impairment of exploration and evaluation assets	16	79,025			33,426
		205,489			139,026
Loss before income taxes		(56,917		)	(75,219		)
Income tax expense (recovery) – current	15	21,819			15,455
– deferred	15	—			(3,009		)
		21,819			12,446
NET LOSS FOR THE YEAR		$	(78,736	)	$	(87,665	)
OTHER COMPREHENSIVE INCOME
Currency translation adjustments - gain		2,793			—
COMPREHENSIVE LOSS FOR THE YEAR		$	(75,943	)	$	(87,665	)
Loss per share	25
Basic		$	(1.09	)	$	(1.21	)
Diluted		$	(1.09	)	$	(1.21	)

See accompanying notes to the Consolidated Financial Statements.

4 2017

Consolidated Balance Sheets

(Expressed in thousands of U.S. Dollars)

		As at		As at
	Notes	December 31, 2017		December 31, 2016
ASSETS
Current
Cash and cash equivalents	11	$	47,449	$	31,468
Restricted cash	13	—		18,323
Accounts receivable	7, 12	18,090		14,836
Prepaids and other		4,745		1,772
Product inventory	14	11,474		19,602
		81,758		86,001
Non-Current
Intangible exploration and evaluation assets	16	41,478		105,869
Property and equipment	17
Petroleum and natural gas assets		200,981		210,027
Other assets		3,485		4,245
		$	327,702	$	406,142
LIABILITIES
Current
Accounts payable and accrued liabilities	19	$	27,104	$	24,529
Convertible debentures	21	—		72,655
Derivative commodity contracts	7	4,015		—
Current portion of note payable	20	—		5,581
		31,119		102,765
Non-Current
Derivative commodity contracts	7	3,955		—
Note payable	20	—		5,581
Long-term debt	20	69,999		—
Asset retirement obligation	18	12,332		12,099
Other long-term liabilities		290		381
		117,695		120,826
SHAREHOLDERS’ EQUITY
Share capital	23	152,084		152,084
Accumulated other comprehensive income		2,793		—
Contributed surplus		23,329		22,695
Retained earnings		31,801		110,537
		210,007		285,316
		$	327,702	$	406,142

See accompanying notes to the Consolidated Financial Statements.

Approved on behalf of the Board:

Signed by:

“Ross G. Clarkson”	“Fred J. Dyment”
Ross G. Clarkson	Fred J. Dyment
CEO	Director
Director

2017 5

Consolidated Statements of Changes in Shareholders’ Equity

(Expressed in thousands of U.S. Dollars)

	Notes	2017			2016
Share Capital
Balance, beginning of year	23	$	152,084		$	152,084
Balance, end of year		$	152,084		$	152,084
Accumulated Other Comprehensive Income
Balance, beginning of year		$	—		$	—
Currency translation adjustment - gain		2,793			—
Balance, end of year		$	2,793		$	—
Contributed Surplus
Balance, beginning of year		$	22,695		$	21,398
Share-based compensation expense	24	634			1,297
Balance, end of year		$	23,329		$	22,695
Retained Earnings
Balance, beginning of year		$	110,537		$	198,202
Net loss		(78,736		)	(87,665		)
Balance, end of year		$	31,801		$	110,537

See accompanying notes to the Consolidated Financial Statements.

6 2017

Consolidated Statements of Cash Flows

(Expressed in thousands of U.S. Dollars)

		Year Ended			Year Ended
	Notes	December 31, 2017			December 31, 2016
CASH FLOWS RELATED TO THE FOLLOWINGACTIVITIES:
OPERATING
Net loss for the year		$	(78,736	)	$	(87,665	)
Adjustments for:
Depletion, depreciation and amortization	17	40,036			29,177
Accretion	18	256			—
Deferred lease inducement		(91		)	(95		)
Impairment of exploration and evaluation assets	16	79,025			33,426
Stock-based compensation	24	1,478			2,418
Finance costs	9	6,233			6,068
Income tax expense	15	21,819			12,446
Loss on financial instruments	7, 21	8,121			7,027
Unrealized (gain) loss on foreign currency translation		(35		)	4,292
Asset retirement obligations settled	18	(695		)	—
Income taxes paid		(21,819		)	(15,455		)
Changes in non-cash working capital	29	3,858			7,296
Net cash generated by (used in) operating activities		59,450			(1,065		)
INVESTING
Additions to intangible exploration and evaluation assets	16	(16,905		)	(19,425		)
Additions to petroleum and natural gas assets	17	(20,301		)	(6,618		)
Additions to other assets	17	(953		)	(615		)
Property acquisitions	6	—			(48,313		)
Changes in restricted cash	13	18,323			(17,462		)
Changes in non-cash working capital	29	(1,587		)	5,556
Net cash used in investing activities		(21,423		)	(86,877		)
FINANCING
Repayment of note payable	20	(11,041		)	—
Financing costs	9	(1,554		)	—
Interest paid		(6,952		)	(5,288		)
Proceeds from long-term debt	20	85,328			—
Repayment of convertible debentures	21	(73,375		)	—
Repayments of long-term debt	20	(15,000		)	—
Net cash used in financing activities		(22,594		)	(5,288		)
Currency translation differences relating to cash and cash equivalents		548			(2,212		)
NET INCREASE (DECREASE) IN CASH AND CASHEQUIVALENTS		15,981			(95,442		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		31,468			126,910
CASH AND CASH EQUIVALENTS, END OF YEAR		$	47,449		$	31,468

See accompanying notes to the Consolidated Financial Statements.

2017 7

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2017 and December 31, 2016 and for the years then ended

(Expressed in U.S. Dollars)

1. CORPORATE INFORMATION

TransGlobe Energy Corporation (the "Company "or" TransGlobe") is a publicly listed company incorporated in Alberta, Canada and its shares are listed on the Toronto Stock Exchange (“TSX”) and the Global Select Market of the NASDAQ Stock Market (“NASDAQ”). The address of its registered office is 2300, 250 – 5th Street SW, Calgary, Alberta, Canada, T2P 0R4. TransGlobe together with its subsidiaries is engaged primarily in oil and gas exploration, development and production and the acquisition of oil and gas properties.

2. BASIS OF PREPARATION

Statement of compliance

These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board effective as of December 31, 2017.

These Consolidated Financial Statements were authorized for issue by the Board of Directors on March 5, 2018.

Basis of measurement

The accounting policies used in the preparation of these Consolidated Financial Statements are described in Note 3, Significant Accounting Policies.

The Company prepared these 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, these Consolidated Financial Statements have been prepared on a historical cost basis, except for cash and cash equivalents, derivative commodity contracts and former convertible debentures that have been measured at fair value. The method used to measure fair value is discussed further in Notes 3 and 7.

Presentation currency

In these Consolidated Financial Statements, unless otherwise indicated, all dollar amounts are presented and expressed in United States (U.S.) dollars. All references to $ are to United States dollars and references to C$ are to Canadian dollars and all values are rounded to the nearest thousand except when otherwise indicated.

3. SIGNIFICANT ACCOUNTING POLICIES

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

Basis of consolidation

Subsidiaries are entities controlled by the Company. 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 of the subsidiaries of the Company are wholly-owned by the parent company, TransGlobe Energy Corporation. The Consolidated Financial Statements include the financial statements of the Company and its wholly-owned, controlled subsidiaries.

The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.

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

Joint operations

The Company conducts many of its oil and gas production activities through joint operations and the Consolidated Financial Statements reflect only the Company's share in such activities.

Foreign currency translation

The Consolidated Financial Statements are presented in U.S. dollars. Effective January 1, 2017, TransGlobe Energy Corporation's functional currency is the Canadian dollar, and the functional currency of all subsidiaries is the U.S. dollar. It was determined that TransGlobe Energy Corporation's functional currency is now the Canadian dollar because the parent company now owns Canadian producing assets, and therefore generates revenues and incurs costs that are largely denominated in Canadian dollars.

