CONTENTS

MESSAGE TO SHAREHOLDERS	Page 3
FINANCIAL AND OPERATING RESULTS	Page 5
MANAGEMENT’S DISCUSSION AND ANALYSIS	Page 8
MANAGEMENT’S REPORT	Page 24
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	Page 25
CONSOLIDATED FINANCIAL STATEMENTS	Page 27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	Page 31

2 2018

MESSAGE TO THE SHAREHOLDERS

2018 was another volatile year for TransGlobe and the industry in general. Volatile oil pricing took Brent to highs of $86/bbl and all the way back down to $51/bbl. Differentials on Canadian commodities reached multi-year highs as challenged egress capacity exerted significant pressure on our Canadian business unit revenues. Despite challenging price volatility, average oil prices were the strongest they’ve been in the last number of years which led to an increase in netbacks and funds flow from operations, and we recorded our best results since 2013. With our stronger financial position, we reduced debt and resumed our suspended dividend program in Q3-2018 with an intent to pay a dividend semi-annually.

Egypt crude oil inventory was further reduced in 2018 and is now at its lowest level since 2014. Our exploration program in the Western Desert of Egypt had mixed results in 2018, a disappointing drill program in Northwest Sitra resulted in a full write-down, but persistence in South Ghazalat led to a light oil discovery on our final commitment well. This is our first Western Desert discovery and our well tested at 3,840 bbls/day¹. We booked 1.44mm bbls of 3P resource at year end and will be filing a development lease to drill and test follow-on locations.

Health, Safety and the Environment were again primary focus areas for the Company and I was very pleased with the progress in Egypt’s lagging and leading indicators, along with an incident-free year in Canada.

TransGlobe produced an average of 14,439 boe/d in 2018 and 15,270 boe/d during the fourth quarter. Egypt production was 12,150 bbls/day in 2018 (Q4-2018 - 12,968 bbls/d) and Canada production was 2,289 boe/d (Q4-2018 - 2,302 boe/d). Annual production was within our adjusted 2018 full-year guidance (14,200 - 14,800 boe/d). Corporate production increased by 7% in Q4-2018 over the previous quarter due to better than expected well performance and well optimization results in Egypt, partially offset by reduced production in Canada associated with unscheduled compressor maintenance and shut-in production due to low pricing.

TransGlobe recorded net earnings of $15.7 million in 2018 compared to a $78.7 million net loss in 2017. Net earnings were inclusive of a $14.5 million non-cash impairment loss on the Company's exploration and evaluation assets in North West Sitra and a $9.3 million unrealized derivative gain on commodity contracts (fair value adjustment on the Company's hedging contracts). Excluding impairment and the unrealized gain on derivative commodity contracts, TransGlobe would have achieved earnings of $20.9 million for 2018.

The Company generated funds flow from operations of $63.3 million (2017 - $55.6 million) in 2018, $0.87 per share (2017 - $0.77 per share). We ended 2018 with positive working capital of $51.0 million (2017 - $50.6 million), including cash and cash equivalents of $51.7 million. The improvement in funds flow from operations is due to stronger oil prices.

In Egypt, we drilled eight development oil wells (two in Arta, two in NW Gharib, two in K-south, and two in M-field) and four exploration wells (two in NW Sitra, and two in South Ghazalat). In Canada, the Company drilled six gross (five net) development oil wells in the Harmattan area. The planned outpost well was delayed until 2019, due to a significant increase in light oil differentials in the closing months of 2018.

We fulfilled all remaining exploration commitments in South Ghazalat with the drilling of the second exploration well (SGZ 6X) and were pleased to have discovered oil. Based on well test results, we filed a declaration with the Egyptian General Petroleum Company ("EGPC") of a Commercial Discovery and subsequently filed a Development Plan for the SGZ 6X discovery in late February, targeting first production in Q3/Q4 2019. In South Alamein, the Company resubmitted a request for military access to drill the SA 24X Jurassic exploration prospect and entered into extension discussions with EGPC.

2P reserves at year end 2018 were 4% lower than 2017 primarily due to production of ~5.3 mmboe, substantially offset by net positive revisions of ~3.5 MMboe. The net positive revisions reflect additions from a discovery at South Ghazalat, extensions at West Bakr, improved recovery in Egypt, and results of the 2017 infill drilling in Canada, offset by a negative revision related to minor asset performance in Egypt and economic factors in Canada.

We continued to reduce inventoried crude oil through sales of 15,103 boe/d versus production of 14,439 boe/d. We ended 2018 with 568.1 mbbls of inventoried entitlement crude oil (2017 - 776.8 mbbls), which is approximately three and a half months of entitlement oil production. This achievement came through a combination of sales to EGPC and selling four cargoes. The first lifting in 2019 is scheduled for mid-March and the Company is confident that we will be able to maintain our inventoried crude oil within a reasonable range of the current balance.

During the year, the Company repaid $15 million of the amount outstanding under the prepayment agreement with Mercuria Energy Trading S.A., leaving $44.1 million (net of deferred financing costs) outstanding at year end. An additional $5 million was repaid subsequent to year end. The Company also repaid $2.8 million of the reserves-based lending facility with Alberta Treasury Branches, leaving $8.2 million drawn at year end. The Company continues to be conservative with its debt structure, balancing working capital considerations against debt service costs and intends to continue that conservative approach into 2019.

TransGlobe resumed paying a dividend in 2018, with a payment of $0.035 per common share on September 14, 2018 to shareholders of record on August 31, 2018. The Company aspires to pay a semi-annual dividend to shareholders, assessed at each period. Subsequent to year end, the Company declared a dividend of $0.035 per share payable April 18, 2019 to shareholders of record on March 29, 2019.

¹ The Company drilled the SGZ 6X exploration well to a total depth of 5,195 feet and cased the well as a potential Bahariya light oil discovery. Subsequently, the Company tested three intervals in the Bahariya formation and tested a combined 3,840 barrels per day of light oil from the upper and lower Bahariya. The lower Bahariya formation flowed naturally at an average rate of 2,437 barrels per day of light (38 API) oil, 21 barrels per day of water and 1.4 million cubic feet of natural gas per day on a 40/64 inch choke from a 42 foot perforated interval. A total of 918 barrels of oil and 7 barrels of water were produced during the 10 hour test. The middle Bahariya produced a small amount of formation water using nitrogen to lift fluid to surface from an 8 foot perforated interval. The upper Bahariya formation flowed at an average rate of 1,403 barrels per day of light (35 API) oil, 210 barrels per day of water and 1.0 million cubic feet of natural gas per day on a 64/64 inch choke from a 23 foot perforated interval. A total of 456 barrels of oil and 65 barrels of water were produced during the 8 hour test.

Based on the positive test rates from SGZ 6X, the Company will begin preparing a development plan for the discovery. In addition, the Company is integrating the SGZ 6X well results into the existing database and mapping to evaluate additional exploration/appraisal drilling in the area and to accelerate potential early development options.The South Ghazalat concession was extended to May 6, 2019 with the option to enter into the final 18 month exploration phase. Although encouraging, test rates are not necessarily indicative of long-term performance or ultimate recovery.

2018 3

Overall operating expenses increased by approximately 17% to $9.73 per boe during 2018 (2017 - $8.29 per boe). This increase was due to higher fuel/diesel costs as a result of cost pressures associated with higher commodity prices, and additional workovers completed in Egypt to maintain production levels. The planned turnaround in Canada also exacerbated our increased opex, necessary maintenance that nevertheless resulted in higher costs on lower production.

Gross G&A costs were $16.3 million in 2018 (2017 - $16.0 million), representing a 2% increase from prior year. Gross G&A per produced barrel increased to $2.98 per boe from $2.61 per boe in 2017. The increase is primarily due to costs related to the AIM listing.

Our 2019 plan is designed to maximize free cash flow for future value growth opportunities. Our $34.1 million 2019 capital budget is weighted 70% to development and 30% to exploration. In Egypt, the $24.1 million budget includes the drilling of 4 development wells and 3 exploration wells. The primary focus of the plan is to sustain/grow Eastern Desert production and to develop the South Ghazalat exploration concession in the Western Desert. We will continue our negotiations with the government of Egypt to amend, extend and consolidate our Eastern Desert operations. In Canada, the $10.0 million budget includes the drilling of 3 development wells and 1 outpost well, contingent on improved differentials. At current prices, the Company expects to fund the 2019 capital program with internally generated cash flow.

Following an extensive review of our current investor base, our geographical strategy, and logistical access to our core operating assets in Egypt we determined that a London listing and relocation of the executive team to London was necessary to enhance our investor penetration in the UK and European marketplace, obtain early access to increased business development opportunities in our geographic focus areas and increase our effectiveness in managing our operations in Egypt. We successfully completed a listing on the London Stock Exchange’s AIM in June and we opened a London office in the fall of 2018 and I, along with Eddie Ok (CFO) and Lloyd Herrick (COO) relocated to London. Subsequent to the end of the year we announced that Geoff Probert would be joining the Company as Vice President and COO, in the London office, and that Lloyd Herrick would be shifting to the role of Executive Vice President. Geoff has an extensive background in operations in the region and is very knowledgeable of the London marketplace and business development.

Fred Dyment, a long-serving director of TransGlobe, retired on December 31, 2018. Fred has been a dedicated supporter of the Company since 2004. As a key member of the Board, he assisted senior management in stewarding the Company through a number of challenging times: the financial crisis of 2009, Arab Spring and global oil price volatility, to name a few. I thank Fred for his valuable counsel and contributions, and wish him much health and happiness in his well-earned retirement.

As announced in September 2018, Ross Clarkson retired from the executive on December 31, 2018. Ross has led TransGlobe as the founder and CEO for the last 22+ years and decided to take a much deserved step back from daily operations to focus on governance and broader strategy as a non-executive Director. On January 1, 2019 I became the President and CEO. On behalf of the executive team and Board of Directors we wish Ross a long, happy and healthy retirement. I look forward to working with the executive team and Board to grow value within TransGlobe.

Signed by:

“Randy C. Neely”

Randy C. Neely

President and Chief Executive Officer

March 13, 2019

4 2018

FINANCIAL AND OPERATING RESULTS

(US$000s, except per share, price, volume amounts and % change)

	Three months ended December 31					Year ended December 31
Financial	2018		2017		% Change	2018		2017		% Change
Petroleum and natural gas sales	72,628		72,954		—	299,142		252,591		18
Petroleum and natural gas sales, net of royalties	40,605		40,725		—	176,227		148,464		19
Realized derivative loss on commodity contracts	8,057		2,496		223	16,386		2,871		471
Unrealized derivative (gain) loss on commodity contracts	(29,492	)	7,584		(489)	(9,335	)	7,970		(217)
Production and operating expense	13,116		11,083		18	53,298		51,005		4
Selling costs	450		569		(21)	2,103		2,495		(16)
General and administrative expense	2,005		3,636		(45)	18,678		15,253		22
Depletion, depreciation and amortization expense	8,214		10,401		(21)	34,291		40,036		(14)
Income taxes	6,612		5,715		16	26,340		21,819		21
Cash flow generated by operating activities	9,822		44,263		(78)	69,192		59,450		16
Funds flow from operations1	8,842		17,018		(48)	63,282		55,592		14
Basic per share	0.12		0.24			0.87		0.77
Diluted per share	0.12		0.24			0.86		0.77
Net earnings (loss)	30,719		(2,382	)	1,390	15,677		(78,736	)	120
Basic per share	0.43		(0.03	)		0.22		(1.09	)
Diluted per share	0.43		(0.03	)		0.22		(1.09	)
Capital expenditures	17,433		9,078		92	40,706		38,159		7
Dividends paid	—		—			2,527		—
Dividends paid per share	—		—			0.035		—
Working capital	50,987		50,639		1	50,987		50,639		1
Long-term debt, including current portion	52,355		69,999		(25)	52,355		69,999		(25)
Common shares outstanding
Basic (weighted average)	72,206		72,206		—	72,206		72,206		—
Diluted (weighted average)	72,706		72,206		1	72,631		72,206		1
Total assets	318,296		327,702		(3)	318,296		327,702		(3)
Operating
Average production volumes (boe/d)	15,270		13,952		9	14,439		15,506		(7)
Average sales volumes (boe/d)	14,483		16,249		(11)	15,013		16,849		(11)
Inventory (mbbls)	568		777		(27)	568		777		(27)
Average sales price ($ per boe)	54.51		48.80		12	54.59		41.07		33
Operating expense ($ per boe)	9.84		7.41		33	9.73		8.29		17
1 Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies.

FINDING AND DEVELOPMENT COSTS/FINDING, DEVELOPMENT AND NET ACQUISITION COSTS

F&D costs are calculated as the aggregate of exploration costs, development costs and the change in estimated future development costs divided by the applicable reserve additions. FD&A costs incorporate acquisitions, net of any dispositions during the year. The Company expects to fund the development costs of the reserves through a combination of cash flow from operations, debt capacity, proceeds from property dispositions and, if necessary, the issuance of Common Shares.

Changes in forecasted future development capital ("FDC") occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the independent evaluator’s best estimate of what it will cost to bring the proved plus probable undeveloped reserves on production at that time. Undiscounted FDCs for proved plus probable undeveloped reserves decreased $16.1 million compared to year end 2017, to total $111.4 million at year end 2018. The decrease in FDC is attributable to fewer undeveloped locations being added due to the current price environment.

Estimates of reserves and future net revenues have been made assuming the development of each property will occur, without regard to the likelihood of us obtaining funding for the development. There can be no guarantee that funds will be available or that we will allocate funding to develop all of the reserves attributed in the reserves evaluator's report. Failure to develop those reserves would have a negative impact on future cash flow from operations.

Interest and other costs of external funding are not included in the reserves and future net revenue estimates. These costs would reduce reserves and future net revenues depending upon the funding sources utilized. TransGlobe does not anticipate that interest or other funding costs would make development of any property uneconomic.

