2019 FIRST QUARTER INTERIM REPORT

Financial and Operating Results

For the three months ended March 31, 2019

All dollar values are expressed in United States dollars unless otherwise stated

ø	Production for the three months ended March 31, 2019 averaged 15,924 boe/d (Egypt 13,616 bbls/d, Canada 2,308 boe/d), an increase of 654 boe/d (4%) from the previous quarter;
ø	Production in April averaged ~16,964 boe/d (Egypt 14,583 bbls/d, Canada 2,381 boe/d), an increase of ~1,040 boe/d (7%) from Q1-2019
ø	Positive first quarter funds flow of $15.2 million ($0.21 per share). First quarter net loss of $8.8 million, inclusive of an $8.4 million impairment loss and $4.8 million unrealized loss on derivative commodity contracts;
ø	Declared a dividend of $0.035 per share ($2.5 million) to shareholders of record on March 29, 2019, paid on April 18, 2019;
ø	Ended the first quarter with positive working capital of $43.6 million, including cash and cash equivalents of $24.7 million;
ø	Drilled 2 oil wells in Egypt (M-10 Twin and NWG 38A-8) and re-entered/deepened 2 water disposal wells (K-8 WDW and K-10 WDW) during the quarter;
ø	Submitted a development lease application for South Ghazalat in February, targeting first production prior to year end;
ø	Equipped and tied in six Cardium oil wells in the Harmattan area, Canada (related to the 2018 capital program) during January 2019;
ø	Sales averaged 15,047 boe/d with one cargo lifting of TransGlobe's entitlement crude oil occurring in March;
ø	Drilled a new pool oil well (HW-2X) in West Bakr with an internally estimated 113 feet of net oil pay subsequent to the quarter, which was placed on production at an initial rate of ~625 bbls/d in early May; and
ø	Drilled a development oil well (H-30) with an internally estimated 25 feet of net Yusr oil pay subsequent to the quarter.

www.trans-globe.com

TSX & AIM: TGL NASDAQ: TGA

CONTENTS

Financial and Operating Results	Page 3
Corporate Summary	Page 4
Operations Update	Page 5
Management's Discussion and Analysis	Page 7
Condensed Consolidated Interim Financial Statements	Page 18
Notes to Condensed Consolidated Interim Financial Statements	Page 22

2 Q1-2019

FINANCIAL AND OPERATING RESULTS

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

	Three Months Ended March 31
Financial	2019		2018		% Change
Petroleum and natural gas sales	69,217		52,951		31
Petroleum and natural gas sales, net of royalties	37,352		24,715		51
Realized derivative loss on commodity contracts	(222	)	(118	)	(88)
Unrealized derivative loss on commodity contracts	(4,774	)	(6,046	)	21
Production and operating expense	11,533		10,641		8
Selling costs	475		46		933
General and administrative expense	4,867		3,996		22
Depletion, depreciation and amortization expense	8,766		6,848		28
Income taxes expense	6,203		6,019		3
Cash flow used in operating activities	(13,071	)	(7,155	)	(83)
Funds flow from operations1	15,155		3,923		286
Basic per share	0.21		0.05
Diluted per share	0.21		0.05
Net loss	(8,806	)	(10,120	)	13
Basic per share	(0.12	)	(0.14	)
Diluted per share	(0.12	)	(0.14	)
Capital expenditures	8,547		4,635		84
Dividends declared	2,539		—		—
Dividends declared per share	0.035		—
Working capital	43,600		45,252		(4)
Long-term debt, including current portion	47,687		67,167		(29)
Common shares outstanding
Basic (weighted average)	72,427		72,206		—
Diluted (weighted average)	72,694		72,206		1
Total assets	308,113		312,691		(1)
Operating
Average production volumes (boe/d)	15,924		14,375		11
Average sales volumes (boe/d)	15,047		11,753		28
Inventory (mbbls)	647.0		1,012.7		(36)
Average sales price ($ per boe)	51.11		50.06		2
Operating expense ($ per boe)	8.52		10.06		(15)
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.

Q1-2019 3

CORPORATE SUMMARY

TransGlobe Energy Corporation ("TransGlobe" or the "Company") produced an average of 15,924 barrels of oil equivalent per day ("boe/d") during the first quarter of 2019. Egypt production was 13,616 barrels of oil per day ("bbls/d") and Canada production was 2,308 boe/d. Production for the quarter was above the 2019 guidance (14,000 - 15,000 boe/d) and 4% higher than the previous quarter.