Foreign currency translations include the translation of foreign currency transactions and the translation of the Canadian operations functional currency, which is Canadian dollars. 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. Translations occur as follows:

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

• Non-monetary assets or liabilities are carried at the prevailing rates on the date of the transaction

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

8 2017

Translation gains and losses from Canadian operations occur when translating the financial statements of TransGlobe Energy Corporation (non-U.S. functional currency) 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 Loss and Comprehensive Loss. Translations occur as follows:

• Income and expenses are translated at the average exchange rates for the period

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

Cash and cash equivalents

Cash and cash equivalents includes cash and short-term, highly liquid investments that mature within three months of the date of their purchase.

Restricted cash

Restricted cash represents a cash collateralized letter of credit facility that is used to guarantee the Company's commitments on its Egyptian exploration concessions.

Financial instruments

Non-derivative financial instruments

Non-derivative financial instruments comprise cash and cash equivalents, accounts receivable, restricted cash, accounts payable and accrued liabilities, long-term debt, the former note payable and previous convertible debentures. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs. Subsequent to initial recognition non-derivative financial instruments are measured as described below.

Financial assets and liabilities at fair value through profit or loss

An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition, such as cash and cash equivalents, derivative commodity contracts and the former convertible debentures. Financial instruments are designated at fair value through profit or loss if the Company makes purchase and sale decisions based on their fair value in accordance with the Company's documented risk management strategy. Upon initial recognition, any transaction costs attributable to the financial instruments are recognized through earnings when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in earnings.

Other

Other non-derivative financial instruments, such as accounts receivable, accounts payable and accrued liabilities, long-term debt, the prior note payable and restricted cash are measured initially at fair value, then at amortized cost using the effective interest method, less any impairment losses.

Derivative financial instruments

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. Attributable transaction costs are recognized in earnings 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. Changes in the fair value of separable embedded derivatives are recognized immediately in profit or loss.

Share capital

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as a deduction from equity. When the Company acquires and cancels its own common shares, share capital is reduced by the cost of shares repurchased, including transaction costs.

Property and equipment and intangible exploration and evaluation assets

Exploration and evaluation assets

Exploration and evaluation ("E&E") costs related to each license/prospect are initially capitalized within "intangible exploration and evaluation assets." Such E&E costs may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, directly attributable expenses, including remuneration of production personnel and supervisory management, and the projected costs of retiring the assets (if any), but do not include pre-licensing costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to earnings as they are incurred and presented as exploration expenses on the Consolidated Statements of Loss and Comprehensive 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. 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. Intangible exploration and evaluation assets are transferred to petroleum properties as development and production ("D&P") assets upon determination of technical feasibility and commercial viability. The intangible E&E assets being transferred to D&P assets are subject to impairment testing upon transfer.

2017 9

Petroleum and natural gas assets

Petroleum and natural gas ("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.

Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property and equipment are recognized as petroleum properties or other assets only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized property and equipment generally represent costs incurred in developing Proved and/or Probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a well, field or geotechnical area basis, together with the discounted value of estimated future costs of asset retirement obligations. When components of PNG assets are replaced, disposed of, or no longer in use, the carrying amount is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

Depletion, depreciation and amortization

The depletion, depreciation and amortization of PNG assets and other assets are recognized in 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 reserve 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.

Proved and probable reserves are estimated using independent reserve evaluator reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially viable. The specified degree of certainty must be a minimum 90% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and a minimum 50% statistical probability for proved and probable reserves to be considered commercially viable.

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

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

Product inventory

Product inventory consists of the Company's unsold Egypt entitlement crude oil barrels, which is valued at the lower of cost, using the first-in, first-out method, and net realizable value. Cost includes operating expenses and depletion associated with the entitlement crude oil barrels as determined on a concession by concession basis.

Impairment

Financial assets carried at amortized cost

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events has had a negative effect on the estimated future cash flows of the asset.

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.

All impairment losses are recognized in profit or loss. An impairment loss may be reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. Any such reversal is recognized in profit or loss.

10 2017

Non-financial assets

The carrying amounts of the Company’s non-financial assets are reviewed at each reporting date to determine whether there is any indication of impairment, except for E&E assets, which are reviewed when circumstances indicate impairment may exist and at least annually, as discussed in more detail below. If any such indication exists, then the asset’s recoverable amount is estimated.

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 pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.

For D&P 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 reclassified to petroleum properties and also if facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount. Impairment indicators are evaluated at a CGU level. Indications of impairment include:

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

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

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

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

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 profit or loss.

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

Share-based payment transactions

Equity-settled transactions

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

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

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

Cash-settled transactions

The cost of cash-settled transactions is measured at fair value using the lattice-based trinomial pricing model and recognized as an expense over the vesting period, with a corresponding liability recognized on the 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 and accrued 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. The liability is measured at each reporting date with changes to fair value recognized through profit or loss until it is ultimately settled.

Provisions and asset retirement obligations

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax 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 property, plant and equipment 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 recorded is increased each reporting period due to the passage of time and this change is charged to net earnings (loss) in the period as 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

2017 11

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. The Company discounts the costs related to asset retirement obligations using the discount rate that reflects the current market assessment of the time value of money and risks specific to the liabilities that have not been reflected in the cash flow estimates. The Company applies discount rates applicable to each of the jurisdictions in which it has future asset retirement obligations. Asset retirement obligations are remeasured at each reporting period in order to reflect the discount rates in effect at that time.

Future abandonment and reclamation costs have been assessed at zero value in Egypt. 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 abandonment of assets or reclamation of lands upon termination of the PSCs.

Revenue recognition

Canada

Revenues from the sale of petroleum and natural gas are recorded when title to the products transfers to the purchasers based on volumes delivered and contracted delivery points and prices. Revenue is measured at the fair value of the consideration received or receivable. Revenue from the sale of crude oil, natural gas, condensate and natural gas liquids ("NGLs") (prior to deduction of transportation costs) is recognized when all of the following conditions have been satisfied:

• The Company has transferred the significant risks and rewards of ownership of the goods to the buyer;

• The Company retains no continuing managerial involvement to the degree usually associated with ownership or effective control over the goods sold;

• The amount of revenue can be measured reliably;

• It is probable that the economic benefits associated with the transaction will flow to the Company; and

• The costs incurred or to be incurred in respect of the transaction can be measured reliably.

Capital processing charges to other entities for use of facilities owned by TransGlobe are recognized as revenue as they accrue in accordance with the terms of the service agreements and are presented as other income.

Egypt

Revenues associated with the sales of the Company's crude oil are recognized by reference to actual volumes produced and quoted market prices in active markets for identical assets, adjusted according to specific terms and conditions as applicable, when the significant risks and rewards of ownership have been transferred, which is when title passes from the Company to its customer. Crude oil produced and sold by the Company below or above its working interest share in the related resource properties results in production under-liftings or over-liftings. Under-liftings are recorded as inventory and over-liftings are recorded as deferred revenue or used to offset receivables.

Pursuant to the PSCs associated with the Company's operations, the Company and other non-governmental partners (if applicable) pay all operating and capital costs for exploration and development. Each PSC establishes specific terms for the Company to recover these costs (Cost Recovery Oil) and to share in the production sharing oil. Cost Recovery Oil is determined in accordance with a formula that is generally limited to a specified percentage of production during each fiscal year. Production sharing oil is that portion of production remaining after Cost Recovery Oil and is shared between the joint interest partners and the government of Egypt, varying with the level of production. Production sharing oil that is attributable to the government includes an amount in respect of all income taxes payable by the Company under the laws of the respective country. Revenue represents the Company's share and is recorded net of royalty payments to the respective government. For the Company's international operations, all government interests, except for income taxes, are considered royalty payments. The Company's revenue also includes the recovery of costs paid on behalf of foreign governments in international locations.

Transportation

Costs paid by TransGlobe for the transportation of crude oil, natural gas, condensate and NGLs to the point of title transfer are recognized when the transportation is provided.

Finance revenue and costs

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

Finance costs comprises interest expense on borrowings.

Borrowing costs incurred for qualifying assets are capitalized during the period of time that is required to complete and prepare the assets for their intended use or sale. Qualifying assets are those that necessarily take a substantial period of time to get ready for their intended use or sale. All other borrowing costs are recognized in earnings using the effective interest method.