2018 5

Proved	Three-Year
	Weighted
($000s, except volumes and $/boe amounts)	Average	2018		2017		2016
Total capital expenditures		40,706		38,159		26,658
Acquisitions1		—		—		59,475
Net change from previous year’s future capital		(10,612	)	(13,311	)	60,084
		30,094		24,848		146,217
Reserve additions and revisions (mboe)
Exploration and development2		4,629		3,262		5,138
Acquisitions, net of dispositions1		—		—		11,667
Total reserve additions (mboe)		4,629		3,262		16,805
Average cost per boe
F&D3	5.80	6.50		7.62		4.02
FD&A3	8.13	6.50		7.62		8.70
1  The 2016 Acquisitions figure consists entirely of acquisition costs on the Canadian assets.
2  The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will     not reflect total finding and development costs related to reserves additions for that year.
3  Neither F&D costs nor FD&A costs have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

Proved Plus Probable	Three-Year
	Weighted
($000s, except volumes and $/boe amounts)	Average	2018		2017		2016
Total capital expenditure		40,706		38,159		26,658
Acquisitions1		—		—		59,475
Net change from previous year’s future capital		(16,100	)	(12,009	)	110,102
		24,606		26,150		196,235
Reserve additions and revisions (mboe)
Exploration and development2		3,465		1,538		4,906
Acquisitions, net of dispositions1		—		—		20,744
Total reserve additions (mboe)		3,465		1,538		25,650
Average cost per boe
F&D3	6.93	7.10		17.00		3.66
FD&A3	8.05	7.10		17.00		7.65
1  The 2016 Acquisitions figure consists entirely of acquisition costs on the Canadian assets.
2  The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will     not reflect total finding and development costs related to reserves additions for that year.
3  Neither F&D costs nor FD&A costs have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

RECYCLE RATIO

	Three-Year
Proved	Weighted
	Average2	2018	2017	2016
Netback ($/boe)1	6.08	10.69	8.08	(3.12	)
Proved F&D costs ($/boe)3	5.80	6.50	7.62	4.02
Proved FD&A costs ($/boe)3	8.13	6.50	7.62	8.80
F&D Recycle ratio2 4	1.05	1.64	1.06	—
FD&A Recycle ratio2 4	0.75	1.64	1.06	—
1  For the purpose of calculating the recycle ratio, Netback is defined as net earnings (loss) adjusted for non-cash items per boe of sales - see "Recycle Netback Calculation" section.
2  In 2016, recycle ratios were negative as a result of a negative netback. Negative recycle ratios are meaningless and have therefore been presented as nil. The negative netback for 2016    was included in the three-year weighted average recycle ratios.
3  Neither F&D costs nor FD&A costs have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.
4  Recycle ratio does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

2018 6

	Three-Year
Proved Plus Probable	Weighted
	Average2	2018	2017	2016
Netback ($/boe)1	6.08	10.69	8.08	(3.12	)
Proved plus Probable F&D costs ($/boe)3	6.93	7.10	17.00	3.66
Proved plus Probable FD&A costs ($/boe)3	8.05	7.10	17.00	7.65
F&D Recycle ratio2 4	0.88	1.51	0.48	—
FD&A Recycle ratio2 4	0.76	1.51	0.48	—
1  For the purpose of calculating the recycle ratio, Netback is defined as net earnings (loss) adjusted for non-cash items per boe of sales - see "Recycle Netback Calculation" section.
2  In 2016, recycle ratios were negative as a result of a negative netback. Negative recycle ratios are meaningless and have therefore been presented as nil. The negative netback for 2016    was included in the three-year weighted average recycle ratios.
3  Neither F&D costs nor FD&A costs have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.
4  Recycle ratio does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

Higher oil prices on the Company's sales of four cargoes of entitlement crude oil (totaling 1,854 mbbls) and sales of an additional 318 mbbls of inventoried entitlement crude oil to EGPC during 2018 were the primary drivers of the positive netbacks in the year. Annual sales in excess of production resulted in an overall decrease in inventoried crude oil by 209 mbbls from 2017.

The recycle ratio is calculated by dividing the recycle netback by the proved and proved plus probable finding and development costs on a per boe basis.

Recycle Netback Calculation

For the purpose of calculating the recycle ratio, Netback is defined as net earnings (loss) adjusted for non-cash items per boe of sales.

($000s, except volumes and per boe amounts)	2018		2017		2016
Net earnings (loss)	15,677		(78,736	)	(87,665	)
Adjustments for non-cash items:
Depletion, depreciation and amortization	34,291		40,036		29,177
Asset retirement obligation accretion	270		256		—
Stock-based compensation	3,536		1,478		2,418
Deferred income taxes	—		—		(3,009	)
Amortization of deferred financing costs	360		329		724
Deferred lease inducement	(90	)	(91	)	(95	)
Realized (gain) loss on commodity contracts	(9,335	)	7,970		956
Unrealized foreign exchange (gain) loss	(135	)	(35	)	4,292
Unrealized loss on financial instruments	—		151		7,027
Impairment loss	14,500		79,025		33,426
Asset retirement obligations settled	(300	)	(695	)	—
Gain on asset disposals	(207	)	—		—
Recycle netback1	58,567		49,688		(12,749	)
Sales volumes (mboe)	5,480		6,150		4,086
Recycle netback per boe	10.69		8.08		(3.12	)
1  Recycle netback does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

2018 7

MANAGEMENT'S DISCUSSION AND ANALYSIS

March 13, 2019

The following discussion and analysis is management’s opinion of TransGlobe Energy Corporation's ("TransGlobe" or the "Company") historical financial and operating results and should be read in conjunction with the message to shareholders and the audited consolidated financial statements of the Company for the years ended December 31, 2018 and 2017, together with the notes related thereto (the "Consolidated Financial Statements"). The Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board in the currency of the United States. Additional information relating to the Company, including the Company’s Annual Information Form, is on SEDAR at www.sedar.com. The Company’s annual report to the United States Securities and Exchange Commission on Form 40-F may be found on EDGAR at www.sec.gov.

READER ADVISORIES

Forward-Looking Statements

Certain statements or information contained herein may constitute forward-looking statements or information under applicable securities laws, including, but not limited to, management’s assessment of future plans and operations, anticipated changes to TransGlobe Energy Corporation's reserves and production, timing of directly marketed crude oil sales, drilling plans and the timing thereof, commodity price risk management strategies, adapting to the current political situation in Egypt, reserves estimates, management’s expectation for results of operations for 2019, including expected 2019 average production, funds flow from operations, the 2019 capital program for exploration and development, the timing and method of financing thereof, collection of accounts receivable from the Egyptian Government, the terms of drilling commitments under the Egyptian Production Sharing Agreements and Production Sharing Concessions (collectively defined as "PSCs") and the method of funding such drilling commitments, the Company's beliefs regarding the reserves and production growth of its assets and the ability to grow with a stable production base, and commodity prices and expected volatility thereof. Statements relating to "reserves" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

Forward-looking statements or information relate to the Company’s future events or performance. All statements other than statements of historical fact may be forward-looking statements or information. Such statements or information are often but not always identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe”, and similar expressions.

Forward-looking statements or information necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, economic and political instability, volatility of commodity prices, currency fluctuations, imprecision of reserves estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals, failure to collect the remaining accounts receivable balance from the Egyptian General Petroleum Company ("EGPC"), ability to access sufficient capital from internal and external sources and the risks contained under "Risk Factors" in the Company's Annual Information Form which is available on www.sedar.com. The recovery and reserves estimates of the Company's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of the Company.

Forward-looking information and statements contained in this document include the payment of dividends, including the timing and amount thereof, and the Company's intention to declare and pay dividends in the future under its current dividend policy. Without limitation of the foregoing, future dividend payments, if any, and the level thereof is uncertain, as the Company's dividend policy and the funds available for the payment of dividends from time to time will be dependent upon, among other things, free cash flow, financial requirements for the Company's operations and the execution of its strategy, ongoing production maintenance, growth through acquisitions, fluctuations in working capital and the timing and amount of capital expenditures and anticipated business development capital, payment irregularity in Egypt, debt service requirements and other factors beyond the Company's control. Further, the ability of the Company to pay dividends will be subject to applicable laws (including the satisfaction of the liquidity and solvency tests contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness.

In addition, forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on the Company's future operations. Such statements and information may prove to be incorrect and readers are cautioned that such statements and information may not be appropriate for other purposes. Although the Company believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements or information because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future commodity prices; currency exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market and receive payment for its oil and natural gas products.

Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could affect the Company's operations and financial results are included in reports on file with Canadian and US securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), EDGAR website (www.sec.gov) and on the Company's website (www.trans-globe.com). Furthermore, the forward-looking statements or information contained herein are made as at the date hereof and the Company does not undertake

8 2018

any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws.

The reader is further cautioned that the preparation of financial statements in accordance with International Financial Reporting Standards ("IFRS") requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Estimating reserves is also critical to several accounting estimates and requires judgments and decisions based upon available geological, geophysical, engineering and economic data. These estimates may change, having either a negative or positive effect on net earnings as further information becomes available, and as the economic environment changes.

This MD&A includes references to certain financial measures which are not specified, defined, or determined under IFRS and are therefore

considered non-GAAP financial measures. These non-GAAP financial measures are unlikely to be comparable to similar financial measures presented

by other issuers. For a full description of these non-GAAP financial measures and a reconciliation of these measures to their most directly comparable

GAAP measures, please refer to "NON-GAAP FINANCIAL MEASURES".

All oil and natural gas reserves information contained in this document has been prepared and presented in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the Canadian Oil and Gas Evaluation Handbook. The actual crude oil and natural gas reserves and future production will be greater than or less than the estimates provided in this document. The estimated future net revenue from the production of crude oil and natural gas reserves does not represent the fair market value of these reserves.

Mr. Darrin Drall, B.Sc., Engineering Manager - Technical Services for TransGlobe Energy Corporation, and a qualified person as defined in the Guidance Note for Mining, Oil and Gas Companies, June 2009, of the London Stock Exchange, has reviewed and approved the technical information contained in this report. Mr. Drall is a professional engineer who obtained a Bachelor of Science in Mechanical Engineering from the University of Manitoba. He is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA), the Association of Professional Engineers and Geoscientists of Saskatchewan (APEGS) and the Society of Petroleum Engineers (SPE) and has over 30 years’ experience in oil and gas.

Natural gas volumes have been converted on the basis of six thousand cubic feet of natural gas to one barrel of oil equivalent. Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

NON-GAAP FINANCIAL MEASURES

Funds flow from operations

This document contains the term “funds flow from operations”, which should not be considered an alternative to or more meaningful than “cash flow from operating activities” as determined in accordance with IFRS. Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital. Management considers this a key measure as it demonstrates TransGlobe’s ability to generate the cash flow necessary to fund future growth through capital investment. Funds flow from operations does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

Reconciliation of funds flow from operations

($000s)	2018		2017
Cash flow from operating activities	69,192		59,450
Changes in non-cash working capital	(5,910	)	(3,858	)
Funds flow from operations1	63,282		55,592
1  Funds flow from operations does not include interest or financing costs. Interest expense is included in financing costs on the Consolidated Statements of Earnings (Loss) and    Comprehensive Income (Loss). Cash interest paid is reported as a financing activity on the Consolidated Statements of Cash Flows.

Net debt-to-funds flow from operations ratio

Net debt-to-funds flow from operations is a measure that is used by management to set the amount of capital in proportion to risk. The Company’s net debt-to-funds flow from operations ratio is computed as long-term debt, including the current portion, net of working capital, over funds flow from operations for the trailing twelve months. Net-debt-to-funds flow from operations does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

Reconciliation of net debt-to-funds flow from operations ratio

($000s)	2018		2017
Long-term debt	52,355		69,999
Current assets	(78,994	)	(81,758	)
Current liabilities	28,007		31,119
Net debt	1,368		19,360
Funds flow from operations	63,282		55,592
Net debt-to-funds flow from operations	0.02		0.35

Netback

Netback is a measure of operating results and is computed as sales net of royalties (all government interests, net of income taxes), operating expenses, current taxes and selling costs. The Company's netbacks include sales and associated costs of production from inventoried crude oil sold during the period. Royalties and taxes associated with inventoried crude oil are recognized in the financial statements at the time of production.

2018 9

As a result, netbacks fluctuate depending on the timing of entitlement oil sales. Management believes that netback is a useful supplemental measure to analyze operating performance and provide an indication of the results generated by the Company’s principal business activities prior to the consideration of other income and expenses. Netback does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

MANAGEMENT STRATEGY AND OUTLOOK

The 2019 outlook provides information as to management’s expectation for results of operations for 2019. Readers are cautioned that the 2019 outlook may not be appropriate for other purposes. The Company’s expected results are sensitive to fluctuations in the business environment, including disruptions caused by the ongoing political changes and civil unrest occurring in the jurisdictions that the Company operates in, and may vary accordingly. This outlook contains forward-looking statements that should be read in conjunction with the Company’s disclosure under “Forward-Looking Statements”, outlined on the first page of this Management's Discussion & Analysis ("MD&A").

2019 Outlook

The 2019 production outlook for the Company is provided as a range to reflect timing and performance contingencies.

Total corporate production is expected to range between 14,000 and 15,000 boe/d for 2019 (mid-point of 14,500 boe/d) with a 94% weighting to oil and liquids. Egypt oil production is expected to range between 11,600 and 12,400 bbls/d in 2019. Canadian production was expected to range between 2,400 and 2,600 boe/d in 2019, which included approximately 300 boe/d of ethane production, which is currently being sold as natural gas with increased energy content. A prolonged shut down of the third party deep cut extraction plant may impact the Canadian production boe/d guidance for 2019. The third party operated gas processor has shut down their deep cut ethane extraction plant due to low ethane prices and associated pipeline egress issues in Alberta. The reduction of ethane sales is expected to be generally revenue neutral due to the increased energy content of natural gas sales. The Canadian production range includes 12 months of production from the 2018 drilling program which was complete and ready for production in January of 2019.

Funds flow from operations in any given period will be dependent upon the timing of crude oil tanker liftings in Egypt and the market price of the crude oil sold. Because these factors are difficult to accurately predict, the Company has not provided funds flow from operations guidance for 2019. Funds flow from operations and inventory levels in Egypt may fluctuate significantly from quarter to quarter due to the timing of liftings.

The below chart provides a comparison of projected netbacks of a typical Cardium well compared to a similar well in Egypt under multiple price sensitivities.

Netback sensitivity
Benchmark crude oil price (US$/bbl)	40		50		60	70	80
Benchmark natural gas price (C$/mcf)	0.95		1.10		1.30	1.50	1.70
Netback ($/boe)
Egypt - crude oil1	2.62		6.85		11.08	15.32	19.55
Canada - crude oil2	17.63		25.17		32.20	39.43	46.61
Canada - natural gas and NGLs2	(1.25	)	(0.10	)	0.87	2.64	4.39
1  Egypt assumptions: using anticipated 2019 Egypt production profile, Ras Gharib price differential estimate of $10.50 per bbl applied consistently at all price points, concession    differentials of 4%/5%/3% applied to WG/WB/NWG respectively, operating costs estimated at ~$9.90/bbl, and maximum cost recovery resulting from accumulated cost pools.
2  Canada assumptions: using anticipated 2019 Canada production profile, Edmonton Light price differential estimate of $8.00 per bbl, Edmonton Light to Harmattan discount of C$2.50    per bbl, operating costs estimated at ~C$12.70/boe, NGL mixture price at 45% of Edmonton Light, and takes into consideration Canadian tax pools.

2019 Capital Budget

The Company’s 2019 budgeted capital program of $34.1 million (before capitalized G&A) includes $24.1 million for Egypt and $10.0 million (C$13.0 million) for Canada. The 2019 plan was prepared to maximize free cash flow to direct at future value growth opportunities.

Egypt

The $24.1 million Egypt program has $7.0 million (30%) allocated to exploration and $17.1 million (70%) to development. 

The $7.0 million 2019 exploration program includes 2 exploration wells in the Eastern Desert (1 well in West Bakr, 1 well in NW Gharib), an appraisal well and contingent early development capital at South Ghazalat. The West Bakr exploration well is in H block targeting a potential Asl A pool extension of the Rabul field which was discovered and placed on production in the adjacent GPC concession to the south. The NW Gharib exploration well is targeting an undrilled fault block north of the NWG 38A pool. 

The $17.1 million 2019 development program is focused on the Eastern Desert which includes: 3 development wells in West Bakr (1 each in M, H and K pools) and 1 development well in the NW Gharib 38A pool, 10 recompletions in West Bakr, facility and water handling expansion at West Bakr and development/maintenance projects in the Eastern Desert (West Bakr, NW Gharib and West Gharib). 

The primary focus of the 2019 Egypt plan is to sustain/grow Eastern Desert production and to evaluate the South Ghazalat exploration concession in the Western Desert. No additional production has been forecast from South Ghazalat pending approval of the SGZ 6X development plan. Additional investment in South Alamein is conditional on negotiating the necessary extensions following the military rejection of access to the SA 24 X exploration well surface location. 

10 2018

Canada

The $10.0 million (C$13.0 million) Canada program consists of 4 (4 net) horizontal (multi-stage frac) wells targeting the Cardium light oil resource at Harmattan and additional maintenance/development capital. The Cardium drilling program in 2019 consists of 3 development wells and 1 outpost well (deferred from the 2018 program) to evaluate the south Harmattan acreage acquired in 2018. The 2019 program is contingent on differentials for Western Canadian Edmonton light sweet oil prices remaining at economic levels.