As at March 31, 2019 the Company had approximately 647.0 thousand barrels ("mbbls") of inventoried entitlement crude oil. All Canadian production was sold during the quarter, and the Company sold 452.6 mbbls of entitlement crude oil in Egypt.

TransGlobe's Egyptian crude oil is sold at a quality discount to Dated Brent. The Company received an average price of $54.93 per barrel during the quarter. In Canada, the Company received an average of $48.53 per barrel of oil and $1.94 per thousand cubic feet ("mcf") of natural gas in the first quarter of 2019.

During the first quarter of 2019, the Company had funds flow from operations of $15.2 million and ended the quarter with positive working capital of $43.6 million, including cash and cash equivalents of $24.7 million. The Company experienced a net loss in the quarter of $8.8 million, which included an $8.4 million non-cash impairment loss on the Company's exploration and evaluation assets in South Alamein and a $4.8 million unrealized derivative loss on commodity contracts which represents a fair value adjustment on the Company's hedging contracts as at March 31, 2019.

The Company declared a dividend of $0.035 per share, paid on April 18, 2019 to shareholders of record on March 29, 2019.

In the Eastern Desert the Company drilled two development oil wells during the first quarter of 2019. At West Bakr, the Company drilled and completed the M-10 replacement well (M-10 Twin) as an Asl A oil producer which was placed on production in February and is currently producing ~400 bbls/d. The Company also re-entered/deepened two suspended oil wells and converted them to water disposal wells (K-8 WDW and K-10 WDW). At North West Gharib, the Company drilled the NWG 38A-8 well to a total depth of 1,631 meters (5,350 feet), targeting the southern area of the NWG 38A Red Bed pool to provide water injection/reservoir pressure support for the 38A pool. The well was completed and placed on production at an initial average rate of 45 bbls/d and 100 barrels per day of water. Based on early production results, the well was converted to water injection during Q2-2019 to initiate pressure support for the NWG 38A pool.

Subsequent to the quarter, the Company drilled two wells in West Bakr resulting in an oil discovery at HW-2X and a development oil well at H-30. The HW-2X exploration well was drilled to a total depth of 1,654 meters (5,425 feet) and cased as a Yusr oil well. Based on open-hole logs and wireline samples, the well encountered an internally estimated 34.5 meters (113 feet) of net oil pay in the Yusr formation. The HW-2X well was completed and placed on production in early May at an initial rate of ~625 bbls/d. The H-30 development well was drilled to a total depth of 1,655 meters (5,454 feet) and cased as a Yusr oil well. Based on open-hole logs and wireline samples, the well encountered an internally estimated 7.8 meters (25 feet) of net oil pay in the Yusr formation. The H-30 well is scheduled for completion and first oil production by the end of May. Following H-30, the drilling rig is scheduled to drill a development well at West Bakr (K-63) and one exploration well at North West Gharib (NWG 38 D-1).

In the Western Desert, the Company filed a development lease application with EGPC in February for the South Ghazalat SGZ 6X oil discovery. The Company is targeting production from this concession prior to year end. At South Alamein, the Company was unsuccessful in its attempts to secure military approval for its desired drilling location. In light of recent events, TransGlobe has recorded an impairment loss of $8.4 million and will continue to negotiate access to the western portion of this concession.

In Canada, the Company equipped and tied in six (five net) Cardium oil wells (from the 2018 capital program) in the Harmattan area during January. Due to low ethane prices, TransGlobe's third-party gas processing plant shut down their deep cut ethane extraction plant in January. Approximately 250 boe/d of ethane was sold as part of the gas stream in Q1-2019 at a higher energy content resulting in a neutral impact to revenue. It is expected that ethane volumes will remain in sales gas volumes until Q4-2019.