12 2017

Royalties

Canada

Royalties are recorded at the time the product is produced and sold. Royalties are calculated in accordance with the applicable regulations and/or the terms of individual royalty agreements. Crown royalties for natural gas, condensate and other associated liquids are based on Alberta Government posted reference prices as all of the Company's producing assets are in Alberta.

Egypt

For the Company’s international operations, all government interests, except for income taxes, are considered royalty payments. Government interests are determined in accordance with the respective PSCs.

Income tax

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

Current tax

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

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

Deferred tax

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

Joint arrangements

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

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

In Canada, the Company conducts many of its oil and gas production activities through jointly controlled operations and the financial statements reflect only the Company's proportionate interest in such activities. Joint control exists for contractual 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 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 currently existing joint arrangements where the Company has rights to net assets. Accordingly, all joint arrangements have been classified as joint operations, and the Company has recognized in the Consolidated Financial Statements its share of all revenues, expenses, assets and liabilities in accordance with the PSCs.

Business combinations

Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities and contingent liabilities assumed are measured at their fair values at the acquisition date. The cost of an acquisition is measured as the aggregate consideration transferred, measured at the acquisition date fair value. If the cost of the acquisition is less than the fair value of the net assets acquired, the difference is recognized immediately in net earnings. If the cost of the acquisition is more than the fair value of the net assets acquired, the difference is recognized on the balance sheet as goodwill. Acquisition costs incurred are expensed.

4. CRITICAL JUDGMENTS AND ACCOUNTING ESTIMATES

Timely preparation of the 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 financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. The effect of these estimates,

2017 13

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 material adjustment to the carrying amounts of assets and liabilities are discussed below.

Recoverability of asset carrying values

The recoverability of development and production 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:

• geographic proximity of the assets within a group to one another;

• geographic proximity of the group of assets to other groups of assets; and

• homogeneity of the production from the group of assets and the sharing of infrastructure used to process and/or transport production.

In Egypt, each production sharing concession ("PSC") is considered a separate CGU. In Canada, CGUs are determined by regional geography. 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, 2017 and December 31, 2016, 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 reserve evaluator.

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

• Reserves - There are numerous uncertainties inherent in estimating oil and gas reserves. An external reserve engineering report which incorporates a full evaluation of reserves is prepared on an annual basis with internal reserve updates completed at each quarterly period. Estimating reserves is highly complex, requiring many judgments including forward price estimates, production costs, and recovery rates based on available geological, geophysical, engineering and economic data. Changes in these judgments may have a material impact on the estimated reserves. These estimates may change, resulting in either negative or positive impacts to net earnings as further information becomes available and as the economic environment changes.

• Commodity prices - Forward price estimates of crude oil and natural gas prices are incorporated into the determination of expected future net cash flows. Commodity prices have fluctuated significantly in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, foreign exchange rates, economic, and geopolitical factors.

• Discount rate - The discount rate used to determine the net present value of future cash flows is based on the Company's estimated weighted average cost of capital. Changes in the economic environment could change the Company's weighted average cost of capital.

Impairment tests were carried out at December 31, 2017 and were based on fair value less costs to sell calculations, using a discount rate of 10% for Canada and 15% for Egypt on future after-tax cash flows and the following forward commodity price estimates:

	Egypt1		Canada1
	Oil		Oil		Gas		Condensate		Butane		Propane		Ethane
Year	$US/Bbl		$US/Bbl		$US/Mcf		$US/Bbl		$US/Bbl		$US/Bbl		$US/Bbl
2018	53.76		54.30		1.63		58.80		38.07		31.88		4.53
2019	51.92		54.27		1.91		57.41		34.37		28.83		5.46
2020	51.41		54.98		2.21		57.81		34.70		28.70		6.45
2021	54.28		57.69		2.52		60.81		36.53		29.17		7.50
2022	57.16		60.65		2.75		63.65		38.36		29.71		8.23
Thereafter (%)2	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%
1 GLJ Petroleum Consultants Ltd. (“GLJ”) price forecasts, effective December 31, 2017.
2 Percentage change represents the increase in each year after 2022 to the end of the reserve life.

Depletion of petroleum properties

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 reserve evaluator. See above for discussion of estimates and judgments involved in reserve estimation.

Income taxes

Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the 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

2017 14

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 earnings.

Business combinations

Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant, and equipment, and exploration and evaluation assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities in the purchase price allocation, and any resulting gain or goodwill. Future net earnings can be affected as a result of changes in future depletion, depreciation and accretion, and asset impairments.

Financial instruments

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.

Share-based payments

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.

Asset retirement obligations

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.

Recoverability of accounts receivable

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.

5. NEW STANDARDS AND INTERPRETATIONS NOT YET ADOPTED

Future changes to accounting policies

As at the date of authorization of the Consolidated Financial Statements the following pronouncements from the International Accounting Standards Board ("IASB") are applicable to TransGlobe and will become effective for future reporting periods, but have not yet been adopted:

IFRS 9 (revised) "Financial Instruments: Classification and Measurement"

In July 2014, the IASB issued the final version of IFRS 9 Financial Instruments to replace IAS 39 Financial Instruments: Recognition and Measurement. IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. For financial liabilities, IFRS 9 retains most of the IAS 39 requirements; however, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in other comprehensive income rather than net earnings, unless this creates an accounting mismatch. In addition, a new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. The Company does not currently apply hedge accounting. IFRS 9 is effective for years beginning on or after January 1, 2018. This amendment will be adopted by the Company on January 1, 2018 and the Company does not expect the adoption of IFRS 9 amendments to have a material effect on its Consolidated Financial Statements.

IFRS 15 "Revenue from Contracts with Customers"

IFRS 15 was issued in May 2014 and replaces IAS 18 Revenue, IAS 11 Construction Contracts and related interpretations. The standard is required to be adopted either retrospectively or using a modified transaction approach. IFRS 15 will be adopted by the Company on January 1, 2018. The Company is finalizing the review of its sales contracts with customers and does not expect IFRS 15 will have a material impact on the consolidated financial statements. Upon adoption, the Company will expand its disclosures in the notes to the consolidated financial statements including disaggregated revenue streams by product type and any impairment losses recognized on receivables arising from contracts with customers.

IFRS 16 "Leases"

In January 2016, the IASB issued IFRS 16 Leases, replacing IAS 17 Leases. IFRS 16 establishes a set of principles that both parties to a contract apply to provide relevant information about leases in a manner that faithfully represents those transactions. The current standard (IAS 17) requires lessees and lessors to classify their leases as either finance leases or operating leases, with separate accounting treatment depending on the classification of the lease. Under the new standard, the accounting treatment associated with an operating lease will no longer exist, and lessees will be required to recognize assets and liabilities associated with all leased items. The standard is effective for fiscal years beginning on or after

2017 15

January 1, 2019 with early adoption permitted if the Company is also applying IFRS 15 Revenue from Contracts with Customers. IFRS 16 will be adopted by the Company on January 1, 2019 and the Company is currently reviewing contracts that are identified as leases.

6. BUSINESS COMBINATION

In a transaction that closed on December 20, 2016 (effective date of December 1, 2016), TransGlobe completed the acquisition of production and working interests in certain facilities in the Cardium light oil and Mannville liquids rich gas assets in the Harmattan area of west central Alberta for total consideration of $59.5 million after adjustments. The acquisition was funded by $48.3 million cash from the balance sheet and a 10%, 24-month vendor take back loan of $11.2 million.

In accordance with IFRS, a transaction is accounted for as a business combination when certain criteria are met, such as the acquisition of inputs and processes to convert those inputs into beneficial outputs. TransGlobe assessed the property acquisition and determined that it constitutes a business combination under IFRS. In a business combination, acquired assets and liabilities are recognized by the acquirer at their fair market value at the time of purchase. Any variance between the determined fair value of the assets and liabilities and the purchase price is recognized as either goodwill or a gain in the statement of comprehensive income in the period of acquisition.