The 2019 capital program is summarized in the following table:

	TransGlobe 2019 Capital ($MM)					Gross Well Count
	Development		Exploration		Total	Drilling
Concession	Wells	Other1	Wells	Other1		Devel	Explor	Total
West Gharib	—	2.7	—	—	2.7	—	—	—
West Bakr	3.4	9.8	1.1	—	14.3	3	1	4
NW Gharib	1.0	0.3	1.0	—	2.3	1	1	2
South Alamein	—	—	—	1.3	1.3	—	—	—
South Ghazalat	—	—	1.2	2.3	3.5	—	1	1
Egypt	$4.4	$12.8	$3.3	$3.6	$24.1	4	3	7
Canada	$6.3	$0.5	$3.2	—	$10.0	3	1	4
2019 Total	$10.7	$13.3	$6.5	$3.6	$34.1	7	4	11
Splits (%)	70%		30%		100%	64%	36%	100%
1  Other includes completions, workovers, recompletions and equipping.

2018 11

SELECTED ANNUAL INFORMATION

($000s, except per share, price and volume amounts)	2018	% Change	2017		% Change	20165
Operations
Average production volumes
Crude oil (bbls/d)	12,708	(5)	13,411		11	12,033
NGLs and condensate (bbls/d)	780	(21)	988		28065	34
Natural gas (mcf/d)	5,707	(14)	6,644		27895	230
Total (boe/d)	14,439	(7)	15,506		28	12,105
Average sales volumes
Crude oil (bbls/d)	13,282	(10)	14,754		33	11,093
NGLs and condensate (bbls/d)	780	(21)	988		28065	34
Natural gas (mcf/d)	5,707	(14)	6,644		27895	230
Total (boe/d)	15,013	(11)	16,849		51	11,165
Average realized sales prices
Crude oil ($/bbl)	59.57	33	44.71		49	30.05
NGLs and condensate ($/bbl)	27.17	27	21.31		24	17.20
Natural gas ($/mcf)	1.26	(26)	1.70		(6)	1.81
Total oil equivalent ($/boe)	54.59	33	41.07		37	29.94
Inventory (mbbls)	568.1	(27)	776.8		(39)	1,265.1
Petroleum and natural gas sales	299,144	18	252,591		106	122,360
Petroleum and natural gas sales, net of royalties	176,227	19	148,464		135	63,134
Cash flow generated by (used in) operating activities	69,192	16	59,450		5,682	(1,065	)
Funds flow from operations1	63,282	14	55,592		765	(8,361	)
Funds flow from operations per share:
- Basic	0.87		0.77			(0.12	)
- Diluted2	0.86		0.77			(0.12	)
Net earnings (loss)	15,677	120	(78,736	)	10	(87,665	)
Net earnings (loss) per share:
- Basic	0.22		(1.09	)		(1.21	)
- Diluted2	0.22		(1.09	)		(1.21	)
Capital expenditures	40,706	7	38,159		43	26,658
Property expenditures	—	—	—		(100)	59,475
Dividends paid	2,527	—	—			—
Dividends paid per share	0.035	—	—			—
Total assets	318,296	(3)	327,702		(19)	406,142
Cash and cash equivalents	51,705	9	47,449		51	31,468
Working capital	50,987	1	50,639		402	(16,764	)
Convertible debentures	—	—	—		—	72,655
Note payable	—	—	—		—	11,162
Total long-term debt, including current portion	52,355	(25)	69,999		100	—
Net debt-to-funds flow from operations ratio3	0.02		0.35			(12.00	)
Reserves
Total proved (mmboe)4	26.9	(2)	27.5		(8)	29.9
Total proved plus probable (mmboe)4	44.1	(4)	45.9		(8)	50.0
1   Funds flow from operations (before finance costs) is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
2   Funds flow from operations per share (diluted) and net earnings (loss) per share (diluted) was not impacted by the convertible debentures for the year ended December 31, 2016 as the convertible debentures were not dilutive in this year.
3   Net debt-to-funds flow from operations ratio is a measure that represents total long-term debt, note payable, and convertible debentures (including the current portion) net of working capital, over funds flow from operations for the trailing 12 months, and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
4 As determined by the Company's 2018 & 2017 independent reserves evaluator, GLJ Petroleum Consultants Ltd. (“GLJ”), in their reports dated January 22, 2019 and January 9, 2018,           with effective dates of December 31, 2018 and December 31, 2017. As determined by the Company's 2016 independent reserves evaluator, DeGolyer and MacNaughton Canada Limited           ("DeGolyer") of Calgary, Alberta, in their report dated January 18, 2017 with an effective date of December 31, 2016. The reports of GLJ and DeGolyer have been prepared in accordance          with the standards contained in the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian          Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time and National Instrument 51-101.
5  The 2016 information includes the results of the operations of the Harmattan assets in Alberta, Canada from December 20, 2016 to December 31, 2016 (12 days). The Harmattan     assets were acquired in a transaction that closed on December 20, 2016 (effective December 1, 2016).

In 2018 compared with 2017, TransGlobe:

• Reported a 7% decrease in production volumes compared to 2017. In Egypt, the decrease was primarily due to natural declines in production, partially offset by drilling and well optimization results. In Canada, production was lower due to the planned Harmattan turnaround, unscheduled compressor maintenance in November and curtailments due to low pricing;

• Ended 2018 with inventoried crude oil of 568.1 mbbls, a decrease of 208.7 mbbls over inventoried crude oil levels at December 31, 2017;

12 2018

• Increased petroleum and natural gas sales by 18% due to a 33% increase in realized prices, partially offset by an 11% decrease in sales volumes;

• Reported positive funds flow from operations of $63.3 million (2017 - $55.6 million);

• Ended the year with positive working capital of $51.0 million, including $51.7 million in cash and cash equivalents as at December 31, 2018;

• Reported net earnings of $15.7 million (2017 - net loss of $78.7 million). The 2018 net earnings includes a $14.5 million impairment loss on the Company's exploration and evaluation assets and a $9.3 million unrealized derivative gain on commodity contracts. Excluding the impairment loss and the unrealized gain on derivative commodity contracts, the Company would have achieved net earnings of $20.9 million;

• Spent $40.7 million on capital expenditures, funded entirely from cash flow from operations and cash on hand;

• Paid a dividend of $0.035 per share ($2.5 million) on September 14, 2018 to shareholders of record on August 31, 2018; and

• Repaid $17.8 million of long-term debt with cash on hand.

2018 13

SELECTED QUARTERLY FINANCIAL INFORMATION

	2018						2017
($000s, except per share,
price and volume amounts)	Q-4	Q-3		Q-2	Q-1		Q-4		Q-3		Q-2		Q-1
Operations
Average production volumes
Crude oil (bbls/d)	13,463	12,506		12,409	12,452		12,027		12,786		14,347		14,514
NGLs (bbls/d)	829	876		521	894		915		1,081		919		1,037
Natural gas (mcf/d)	5,865	5,695		5,094	6,176		6,059		6,268		7,191		7,075
Total (boe/d)	15,270	14,331		13,779	14,375		13,952		14,912		16,465		16,731
Average sales volumes
Crude oil (bbls/d)	12,676	12,665		17,931	9,830		14,324		15,894		17,141		11,610
NGLs (bbls/d)	829	876		521	894		915		1,081		919		1,037
Natural gas (mcf/d)	5,865	5,695		5,094	6,176		6,059		6,268		7,191		7,075
Total (boe/d)	14,483	14,490		19,301	11,753		16,249		18,020		19,259		13,826
Average realized sales prices
Crude oil ($/bbl)	60.12	61.79		59.39	56.26		53.25		44.82		39.46		41.66
NGLs ($/bbl)	24.39	22.64		38.39	27.72		26.86		18.90		21.08		19.08
Natural gas ($/mcf)	1.22	1.01		1.08	1.70		0.94		1.65		2.14		1.96
Total oil equivalent ($/boe)	54.51	55.77		56.49	50.06		48.80		41.24		36.92		37.41
Inventory (mbbls)	568.1	495.6		510.3	1,012.7		776.8		988.1		1,274.1		1,528.3
Petroleum and natural gas sales	72,628	74,345		99,220	52,951		72,954		68,372		64,712		46,553
Petroleum and natural gas sales, net of royalties	40,605	42,453		68,454	24,715		40,725		44,839		40,439		22,461
Cash flow generated by (used in) operating activities	9,822	47,639		18,886	(7,155	)	44,263		20,437		(2,753	)	(2,497	)
Funds flow from operations1	8,842	17,018		33,499	3,923		17,018		19,217		16,855		2,502
Funds flow from operations per share:
- Basic	0.12	0.24		0.46	0.05		0.24		0.27		0.23		0.03
- Diluted	0.12	0.23		0.46	0.05		0.24		0.27		0.23		0.03
Net earnings (loss)	30,719	(12,283	)	7,361	(10,120	)	(2,382	)	(6,855	)	(56,622	)	(12,877	)
Net earnings (loss) per share:
- Basic	0.43	(0.17	)	0.10	(0.14	)	(0.03	)	(0.09	)	(0.78	)	(0.18	)
- Diluted	0.43	(0.17	)	0.10	(0.14	)	(0.03	)	(0.09	)	(0.78	)	(0.18	)
Capital expenditures	17,433	12,783		5,855	4,635		9,078		10,133		8,230		10,718
Dividends paid	—	2,527		—	—		—		—		—		—
Dividends paid per share	—	0.035		—	—		—		—		—		—
Total assets	318,296	314,203		329,542	312,691		327,702		338,802		337,596		403,686
Cash and cash equivalents	51,705	62,663		38,088	31,084		47,449		21,464		13,780		21,324
Working capital	50,987	52,351		60,464	45,252		50,639		58,815		60,319		42,759
Note payable	—	—		—	—		—		—		—		11,259
Total long-term debt, including current portion	52,355	52,532		62,173	67,167		69,999		79,839		83,725		73,549
Net debt-to-funds flow from operations ratio2	0.02	0.00		0.02	0.36		0.35		0.70		2.00		(13.90	)
1  Funds flow from operations (before finance costs) is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be    comparable to measures used by other companies. See "Non-GAAP Financial Measures".
2  Net debt-to-funds flow from operations ratio is a measure that represents total long-term debt, including the current portion, net of working capital over funds flow from operations     from the trailing 12 months and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".

During the fourth quarter of 2018, TransGlobe:

• Reported a 9% increase in production volumes compared to Q4-2017 primarily due to drilling and well optimization results in Egypt which were partially offset by reduced production in Canada during November associated with unscheduled compressor maintenance and curtailments due to low pricing;

• Sold one cargo of TransGlobe's entitlement crude oil of 450.0 mbbls during the quarter and ended the year with crude oil inventory of 568.1 mbbls;

• Petroleum and natural gas sales were flat compared to Q4-2017 due to a 12% increase in realized prices offset by an 11% decrease in sales volumes;

• Reported positive funds flow from operations of $8.8 million, inclusive of an $8.1 million realized derivative loss on commodity contracts;

• Reported net earnings of $30.7 million, inclusive of a $29.5 million unrealized derivative gain on commodity contracts; and

• Spent $17.4 million on capital expenditures, funded entirely from cash flows from operations and cash on hand.

14 2018

BUSINESS ENVIRONMENT

The Company’s financial results are significantly influenced by fluctuations in commodity prices, including oil price differentials. The following table shows select market benchmark prices and foreign exchange rates:

Average reference prices	2018	2017
Crude oil
Dated Brent average oil price (US$/bbl)	71.06	54.25
Edmonton Sweet index (US$/bbl)	53.65	48.50
Natural gas
AECO (C$/mmbtu)	1.50	2.16
US/Canadian Dollar average exchange rate	1.29	1.30

In 2018, the average price of Dated Brent was 31% higher than 2017. Egypt production is priced based on Dated Brent, less a quality differential and is shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost oil or cost recovery barrels) which are assigned 100% to the Company. The contracts provide for cost recovery per quarter up to a maximum percentage of total production. Timing differences often exist between the Company's recognition of costs and their recovery as the Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSC, the Contractor's share of excess ranges between 0% and 30%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum cost oil ranges from 25% to 30% in Egypt. The balance of the production after maximum cost recovery is shared with the government (profit oil). Depending on the contract, the Egyptian government receives 70% to 86% of the profit oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of profit oil increases when production exceeds pre-set production levels in the respective contracts. During times of high oil prices, the Company receives less cost oil and may receive more production-sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil. For reporting purposes, the Company records the government’s share of production as royalties and taxes (all taxes are paid out of the government’s share of production) which will increase during times of rising oil prices and decrease in times of declining oil prices. If oil prices are sufficiently low and the Ras Gharib/Dated Brent differential is high, the cost oil portion may not be sufficient to cover operating costs and capital costs, or even operating costs alone. When this occurs, the non-recovered costs accumulate in the Company’s cost pools and are available to be offset against future cost oil during the term of the PSC and any eligible extension periods.

EGPC owns the storage and export facilities where the Company's production is delivered and the Company requires EGPC cooperation and approval to schedule liftings. Once liftings occur, the Company incurs a 30-day collection cycle on liftings as a result of direct marketing to third-party international buyers. Depending on the Company's assessment of the credit of crude oil cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings.

In 2018, the average price of Edmonton Sweet index oil (expressed in USD) was 11% higher than 2017. In 2018, the average price of AECO natural gas decreased 31% compared to 2017.

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest before Royalties (boe/d)

Production Volumes

	2018	2017
Egypt crude oil (bbls/d)	12,150	12,822
Canada crude oil (bbls/d)	558	589
Canada NGLs (bbls/d)	780	988
Canada natural gas (mcf/d)	5,707	6,644
Total Company (boe/d)	14,439	15,506

Sales Volumes (excludes volumes held as inventory)

	2018	2017
Egypt crude oil (bbls/d)	12,724	14,165
Canada crude oil (bbls/d)	558	589
Canada NGLs (bbls/d)	780	988
Canada natural gas (mcf/d)	5,707	6,644
Total Company (boe/d)	15,013	16,849

2018 15

Netback

Consolidated netback
	2018		2017
($000s, except per boe amounts)1	$	$/boe	$	$/boe
Petroleum and natural gas sales	299,144	54.59	252,591	41.07
Royalties2	122,917	22.43	104,127	16.93
Current taxes2	26,340	4.81	21,819	3.55
Production and operating expenses	53,298	9.73	51,005	8.29
Selling costs	2,103	0.38	2,495	0.41
Netback	94,486	17.24	73,145	11.89
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended December 31, 2018 and December 31, 2017 (these figures do not include TransGlobe's    Egypt entitlement barrels held as inventory at December 31, 2018 and December 31, 2017).
2  Royalties and taxes are settled on a production basis, royalties and taxes attributable to oil sales fluctuates dependent upon the sale of inventoried entitlement oil.

Egypt - total
	2018		2017
($000s, except per bbl amounts)1	$	$/bbl	$	$/bbl
Oil sales	278,111	59.88	230,323	44.55
Royalties2	120,271	25.90	99,336	19.21
Current taxes2	26,340	5.67	21,819	4.22
Production and operating expenses	45,562	9.81	44,705	8.65
Selling costs	2,103	0.45	2,495	0.48
Netback	83,835	18.05	61,968	11.99
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended December 31, 2018 and December 31, 2017 (these figures do not include TransGlobe's    Egypt entitlement barrels held as inventory at December 31, 2018 and December 31, 2017).
2  Royalties and taxes are settled on a production basis, royalties and taxes attributable to oil sales fluctuates dependent upon the sale of inventoried entitlement oil.

The netback per bbl in Egypt increased by 51% in 2018 compared to 2017. The increase was due to a 34% higher realized oil price offset by a decrease in production and increase in operating expenses of 13%. The increase in production and operating expenses was primarily due to an extensive workover program and higher diesel, transportation and service costs due to stronger oil prices.