4 Q1-2019

OPERATIONS UPDATE

ARAB REPUBLIC OF EGYPT

EASTERN DESERT

West Gharib, West Bakr, and North West Gharib (100% working interest, operated)

Operations and Exploration

During the first quarter of 2019, the Company drilled two development oil wells (M-10 Twin and NWG 38A-8). At West Bakr, the Company finished drilling the M-10 replacement well (M-10 Twin), which was completed as an Asl A oil producer in February and is currently producing ~400 bbls/d. The Company also re-entered/deepened two suspended oil wells and converted them to water disposal wells (K-8 WDW and K-10 WDW). At North West Gharib, the Company drilled the NWG 38A-8 well to a total depth of 1,631 meters (5,350 feet) and cased it as a potential Red Bed oil well/water injector. NWG 38A-8 was targeting the southern area of the NWG 38A Red Bed pool to provide water injection/reservoir pressure support for the 38A pool. The well was completed and placed on production at an initial average rate of 45 bbls/d and 100 barrels of water per day, confirming the well had intersected the oil water contact for the pool. Based on early production results, the well was converted to water injection post quarter end to initiate water injection and pressure support for the NWG 38A pool.

Subsequent to the quarter, the Company drilled two wells at West Bakr resulting in an oil discovery at HW-2X and a development oil well at H-30. The HW-2X exploration well was drilled to a total depth of 1,654 meters (5,425 feet) and cased as a Yusr oil well. Based on open hole logs and wireline samples, the well encountered an internally estimated 34.5 meters (113 feet) of net oil pay in the Yusr formation. The HW-2X well was completed and placed on production at an initial rate of ~625 bbls/d in early May. The H-30 development well was drilled to a total depth of 1,655 meters (5,454 feet) and cased as a Yusr oil well. Based on open hole logs and wireline samples, the well encountered an internally estimated 7.8 meters (25 feet) of net oil pay. The H-30 well is scheduled for completion and first production in May. Following H-30, the drilling rig is scheduled to drill a development well at K-63 and one exploration well at North West Gharib (NWG 38 D-1).

During Q1-2019, the Company commenced the K Station Phase 3 project to add a third process train and triple the original fluid handling capacity to ~45,000 barrels per day; completion is expected in the second half of 2019.

Production

Production averaged 13,616 bbls/d to TransGlobe during the quarter, a 5% (646 bbls/d) increase from the previous quarter, primarily due to the success of M-10 Twin and successful well optimization projects in West Bakr.

Production in April averaged ~14,583 bbls/d representing a 7% increase over the quarter, due to new wells and a successful well recompletion/optimization program.

Sales

The Company sold 452.6 mbbls of inventoried entitlement crude to a third-party for $25.4 million in Q1-2019.

Quarterly Eastern Desert Production (bbls/d)	2019		2018
	Q-1		Q-4		Q-3	Q-2
Gross production rate1	13,616		12,970		11,939	11,913
TransGlobe production (inventoried) sold	(877	)	(787	)	159	5,521
Total sales	12,739		12,183		12,098	17,434
Government share (royalties and tax)	7,711		7,292		6,645	6,612
TransGlobe sales (after royalties and tax)2	5,028		4,891		5,453	10,822
Total sales	12,739		12,183		12,098	17,434
1  Quarterly production by concession (bbls/d): West Gharib - 4,238 (Q1-2019), 4,512 (Q4-2018), 4,793 (Q3-2018), and 5,015 (Q2-2018) West Bakr - 8,132 (Q1-2019), 7,323 (Q4-2018), 6,126 (Q3-2018), and 5,747 (Q2-2018) North West Gharib - 1,246 (Q1-2019), 1,135 (Q4-2018), 1,020 (Q3-2018), and 1,151 (Q2-2018)
2  Under the terms of the Production Sharing Concession Agreements, royalties and taxes are paid out of the Government's share of production sharing oil.

WESTERN DESERT

South Ghazalat, South Alamein and North West Sitra (100% working interest, operated)

Operations and Exploration

At South Ghazalat, the Company filed a development lease application with EGPC in February for the South Ghazalat SGZ-6X oil discovery. Subject to final approvals by EGPC, the Ministry and necessary regulatory approvals, the Company is targeting first production prior to year end. Concurrent with the construction of an early production facility and equipping SGZ-6X for production, the Company has submitted permits to drill an appraisal well in the SGZ 6X pool during the second half of 2019 and initiated a project to merge and reprocess two existing 3D seismic surveys over the proposed development lease area. In addition to the planned appraisal well, the Company is committed to drill a minimum of one additional exploration well.