The estimated fair value of the property, plant and equipment acquired through the transaction was determined based on the present value of the expected future cash flows associated with the acquired property using both internal estimates and an independent reserve evaluation. The decommissioning liabilities assumed were determined using the timing and estimated costs associated with the abandonment, restoration and reclamation of the wells and facilities acquired. The total net fair value of the acquired property was equal to the consideration paid by the Company. As a result, no bargain purchase gain or goodwill was recognized for the year ended December 31, 2016 relating to the acquisition.

The consideration paid and fair values of the identifiable assets acquired and liabilities assumed by the Company are as follows:

(000s)
Consideration paid
Cash paid to vendor	$	48,313
Vendor take back loan	11,162
	$	59,475
Net assets acquired
Petroleum and natural gas assets	$	71,564
Asset retirement obligations assumed	(12,089		)
	$	59,475

For the year ended December 31, 2016, if the acquisition had been effective January 1, 2016, the Company would have realized an estimated additional $17.2 million (unaudited) of production revenue and an estimated additional $7.9 million (unaudited) of net operating income before tax. Between the acquisition date of December 20, 2016 and December 31, 2016, approximately $0.6 million of production revenue and $0.2 million of net operating income before tax was recognized relating to the acquired properties.

7. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair Values of Financial Instruments

The Company has classified its cash and cash equivalents as assets at fair value through profit or loss, its derivative commodity contracts and former convertible debentures as financial liabilities at fair value through profit or loss, which are both measured at fair value with changes being recognized through earnings. Accounts receivable and restricted cash are classified as loans and receivables; accounts payable and accrued liabilities, long-term debt and the previous note payable are classified as other liabilities, all of which are measured initially at fair value, then at amortized cost after initial recognition. Transaction costs attributable to financial instruments classified as fair value through profit or loss are included in the recognized amount of the related financial instrument and recognized over the life of the resulting financial instrument using the effective interest method.

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

	December 31, 2017				December 31, 2016
	Carrying		Fair		Carrying		Fair
Classification (000s)	Value		Value		Value		Value
Financial assets at fair value through profit or loss	$	47,449	$	47,449	$	31,468	$	31,468
Loans and receivables	18,090		18,090		33,159		33,159
Financial liabilities at fair value through profit or loss	7,970		7,970		72,655		72,655
Other liabilities	97,103		98,329		35,691		35,691

Assets and liabilities at December 31, 2017 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

2017 16

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, derivative commodity contracts and prior convertible debentures are assessed on the fair value hierarchy described above. TransGlobe’s cash and cash equivalents and former convertible debentures 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.

Derivative commodity contracts

In conjunction with the prepayment agreement (Note 20), TPI has also entered into a marketing contract with Mercuria Energy Trading S.A. ("Mercuria") to market nine million barrels of TPI’s Egypt entitlement production. The pricing of the crude oil sales will be based on market prices at the time of sale.

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 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.

There were eleven outstanding derivative commodity contracts as at December 31, 2017 (December 31, 2016 - nil), the fair values of which have been presented as liabilities on the Consolidated Balance Sheet.

The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at December 31, 2017:

Financial Brent Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume bbl	Bought Put USD$/bbl	Sold Call USD$/bbl	Sold Put USD$/bbl
7-Apr-17	Mar-18	3-Way Collar	250,000	53.00	61.15	44.00
12-Apr-17	Jun-18	3-Way Collar	250,000	54.00	63.10	45.00
12-Apr-17	Sep-18	3-Way Collar	250,000	54.00	64.15	45.00
12-Apr-17	Dec-18	3-Way Collar	250,000	54.00	65.45	45.00
23-May-17	Jul 2020 - Dec 20201	3-Way Collar	300,000	54.00	63.45	45.00
31-Aug-17	Jan 2020 - Jun 20202	3-Way Collar	300,000	54.00	61.25	46.50
12-Oct-17	Jan 2019 - Dec 20193	3-Way Collar	396,000	53.00	62.10	46.00
26-Oct-17	Jan 2019 - Dec 20194	3-Way Collar	399,996	54.00	61.35	46.00
1. 50,000 bbls per calendar month through Jul 2020 - Dec 2020
2. 50,000 bbls per calendar month through Jan 2020 - Jun 2020
3. 33,000 bbls per calendar month through Jan 2019 - Dec 2019
4.33,333 bbls per calendar month through Jan 2019 - Dec 2019

Financial WTI Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume bbl	Sold Swap USD$/bbl	Bought Put CAD$/bbl	Sold Call CAD$/bbl
15-Dec-17	Jan 2018 - Dec 20181	Swap	60,225	56.35	—	—
15-Dec-17	Jan 2018 - Dec 20181	Put Option	60,225	—	64.00	—
15-Dec-17	Jan 2018 - Dec 20181	Call Option	60,255	—	—	78.85
1. 165 bbls per day

The loss on financial instruments for 2017 and 2016 was comprised of the following:

(000's)	December 31, 2017	December 31, 2016
Realized derivative loss on commodity contracts settled during the year	2,871	956
Unrealized derivative loss on commodity contracts outstanding at the end of the year	7,970	—
Fair value adjustment on convertible debentures - (Note 21)	151	7,027
	10,992	7,983

Overview of Risk Management

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:

• Credit risk

• Market risk

• Liquidity risk

2017 17

This note presents information about the Company’s exposure to each of the above risks, the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital. Further quantitative disclosures are included throughout these Consolidated Financial Statements.

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

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 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 on the 25th day of the month following production. 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.

Trade and other receivables are analyzed in the table below. The majority of the overdue receivables are due from the Egyptian General Petroleum Company ("EGPC"). The political transition and resultant economic malaise in the country that began in 2011 resulted in irregular collection of accounts receivable from EGPC and generally a larger receivable balance, which increased TransGlobe's credit risk. Despite these factors, the Company expects to collect in full all receivables outstanding from EGPC.

In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. The Company completed three separate direct crude sale shipments to third party buyers in 2017. Depending on the Company's assessment of the credit of crude cargo buyers, buyers may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. During 2017, the Company sold an additional 1,121,391 barrels of inventoried entitlement crude oil to EGPC for $48.5 million to cover in-country expenditures. The Company collected $47.8 million of accounts receivable from EGPC during 2017. As at December 31, 2017, $14.2 million of the total accounts receivable balance of $18.1 million is due from EGPC. The Company anticipates that direct sales will continue to reduce outstanding accounts receivable and credit risk in future periods.

(000s)	December 31, 2017		December 31, 2016
Neither impaired nor past due	$	10,534	$	620
Impaired (net of valuation allowance)
Not impaired and past due in the following period:
Within 30 days	3,804		—
31-60 days	2,575		—
61-90 days	—		—
Over 90 days	1,177		14,216
	$	18,090	$	14,836

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

Market risk

Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a 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 objective of market risk management is to manage and control market risk exposures within acceptable parameters, while optimizing the return.

Commodity price risk

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 earnings. 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 counter-parties 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.

18 2017

Foreign currency exchange risk

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, former convertible debentures, 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 the net loss for the year ended December 31, 2017 by approximately $0.5 million and conversely a 10% decrease in the value of the Canadian dollar against the U.S. dollar would decrease the net loss by $0.4 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. 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 2017 was $0.8 million (2016 - $3.9 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 the net loss for the year ended December 31, 2017 by approximately $0.1 million and conversely a 10% decrease in the value of the Egyptian pound against the U.S. dollar would decrease the net loss by $0.1 million for the same period. The Company does not currently utilize derivative instruments to manage foreign currency exchange risk.

Interest rate risk

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 2017 to mitigate interest rate risk. When assessing interest rate risk applicable to the Company’s variable interest, U.S. dollar-denominated debt the Company believes 1% volatility is a reasonable measure. The effect of interest rates increasing by 1% would decrease the Company’s net earnings, for the year ended December 31, 2017, by $0.5 million and conversely the effect of interest rates decreasing by 1% would increase the Company’s net earnings, for the year ended December 31, 2017, by $0.5 million.