Royalties and taxes as a percentage of revenue were 53% in 2018 (2017 - 53%). Royalties and taxes are settled on a production basis, therefore, the correlation of royalties and taxes to oil sales fluctuates depending on the timing of entitlement oil sales. If sales volumes had been equal to production volumes during the year, royalties and taxes as a percentage of revenue would have been 55% (2017 - 58%). In periods when the Company sells less than its entitlement production, royalties and taxes as a percentage of revenue will be higher than the PSCs dictate. In periods when the Company sells more than its entitlement production, royalties and taxes as a percentage of revenue will be lower than the terms the PSCs dictate.

The average selling price for the year ended December 31, 2018 was $59.88/bbl (2017 - $44.55/bbl), which was $11.18/bbl lower (2017 - $9.70/bbl) than the average Dated Brent oil price of $71.06/bbl for 2018 (2017 - $54.25/bbl). The difference between the average Dated Brent price and the Company's realized selling price is due to a gravity/quality adjustment and is impacted by the timing of direct sales.

Canada
	2018		2017
($000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	10,666	52.37	10,464	48.67
Natural gas sales	2,632	7.58	4,120	10.19
NGL sales	7,735	27.17	7,684	21.31
Total sales	21,033	25.17	22,268	22.73
Royalties	2,646	3.17	4,791	4.89
Production and operating expenses	7,736	9.26	6,300	6.43
Netback	10,651	12.74	11,177	11.41

The netback in Canada was $12.74 per boe in 2018, an increase of $1.33 per boe (12%) compared to 2017. The increase is mainly due to an 11% higher realized sales price and 35% lower royalties. This was partially offset by a 44% increase in production and operating expenses attributable to the planned turnaround at Harmattan in Q2-2018, workovers and higher costs due to stronger oil prices.

In 2018, the Company's Canadian operations incurred $2.1 million lower royalty costs than in 2017. The reduction in royalties is primarily due to Gas Cost Allowance (GCA) rebates received in 2018. Royalties amounted to 13% of petroleum and natural gas sales revenue during 2018 compared to 22% during the prior year. TransGlobe pays royalties to the Alberta provincial government and landowners in accordance with the established royalty regime. In Alberta, Crown royalty rates are based on reference commodity prices, production levels and well depths, and are offset by certain incentive programs, which usually have a finite period of time and are in place to promote drilling activity by reducing overall royalty expense.

16 2018

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)

	2018				2017
($000s, except per boe amounts)	$		$/boe		$		$/boe
General and administrative (gross)	16,312		2.98		16,033		2.61
Stock-based compensation	3,536		0.65		1,478		0.24
Capitalized G&A and overhead recoveries	(1,160	)	(0.21	)	(2,258	)	(0.37	)
General and administrative (net)	18,688		3.42		15,253		2.48

General and administrative (gross) increased by 2% in 2018 compared with 2017. The increase is primarily due to costs related to the AIM listing, offset by a general reduction of G&A in 2018. Stock-based compensation expense increased by 139% in 2018 compared with 2017. This increase is primarily due to an increase in the Company's average share price in 2018 and the associated revaluation of previously granted and unexercised stock-based compensation.

FINANCE COSTS

($000s)	2018		2017
Convertible debentures1	$	—	$	1,089
Long-term debt	4,275		3,994
Note payable2	—		532
Reserves based lending facility	440		289
Amortization of deferred financing costs	360		329
Finance costs	$	5,075	$	6,233
1  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).
2  The Company repaid the outstanding vendor take-back note balance of C$13.6 million ($10.0 million) on May 16, 2017.

Finance costs decreased to $5.1 million in 2018 from $6.2 million in 2017. This decrease is due to the reduction in balances of long-term debt from repayments, partially offset by higher borrowing costs due to an increase in LIBOR, which has increased by 71% over the average in 2017.

As at December 31, 2018, the Company had a prepayment arrangement with Mercuria Energy Trading S.A. ("Mercuria") that allows for a revolving balance of up to $75.0 million, of which $45.0 million is outstanding. During 2018, the Company made repayments of $15.0 million on this loan.

As at December 31, 2018, the Company had a revolving Canadian reserves-based lending facility with Alberta Treasury Branches ("ATB") totaling C$30.0 million ($22.0 million), of which C$11.2 million ($8.2 million) is outstanding. During 2018, the Company made repayments of $2.8 million on this loan.

The prepayment agreement and reserves-based lending facility are subject to certain covenants, the details of which are outlined in Note 17 to the Company's Consolidated Financial Statements. Refer to the related description of TransGlobe's debt included in the December 31, 2018 Consolidated Financial Statements.

DEPLETION, DEPRECIATION AND AMORTIZATION (“DD&A”)

	2018		2017
($000s, except per boe amounts)	$	$/boe	$	$/boe
Egypt	26,271	5.66	30,653	5.93
Canada	7,711	9.23	8,985	9.17
Corporate	309	—	398	—
Total	34,291	6.26	40,036	6.51

In Egypt, DD&A decreased by 14% in 2018 compared to 2017. The decrease was primarily related to lower production in 2018.

In Canada, DD&A was $9.23 per boe which was in line with DD&A per barrel recognized in 2017.

IMPAIRMENT LOSS

E&E assets are tested for impairment if facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount and when they are reclassified to petroleum properties.

For the year ended December 31, 2018 the Company recorded a non-cash impairment loss of $14.5 million on its exploration and evaluation assets. The impairment related to the North West Sitra concession in Egypt and represents the entire intangible E&E asset balance of this concession. It was determined that an impairment loss was necessary as no commercially viable quantities of oil were discovered at North West Sitra, and no further drilling activities were planned.

All commitments have been met in advance of the end of the first exploration phase. Prior to January 7, 2019, the expiration date of the concession, the Company did not elect to enter the second and final exploration phase.

For the year ended December 31, 2017 the Company recorded an impairment loss of $79.0 million on its E&E 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).

2018 17

In 2017 at South West Gharib it was determined that an impairment loss was necessary as no commercial quantities of oil were discovered, and no further drilling activities were planned. The Company elected to not enter the second exploration period and relinquished the concession in 2017. At North West Gharib the Company elected to not enter the second exploration period, and instead filed for and received four development leases in the concession, all remaining exploration lands not covered by development leases were relinquished. At South Alamein, it was determined that an impairment loss was necessary, due to the results of the Boraq 5 well test and the uncertainty of an economic development of Boraq in the future. The Boraq 5 well failed to produce any hydrocarbons from the two zones and was plugged and abandoned in 2017.

CAPITAL EXPENDITURES

($000s)	2018	2017
Egypt	28,673	31,151
Canada	11,965	6,967
Corporate	68	41
Total	40,706	38,159

Capital expenditures in 2018 were $40.7 million (2017 - $38.2 million).

In Egypt, the Company incurred $15.2 million of capitalized drilling costs, $2.4 million in completion costs and $5.1 million of facilities-related capital. During 2018, the Company drilled eight development wells in the Eastern Desert and four exploration wells in the Western Desert. Four development wells were drilled and completed at West Bakr (K-46, K-45, M-North and M-South), two at West Gharib (Arta 48 and Arta 54) and two at NW Gharib (NWG 38A-Inj and NWG 38A-7). The Company also began drilling the M-10 twin well at West Bakr in early December and commenced well-site construction at North West Gharib for NWG 38A-8. Two exploration wells were drilled at North West Sitra (NWS 9 and NWS 12X) and two at South Ghazalat (SGZ 1X and SGZ 6X).

In Canada, the Company incurred $5.5 million of capitalized drilling costs, $5.7 million in completion, pipeline and facilities-related capital and $0.5 million in land acquisition costs. During 2018, the Company drilled and cased five gross (4.5 net) one-mile horizontal wells, one two-mile horizontal well and acquired 16 net sections (10,240 acres) of Cardium prospective exploration lands to the south/south west of the Harmattan pool. The Company also completed construction of a new oil gathering pipeline to connect the new multi-well pad and two existing producers to the Company's main oil processing facility.

OUTSTANDING SHARE DATA

As at December 31, 2018, the Company had 72,205,369 common shares issued and outstanding and 4,875,382 stock options issued and outstanding, of which 2,765,569 are exercisable in accordance with their terms into an equal number of common shares of the Company.

LIQUIDITY AND CAPITAL RESOURCES

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 that maintain and increase production and reserves, to acquire strategic oil and gas assets and to repay current liabilities and debt. TransGlobe’s capital programs are funded by its existing working capital and cash provided from operating activities. The Company's cash flow from operations varies significantly from quarter to quarter, depending on the timing of tanker liftings, and these fluctuations in cash flow impact the Company's liquidity. TransGlobe's management will continue to steward capital programs and focus on cost reductions in order to maintain balance sheet strength through the current volatile oil price environment.

Funding for the Company’s capital expenditures was provided by cash flow from operations and cash on hand. The Company expects to fund its

2019 exploration and development program through the use of working capital and cash flow from operations. The Company also expects to pay down debt and explore business development opportunities with its working capital. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks may impact capital resources and capital expenditures.

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2018, the Company had a working capital surplus of $51.0 million (December 31, 2017 - surplus of $50.6 million). The increase in working capital in 2018 is due to an increase in cash from higher sales due to stronger crude oil prices and the asset position of the Company's derivative commodity contracts marked-to-market, offset by a decrease in accounts receivable and inventory since December 31, 2017.

As at December 31, 2018, 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.

In the past 10 years, the Company experienced delays in the collection of accounts receivable from EGPC. The length of delay peaked in 2013, returned to historical delays of up to six months in 2017, and has since decreased to a historical low. As at December 31, 2018, amounts owing from EGPC were $7.0 million. The Company considers there to be minimal credit risk associated with EGPC's delays.

The Company completed a fourth direct crude oil sale in Q4-2018 for total proceeds of $30.9 million, which were collected in December 2018 and January 2019. The Company now incurs a 30-day collection cycle on sales to third-party international buyers. Depending on the Company's assessment of the credit of crude oil cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings, which has significantly reduced the Company's credit risk profile. As at December 31, 2018, the Company held 568.1 mbbls of entitlement oil as inventory.

At December 31, 2018, the Company had $97.0 million of revolving credit facilities with $53.2 million drawn and $43.8 million available. The Company had the prepayment agreement with Mercuria that allows for a revolving balance of up to $75.0 million, of which $45.0 million is drawn. During 2018, the Company repaid $15.0 million of this facility. The Company also had a revolving Canadian reserves-based lending facility with ATB totaling C$30.0 million ($22.0 million), of which C$11.2 million ($8.2 million) was drawn. During 2018, the Company had drawings of C$0.6 million ($0.5 million) and repayments of C$3.6 million ($2.8 million) on this facility.

18 2018

The Company paid a dividend of $0.035 per share ($2.6 million) on September 14, 2018 to shareholders of record on August 31, 2018. The Company declared a dividend of $0.035 per share payable April 18, 2019 to shareholders of record on March 29, 2019.

To date, the Company has experienced no difficulties with transferring funds abroad (see "Risks and Uncertainties").

PRODUCT INVENTORY

Product inventory consists of the Company's Egypt entitlement crude oil barrels, which are valued at the lower of cost or net realizable value. Cost includes operating expenses and depletion associated with the unsold entitlement crude oil as determined on a concession by concession basis. All oil produced is delivered to EGPC facilities, and EGPC also owns the storage and export facilities where the Company's product inventory is sold. The Company requires EGPC approval to schedule liftings and works with EGPC on a continuous basis to schedule tanker liftings. Crude oil inventory levels fluctuate from year to year depending on EGPC approvals, as well as the timing and size of tanker liftings in Egypt. As at December 31, 2018, the Company had 568.1 mbbls of entitlement oil as inventory, which represents approximately three and a half months of entitlement oil production. Since the Company began directly marketing its oil on January 1, 2015, both increases and decreases in crude oil inventory levels have been experienced from year to year. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows. The Company is targeting the sale of approximately four cargoes of entitlement oil during 2019. Depending on the timing of sales and production during 2019, it is expected that 2019 year end inventory will be similar to 2018 year end. Inventoried entitlement crude oil was reduced by 208.7 mbbls in 2018 compared to 2017.

	Year ended		Year ended
(mbbls)	December 31, 2018		December 31, 2017
Product inventory, beginning of period	776.8		1,265.1
TransGlobe entitlement production	1,963.8		2,101.8
Tanker liftings	(953.9	)	(1,468.7	)
EGPC sales	(1,218.6	)	(1,121.4	)
Product inventory, end of period	568.1		776.8

Inventory reconciliation

The following table summarizes the operating expenses and depletion capitalization in unsold entitlement crude oil inventory.

	Year ended	Year ended
	December 31, 2018	December 31, 2017
Production and operating expenses ($/bbls)	9.98	8.46
Depletion - ($/bbls)	5.32	6.31
Unit cost of inventory - ($/bbls)	15.30	14.77
Product inventory, end of period - (mbbls)	568.1	776.8
Product inventory, end of period - $000	8,692	11,474

COMMITMENTS AND CONTINGENCIES

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

($000s)		Payment Due by Period1,2
	Recognized
	in Financial	Contractual	Less than
	Statements	Cash Flows	1 year	1-3 years
Accounts payable and accrued liabilities	Yes - Liability	28,007	28,007	—
Long-term debt	Yes - Liability	52,355	—	52,355
Other long-term liabilities	Yes - Liability	1,007	—	1,007
Office and equipment leases3	No	2,949	1,985	964
Total		84,318	29,992	54,326
1  Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2  Payments denominated in foreign currencies have been translated at December 31, 2018 exchange rates.
3  Office and equipment leases include all drilling rig contracts.

Pursuant to the PSC of North West Sitra in Egypt, the Company had a minimum financial commitment of $10.0 million and a work commitment

for two wells and 300 square kilometers of 3-D seismic during the initial three-and-a-half year exploration period, which commenced on January

8, 2015. The Company requested and received a six month extension of the initial exploration period to January 7, 2019. As at December 31, 2018, the Company had met its financial and operating commitments, with the acquisition of 600 square kilometers of 3-D seismic in 2017 and thedrilling of two wells in 2018. The Company has now completed the initial exploration period work program and based on well results did not elect to enter the second exploration phase and relinquished the concession on January 7, 2019.

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.

2018 19

The Company is not aware of any material provisions or other contingent liabilities as at December 31, 2018.

ASSET RETIREMENT OBLIGATION

As at December 31, 2018, TransGlobe had an asset retirement obligation ("ARO") of $12.1 million (December 31, 2017 - $12.3 million) for the future abandonment and reclamation costs of the Canadian assets. The estimated ARO liability includes assumptions of actual costs to abandon and/or reclaim wells and facilities, the time frame in which such costs will be incurred, as well as inflation factors in order to calculate the undiscounted total future liability. TransGlobe calculated the present value of the obligations using discount rates between 1.86% and 2.18% 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.

Under the terms of the PSCs, TransGlobe is not responsible for ARO in Egypt.

DERIVATIVE COMMODITY CONTRACTS

The nature of TransGlobe’s operations exposes it to fluctuations in commodity prices, interest rates and foreign currency exchange rates. TransGlobe monitors and when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by TransGlobe are related to an underlying financial position or to future crude oil and natural gas production. TransGlobe does not use derivative financial instruments for speculative purposes. TransGlobe has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in net earnings (loss) at each reporting period. TransGlobe has not obtained collateral or other security to support its financial derivatives as management reviews the creditworthiness of its counterparties prior to entering into derivative contracts. The derivative financial instruments are initiated within the guidelines of the Company's corporate hedging policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.

In conjunction with the prepayment agreement, discussed further in the Liquidity and Capital Resources section of this MD&A, TransGlobe also entered into a marketing contract with Mercuria to market nine million barrels of TransGlobe's Egypt entitlement production. The pricing of the crude oil sales is based on market prices at the time of sale.