At South Alamein, the Company continued extension discussions with EGPC during the quarter and resubmitted a request for military access to drill the SA-24X Jurassic exploration prospect which was rejected by the military in April 2019. Based on the 2017 well results in the Boraq area,

Q1-2019 5

the limited commerciality of the original Boraq 2 discovery (2009) and continued access restrictions in the eastern area of the concession, the Company is exploring a variety of extension options with EGPC including partial, or possibly complete, relinquishment of the concession. In light of the high risk nature of the upside potential of the remaining concession area and restricted access issues, the Company fully impaired the remaining carrying value of the South Alamein intangible assets ($8.4 million) in Q1-2019.

At North West Sitra, the Company officially relinquished the concession on January 7, 2019 and did not enter the next exploration phase. All work commitments have been met for the concession.

CANADA

Operations and Exploration

During the quarter, the Company completed the equipping and tie-in of six Cardium wells in the Harmattan area from the 2018 drilling program. The wells were brought on production in a systematic manner in order to maximize ultimate recoveries, however this process was somewhat hampered by facility outages and extremely cold winter weather during the quarter.

Subsequent to the quarter, the Company initiated permitting and surface land acquisition for the 2019 drilling program which will consist of four net horizontal wells targeting the Cardium formation in the Harmattan area (three 100% development wells and one 100% outpost well) commencing in early Q3-2019.

Production

In Canada, oil production averaged 894 bbls/d during the quarter, up 399 bbls/d (81%) from the previous quarter, primarily due to new production from the 2018 drilling program. Increased oil production was offset (on a boe/d basis) by the reduction of ~250 boe/d of low value ethane sales during the quarter and unscheduled facility repairs. The Company's central production facility was shut-down in February to replace a burner in the main treater. Production was impacted by these facility repairs and was further delayed due to the extremely cold weather in February. In January, the operator of the main gas processing plant (third-party) of the Company’s gas production shut down their deep cut ethane extraction plant due to low ethane prices and pipeline egress issues in Alberta. It is expected that the ethane will remain in the sales gas volumes until the fourth quarter at a minimum, which will be sold with a higher energy content and is expected to be generally revenue neutral, due to low prices for ethane. It is estimated that approximately 250 boe/d of ethane is now sold as natural gas.

Production averaged ~2,381 boe/d in April (~897 bbls/d of oil).

Quarterly Canada Production (boe/d)	2019	2018
	Q-1	Q-4	Q-3	Q-2
Canada crude oil (bbls/d)	894	495	567	497
Canada NGLs (bbls/d)	470	829	876	521
Canada natural gas (mcf/d)	5,663	5,865	5,695	5,094
Total production (boe/d)	2,308	2,302	2,392	1,867

6 Q1-2019

MANAGEMENT'S DISCUSSION AND ANALYSIS

May 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 unaudited Condensed Consolidated Interim Financial Statements of the Company for the three months ended March 31, 2019 and 2018, and the audited Consolidated Financial Statements and Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2018 included in the Company's annual report. The Condensed Consolidated Interim Financial Statements were prepared in accordance with International Accounting Standard 34, Interim Financial Reporting using accounting policies consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board in the currency of the United States, except where otherwise noted. 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 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).

Q1-2019 7

Furthermore, the forward-looking statements or information contained herein are made as at the date hereof and the Company does not undertake 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

	Three Months Ended March 31
($000s)	2019		2018
Cash flow used in operating activities	(13,071	)	(7,155	)
Changes in non-cash working capital	28,226		11,078
Funds flow from operations1	15,155		3,923
1  Funds flow from operations does not include interest costs. Interest expense is included in financing costs on the Condensed Consolidated Interim Statements of Loss and Comprehensive    Loss. Cash interest paid is reported as a financing activity on the Condensed Consolidated Interim 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.

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. 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.

8 Q1-2019

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 average in a range between 11,600 and 12,400 bbls/d in 2019. Canadian production is expected to range between 2,400 and 2,600 boe/d in 2019, which included approximately 250 boe/d of ethane production that is currently being sold as natural gas with increased energy content.