Liquidity risk

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, 2017:

(000s)		Payment Due by Period1 2
	Recognized
	in Financial	Contractual		Less than
	Statements	Cash Flows		1 year		1-3 years		4-5 years
Accounts payable and accrued liabilities	Yes - Liability	$	27,104	$	27,104	$	—	$	—
Long-term debt	Yes - Liability	69,999		—		11,207		58,792
Financial derivative instruments	Yes - Liability	7,970		4,015		3,955		—
Office and equipment leases3	No	3,587		1,707		1,880		—
Minimum work commitments4	No	5,129		5,129		—		—
Total		$	113,789	$	37,955	$	17,042	$	58,792
1  Payments exclude on-going operating costs, finance costs and payments required to settle derivatives.
2  Payments denominated in foreign currencies have been translated at December 31, 2017 exchange rates.
3  Office and equipment leases include all drilling rig contracts.
4   Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations (see Note 22).

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.

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 Energy Trading SA ("Mercuria") of Geneva, Switzerland. The initial advance under the prepayment agreement was used to repay the 6.0% convertible debentures of the Company which matured on March 31, 2017 and thereafter for working capital purposes of the Company and its subsidiaries (Note 20).

The Company entered into a credit agreement for a revolving reserves-based lending facility with Alberta Treasury Branches ("ATB") totaling

C$30.0 million, of which C$13.6 million was drawn on May 16, 2017 to repay the remaining outstanding vendor take-back note balance in

full (Note 20).

The Company terminated its Borrowing Base Facility in December 2016. There were no amounts drawn on the Borrowing Base Facility at any time in 2016.

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

2017 19

Capital disclosures

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 relies on cash flow to fund its capital investments. However, due to long lead cycles of some of its developments and corporate acquisitions, the Company’s capital requirements may exceed its cash flow generated in any one period. This requires the Company to maintain financial flexibility and liquidity.

The Company sets the amount of capital in proportion to risk and has historically managed to ensure that the total of the long-term debt is not greater than two times the Company’s funds flow from operations for the trailing twelve months. For the purposes of measuring the Company’s ability to meet the above stated criteria, funds flow from operations is defined as cash generated from operating activities before changes in non-cash working capital. TransGlobe’s net debt to funds flow from operations ratio continued to improve throughout the year and was positive 0.3 at December 31, 2017 (December 31, 2016 - negative 12.0) as a result of positive funds flow from operations for the year. The Company remains in a strong financial position due to prudent capital resource management. The Company's capital programs are funded by its existing working capital and cash provided from operating activities.

TransGlobe considers funds flow from operations to be a key measure of operating performance as it demonstrates the Company's ability to generate the necessary funds for sustaining capital, future growth through capital investment, and to repay debt. Management believes that such a measure provides an insightful assessment of TransGlobe's operations on a continuing basis by eliminating certain non-cash charges and actual settlements of ARO, the extent and timing of which, in the opinion of Management, is discretionary. Funds flow from operations is not a standardized measure and therefore may not be comparable with the calculation of similar measures by other entities.

The Company defines and computes its capital as follows:

(000s)	2017			2016
Long-term debt, including the current portion (net of unamortized transaction costs)	69,999			—
Long-term note payable, including the current portion	—			11,162
Convertible debentures	—			72,655
Working capital	(50,639		)	16,764
Net debt obligations	$	19,360		$	100,581
Shareholders’ equity	210,007			285,316
Total capital	$	229,367		$	385,897

The Company’s net debt-to-funds flow ratio is computed as follows:

(000s)	2017			2016
Long-term debt, including the current portion (net of unamortized transaction costs)	$	69,999		$	—
Long-term note payable, including the current portion	—			11,162
Convertible debentures	—			72,655
Working capital	(50,639		)	16,764
Net debt obligations	19,360			100,581
Cash flow from operating activities	59,450			(1,065		)
Changes in non-cash working capital	(3,858		)	(7,296		)
Funds flow from operations (Note 28)	$	55,592		$	(8,361	)
Ratio	0.3			(12.0		)

The Company’s financial objectives and strategy as described above have remained substantially unchanged over the last two completed fiscal years. These objectives and strategy are reviewed on an annual basis. The Company's debt to funds flow from operations ratio continued to improve from the prior year. 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 RBL as at December 31, 2017. The Company was in compliance with all financial covenants at December 31, 2017 (Note 20).

8. PETROLEUM AND NATURAL GAS SALES

(000s)	2017		2016
Petroleum and natural gas sales	$	252,591	$	122,360
Less: Royalties	104,127		59,226
Petroleum and natural gas sales, net of royalties	$	148,464	$	63,134

9. FINANCE REVENUE AND COSTS

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

Finance costs recognized in earnings were as follows:

20 2017

(000s)	2017		2016
Interest on convertible debenture	$	1,089	$	4,418
Interest on long-term debt	3,994		—
Interest on note payable	532		140
Interest on reserves-based lending facility	289		—
Interest on borrowing base facility	—		786
Amortization of deferred financing costs	329		724
Finance costs	$	6,233	$	6,068

10. SELLING COSTS

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 three direct crude sales to third party buyers, which were marketed by Mercuria during the year ended December 31, 2017; and three direct crude sales to third party buyers during the year ended December 31, 2016.

11. CASH AND CASH EQUIVALENTS

(000s)	December 31, 2017		December 31, 2016
Cash	$	46,051	$	31,392
Cash equivalents	1,398		76
	$	47,449	$	31,468

As at December 31, 2017 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.

12. ACCOUNTS RECEIVABLE

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, 2017 or December 31, 2016.

As at December 31, 2017, the Company was utilizing $5.1 million of its accounts receivable from EGPC as a guarantee to support work commitments on the North West Sitra concession (see Note 22).

The Company’s exposure to credit, currency and interest rate risks related to trade and other receivables is disclosed in Note 7, Financial Instruments and Risk.

13. RESTRICTED CASH

As at December 31, 2017, the Company had no restricted cash (December 31, 2016 - $18.3 million). The exploration commitments associated with the restricted cash were fulfilled in 2017. In 2016, restricted cash represented a cash collateralized letter of credit facility used to guarantee the Company's commitments on its Egyptian exploration concessions.

14. PRODUCT INVENTORY

Product inventory consists of the Company's Egypt entitlement crude oil barrels, which is valued at the lower of cost or net realizable value. Cost includes operating expenses and depletion associated with the unsold crude oil entitlement barrels and is determined on a concession by concession basis.

As at December 31, 2017, the Company held 776,754 barrels of entitlement oil in inventory valued at $14.77 per barrel (December 31, 2016 - 1,265,080 barrels valued at $15.49 per barrel). During 2017, product inventory of $8.1 million (2016 - $2.3 million capitalized) was recorded as an expense.

15. INCOME TAXES

The Company’s deferred income tax assets and liabilities are as follows:

(000s)	2017			2016
Balance, beginning of year	$	—		$	3,009
Expenses related to the origination and reversal of temporary differences for:
Property and equipment	1,707			(13,788		)
Non-capital losses carried forward	(2,909		)	(2,936		)
Long-term liabilities	(41		)	(1,724		)
Share issue expenses	—			178
Changes in unrecognized tax benefits	1,243			15,261
Deferred income tax expense (recovery) recognized in earnings	—			(3,009		)
Balance, end of year	$	—		$	—

2017 21

The Company has non-capital losses of $81.5 million (2016 - $70.8 million) that expire between 2027 and 2037. No deferred tax assets have been recognized in respect of these unused tax losses. The Company has an additional $19.4 million (2016 - $18.3 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 27.0% (2016 – 27.0%) to income before taxes as follows:

(000s)	2017			2016
Income taxes calculated at the Canadian statutory rate	$	(15,368	)	$	(20,175	)
Increases (decreases) in income taxes resulting from:
Non-deductible expenses	2,023			3,641
Changes in unrecognized tax benefits	1,243			15,261
Effect of tax rates in foreign jurisdictions1	31,728			18,635
Changes in tax rates and other	2,193			(4,916		)
Income tax expense	$	21,819		$	12,446
1 The statutory tax rates in Egypt are 40.55%.

The Company's consolidated effective income tax rate for 2017 was 38.3% (2016 - 16.7%).