The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at December 31, 2018, the fair values of which have been presented on the Consolidated Balance Sheet:

Financial Brent Crude Oil Contracts
Period Hedged	Contract	Volume bbl	Monthly Volume bbl	Bought Put USD$/bbl	Sold Call USD$/bbl	Sold Put USD$/bbl
Jul 2020 - Dec 2020	3-Way Collar	300	50,000	54.00	70.00	45.00
Jan 2020 - Jun 2020	3-Way Collar	300	50,000	54.00	70.00	46.50
Jan 2019 - Dec 2019	3-Way Collar	198	16,500	53.00	62.10	46.00
Jan 2019 - Dec 2019	3-Way Collar	200	16,666.5	54.00	61.35	46.00
Jan 2019 - Dec 2019	Bear Put Spread	198	16,500	53.00	—	46.00
Jan 2019 - Dec 2019	Bear Put Spread	200	16,666.5	54.00	—	46.00

OFF BALANCE SHEET ARRANGEMENTS

The Company has certain lease arrangements, all of which are reflected in the Commitments and Contingencies table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the Consolidated Balance Sheet as at December 31, 2018.

RISKS AND UNCERTAINTIES

TransGlobe’s results are affected by a variety of business risks and uncertainties in the international petroleum industry. Many of these risks are not within the control of management, however the Company has adopted several strategies to reduce and minimize the effects of these risks:

Financial risk

Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions that could have a positive or negative impact on TransGlobe.

The Company actively manages its cash position and maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future cash flow from operations, working capital and availability under existing credit facilities will be adequate to support these financial liabilities and its capital programs.

The political changes that have created financial instability in Egypt since 2011 could present challenges to the Company if the issues re-emerge in future years. Future instability could reduce the Company’s ability to access debt, capital and banking markets. To mitigate potential financial risk factors, the Company maintains a strong liquidity position. Management regularly evaluates operational and financial risk strategies and continues to monitor the 2019 capital budget and the Company’s long-term plans. In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. The Company anticipates that direct sales will continue to reduce financial risk in future periods.

20 2018

Market risk

Market risk is the risk or uncertainty arising from possible market price movements and the associated impact on future performance of the business. The market price movements that the Company is exposed to include commodity prices, foreign currency exchange rates and interest rates, all of which could have a positive or negative impact on TransGlobe.

Commodity price risk

The Company’s operational results and financial condition are dependent on the commodity prices received for its oil and gas production.

Any movement in commodity prices would have an effect on the Company’s financial condition which could result in the delay or cancellation of drilling, development or construction programs, all of which could have a material adverse impact on the Company. The Company uses financial derivative contracts from time to time, as deemed necessary, to manage fluctuations in commodity prices in the normal course of operations. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors.

Foreign currency exchange risk

As the Company’s business is conducted primarily in US dollars and its financial instruments are primarily denominated in US dollars, the Company’s exposure to foreign currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, long-term debt and accounts payable and accrued liabilities denominated in Canadian dollars. When assessing the potential impact of foreign currency exchange risk, the Company believes that 10% volatility is a reasonable measure. The Company estimates that a 10% increase in the value of the Canadian dollar against the US dollar would decrease the net earnings for the year ended December 31, 2018 by approximately $1.5 million and conversely a 10% decrease in the value of the Canadian dollar against the US dollar would increase net earnings by $1.2 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 2018 was $2.0 million (2017 - $0.8 million) in equivalent US dollars. The Company estimates that a 10% increase in the value of the Egyptian pound against the US dollar would decrease net earnings for the year ended December 31, 2018 by approximately $0.2 million and conversely a 10% decrease in the value of the Egyptian pound against the US dollar would increase net earnings by $0.2 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 2018 to mitigate interest rate risk. When assessing interest rate risk applicable to the Company’s variable interest, US 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, 2018, 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, 2018, by $0.5 million.

Credit risk

Credit risk is the risk of loss if counter-parties do not 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 gas operations. The Company is currently, and may in the future, be exposed to third-party credit risk through its contractual arrangements with its current or future joint interest partners, marketers of its petroleum production and other parties, including the government of Egypt. Significant changes in the oil and gas industry, including fluctuations in commodity prices and economic conditions, environmental regulations, government policy, royalty rates and other geopolitical factors, could adversely affect the Company’s ability to realize the full value of its accounts receivable. The Company has historically had significant receivables outstanding from the Government of Egypt. In the past, the timing of payments on these receivables from the Government of Egypt were longer than the industry standard. Despite these factors, the Company expects to collect these receivables in full, though there can be no assurance that this will occur. In the event the Government of Egypt fails to meet its obligations, or other third-party creditors fail to meet their obligations to the Company, such failures could individually or in the aggregate have a material adverse effect on the Company, its cash flow from operating activities and its ability to conduct its ongoing capital expenditure program. The Company has not experienced any material credit loss in the collection of accounts receivable to date.

TransGlobe entered into a joint marketing arrangement with EGPC in December 2014. In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. Buyers may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. The Company anticipates that direct sales will continue to reduce credit risk in future periods.

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 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 its credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future cash flows from operations, working capital and availability under existing credit facilities will be adequate to support these financial liabilities and its capital programs. All of the payments received from the lifting and sale of the Company's entitlement crude oil are deposited directly to its accounts held in London, England.

2018 21

Crude oil inventory levels fluctuate from quarter to quarter depending on the timing and size of tanker liftings in Egypt. Since the Company began directly marketing its oil on January 1, 2015, both increases and decreases in crude oil inventory levels have been experienced from quarter to quarter. Throughout 2016 and Q1-2017 there was a steady increase in crude oil inventory levels, as production outpaced sales. In 2017 and 2018, crude oil inventory levels dropped as a result of crude oil sales exceeding production. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows.

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

Operational risk

The Company’s future success largely depends on its ability to exploit its current reserve base and to find, develop or acquire additional oil reserves that are economically recoverable. Failure to acquire, discover or develop these additional reserves will have an impact on cash flows of the Company.

To mitigate these operational risks, as part of its capital approval process, the Company applies rigorous geological, geophysical and engineering analysis to each prospect. The Company utilizes its in-house expertise for all international and domestic ventures or employs and contracts professionals to handle each aspect of the Company’s business. The Company retains independent reserves evaluators to determine year end Company reserves and estimated future net revenues.

The Company also mitigates operational risks by maintaining a comprehensive insurance program according to customary industry practice, but cannot fully insure against all risks.

Safety, environmental, social and regulatory risk

To mitigate safety, environmental and social risks, TransGlobe conducts its operations in accordance with the Company's Health, Safety, Environmental, and Social Responsibility Policy to ensure compliance with government regulations and guidelines. Monitoring and reporting programs for environmental health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental and regulatory standards are met. Security risks are managed through security procedures designed to protect TransGlobe's personnel and assets. The Company has a Whistleblower Protection Policy which protects employees if they raise any concerns regarding TransGlobe's operations, accounting or internal control matters.

Regulatory and legal risks are identified and monitored by TransGlobe's corporate team and external legal professionals to ensure that the Company continues to comply with laws and regulations.

Political risk

TransGlobe operates in countries with political, economic and social systems which subject the Company to a number of risks that are not within the control of the Company. These risks may include, among others, currency restrictions and exchange rate fluctuations, loss of revenue and property and equipment as a result of expropriation, nationalization, war, insurrection and geopolitical and other political risks, increases in taxes and governmental royalties, changes in laws and policies governing operations of companies, economic and legal sanctions and other uncertainties arising from foreign and domestic governments.

Egypt has been experiencing significant political changes over the past eight years and while this has had an impact on the efficient operations of the government in general, business processes and the Company’s operations have generally proceeded as normal. The current government has added stability in the Egyptian political landscape; however, the possibility of future political changes exists. Future political changes could have a material adverse impact on the Company's operations.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with IFRS requires that management make appropriate decisions with respect to the selection of accounting policies and in formulating estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses.

The following is included in the MD&A to aid the reader in assessing the critical accounting policies and practices of the Company. The information will also aid in assessing the likelihood of materially different results being reported depending on management's assumptions and changes in prevailing conditions which affect the application of these policies and practices. Significant accounting policies are disclosed in Note 3 of the Consolidated Financial Statements, and critical judgements and accounting estimates are disclosed in Note 4.

Oil and gas reserves

TransGlobe's proved and probable oil and gas reserves are evaluated and reported on by independent reserve evaluators to the Reserves, Health, Safety, Environment and Social Responsibility Committee comprised of a majority of independent directors. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to reflect updated information. Reserve estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts.

Production sharing concessions

International operations conducted pursuant to PSCs are reflected in the Consolidated Financial Statements based on the Company's working interest in such operations. Under the PSCs, the Company and other non-governmental partners pay all operating and capital costs for exploring and developing the concessions. Each PSC establishes specific terms for the Company to recover these costs 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 quarter. 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 each country, 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 government and other mineral interest owners. For the Company's international operations; all government

22 2018

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.

FUTURE CHANGES IN ACCOUNTING POLICIES

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 January 1, 2019 with early adoption permitted if the Company is also applying IFRS 15 Revenue from Contracts with Customers.

The standard will come into effect for annual periods beginning on or after January 1, 2019. IFRS 16 is required to be adopted retrospectively or on a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as it recognized the cumulative effect of IFRS 16 as an adjustment to opening retained earnings and applies the standard prospectively. TransGlobe will apply IFRS 16 on January 1, 2019, using the modified retrospective transition approach.

IFRS 16 will increase the Company’s total assets and liabilities at January 1, 2019 as TransGlobe recognizes the right-of-use assets and lease obligations on its balance sheet that were not recognized prior to adoption of IFRS 16. The most significant impact identified is that the Company will now recognize new assets and liabilities on its Consolidated Balance Sheets for certain office and equipment leases including drilling rig contracts. Future net earning will be impacted as the lease contracts will result in finance charges and depreciation expense. The cash flow statement will recognize the lease payments allocated between the operating and financing activities based on the finance charges and principal repayments. The impact of the adoption of this standard is discussed further in Note 5 of the Consolidated Financial Statements.

DISCLOSURE CONTROLS AND PROCEDURES

As of December 31, 2018, an evaluation was carried out, under the supervision and with the participation of the Company's management including the Chief Executive Officer and Chief Financial Officer, on the effectiveness of the Company's disclosure controls and procedures as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as of the end of the fiscal year, the design and operation of these disclosure controls and procedures were effective to ensure that all information required to be disclosed by the Company in its annual filings is recorded, processed, summarized and reported within the specified time periods.

Disclosure controls and procedures are defined as controls and other procedures of an issuer that are designed to provide reasonable assurance that information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the issuer’s management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosure.

INTERNAL CONTROLS OVER FINANCIALREPORTING

TransGlobe's management designed and implemented internal controls over financial reporting, as defined under National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings, of the Canadian Securities Administrators and as defined in Rule 13a-15 under the US Securities Exchange Act of 1934. Internal controls over financial reporting is a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS as issued by the IASB. Due to its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements on a timely basis. A system of internal controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Management has assessed the effectiveness of the Company's internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission framework on Internal Control - Integrated Framework (2013). Based on this assessment, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2018. No changes were made to the Company's internal control over financial reporting during the year ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

2018 23

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, 2018.

Signed by:
“Randy C. Neely”	“Edward D. Ok”
Randy C. Neely	Edward D. Ok
President & Chief Executive Officer	Vice President, Finance & Chief Financial Officer
March 13, 2019

24 2018

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of TransGlobe Energy Corporation and subsidiaries (the "Company") as at December 31, 2018 and 2017, the related consolidated statements of earnings (loss) and comprehensive income (loss), changes in shareholders’ equity and cash flows, for each of the two years in the period ended December 31, 2018, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2018 and 2017, and its financial performance and its cash flows for each of the two years in the period ended December 31, 2018, in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2018, 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 13, 2019, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

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

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

/s/ Deloitte LLP

Chartered Professional Accountants

Calgary, Canada

March 13, 2019

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

2018 25

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, 2018, 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2018, of the Company and our report dated March 13, 2019, expressed an 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 generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ Deloitte LLP

Chartered Professional Accountants

Calgary, Canada

March 13, 2019

26 2018

Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss)

(Expressed in thousands of US Dollars, except per share amounts)

		Years Ended December 31
	Notes	2018			2017
REVENUE
Petroleum and natural gas sales, net of royalties	25	$	176,227		$	148,464
Finance revenue	7	570			108
		176,797			148,572
EXPENSES
Production and operating	11	53,298			51,005
Selling costs	8	2,103			2,495
General and administrative		18,688			15,253
Foreign exchange (gain) loss		(289		)	194
Finance costs	7	5,075			6,233
Depletion, depreciation and amortization	14	34,291			40,036
Asset retirement obligation accretion	15	270			256
Loss on financial instruments	6	7,051			10,992
Impairment loss	13	14,500			79,025
Gain on disposition of assets		(207		)	—
		134,780			205,489
Earnings (loss) before income taxes		42,017			(56,917		)
Income tax expense – current	12	26,340			21,819
NET EARNINGS (LOSS)		$	15,677		$	(78,736	)
OTHER COMPREHENSIVE INCOME (LOSS)
Currency translation adjustments		(3,732		)	2,793
COMPREHENSIVE INCOME (LOSS)		$	11,945		$	(75,943	)
Earnings (loss) per share	21
Basic		$	0.22		$	(1.09	)
Diluted		$	0.22		$	(1.09	)

See accompanying notes to the Consolidated Financial Statements

2018 27

Consolidated Balance Sheets

(Expressed in thousands of US Dollars)

		As at			As at
	Notes	December 31, 2018			December 31, 2017
ASSETS
Current
Cash and cash equivalents	9	$	51,705		$	47,449
Accounts receivable	6,10	12,014			18,090
Derivative commodity contracts	6	1,198			—
Prepaids and other		5,385			4,745
Product inventory	11	8,692			11,474
		78,994			81,758
Non-Current
Derivative commodity contracts	6	171			—
Intangible exploration and evaluation assets	13	36,266			41,478
Property and equipment	14
Petroleum and natural gas assets		195,263			200,981
Other assets		3,079			3,485
Deferred taxes	12	4,523			—
		$	318,296		$	327,702
LIABILITIES
Current
Accounts payable and accrued liabilities	16	$	28,007		$	27,104
Derivative commodity contracts	6	—			4,015
		28,007			31,119
Non-Current
Derivative commodity contracts	6	—			3,955
Long-term debt	17	52,355			69,999
Asset retirement obligation	15	12,113			12,332
Other long-term liabilities		1,007			290
Deferred taxes	12	4,523			—
		98,005			117,695
SHAREHOLDERS’ EQUITY
Share capital	19	152,084			152,084
Accumulated other comprehensive income (loss)		(939		)	2,793
Contributed surplus	20	24,195			23,329
Retained earnings		44,951			31,801
		220,291			210,007
		$	318,296		$	327,702

Commitments and Contingencies (Note 18)

See accompanying notes to the Consolidated Financial Statements

Approved on behalf of the Board of Directors

Signed by:

“Randy C. Neely”	“Steven Sinclair”
Randy C. Neely	Steven Sinclair
President & CEO	Director
Director

28 2018

Consolidated Statements of Changes in Shareholders’ Equity

(Expressed in thousands of US Dollars)

		Years Ended December 31
	Notes	2018			2017
Share Capital
Balance, beginning of year	19	$	152,084		$	152,084
Balance, end of year		$	152,084		$	152,084
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of year		$	2,793		$	—
Currency translation adjustment		(3,732		)	2,793
Balance, end of year		$	(939	)	$	2,793
Contributed Surplus
Balance, beginning of year		$	23,329		$	22,695
Share-based compensation expense	20	866			634
Balance, end of year		$	24,195		$	23,329
Retained Earnings
Balance, beginning of year		$	31,801		$	110,537
Net earnings (loss)		15,677			(78,736		)
Dividends	22	$	(2,527	)	$	—
Balance, end of year		$	44,951		$	31,801