Total production to date (January through April) has averaged ~16,000 boe/d, which is ~1,000 boe/d above the upper range of guidance for the year. The increased production against plan is primarily due to an accelerated drilling schedule for the 2019 Egypt plan (Q1/Q2 versus a planned Q2/Q3) and higher initial production performance from the 2019 Egypt plan (completed to date) than forecasted. The original 2019 plan did not include production from exploration wells or the South Ghazalat 6X discovery. Should performance continue to exceed forecast, the Company may revise 2019 guidance mid year to include exploration results and first oil from South Ghazalat.

Funds flow from operations in any given period is dependent upon the timing and market price of crude oil sales in Egypt. 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 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, debt repayments and dividends.

The below chart provides a comparison of well netbacks in the Company’s Egyptian and Canadian assets under multiple price sensitivities. A typical Cardium well produces both oil and natural gas/NGLs. The price of each commodity varies significantly, therefore the below chart presents the netback of each revenue stream separately.

Netback sensitivity
Benchmark crude oil price (US$/bbl)	40		50	60	70	80
Benchmark natural gas price (C$/mcf)	0.95		1.15	1.35	1.55	1.75
Netback ($/boe)
Egypt - crude oil1	1.63		5.80	9.97	14.15	18.11
Canada - crude oil2	19.62		27.65	35.39	43.22	51.06
Canada - natural gas and NGLs2	(0.46	)	0.63	1.70	3.45	5.19
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 ~$10.50/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$11.50/boe, NGL mixture price at 45% of Edmonton Light, and takes into consideration Canadian tax pools.

Q1-2019 9

SELECTED QUARTERLY FINANCIAL INFORMATION

	2019		2018						2017
($000s, except per share,
price and volume amounts)	Q-1		Q-4	Q-3		Q-2	Q-1		Q-4		Q-3		Q-2
Operations
Average production volumes
Crude oil (bbls/d)	14,510		13,463	12,506		12,409	12,452		12,027		12,786		14,347
NGLs (bbls/d)	470		829	876		521	894		915		1,081		919
Natural gas (mcf/d)	5,663		5,865	5,695		5,094	6,176		6,059		6,268		7,191
Total (boe/d)	15,924		15,270	14,331		13,779	14,375		13,952		14,912		16,465
Average sales volumes
Crude oil (bbls/d)	13,633		12,676	12,665		17,931	9,830		14,324		15,894		17,141
NGLs (bbls/d)	470		829	876		521	894		915		1,081		919
Natural gas (mcf/d)	5,663		5,865	5,695		5,094	6,176		6,059		6,286		7,191
Total (boe/d)	15,047		14,483	14,490		19,301	11,753		16,249		18,020		19,259
Average realized sales prices
Crude oil ($/bbl)	54.51		60.12	61.79		59.39	56.26		53.25		44.82		39.46
NGLs ($/bbl)	31.80		24.39	22.64		38.39	27.72		26.86		18.90		21.08
Natural gas ($/mcf)	1.94		1.22	1.01		1.08	1.70		0.94		1.65		2.14
Total oil equivalent ($/boe)	51.11		54.51	55.77		56.49	50.06		48.80		41.24		36.92
Inventory (mbbls)	647.0		568.1	495.6		510.3	1,012.7		776.8		988.1		1,274.1
Petroleum and natural gas sales	69,217		72,628	74,345		99,220	52,951		72,954		68,372		64,712
Petroleum and natural gas sales, net of royalties	37,352		40,605	42,453		68,454	24,715		40,725		44,839		40,439
Cash flow from (used in) operating activities	(13,071	)	9,822	47,639		18,886	(7,155	)	44,263		20,437		(2,753	)
Funds flow from operations1	15,155		8,842	17,018		33,499	3,923		17,018		19,217		16,855
Funds flow from operations per share:
- Basic	0.21		0.12	0.24		0.46	0.05		0.24		0.27		0.23
- Diluted	0.21		0.12	0.23		0.46	0.05		0.24		0.27		0.23
Net earnings (loss)	(8,806	)	30,719	(12,283	)	7,361	(10,120	)	(2,382	)	(6,855	)	(56,622	)
Net earnings (loss) per share:
- Basic	(0.12	)	0.43	(0.17	)	0.10	(0.14	)	(0.03	)	(0.09	)	(0.78	)
- Diluted	(0.12	)	0.43	(0.17	)	0.10	(0.14	)	(0.03	)	(0.09	)	(0.78	)
Capital expenditures	8,547		17,433	12,783		5,855	4,635		9,078		10,133		8,230
Dividends declared	2,539		—	2,527		—	—		—		—		—
Dividends declared per share	0.035		—	0.035		—	—		—		—		—
Total assets	308,113		318,296	314,203		329,542	312,691		327,702		338,802		337,596
Cash and cash equivalents	24,735		51,705	62,663		38,088	31,084		47,449		21,464		13,780
Working capital	43,600		50,987	52,351		60,464	45,252		50,639		58,815		60,319
Total long-term debt, including      current portion	47,687		52,355	52,532		62,173	67,167		69,999		79,839		83,725
Net debt-to-funds flow from operations ratio2	0.05		0.02	0.00		0.02	0.36		0.35		0.70		2.00
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 for    the trailing 12 months and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".