16. INTANGIBLE EXPLORATION AND EVALUATIONASSETS

(000s)
Balance at December 31, 2015	$	122,020
Additions	19,425
Transfer to petroleum properties	(2,150		)
Impairment loss	(33,426		)
Balance at December 31, 2016	105,869
Additions	16,905
Transfer to petroleum and natural gas assets	(2,271		)
Impairment loss	(79,025		)
Balance at December 31, 2017	$	41,478

For the year ended December 31, 2017 the Company recorded an impairment loss of $79.0 million on its exploration and evaluation assets. The impairment loss was split between the South West Gharib concession ($1.2 million), the North West Gharib concession ($67.5 million) and the South Alamein concession ($10.3 million).

At South West Gharib, it was determined during Q1-2017 that an impairment loss was necessary as no commercial quantities of oil were discovered, and no further drilling activities were planned. The South West Gharib exploration lands have been fully evaluated and all commitments had been met at the end of the first exploration phase. The Company elected to not enter the second exploration period and relinquished the concession in 2017.

At North West Gharib, the recoverable amount of the North West Gharib CGU was $4.4 million. The remaining North West Gharib exploration and evaluation assets were written down to nil during the second quarter. The North West Gharib exploration lands have been fully evaluated and all commitments had been met at the end of the first exploration phase. The Company elected to not enter the second exploration period. The Company filed for and received four development leases in the North West Gharib concession, all remaining exploration lands not covered by development leases were relinquished.

At South Alamein, it was determined during Q3-2017 that an impairment loss was necessary, due to the results of the Boraq 5 well and the uncertainty of an economic development of Boraq in the future. The Company completed testing two zones in the Boraq 5 appraisal well. The Boraq 5 well failed to produce any hydrocarbons from the two zones and was plugged and abandoned.

In 2016, the Company recorded an impairment loss of $33.4 million on its exploration and evaluation assets. The impairment loss was related principally to the South East Gharib and South West Gharib concessions in Egypt. The impairment loss recognized on these two concessions represented the entire intangible exploration and evaluation asset balances on the concessions, as the recoverable amounts of the concessions were determined to be nil. The Company relinquished its interest in South East Gharib in November 2016, and relinquished its interest in South West Gharib in the first half of 2017 as no commercially viable quantities of oil had been discovered on either concession.

The Company's policy regarding the assessment of impairment for exploration and evaluation assets is disclosed in Note 3, Significant Accounting Policies.

22 2017

17. PROPERTY AND EQUIPMENT

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

	PNG			Other
(000s)	Assets			Assets		Total
Balance at December 31, 2015	$	545,551		$	13,957	$	559,508
Acquisitions through business combination	59,475			—		59,475
Additions	6,618			615		7,233
Asset retirement obligations	12,099			—		12,099
Transfer from exploration and evaluation assets	2,150			—		2,150
Balance at December 31, 2016	625,893			14,572		640,465
Additions	20,301			953		21,254
Changes in estimate for asset retirement obligations	(236		)	—		(236		)
Transfer from exploration and evaluation assets	2,271			—		2,271
Foreign exchange	4,602			—		4,602
Balance at December 31, 2017	$	652,831		$	15,525	$	668,356
Accumulated depletion, depreciation, amortization and impairment        losses at December 31, 2015	$	388,954		$	8,990	$	397,944
Depletion, depreciation and amortization for the year	26,912			1,337		28,249
Accumulated depletion, depreciation, amortization and impairment        losses at December 31, 2016	415,866			10,327		426,193
Depletion, depreciation and amortization for the year	35,984			1,713		37,697
Balance at December 31, 2017	$	451,850		$	12,040	$	463,890

Net Book Value
At December 31, 2016	$	210,027	$	4,245	$	214,272
At December 31, 2017	$	200,981	$	3,485	$	204,466

At December 31, 2017, the Company's market capitalization was less than its net asset value, which was identified as an indicator of impairment of all assets. In addition, the decreased natural gas benchmark prices as compared to December 31, 2016 was a potential indicator of impairment for the Canadian assets. As a result, the Company completed impairment tests on all of its CGU's in accordance with IAS 36 and determined that the carrying amounts of the CGUs did not exceed their fair value less costs of sale.

Neither a five percent increase in the discount rate nor a five percent 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 Canada CGUs.

18. ASSET RETIREMENT OBLIGATION

(000s)
Balance at December 31, 2015	$	—
Acquisitions through business combination	12,089
Effect of movements in foreign exchange rates	10
Balance at December 31, 2016	$	12,099
Changes in estimates for asset retirement obligations	(236		)
Obligations settled	(695		)
Accretion expense	256
Effect of movements in foreign exchange rates	908
Balance at December 31, 2017	$	12,332

TransGlobe has estimated the net present value of its asset retirement obligation to be $12.3 million as at December 31, 2017 (2016 - $12.1 million) based on a total undiscounted future liability, after inflation adjustment, of $19.6 million (2016 - $19.0 million). These payments are expected to be made between 2019 and 2066. TransGlobe calculated the present value of the obligations using discount rates between 1.68% and 2.26% to reflect the market assessment of the time value of money as well as risks specific to the 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.

The Company reviews annually its estimates of the expected costs to reclaim the net interest in its wells and facilities. The resulting changes are categorized as changes in estimates for existing obligations in the preceding table.

As at December 31, 2017, the entire asset retirement obligation balance related to the Company's Canadian operations.

19. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

2017 23

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, 2017 or December 31, 2016.

The Company’s exposure to currency and liquidity risk related to trade and other payables is disclosed in Note 7, Financial Instruments and Risk.

20. LONG-TERM DEBT

The Company's interest-bearing loans and borrowings are measured at amortized cost. As at December 31, 2017, the only significant interest-bearing loans and borrowings are related to the Prepayment Agreement and the Reserves Based Lending Facility as described below.

The following table summarizes TransGlobe's outstanding long-term debt:

(000s)	December 31, 2017		December 31, 2016
Prepayment agreement	$	58,792	$	—
Reserves based lending facility	11,207		—
Note payable	—		5,581
	69,999		5,581
Current portion of long-term debt	—		5,581
	$	69,999	$	11,162

The following table reconciles the changes in TransGlobe's long-term debt:

(000s)
Balance at January 1, 2017	$	11,162
Increase in long-term debt - prepayment agreement	73,500
Increase in long-term debt - reserves based lending facility	10,209
Draws on facility	64
Repayment of long-term debt	(26,162		)
Amortization of deferred financing costs	329
Effect of movements in foreign exchange rates	897
Balance at December 31, 2017	$	69,999

Prepayment Agreement

(000s)	December 31, 2017
Prepayment agreement	$	75,000
Repayment of prepayment agreement	(15,000		)
Deferred financing costs	(1,208		)
	58,792
Current portion of long-term debt	—
	$	58,792

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.

The initial advance under the prepayment agreement was used to repay the 6.0% convertible debentures of the Company, which matured on March 31, 2017 (Note 21).

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 will be 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:

• the ratio of the Company's total consolidated indebtedness (calculated by including any outstanding letters of credit or bank guarantees and adding back any cash held by the Company on a consolidated basis) on each financial covenant test date to the Company's consolidated net cash generated by (used in) operating activities (where net cash generated includes the fair market value of crude oil inventory held as at the financial covenant test date) for the trailing 12 month period ending on that financial covenant test date will not exceed 4.00:1.00. The ratio as at December 31, 2017 is 0.22:1.00, the Company is in compliance with the ratio;

24 2017

• the ratio of Current Assets of the Company on a consolidated basis (calculated, in the case of crude oil inventory, by adjusting the value to market value) to Current Liabilities of the Company on a consolidated basis on each financial covenant test date will not be less than 1.00:1.00. The ratio as at December 31, 2017 is 3.60:1.00, the Company is in compliance with the ratio; and

• the ratio of the parent's non-consolidated asset value to the aggregate amount of indebtedness outstanding under the advance documents on each financial covenant test date will not be less than 2.00:3.00. The ratio as at December 31, 2017 is 6.90:3.00, the Company is in compliance with the ratio.

As at December 31, 2017, the Company was in compliance with all the financial covenants.