See accompanying notes to the Consolidated Financial Statements

2018 29

Consolidated Statements of Cash Flows

(Expressed in thousands of US Dollars)

		Years Ended December 31
	Notes	2018			2017
CASH FLOWS RELATED TO THE FOLLOWINGACTIVITIES:
OPERATING
Net earnings (loss)		$	15,677		$	(78,736	)
Adjustments for:
Depletion, depreciation and amortization	14	34,291			40,036
Asset retirement obligation accretion	15	270			256
Deferred lease inducement		(90		)	(91		)
Impairment loss	13	14,500			79,025
Stock-based compensation	20	3,536			1,478
Finance costs	7	5,075			6,233
Unrealized (gain) loss on financial instruments	6	(9,335		)	8,121
Unrealized loss on foreign currency translation		(135		)	(35		)
Gain on asset dispositions		(207		)	—
Asset retirement obligations settled	15	(300		)	(695		)
Changes in non-cash working capital	26	5,910			3,858
Net cash generated by operating activities		69,192			59,450
INVESTING
Additions to intangible exploration and evaluation assets	13	(9,288		)	(16,905		)
Additions to petroleum and natural gas assets	14	(30,832		)	(20,301		)
Additions to other assets	14	(586		)	(953		)
Proceeds from asset dispositions		207			—
Changes in restricted cash		—			18,323
Changes in non-cash working capital	26	251			(1,587		)
Net cash used in investing activities		(40,248		)	(21,423		)
FINANCING
Interest paid		(4,767		)	(8,506		)
Increases in long-term debt	17	508			85,328
Repayment of convertible debentures		—			(73,375		)
Repayments of long-term debt	17	(17,797		)	(26,041		)
Dividends paid	22	(2,527		)	—
Changes in non-cash working capital	26	(3		)	—
Net cash used in financing activities		(24,586		)	(22,594		)
Currency translation differences relating to cash and cash equivalents		(102		)	548
NET INCREASE IN CASH AND CASHEQUIVALENTS		4,256			15,981
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		47,449			31,468
CASH AND CASH EQUIVALENTS, END OF YEAR		$	51,705		$	47,449

See accompanying notes to the Consolidated Financial Statements

30 2018

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2018 and December 31, 2017 and for the years then ended

(Expressed in US Dollars)

1. CORPORATE INFORMATION

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

2. BASIS OF PREPARATION

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

The Company prepared the Consolidated Financial Statements on a going concern basis, which contemplates the realization of assets and liabilities in the normal course of business as they become due. Accordingly, the Consolidated Financial Statements have been prepared on a historical cost basis, except for cash and cash equivalents, derivative commodity contracts and other long-term liabilities that have been measured at fair value. The method used to measure fair value is discussed further in Notes 3 and 6.

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

The Consolidated Financial Statements were authorized for issue by the Board of Directors on March 11, 2019.

3. SIGNIFICANT ACCOUNTING POLICIES

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

Basis of consolidation

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

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

Foreign currency translation

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

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

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

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

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

Translation gains and losses occur when translating the financial statements of non-US functional currency operations to the US dollar. These translation gains and losses are recorded as currency translation adjustments and presented as other comprehensive income on the Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss). Translations occur as follows:

• Income and expenses are translated at the date of the transaction

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

Cash and cash equivalents

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

2018 31

Financial instruments

Effective January 1, 2018, the Company adopted IFRS 9 Financial Instruments, which replaced IAS 39 Financial Instruments: Recognition and Measurement. This standard introduced a single approach to determine whether a financial asset is measured at amortized cost or fair value. 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 its financial assets. For financial liabilities, IFRS 9 stipulates that where the fair value option is applied, the change in fair value resulting from an entity’s own credit risk is recorded in other comprehensive income (loss) rather than net earnings (loss), unless this creates an accounting mismatch.

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

• Fair value through profit or loss - subsequently carried at fair value with changes recognized in net earnings (loss). Financial instruments under this classification include cash and cash equivalents, and derivative commodity contracts; and

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

IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. The Company enters into certain financial derivative contracts from time to time in order to reduce its exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company does not designate financial derivative contracts as effective accounting hedges, and thus does not apply hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, the Company's policy is to classify all financial derivative contracts at fair value through profit or loss and to record them on the Consolidated Balance Sheet at fair value with a corresponding gain or loss in net earnings (loss). Attributable transaction costs are recognized in net earnings (loss) when incurred. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts.

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

Refer to Note 6 for the classification and measurement of these financial instruments. TransGlobe adopted this standard using the modified retrospective approach, whereby the cumulative effect of initial adoption of the standard is recognized as an adjustment to retained earnings. There was no effect on the Company's retained earnings or prior period amounts as a result of adopting this standard.

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 net earnings (loss) as they are incurred and presented as exploration expenses on the Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss).

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

Petroleum and natural gas assets

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.

32 2018

When components of PNG assets are replaced, disposed of or no longer in use, the carrying amount is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in net earnings (loss) as incurred.

Depletion, depreciation and amortization

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

The net carrying value of the PNG assets included in petroleum properties is depleted using the unit of production method by reference to the ratio of production 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.

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

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

Product inventory

Product inventory consists of the Company's unsold Egypt entitlement crude oil barrels, valued at the lower of cost, using the first-in, first-out method, 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

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

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

Non-financial assets

At each reporting date, the carrying amounts of the Company’s non-financial assets are reviewed to determine whether there is indication of impairment, except for E&E assets, which are reviewed when circumstances indicate impairment may exist. If there is indication of impairment, the asset's recoverable amount is estimated and compared to its carrying value.

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

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

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

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.

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

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

2018 33

award. Fair value is determined by using the lattice-based trinomial option pricing model. An estimated forfeiture rate is taken into consideration when assigning a fair value to options granted such that no expense is recognized for awards that do not ultimately vest.

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

When the terms of an equity-settled award are modified or a new award is designated as replacing a 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 expense related to the share units granted under these plans is measured at fair value using the lattice-based trinomial pricing model and is recognized over the vesting period, with a corresponding liability recognized on the Consolidated Balance Sheet.

The grant date fair value of cash-settled units granted to employees is recognized as compensation expense within general and administrative expenses, with a corresponding increase in accounts payable, accrued liabilities and other long-term liabilities over the period that the employees become unconditionally entitled to the units. The amount recognized as an expense is adjusted to reflect the actual number of units for which the related service and non-market vesting conditions are met. Until the liability is ultimately settled, it is re-measured at each reporting date with changes to fair value recognized in net earnings (loss).

Provisions and asset retirement obligations

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

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

In accordance with all of the Company's Production Sharing Agreements and Production Sharing Concessions (collectively defined as "PSCs"), the Company does, not at any time, hold title to the lands on which it operates, and title to fixed and movable assets is transferred to the respective government when its total cost has been recovered through cost recovery, or at the time of termination of the PSC. Since the Company will not hold title to the land or the assets at the termination of the PSC, the Company does not have a legal obligation, nor the legal ability to decommission the Egypt assets. Furthermore, there is no explicit contractual obligation under the Company's PSCs for abandonment of assets or reclamation of lands upon termination of the PSCs.

Revenue recognition

Effective January 1, 2018, TransGlobe adopted IFRS 15 Revenue from Contracts with Customers, which replaced IAS 18 Revenue, IAS 11 Construction Contracts and related interpretations. This standard established a comprehensive framework for determining whether, how much and when revenue from contracts with customers is recognized. Under IFRS 15, revenue is recognized when a customer obtains control of the good or services as stipulated in a performance obligation. Determining whether the timing of the transfer of control is at a point in time or over time requires judgement and can significantly affect when revenue is recognized. In addition, the entity must also determine the transaction price and apply it correctly to the goods or services contained in the performance obligation.

The Company's revenue is derived exclusively from contracts with customers, except for immaterial amounts related to interest and other income. Royalties are considered to be part of the price of the sale transaction and are therefore presented as a reduction to revenue. Revenue associated with the sale of crude oil, natural gas and natural gas liquids (“NGLs”) is measured based on the consideration specified in contracts with customers. Revenue from contracts with customers is recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the customer and the customer taking physical possession. TransGlobe mainly satisfies its performance obligations at a point in time and the amounts of revenue recognized relating to performance obligations satisfied over time are not significant.

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

Revenues from the sale of crude oil, natural gas, condensate and NGLs in Canada are recognized by reference to actual volumes delivered at contracted delivery points and prices. Prices are determined by reference to quoted market prices in active markets (crude oil - NYMEX WTI, natural gas - AECO C, condensate - NYMEX WTI, NGLs - various based on product), adjusted according to specific terms and conditions applicable per the

34 2018

sales contracts. Revenues are recognized prior to the deduction of transportation costs. Revenues are measured at the fair value of the consideration received. TransGlobe pays royalties to the Alberta provincial government and other mineral rights owners in accordance with the established royalty regime.

The Company reviewed its sales contracts with customers and determined that IFRS 15 did not have a material impact on its revenue recognition and accordingly no material impact on the Consolidated Financial Statements. TransGlobe adopted this standard using the modified retrospective approach, whereby the cumulative effect of initial adoption of the standard is recognized as an adjustment to retained earnings. There was no effect on the Company's retained earnings or prior period amounts as a result of adopting this standard.

Revenue segregated by product type and geographical market is disclosed in Note 25.

Finance revenue and costs

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

Finance costs 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 comprised of those significant assets that require a period greater than one year to be available for their intended use. All other borrowing costs are recognized in net earnings (loss).

Income tax

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

Current tax

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

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

Deferred tax

The Company determines the amount of deferred income tax assets and liabilities based on the difference between the carrying amounts of the assets and liabilities reported for financial accounting purposes from those reported for tax. Deferred income tax assets and liabilities are measured using the substantively enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. Deferred income tax assets 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 joint operations and the Consolidated Financial Statements reflect only the Company's proportionate interest in such activities. Joint control exists for contractual agreements governing TransGlobe's assets whereby TransGlobe has less than 100% working interest, all of the partners have control of the arrangement collectively, and spending on the project requires unanimous consent of all parties that collectively control the arrangement and share the associated risks. TransGlobe does not have any joint arrangements that are individually material to the Company or that are structured through joint venture arrangements.

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

4. CRITICAL JUDGMENTS AND ACCOUNTING ESTIMATES

Timely preparation of financial statements in conformity with IFRS as issued by the International Accounting Standards Board requires that management make estimates and assumptions and use judgments that affect the application of accounting policies and the reported amounts of

2018 35

assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. The effect of these estimates,

assumptions and the use of judgments are explained throughout the notes to the Consolidated Financial Statements. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected.

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

Recoverability of asset carrying values

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

• 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 PSC is considered a separate CGU. In Canada, CGUs are determined by regional geography and one CGU has been identified. The asset composition of a CGU can directly impact the recoverability of the assets included therein. In assessing the recoverability of the Company's petroleum properties, each CGU's carrying value is compared to its recoverable amount, defined as the greater of its fair value less costs to sell and value-in-use. As at December 31, 2018 and December 31, 2017, 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 (loss) 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, 2018 and were based on fair value less costs to sell calculations, using a discount rate of 15% for Egypt and 10% for Canada on future after-tax cash flows and the following commodity price estimates:

	Egypt1		Canada1
	Brent Blend Crude Oil		WTI Oil		AECO Gas		Edmonton Condensate		Edmonton Butane		Edmonton Propane		Spec Ethane		Exchange Rate
Year	$US/Bbl		$US/Bbl		$C/Mcf		$C/Bbl		$C/Bbl		$C/Bbl		$C/Bbl		USD/CAD
2019	63.25		56.25		1.85		67.67		21.45		25.33		5.69		0.750
2020	68.50		61.76		2.29		79.22		37.66		32.39		7.20		0.770
2021	71.25		64.40		2.67		83.54		47.85		36.68		8.51		0.790
2022	73.00		65.96		2.90		85.49		57.04		39.11		9.27		0.810
2023	75.50		66.98		3.14		87.80		58.48		41.77		10.12		0.820
2024	78.00		67.93		3.23		90.30		60.24		43.03		10.42		0.825
2025	80.50		68.82		3.34		93.33		62.36		44.55		10.78		0.825
2026	83.41		70.00		3.41		96.86		64.83		46.31		11.03		0.825
Thereafter2	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%	0.825
1  GLJ Petroleum Consultants Ltd. (“GLJ”) price forecasts, effective December 31, 2018.
2  Percentage change represents the increase in each year after 2026 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.

2018 36

Income taxes

Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the Consolidated Financial Statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly affect the amount of the deferred tax asset or liability calculated at a point in time. Tax interpretations, regulations and legislation in the various jurisdictions in which TransGlobe and its subsidiaries operate are subject to change and interpretation. Such changes can affect the timing of the reversal of temporary tax differences, the tax rates in effect when such differences reverse and TransGlobe's ability to use tax losses and other tax pools in the future. The Company’s income tax filings are subject to audit by taxation

authorities in different jurisdictions and the results of such audits may increase or decrease the tax liability. The determination of current and deferred tax amounts recognized in the Consolidated Financial Statements are based on management’s assessment of the tax positions, which includes consideration of their technical merits, communications with tax authorities and management’s view of the most likely outcome. These differences could materially impact net earnings (loss).

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.

E&E Assets

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

5. CHANGES IN ACCOUNTING POLICIES

Standards issued but not yet effective

IFRS 16 "Leases"

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

The standard will come into effect for annual periods beginning on or after January 1, 2019, with earlier adoption if the entity is also adopting IFRS 15. IFRS 16 is required to be adopted retrospectively or on a modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as the cumulative effect of IFRS 16 is recognized as an adjustment to opening retained earnings and applies the standard prospectively. TransGlobe will apply IFRS 16 on January 1, 2019, using the modified retrospective approach. On initial adoption, TransGlobe intends to apply the following expedients permitted under the standard:

• Certain short-term leases and leases of low value assets that have been identified at January 1, 2019, will not be recognized on the balance sheet. Payments for the leases will be disclosed in the notes to the Consolidated Financial Statements.

• At January 1, 2019, TransGlobe will recognize the lease payments due within one year as short-term lease obligations, and those payments outside of one year as long-term lease obligations.

• At initial measurement, some leases having similar characteristics, will have a mutual discount rate applied to all leases.

It is anticipated that the adoption of IFRS 16 will not have a material impact on the Company’s total assets and liabilities at January 1, 2019. The most significant impact identified is that the Company will now recognize new assets and liabilities in the Consolidated Balance Sheets for certain office and equipment leases including drilling rig contracts. The Company will measure the ROU assets at an amount equal to the lease liability, adjusted by the amount of any prepaid or accrued lease payments relating to that lease recognized in the Consolidated Balance Sheets immediately before the date of initial application. Future net earnings (loss) will be impacted as the lease contracts will result in changes in finance costs, depletion, depreciation and amortization, production and operating and general and administrative expenses. The statement of cash flows will allocate the finance charges and principal repayments of lease payments between operating and financing activities.

2018 37

6. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair values of financial instruments

The Company has classified its cash and cash equivalents and derivative commodity contracts as fair value through profit or loss. Both are measured at fair value with subsequent changes recognized through net earnings (loss).

Accounts receivable are classified as assets at amortized cost; accounts payable and accrued liabilities and long-term debt are classified as liabilities at amortized cost, all of which are measured initially at fair value, and subsequently at amortized cost. Transaction costs attributable to financial instruments carried at amortized cost are included in the initial measurement of the financial instrument and are subsequently amortized using the effective interest rate method.