During the first quarter of 2019, TransGlobe:

• Increased production volumes by 11% compared to Q1-2018 primarily due to new wells in Egypt and Canada;

• Sold one cargo of TransGlobe's entitlement crude oil of 452.6 mbbls and ended Q1-2019 with crude oil inventory of 647.0 mbbls, an increase of 78.9 mbbls from crude inventory levels at December 31, 2018;

• Reported positive funds flow from operations of $15.2 million;

• Ended Q1-2019 with positive working capital of $43.6 million, including $24.7 million in cash and cash equivalents;

• Reported a net loss of $8.8 million, inclusive of a $4.8 million unrealized derivative loss on commodity contracts and an $8.4 million impairment loss on the Company's exploration and evaluation assets;

• Spent $8.5 million on capital expenditures; and

• Declared a dividend of $0.035 per share ($2.5 million) to shareholders of record on March 29, 2019, paid on April 18, 2019.

10 Q1-2019

BUSINESS ENVIRONMENT

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

Average Reference Prices and Exchange Rates	2019	2018
	Q-1	Q-4	Q-3	Q-2	Q-1
Crude oil
Dated Brent average oil price (US$/bbl)	63.17	67.71	75.22	74.50	66.81
Edmonton Sweet index (US$/bbl)	49.96	32.51	62.68	62.43	56.98
Natural gas
AECO (C$/mmbtu)	2.62	1.56	1.18	1.18	2.08
US/Canadian Dollar average exchange rate	1.33	1.32	1.30	1.29	1.26

In Q1-2019, the average price of Dated Brent oil was 5% and 7% lower than Q1-2018 and Q4-2018 respectively. 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 PSCs 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 the first quarter of 2019, the average price of Edmonton Sweet index oil (expressed in USD) was 12% lower and 54% higher than Q1-2018 and Q4-2018 respectively. In Q1-2019, the average price of AECO natural gas increased 26% and 68% compared with Q1-2018 and Q4-2018, respectively.

OPERATING RESULTS AND NETBACK

Daily volumes, working interest before royalties (boe/d)

Production Volumes
	Three Months Ended March 31
	2019	2018
Egypt crude oil (bbls/d)	13,616	11,777
Canada crude oil (bbls/d)	894	675
Canada NGLs (bbls/d)	470	894
Canada natural gas (mcf/d)	5,663	6,176
Total Company (boe/d)	15,924	14,375

Sales Volumes (excludes volumes held as inventory)
	Three Months Ended March 31
	2019	2018
Egypt crude oil (bbls/d)	12,739	9,155
Canada crude oil (bbls/d)	894	675
Canada NGLs (bbls/d)	470	894
Canada natural gas (mcf/d)	5,663	6,176
Total Company (boe/d)	15,047	11,753

Q1-2019 11

Netback

Consolidated Netback
	Three Months Ended March 31
	2019		2018
($000s, except per boe amounts)1	$	$/boe	$	$/boe
Petroleum and natural gas sales	69,217	51.11	52,951	50.06
Royalties and other2	31,865	23.53	28,236	26.69
Current taxes2	6,203	4.58	6,019	5.69
Production and operating expenses	11,533	8.52	10,641	10.06
Selling costs	475	0.35	46	0.04
Netback	19,141	14.13	8,009	7.58
1  The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended March 31, 2019 and March 31, 2018 (these figures do not include TransGlobe's Egypt     entitlement barrels held as inventory at March 31, 2019).
2  Royalties and taxes are settled at the time of production. Fluctuations in royalty and tax costs per bbl are due to timing differences between the production and sale of the Company's    entitlement crude.