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 1.25:1.0. Prepayment service obligations includes 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:

• reimburse in cash the relevant portion of the advances such that the cover ratio becomes equal to or greater than 1.25:1.0; and/or

• amend the initial commercial contract to extend its duration and amend the maturity date under the agreement.

The cover ratio as at December 31, 2017 is 1.49:1.00, the Company is in compliance with the ratio.

Based on the Company's current forecast of future production and current Brent Crude prices the estimated future debt payments on long-term debt as of December 31, 2017 are as follows:

(000s)
2018	$	—
2019	—
2020	—
2021	58,792
	$	58,792

Reserves Based Lending Facility

As at December 31, 2017, the Company had in place a revolving Canadian reserves-based lending facility with Alberta Treasury Branches ("ATB") totaling C$30.0 million ($24.0 million), of which C$14.0 million ($11.2 million) was drawn.

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 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 lender may in its sole discretion agree to extend the term date for a further period of 364 days. Unless extended, before May 11, 2018, any unutilized amount of the facility will be cancelled, 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 will be amortized over the 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:

• the Company shall not permit the working capital ratio (calculated as current assets plus any undrawn availability under the facility, to current liabilities less any amount drawn under the facility) to fall below 1:00:1:00. The working capital ratio as at December 31, 2017 is 1.46:1.00, the Company is in compliance with the ratio; and

• permit the ratio of net debt to trailing cash flows as at the end of any fiscal quarter to exceed 3:00:1:00. According to the agreement net debt is, as of the end of any fiscal quarter and as determined in accordance with IFRS on an non-consolidated basis, and without duplication, an amount equal to the amount of total debt less current assets. Trailing cash flow is defined as the two most recently completed fiscal quarters, annualized. The net debt to trailing cash flows ratio as at December 31, 2017 is 0.19:1.00, the Company is in compliance with the ratio.

Note Payable

On December 20, 2016, the Company closed the acquisition of certain petroleum properties in west central Alberta, Canada (Note 6). The acquisition was partially funded by a vendor take-back note of C$15.0 million ($11.2 million). The note payable had a 24-month term and bore interest at a rate of 10% per annum. The Company repaid the outstanding vendor take-back note balance of C$13.6 million ($10.0 million) on May 16, 2017. Repayment was made using the revolving reserves-based lending facility.

2017 25

Borrowing Base Facility

In December 2016 the Company terminated its Borrowing Base Facility. There were no amounts outstanding under the Borrowing Base Facility at the time of termination; however, the Company was utilizing approximately $16.0 million in the form of letters of credit to support its exploration commitments in Egypt. The letters of credit outstanding under the borrowing base facility were transferred to a bilateral letter of credit facility with Sumitomo Mitsui Banking Corporation ("SMBC"). The issued letters of credit under the bilateral letter of credit facility were secured by cash collateral which was on deposit with SMBC (Note 13). The exploration commitments associated with the cash collateralized letter of credit facility were fulfilled in 2017. All remaining deferred financing costs related to the Borrowing Base Facility were expensed at the time of termination of the facility.

21. CONVERTIBLE DEBENTURES

(000s)
Balance at December 31, 2015	$	63,848
Fair value adjustment	7,027
Foreign exchange adjustment	1,780
Balance at December 31, 2016	72,655
Repayment	(73,375		)
Fair value adjustment	151
Foreign exchange adjustment	569
Balance at December 31, 2017	$	—

The convertible debentures matured on March 31, 2017 and were repaid in full on that date for their aggregate face value of C$97.8 million ($73.4 million). Repayment was made using the proceeds from the prepayment agreement (Note 20).

22. COMMITMENTS AND CONTINGENCIES

The Company is subject to certain office and equipment leases.

Pursuant to the PSC for North West Gharib in Egypt, the Company had a minimum financial commitment of $35.0 million and a work commitment for 30 wells and 200 square kilometers of 3-D seismic during the initial three year exploration period, which commenced on November 7, 2013. The Company received a six month extension to the initial exploration period, which extended to May 7, 2017. The Company completed the initial exploration period work program and met all financial commitments during the second quarter of 2017. The Company elected not to enter the second exploration period and has relinquished the remaining exploration lands not covered by the four development leases.

Pursuant to the PSC for South West Gharib in Egypt, the Company had a minimum financial commitment of $10.0 million and a work commitment for four wells and 200 square kilometers of 3-D seismic during the initial three year exploration period, which commenced on November 7, 2013. The Company received a six month extension to the initial exploration period, which extended to May 7, 2017. As no commercially viable quantities of oil were discovered at South West Gharib, the Company relinquished its interest in the concession on May 7, 2017. The Company met its financial commitment during the first quarter of 2017.

Pursuant to the PSC for South Ghazalat in Egypt, the Company had a minimum financial commitment of $8.0 million and a work commitment for two wells and 400 square kilometers of 3-D seismic during the initial three-year exploration period, which commenced on November 7, 2013 and reached its primary term on November 7, 2016. Prior to expiry, the Company elected to enter the first two-year extension period (expiry November 7, 2018). The Company had met its financial commitment for the first phase ($8.0 million) and the first extension ($4.0 million), however the Company had not completed the first phase work program. Prior to entering the first extension the Company posted a $4.0 million performance bond with EGPC to carry forward two exploration commitment wells into the first extension period. The $4.0 million performance bond is supported by a production guarantee from the Company's producing concessions which will be released when the commitment wells have been drilled. In accordance with the concession agreement the Company relinquished 25% of the original exploration acreage prior to entering the first extension period. In addition, the first extension period has an additional financial commitment of $4.0 million, which has been met, and two additional exploration wells.

Pursuant to the PSC for North West Sitra in Egypt, the Company has a minimum financial commitment of $10.0 million ($5.1 million remaining) 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 commencedon January 8, 2015. As at December 31, 2017, the Company had expended $4.9 million towards meeting the financial and operating commitment, with the acquisition of 600 square kilometers of 3-D seismic in 2017.

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, 2017.

26 2017

23. SHARE CAPITAL

Authorized

The Company is authorized to issue an unlimited number of common shares with no par value.

Issued

	December 31, 2017			December 31, 2016
(000s)	Shares	Amount		Shares	Amount
Balance, beginning of year	72,206	$	152,084	72,206	$	152,084
Balance, end of year	72,206	$	152,084	72,206	$	152,084

24. SHARE-BASED PAYMENTS

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 tranches.

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

	2017			2016
			Weighted-			Weighted-
	Number		Average	Number		Average
	of		Exercise	of		Exercise
(000s except per share amounts)	Options		Price (C$)	Options		Price (C$)
Options outstanding, beginning of year	6,046		6.87	5,348		9.05
Granted	1,043		2.16	1,470		2.19
Cancelled / Forfeited	(1,281	)	6.75	(54	)	11.84
Expired	(849	)	11.43	(718	)	12.95
Options outstanding, end of year	4,959		5.10	6,046		6.87
Options exercisable, end of year	2,925		6.87	3,527		9.14

	Options Outstanding			Options Exercisable
		Weighted-			Weighted-
	Number	Average	Weighted-	Number	Average	Weighted-
Exercise	Outstanding at	Remaining	Average	Exercisable at	Remaining	Average
Prices	December 31, 2017	Contractual	Exercise Price	December 31, 2017	Contractual	Exercise
(C$)	(000s)	Life (Years)	(C$)	(000s)	Life (Years)	Price (C$)
2.16 - 2.17	953	4.4	2.16	—	—	—
2.18 - 3.59	1,212	3.2	2.19	404	3.2	2.19
3.60 - 6.13	820	2.4	4.99	547	2.4	4.99
6.14 - 8.20	820	1.4	7.26	820	1.4	7.26
8.21 - 9.13	1,154	0.2	9.13	1,154	0.2	9.13
	4,959	2.3	5.10	2,925	1.4	6.87

Share–based compensation

Compensation expense of $0.6 million was recorded in general and administrative expenses in the Consolidated Statements of Loss and Comprehensive Loss and Changes in Shareholders’ Equity during year ended December 31, 2017 (2016 - $1.3 million) in respect of equity-settled share-based payment transactions. 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 as noted below:

	2017		2016
Weighted average fair market value per option (C$)	0.70		0.72
Risk free interest rate (%)	0.74	%	0.54	%
Expected volatility (based on actual historical volatility) (%)	48.67	%	49.76	%
Dividend rate	—	%	—	%
Expected forfeiture rate (non-executive employees) (%)	—	%	—	%
Suboptimal exercise factor	1.25		1.25

2017 27

All options granted vest annually over a three-year period and expire five years after the grant date. During the year ended December 31, 2017, no employee stock options were exercised (2016 – nil). As at December 31, 2017 and December 31, 2016, the entire balance in contributed surplus was related to previously recognized stock-based compensation expense on equity-settled stock options.