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

	December 31, 2018				December 31, 2017
	Carrying		Fair		Carrying		Fair
Classification ($000s)	Value		Value		Value		Value
Financial assets at fair value through profit or loss	$	53,074	$	53,074	$	47,449	$	47,449
Financial assets at amortized cost	12,014		12,014		18,090		18,090
Financial liabilities at fair value through profit or loss	—		—		7,970		7,970
Financial liabilities at amortized cost	80,362		81,228		97,103		98,329

Assets and liabilities as at December 31, 2018 that are measured at fair value are classified into levels reflecting the method used to make the measurements. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant inputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair value measurement.

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

Derivative commodity contracts

The nature of TransGlobe’s operations exposes it to fluctuations in commodity prices, interest rates and foreign currency exchange rates. TransGlobe monitors and, when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by TransGlobe are related to an underlying financial position or to future crude oil and natural gas production. TransGlobe does not use derivative financial instruments for speculative purposes. TransGlobe has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in net earnings (loss) at each reporting period. TransGlobe has not obtained collateral or other security to support its financial derivatives as management reviews the creditworthiness of its counterparties prior to entering into derivative contracts. The derivative financial instruments are initiated within the guidelines of the Company's corporate hedging policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.

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

The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at December 31, 2018, the fair values of which have been presented on the Consolidated Balance Sheet:

Financial Brent Crude Oil Contracts
Period Hedged	Contract	Volume bbl	Monthly Volume bbl	Bought Put USD$/bbl	Sold Call USD$/bbl	Sold Put USD$/bbl
Jul 2020 - Dec 2020	3-Way Collar	300,000	50,000	54.00	70.00	45.00
Jan 2020 - Jun 2020	3-Way Collar	300,000	50,000	54.00	70.00	46.50
Jan 2019 - Dec 2019	3-Way Collar	198,000	16,500	53.00	62.10	46.00
Jan 2019 - Dec 2019	3-Way Collar	199,998	16,666.5	54.00	61.35	46.00
Jan 2019 - Dec 2019	Bear Put Spread	198,000	16,500	53.00	—	46.00
Jan 2019 - Dec 2019	Bear Put Spread	199,998	16,666.5	54.00	—	46.00

The loss on financial instruments for 2018 and 2017 comprised the following:

($000's)	December 31, 2018		December 31, 2017
Realized derivative loss on commodity contracts settled during the year	16,386		2,871
Unrealized derivative (gain) loss on commodity contracts outstanding at year end	(9,335	)	7,970
Unrealized loss on financial instruments	—		151
Loss on financial instruments	7,051		10,992

38 2018

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

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 its cash investments or in the collection of accounts receivable to date.

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

Trade and other receivables are analyzed in the table below.

($000s)
Trade receivables	December 31, 2018		December 31, 2017
Neither impaired nor past due	$	5,540	$	10,534
Not impaired and past due in the following period:
Within 30 days	829		3,804
31-60 days	212		2,575
61-90 days	102		—
Over 90 days	5,331		1,177
	$	12,014	$	18,090

The Company completed four crude oil cargo sales in 2018. Depending on the Company's assessment of the credit of crude oil cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. During 2018, the Company sold an additional 318.3 mbbls of inventoried entitlement crude oil to EGPC for $17.9 million. As at December 31, 2018, $7.2 million of the $12.0 million total accounts receivable balance is due from EGPC.

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 the associated impact on future performance of the business. The market price movements that the Company is exposed to include commodity prices, foreign currency exchange rates and interest rates, all of which could adversely affect the value of the Company’s financial assets, liabilities and financial results. The 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 net earnings (loss). The Company assesses these instruments on the fair value hierarchy and has classified the determination of fair value of these instruments as Level 2, as the fair values of these transactions are based on an approximation of the amounts that would have been received from 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.

Foreign currency exchange risk

As the Company’s business is conducted primarily in US dollars and its financial instruments are primarily denominated in US dollars, the Company’s exposure to foreign currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, long-term debt and accounts

2018 39

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 US dollar would decrease net earnings for the year ended December 31, 2018 by approximately $1.5 million and conversely a 10% decrease in the value of the Canadian dollar against the US dollar would increase net earnings by $1.2 million for the same period. The Company does not utilize derivative instruments to manage this risk.

The Company is also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds and GB 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 2018 was $2.0 million (2017 - $0.8 million) in equivalent US dollars. The Company estimates that a 10% increase in the value of the Egyptian pound against the US dollar would decrease net earnings for the year ended December 31, 2018 by approximately $0.2 million and conversely a 10% decrease in the value of the Egyptian pound against the US dollar would increase net earnings by $0.2 million for the same period. The Company does not currently utilize derivative instruments to manage foreign currency exchange risk. The Company maintains nominal balances of GBP to pay in-country costs incurred in operating its London office. Foreign exchange risk on these funds are not considered material.

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 2018 to mitigate interest rate risk. When assessing interest rate risk applicable to the Company’s variable interest, US 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, 2018, 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, 2018, 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, 2018:

($000s)		Payment Due by Period1,2
	Recognized
	in Financial	Contractual	Less than
	Statements	Cash Flows	1 year	1-3 years
Accounts payable and accrued liabilities	Yes - Liability	28,007	28,007	—
Long-term debt	Yes - Liability	52,355	—	52,355
Other long-term liabilities	Yes - Liability	1,007	—	1,007
Office and equipment leases3	No	2,949	1,985	964
Total		84,318	29,992	54,326
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, 2018 exchange rates.
3  Office and equipment leases include all drilling rig contracts.

At December 31, 2018, the Company had $97.0 million of revolving credit facilities with $53.2 million drawn and $43.8 million available. The Company had the prepayment agreement with Mercuria that allows for a revolving balance of up to $75.0 million, of which $45.0 million is drawn. During 2018, the Company repaid $15.0 million of this facility. The Company also had a revolving Canadian reserves-based lending facility with ATB totaling C$30.0 million ($22.0 million), of which C$11.2 million ($8.2 million) was drawn. During 2018, the Company had drawings of C$0.6 million ($0.5 million) and repayments of C$3.6 million ($2.8 million) on this facility (Note 17).

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

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

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’s financial objectives and strategy have remained substantially unchanged over the last two completed fiscal years. These objectives and strategy are reviewed on an annual basis. TransGlobe remains in a relatively strong financial position, and will continue to focus on cost reductions and prudent stewardship of capital with the objective of maintaining a strong balance sheet. The Company was subject to financial covenants with the prepayment agreement and the reserves-based lending facility as at December 31, 2018 and 2017. The Company was in compliance with all financial covenants at December 31, 2018 and 2017 (see Note 17).

40 2018

The Company defines and computes its capital as follows:

($000s)	2018			2017
Long-term debt, including the current portion (net of unamortized transaction costs)	$	52,355		$	69,999
Current assets	(78,994		)	(81,758		)
Current liabilities	28,007			31,119
Net debt obligations	1,368			19,360
Shareholders’ equity	220,291			210,007
Total capital	$	221,659		$	229,367

7. FINANCE REVENUE AND COSTS

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

Finance costs recognized in net earnings (loss) were as follows:

($000s)	2018		2017
Interest on convertible debenture1	$	—	$	1,089
Interest on long-term debt (Note 17)	4,275		3,994
Interest on note payable2	—		532
Interest on reserves-based lending facility (Note 17)	440		289
Amortization of deferred financing costs	360		329
Finance costs	$	5,075	$	6,233
1  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).
2  The Company repaid the outstanding vendor take-back note balance of C$13.6 million ($10.0 million) on May 16, 2017.

8. 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 four direct crude oil sales to third-party buyers during the year ended December 31, 2018 (2017 - three).

9. CASH AND CASH EQUIVALENTS

The following table reconciles TransGlobe's cash and cash equivalents:

($000s)	December 31, 2018		December 31, 2017
Cash	$	33,893	$	46,051
Cash equivalents	17,812		1,398
Cash and cash equivalents	$	51,705	$	47,449

As at December 31, 2018 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.

10. 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, 2018 or December 31, 2017.

As at December 31, 2018, the Company utilized $5.1 million of its accounts receivable from EGPC as a guarantee to support work commitments on the North West Sitra concession (see Note 18). These commitments were met as of December 31, 2018.

11. PRODUCT INVENTORY

Product inventory consists of the Company's entitlement crude oil barrels, which are valued at the lower of cost or net realizable value. Costs include operating expenses and depletion associated with crude oil entitlement barrels and are determined on a concession by concession basis. Amounts are initially capitalized and expensed when sold. See Note 25 for the amount of inventory recognised as an expense during the period.

As at December 31, 2018, the Company held 568.1 mbbls of entitlement oil in inventory valued at approximately $15.30 per barrel (December 31, 2017 - 776.8 mbbls valued at approximately $14.77 per barrel). During 2018, product inventory of $2.8 million was recorded as an expense (2017 - $8.1 million).

2018 41

12. INCOME TAXES

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

($000s)	2018			2017
Deferred income tax asset and liability, beginning of year	$	—		$	—
Expenses related to the origination and reversal of temporary differences for:
Property and equipment	6,381			1,707
Non-capital losses carried forward	(733		)	(2,909		)
Long-term liabilities	(2		)	(41		)
Share issue expenses	(1		)	—
Changes in unrecognized tax benefits	(5,645		)	1,243
Deferred income tax expense recognized in net earnings	4,523			—
Deferred income tax (recovery) recognized in net earnings	(4,523		)	—
Deferred income tax asset, end of year	4,523			—
Deferred income tax liability, end of year	(4,523		)	—

The Company has non-capital losses of $84.3 million (2017 - $81.5 million) that expire between 2027 and 2037. A deferred tax asset of $4.5 million (2017 - $nil) was recognized in respect of unused tax losses in West Gharib. The Company has an additional $14.2 million (2017 - $19.4 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% (2017 – 27.0%) to income before taxes as follows:

($000s)	2018			2017
Income taxes calculated at the Canadian statutory rate	$	11,344		$	(15,368	)
Increases (decreases) in income taxes resulting from:
Non-deductible expenses	2,087			2,023
Changes in unrecognized tax benefits	(5,646		)	1,243
Effect of tax rates in foreign jurisdictions1	16,002			31,728
Changes in tax rates and other	2,553			2,193
Income tax expense - current	$	26,340		$	21,819
1 The statutory tax rate in Egypt is 40.55%.

The Company's consolidated effective income tax rate for 2018 was 62.7% (2017 - 38.3%).

13. INTANGIBLE EXPLORATION AND EVALUATIONASSETS

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

($000s)	2018			2017
Balance, beginning of year	$	41,478		$	105,869
Additions	9,288			16,905
Transfer to petroleum and natural gas assets	—			(2,271		)
Impairment loss	(14,500		)	(79,025		)
Balance, end of year	$	36,266		$	41,478

For the year ended December 31, 2018, the Company recorded an impairment loss of $14.5 million on its exploration and evaluation assets which is fully related to the North West Sitra concession. It was determined that an impairment loss was necessary as no commercially viable quantities of oil were discovered and no further drilling activities are planned. As at December 31, 2018, the recoverable amount of the North West Sitra cash-generating unit is $nil.

In 2017 the Company recorded an impairment loss of $79.0 million on its exploration and evaluation assets. The total loss related to the South West Gharib concession ($1.2 million), the North West Gharib concession ($67.5 million) and the South Alamein concession ($10.3 million).

During 2018, the Company spent $5.6 million and $3.2 million on exploration and evaluation activities at North West Sitra and South Ghazalat, respectively. In Canada the Company incurred $0.5 million in land acquisition costs.

Exploration and evaluation assets as at December 31, 2018 includes $12.5 million in South Alamein (December 31, 2017 - $13.3 million), $23.2 million in South Ghazalat (December 31, 2017 - $20.0 million), $nil in North West Sitra (December 31, 2017 - $8.2 million) and $0.5 million in Canada (2017 - $nil).

42 2018

14. PROPERTY AND EQUIPMENT

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

($000s)	PNG			Other
Cost	Assets			Assets		Total
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
Balance at December 31, 2017	648,229			15,525		663,754
Additions	30,832			586		31,418
Changes in estimate for asset retirement obligations	844			—		844
Balance at December 31, 2018	$	679,905		$	16,111	$	696,016

Accumulated depreciation, amortization and impairment losses
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
Accumulated depletion, depreciation, amortization and impairment        losses at December 31, 2017	451,850		12,040		463,890
Depletion, depreciation and amortization for the year	31,422		992		32,414
Balance at December 31, 2018	$	483,272	$	13,032	$	496,304

Foreign Exchange
Balance at December 31, 2016	$	—		$	—	$	—
Currency translation adjustments	4,602			—		4,602
Balance at December 31, 2017	4,602			—		4,602
Currency translation adjustments	(5,972		)	—		(5,972		)
Balance at December 31, 2018	$	(1,370	)	$	—	$	(1,370	)

Net Book Value
At December 31, 2017	$	200,981	$	3,485	$	204,466
At December 31, 2018	$	195,263	$	3,079	$	198,342

At December 31, 2018, the Company's market capitalization was less than its net asset value. This was identified as an indicator of impairment and as a result, the Company completed impairment tests on all of its CGUs in accordance with IAS 36. It was determined that the carrying amounts of the CGUs did not exceed their fair value less costs to sale.

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

15. ASSET RETIREMENT OBLIGATION

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

($000s)	2018
Balance, beginning of year	$	12,332
Changes in estimates for asset retirement obligations and additional obligations recognized	843
Obligations settled	(300		)
Asset retirement obligation accretion	270
Effect of movements in foreign exchange rates	(1,032		)
Balance, end of year	$	12,113

As at December 31, 2018, the entire asset retirement obligation balance related to the Company's Canadian operations. TransGlobe has estimated the net present value of its asset retirement obligation to be $12.1 million as at December 31, 2018 (2017 - $12.3 million) based on a total undiscounted future liability of $18.3 million (2017 - $19.6 million). These payments are expected to be made between 2020 and 2066. TransGlobe calculated the present value of the obligations using discount rates between 1.86% and 2.18% 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.

16. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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, 2018 or December 31, 2017.

2018 43

17. LONG-TERM DEBT

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

($000s)	2018			2017
Balance, beginning of year	$	69,999		$	11,162
Increase in prepayment agreement	—			73,500
Increase in reserves-based lending facility	—			10,209
Draws on facility	508			64
Repayment of long-term debt	(17,797		)	(26,162		)
Amortization of deferred financing costs	360			329
Effect of movements in foreign exchange rates	(715		)	897
Balance, end of year	$	52,355		$	69,999

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

Based on the Company's current forecast of future production and prices the estimated future debt payments on long-term debt as of December 31, 2018 are as follows:

($000s)	Prepayment Agreement		Reserves Based Lending Facility		Total
2019	$	—	$	—	$	—
2020	—		—		—
2021	44,134		8,221		52,355
	$	44,134	$	8,221	$	52,355

Prepayment Agreement

	As at			As at
($000s)	December 31, 2018			December 31, 2017
Prepayment agreement - amount drawn	$	45,000		$	60,000
Deferred financing costs	(866		)	(1,208		)
	$	44,134		$	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.

TPI's obligations under the prepayment agreement are guaranteed by the Company and the subsidiaries of TPI (the "Guarantors"). The obligations of TPI and the Guarantors will be supported by, among other things, a pledge of equity held by the Company in TPI and a pledge of equity held by TPI in its subsidiaries. The funding arrangement has a term of four years, maturing March 31, 2021 and advances bear interest at a rate of LIBOR plus 6.0%. The funding arrangement is revolving with each advance to be satisfied through the delivery of crude oil to Mercuria. Further advances become available upon delivery of crude oil to Mercuria up to a maximum of $75.0 million and subject to compliance with the other terms and conditions of the prepayment agreement. The prepayment agreement was initially recognized at fair value, net of financing costs, and has subsequently been measured at amortized cost. Financing costs of $1.5 million are being amortized over the term of the prepayment agreement using the effective interest rate method.

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

• 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, 2018 is 0.01:1.00 (2017 - 0.22:1.00);

• 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, 2018 is 3.76:1.00 (2017 - 3.60:1.00); 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, 2018 is 8.03:3.00 (2017 - 6.90:3.00).

As at December 31, 2018 and 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:

44 2018

• 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, 2018 is 2.21:1.00 (2017 - 1.49:1.00), the Company is in compliance with the ratio.

Reserves-Based Lending Facility

	As at		As at
($000s)	December 31, 2018		December 31, 2017
Reserves-based lending facility - amount drawn	$	8,221	$	11,225
Deferred financing costs	—		(18		)
	$	8,221	$	11,207

As at December 31, 2018, the Company had in place a revolving Canadian reserves-based lending facility with ATB totaling C$30.0 million ($22.0 million), of which C$11.2 million ($8.2 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 31, 2019, 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 were amortized over the initial term of the agreement using the effective interest rate method.

The Company is subject to certain financial covenants in accordance with the terms of the agreement. These financial measures are defined by the agreement as follows:

• 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, 2018 is 1.10:1.00 (2017 - 1.46:1.00); 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, 2018 is 1.26:1.00 (2017 - 0.19:1.00).

As at December 31, 2018 and 2017, the Company was in compliance with all the financial covenants.

18. COMMITMENTS AND CONTINGENCIES

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

($000s)		Payment Due by Period1,2
	Recognized
	in Financial	Contractual	Less than
	Statements	Cash Flows	1 year	1-3 years
Accounts payable and accrued liabilities	Yes - Liability	28,007	28,007	—
Long-term debt	Yes - Liability	52,355	—	52,355
Other long-term liabilities	Yes - Liability	1,007	—	1,007
Office and equipment leases3	No	2,949	1,985	964
Total		84,318	29,992	54,326
1  Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2  Payments denominated in foreign currencies have been translated at December 31, 2018 exchange rates.
3  Office and equipment leases include all drilling rig contracts.

Pursuant to the PSC for North West Sitra in Egypt, the Company had a minimum financial commitment of $10.0 million and a work commitment

for two wells and 300 square kilometers of 3-D seismic during the initial three-and-a-half year exploration period, which commenced on January

8, 2015. The Company requested and received a six month extension of the initial exploration period to January 7, 2019. As at December 31, 2018, the Company has met its financial and operating commitments, with the acquisition of 600 square kilometers of 3-D seismic in 2017 and thedrilling of two wells in 2018. The Company has now completed the initial exploration period work program and based on well results did not elect to enter the second exploration phase and relinquished the concession on January 7, 2019.

2018 45

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, 2018.

19. SHARE CAPITAL

Authorized

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

Issued

	December 31, 2018			December 31, 2017
(000s)	Shares	Amount		Shares	Amount
Balance, beginning and end of year	72,206	$	152,084	72,206	$	152,084

20. SHARE-BASED PAYMENTS

Stock option plan

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

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

	2018			2017
			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	4,959		5.10	6,046		6.87
Granted	1,071		2.62	1,043		2.16
Cancelled / Forfeited	—		—	(1,281	)	6.75
Expired	(1,154	)	9.13	(849	)	11.43
Options outstanding, end of year	4,876		3.60	4,959		5.10
Options exercisable, end of year	2,766		4.52	2,925		6.87

	Options Outstanding			Options Exercisable
		Weighted-			Weighted-
	Number	Average	Weighted-	Number	Average	Weighted-
Exercise	Outstanding at	Remaining	Average	Exercisable at	Remaining	Average
Prices	December 31, 2018	Contractual	Exercise Price	December 31, 2018	Contractual	Exercise
(C$)	(000s)	Life (Years)	(C$)	(000s)	Life (Years)	Price (C$)
2.16 - 2.17	953	3.4	2.16	318	3.4	2.16
2.18 - 2.41	1,212	2.2	2.19	808	2.2	2.19
2.42 - 3.81	1,071	4.4	2.62	—	—	—
3.82 - 6.13	820	1.4	4.99	820	1.4	4.99
6.14 - 7.26	820	0.4	7.26	820	0.4	7.26
	4,876	2.5	3.60	2,766	1.6	4.52

Compensation expense of $0.9 million was recorded in general and administrative expenses in the Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss) and Changes in Shareholders’ Equity during year ended December 31, 2018 (2017 - $0.6 million) in respect of stock options. The fair value of all common stock options granted is estimated on the date of grant using the lattice-based trinomial option pricing model.

46 2018

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

	2018		2017
Weighted average fair market value per option (C$)	0.88		0.70
Risk free interest rate (%)	2.14	%	0.74	%
Expected volatility (based on actual historical volatility) (%)	49.45	%	48.67	%
Dividend rate	—	%	—	%
Expected forfeiture rate (non-executive employees) (%)	—	%	—	%
Suboptimal exercise factor	1.25		1.25

All options granted vest annually over a three-year period and expire five years after the grant date. During the year ended December 31, 2018, no employee stock options were exercised (2017 – nil). As at December 31, 2018 and December 31, 2017, the entire balance in contributed surplus was related to previously recognized share-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 subsequent to 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, 2018:

(000s)	RSUs		PSUs		DSUs
Units outstanding, December 31, 2016	546		1,366		437
Granted	807		573		214
Exercised	(245	)	(248	)	(56	)
Forfeited	(138	)	(315	)	—
Units outstanding, December 31, 2017	970		1,376		595
Granted	410		678		225
Exercised	(361	)	(316	)	—
Forfeited	(163	)	(71	)	—
Reinvested	8		16		8
Units outstanding, December 31, 2018	864		1,683		828

Compensation expense of $2.7 million was recorded in general and administrative expenses in the Consolidated Statement of Earnings (Loss) and Comprehensive Income (Loss) during the year ended December 31, 2018 in respect of share units granted under the three plans described above (2017 - $0.8 million).

21. PER SHARE AMOUNTS

The basic and diluted weighted-average number of common shares outstanding for the year ended December 31, 2018 was 72,205,369 and 72,631,320, respectively (2017 - basic and diluted: 72,205,369). These outstanding share amounts were used to calculate net earnings (loss) per share in the respective periods.

In determining diluted net earnings (loss) per share, the Company assumes that the proceeds received from the exercise of “in-the-money” stock options are used to repurchase common shares at the average market price. In calculating the weighted-average number of diluted common shares outstanding for the year ended December 31, 2018, the Company excluded 1,640,000 stock options (2017 – 4,576,100) as their exercise price was greater than the average common share market price in the year.

22. DIVIDENDS

During the year ended December 31, 2018, the Company paid the following dividends on its common shares:

Ex-dividend date	Record date	Payment date	Per share amount
August 30, 2018	August 31, 2018	September 14, 2018	$0.035

2018 47

23. RELATED PARTY DISCLOSURES

Details of controlled and consolidated entities active as at December 31, 2018 are as follows:

	Country of	Ownership Interest	Ownership Interest
	Incorporation	2018	2017
TG Energy UK Ltd	United Kingdom	100%	—
TransGlobe Petroleum International Inc.	Turks & Caicos	100%	100%
TG Holdings Yemen Inc.	Turks & Caicos	100%	100%
TransGlobe West Bakr Inc.	Turks & Caicos	100%	100%
TransGlobe West Gharib Inc.	Turks & Caicos	100%	100%
TG Holdings Egypt Inc.	Turks & Caicos	100%	100%
TG South Alamein Inc.	Turks & Caicos	100%	100%
TG South Mariut Inc.	Turks & Caicos	100%	100%
TG South Alamein II Inc.	Turks & Caicos	100%	100%
TG Energy Marketing Inc.	Turks & Caicos	100%	100%
TG NW Gharib Inc.	Turks & Caicos	100%	100%
TG SW Gharib Inc.	Turks & Caicos	100%	100%
TG SE Gharib Inc.	Turks & Caicos	100%	100%
TG S Ghazalat Inc.	Turks & Caicos	100%	100%
TransGlobe Petroleum Egypt Inc.	Turks & Caicos	100%	100%

24. COMPENSATION OF KEY MANAGEMENT PERSONNEL

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

Key management personnel remuneration consisted of the following:

($000s)	2018		2017
Salaries, incentives and short-term benefits	$	2,352	$	2,015
Share-based compensation	2,210		692
	$	4,562	$	2,707

25. SEGMENTED INFORMATION

The Company has two reportable operating segments for the year ended December 31, 2018: the Arab Republic of Egypt and Canada. The Company, through its operating segments, is engaged primarily in oil exploration, development and production and the acquisition of oil and gas properties.

In presenting information on the basis of operating segments, segment revenue is based on the geographical location of assets which is also consistent with the location of the segment customers. Segmented assets are also based on the geographical location of the assets. There are no inter-segment sales. The accounting policies of the operating segments are the same as the Company’s accounting policies.

48 2018

	Egypt						Canada						Corporate						Total
($000s)	2018			2017			2018			2017			2018			2017			2018			2017
Revenue
Oil sales	$	278,111		$	230,323		$	10,666		$	10,464		$	—		$	—		$	288,777		$	240,787
Natural gas sales	—			—			2,632			4,120			—			—			2,632			4,120
Natural gas liquids sales	—			—			7,735			7,684			—			—			7,735			7,684
Less: Royalties	(120,271		)	(99,336		)	(2,646		)	(4,791		)	—			—			(122,917		)	(104,127		)
Petroleum and natural gas sales, net of royalties	157,840			130,987			18,387			17,477			—			—			176,227			148,464
Finance revenue	87			33			—			—			483			75			570			108
Total segmented revenue	157,927			131,020			18,387			17,477			483			75			176,797			148,572
Segmented expenses
Production and operating	45,562			44,705			7,736			6,300			—			—			53,298			51,005
Selling costs	2,103			2,495			—			—			—			—			2,103			2,495
General and administrative	4,798			5,782			1,134			1,147			12,756			8,324			18,688			15,253
Foreign exchange (gain) loss	—			—			—			—			(289		)	194			(289		)	194
Finance costs	4,635			4,357			440			860			—			1,016			5,075			6,233
Depletion, depreciation and amortization	26,271			30,653			7,711			8,985			309			398			34,291			40,036
Asset retirement obligation accretion	—			—			270			256			—			—			270			256
Loss on financial instruments	6,755			10,748			296			93			—			151			7,051			10,992
Impairment loss	14,500			79,025			—			—			—			—			14,500			79,025
Gain on disposition of assets	—			—			(207		)	—			—			—			(207		)	—
Income tax expense	26,340			21,819			—			—			—			—			26,340			21,819
Segmented net earnings (loss)	$	26,963		$	(68,564	)	$	1,007		$	(164	)	$	(12,293	)	$	(10,008	)	$	15,677		$	(78,736	)
Capital expenditures
Exploration and development	$	28,673		$	31,151		$	11,965		$	6,967		$	—		$	—		$	40,638		$	38,118
Corporate	—			—			—			—			68			41			68			41
Total capital expenditures																			$	40,706		$	38,159

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

	At December 31, 2018						At December 31, 2017
($000s)	Egypt		Canada		Total		Egypt		Canada		Total
Assets
Accounts receivable	$	9,031	$	2,525	$	11,556	$	14,956	$	2,684	$	17,640
Derivative commodity contracts	1,369		—		1,369		—		—		—
Intangible exploration and evaluation assets	35,735		531		36,266		41,478		—		41,478
Property and equipment
Petroleum and natural gas assets	123,043		72,220		195,263		127,363		73,618		200,981
Other assets	2,222		22		2,244		2,381		27		2,408
Other	58,518		1,296		59,814		49,769		3,467		53,236
Deferred taxes	4,523		—		4,523		—		—		—
Segmented assets	234,441		76,594		311,035		235,947		79,796		315,743
Non-segmented assets					7,261						11,959
Total assets					$	318,296					$	327,702
Liabilities
Accounts payable and accrued liabilities	$	13,407	$	8,010	$	21,417	$	17,035	$	4,004	$	21,039
Derivative commodity contracts	—		—		—		7,813		157		7,970
Long-term debt	44,134		8,221		52,355		58,792		11,207		69,999
Asset retirement obligation	—		12,113		12,113		—		12,332		12,332
Deferred taxes	4,523		—		4,523
Segmented liabilities	62,064		28,344		90,408		83,640		27,700		111,340
Non-segmented liabilities					7,597						6,355
Total liabilities					$	98,005					$	117,695

2018 49

26. SUPPLEMENTAL CASH FLOW INFORMATION

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

($000s)	2018			2017
Operating Activities
(Increase) decrease in current assets
Accounts receivable	$	6,076		$	(3,254	)
Prepaids and other	97			(3,044		)
Product inventory1	905			5,789
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	(1,975		)	4,367
Other long-term liabilities	807			—
	$	5,910		$	3,858
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.

($000s)	2018			2017
Investing Activities
(Increase) decrease in current assets
Prepaids and other	$	(4	)	$	—
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	255			(1,587		)
	$	251		$	(1,587	)

($000s)	2018			2017
Financing Activities
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	$	(3	)	$	—
	$	(3	)	$	—

27. SUBSEQUENT EVENTS

TransGlobe Energy Corporation made a $5.0 million repayment of the Mercuria prepayment agreement on January 28, 2019.

On March 11, 2019, the Company declared a dividend of $0.035 per share to shareholders of record on March 29, 2019.

50 2018

CORPORATE & SHAREHOLDER INFORMATION
DIRECTORS	INVESTOR RELATIONS
	Telephone: +1 (403) 264-9888
Robert G. Jennings(1)- Chairman	investor.relations@trans-globe.com
Randy C. Neely (4)- President & Chief Executive Officer
Ross G. Clarkson(3)
Matthew Brister (2)(3)	NOMINATED ADVISER & JOINT BROKER
David B. Cook (1)(2)	Canaccord Genuity Limited
Edward LaFehr (1)(3)	8 Wood Street, London, EC2V 7QR
Carol Bell (1)(2)
Susan M. MacKenzie (2)(3)
Steven W. Sinclair (1)(2)	CO-BROKER
	GMP FirstEnergy Capital LLP
(1) Audit Committee	88 London Wall
(2) Compensation Human Resources & Governance Committee	London EC2M 7AD
(3) Reserves Health Safety & Social Responsibility Committee
(4) Disclosure and AIM Compliance Committee
	LEGAL COUNSEL
OFFICERS	Burnet, Duckworth & Palmer LLP
Randy C. Neely (4)- President & Chief Executive Officer	Calgary, Alberta
Lloyd W. Herrick (4)- Vice President & Chief Operating Officer
Edward D. Ok (4)- Vice President, Finance & Chief Financial Officer
Marilyn A. Vrooman-Robertson - Corporate Secretary	AUDITORS
	Deloitte LLP
	Calgary, Alberta
HEAD OFFICE
2300, 250 – 5th Street S.W.
Calgary, Alberta, Canada T2P 0R4	EVALUATION ENGINEERS
Telephone: +1 (403) 264-9888	GLJ Petroleum Consultants Ltd.
Facsimile: +1 (403) 770-8855	Calgary, Alberta
EGYPT OFFICE	BANKS
6 Badr Towers, 10th Floor	Sumitomo Mitsui Banking Corporation Europe Limited
Ring Road	London, Great Britain
New Maadi, Cairo, Egypt
	Alberta Treasury Branches
	Calgary, Alberta, Canada
UK OFFICE
Suite 600 - 105 Victoria Street
London, UK SW1E 6QT	PUBLIC RELATIONS
	FTI Consulting Inc.
	Telephone: +44 (0) 203 727 1000
WEBSITE	Email: transglobeenergy@fticonsulting.com
www.trans-globe.com

www.trans-globe.com

TSX & AIM: TGL NASDAQ: TGA