Restricted share unit, performance share unit and deferred share unit plans

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, vested PSUs granted prior to 2017 can range between 50% and 150% of the original PSU grant, and 0% to 200% for PSU's granted in 2017. 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, 2017:

	Restricted		Performance		Deferred
	Share		Share		Share
(000s)	Units		Units		Units
Units outstanding, beginning of year	546		1,366		437
Granted	807		573		214
Exercised	(245	)	(248	)	(56	)
Forfeited	(138	)	(315	)	—
Units outstanding, end of year	970		1,376		595

Compensation expense of $0.8 million was recorded in general and administrative expenses in the Consolidated Statement of Loss and Comprehensive Loss during the year ended December 31, 2017 in respect of share units granted under the three plans described above (2016 - $1.1 million). 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. Until the liability is ultimately settled, it is re-measured at each reporting date with changes to fair value recognized in earnings.

25. PER SHARE AMOUNTS

The weighted-average number of common shares outstanding (basic and diluted) for the year ended December 31, 2017 was 72,205,369 (2016 - 72,205,369). These outstanding share amounts were used to calculate loss per share in the respective periods.

In determining diluted 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, 2017, the Company excluded 4,958,553 stock options (2016 – 4,576,100) as their exercise price was greater than the average common share market price in the year.

The convertible debentures were considered dilutive in any period in which earnings per share were reduced by the effect of adjusting net earnings for the impact of the convertible debentures, and adjusting the weighted-average number of shares outstanding for the potential shares issuable on conversion of the convertible debentures.

28 2017

26. RELATED PARTY DISCLOSURES

Details of controlled entities are as follows*:

	Country of	Ownership Interest	Ownership Interest
	Incorporation	2017	2016
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%

* Includes only entities that were active as at December 31, 2017.

27. COMPENSATION OF KEY MANAGEMENT PERSONNEL

Key management personnel have been identified as the board of directors and the four executive officers of the Company.

Key management personnel remuneration consisted of the following:

(000s)	2017		2016
Salaries, incentives and short-term benefits	$	2,615	$	3,237
Share-based compensation	898		1,775
	$	3,513	$	5,012

2017 29

28. SEGMENTED INFORMATION

The Company has two reportable operating segments for the year-ended December 31, 2017: 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.

TransGlobe's management regularly reviews funds flow from operations generated by each of TransGlobe's operating segments. Funds flow from operations is a measure of profit or loss that provides the management with the ability to assess the operating segments’ profitability and, correspondingly, the ability of each operating segment to sustaining capital, future growth through capital investment, and to repay debt.

The accounting policies of the operating segments are the same as the Company’s accounting policies.

	Egypt					Canada					Corporate						Total
(000s)	2017		2016			2017			2016		2017			2016			2017			2016
Revenue
Oil sales, net of royalties	$	130,987	$	62,634		$	17,477		$	500	$	—		$	—		$	148,464		$	63,134
Finance revenue	33		102			—			—		75			571			108			673
Total segmented revenue	131,020		62,736			17,477			500		75			571			148,572			63,807
Segmented expenses
Production and operating	44,705		40,054			5,507			269		—			—			50,212			40,323
Transportation	—		—			793			12		—			—			793			12
Selling costs	2,495		875			—			—		—			—			2,495			875
G&A	5,782		7,060			1,147			—		8,324			10,495			15,253			17,555
Stock-based compensation	—		—			—			—		(1,478		)	(2,418		)	(1,478		)	(2,418		)
Lease inducement	—		—			—			—		91			95			91			95
Settlement of ARO	—		—			695			—		—			—			695			—
Realized foreign exchange loss	—		—			—			—		194			3,607			194			3,607
Unrealized foreign exchange loss	—		—			—			—		35			(4,292		)	35			(4,292		)
Realized loss on financial instruments	2,935		956			(64		)	—		—			—			2,871			956
Income tax expense	21,819		12,446			—			—		—			—			21,819			12,446
Income taxes - deferred	—		3,009			—			—		—			—			—			3,009
Segmented funds flow from operations	$	53,284	$	(1,664	)	$	9,399		$	219	$	(7,091	)	$	(6,916	)	$	55,592		$	(8,361	)
Capital expenditures
Exploration and development	$	31,151	$	26,658		$	6,967		$	—	$	—		$	—		$	38,118		$	26,658
Property acquisition	—		—			—			59,475		—			—			—			59,475
Corporate	—		—			—			—		41			—			41			—
Total capital expenditures																	$	38,159		$	86,133

Reconciliation of funds flow from operations to net loss:

(000's)	December 31, 2017			December 31, 2016
Funds flow from operations	$	55,592		$	(8,361	)
Depletion, depreciation and amortization	(40,036		)	(29,177		)
Accretion	(256		)	—
Deferred lease inducement	91			95
Impairment of exploration and evaluation assets	(79,025		)	(33,426		)
Stock-based compensation	(1,478		)	(2,418		)
Finance costs	(6,233		)	(6,068		)
Income tax expense	(21,819		)	(12,446		)
Loss on financial instruments	(8,121		)	(7,027		)
Unrealized (gain) loss on foreign currency translation	35			(4,292		)
Asset retirement obligations settled	695			—
Income taxes paid	21,819			15,455
Net loss	$	(78,736	)	$	(87,665	)

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

30 2017

December 31, 2017
(000s)	Egypt		Canada		Total
Assets
Accounts receivable	$	14,956	$	2,684	$	17,640
Intangible exploration and evaluation assets	41,478		—		41,478
Property and equipment
Petroleum properties	127,363		73,618		200,981
Other assets	2,381		27		2,408
Other	49,769		3,467		53,236
Segmented assets	235,947		79,796		315,743
Non-segmented assets					11,959
Total assets					$	327,702
Liabilities
Accounts payable and accrued liabilities	$	17,035	$	4,004	$	21,039
Derivative commodity contracts	7,813		157		7,970
Long-term debt	58,792		11,207		69,999
Asset retirement obligation	—		12,332		12,332
Segmented liabilities	83,640		27,700		111,340
Non-segmented liabilities					6,355
Total liabilities					$	117,695

December 31, 2016
(000s)	Egypt		Canada			Total
Assets
Accounts receivable	$	13,778	$	620		$	14,398
Intangible exploration and evaluation assets	105,869		—		122,020	105,869
Property and equipment
Petroleum properties	138,757		71,270			210,027
Other assets	2,785		—			2,785
Other	21,977		—			21,977
Segmented assets	283,166		71,890			355,056
Non-segmented assets						51,086
Total assets						$	406,142
Liabilities
Accounts payable and accrued liabilities	$	14,005	432			14,437
Current and long-term note payable			11,162			11,162
Asset retirement obligation	—		12,099			12,099
Segmented liabilities	14,005		23,693			37,698
Non-segmented liabilities						83,128
Total liabilities						$	120,826

29. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital consisted of the following:

(000s)	2017			2016
Operating Activities
(Increase) decrease in current assets
Accounts receivable	$	(3,254	)	$	8,093
Prepaids and other	(3,044		)	1,159
Product inventory1	5,789			(3,242		)
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	4,367			1,286
	$	3,858		$	7,296
1   The change in non-cash working capital associated with product inventory represents the change in operating costs capitalized as product inventory in the respective periods.

2017 31

(000s)	2017			2016
Investing Activities
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	(1,587		)	5,556
	$	(1,587	)	$	5,556

32 2017