Egypt
	Three Months Ended March 31
	2019		2018
($000s, except per bbl amounts)1	$	$/bbl	$	$/bbl
Oil sales	62,980	54.93	46,302	56.20
Royalties2	30,987	27.03	26,971	32.74
Current taxes2	6,203	5.41	6,019	7.31
Production and operating expenses	9,771	8.52	8,462	10.27
Selling costs	475	0.41	46	0.06
Netback	15,544	13.56	4,804	5.82
1  The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended March 31, 2019 and March 31, 2018 (these figures do not include TransGlobe's Egypt     entitlement barrels held as inventory at March 31, 2019).
2  Royalties and taxes are settled at the time of production. Fluctuations in royalty and tax costs per bbl are due to timing differences between the production and sale of the Company's    entitlement crude.

Netback per bbl in Egypt increased by 133% in the three months ended March 31, 2019 compared with the same period in 2018. The higher netback was primarily due to a 17% decrease in production and operating expenses per barrel, partially offset by a 2% decrease in realized oil prices.

Production and operating expenses increased by $1.3 million in the three months ended March 31, 2019 compared with the same period in 2018. This increase was primarily due to well recompletion projects that occurred in Q1-2019 and higher sales of crude oil inventory compared to Q1-2018. On a per bbl basis, production and operating expenses decreased by 17% versus the comparative period due to higher production volumes (16%).

Royalties and taxes as a percentage of revenue were 59% in the three month period ended March 31, 2019, compared to 71% in the same period of 2018. 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 three month period ended March 31, 2019, royalties and taxes as a percentage of revenue would have been 55% (2018 - 55%). In periods when the Company sells less than its entitlement production, royalties and taxes as a percentage of revenue will be higher than the terms of 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 of the PSCs dictate.

The average selling price during the three months ended March 31, 2019 was $54.93/bbl (Q1-2018 - $56.20), which was $8.24/bbl lower (Q1-2018 - $10.61) than the average Dated Brent oil price of $63.17/bbl for the period (Q1-2018 - $66.81/bbl). The difference between the average selling price in Q1-2019 and the Dated Brent price is due to a gravity/quality adjustment and is impacted by the specific timing of direct sales.

Canada
	Three Months Ended March 31
	2019		2018
($000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	3,905	48.53	3,472	57.15
Natural gas sales	987	11.62	947	10.22
NGL sales	1,345	31.80	2,230	27.72
Total sales	6,237	30.03	6,649	28.43
Royalties	878	4.23	1,265	5.41
Production and operating expenses	1,762	8.48	2,179	9.32
Netback	3,597	17.32	3,205	13.70

The netback in Canada was $17.32 per boe for the three months ended March 31, 2019, which represents an increase of $3.62 per boe compared with the same period of 2018. The increase is mainly due to an increase in the total realized sales price of $1.60 per boe and a decrease in production and operating expenses of $0.84 per boe. The decrease in production and operating expenses is primarily attributed to a 5% lower Canadian exchange rate in Q1-2019, fewer workovers and certain costs being recorded as depletion, depreciation and amortization due to the adoption of

12 Q1-2019

IFRS 16. For the three months ended March 31, 2019, the Company's Canadian operations incurred $0.4 million lower royalty costs than the respective period in 2018 primarily due to higher Gas Cost Allowance (GCA) rebates. Royalties amounted to 14% of petroleum and natural gas sales revenue during the three months ended March 31, 2019 compared to 19% during the comparative period.

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.

GENERAL AND ADMINISTRATIVE EXPENSES ("G&A")

	Three Months Ended March 31
	2019				2018
($000s, except boe amounts)	$		$/boe		$		$/boe
General and administrative (gross)	4,235		3.13		4,023		3.80
Stock-based compensation	915		0.68		267		0.25
Capitalized G&A and overhead recoveries	(283	)	(0.21	)	(294	)	(0.28	)
General and administrative (net)	4,867		3.60		3,996		3.77

General and administrative (gross) for the three months ended March 31, 2019 increased 5% compared with the same period in 2018. This increase was primarily due to an increase in costs related to business development and recurring AIM costs, partially offset by lower professional fees in the comparative period. Stock-based compensation expense for the three months ended March 31, 2019 increased by 243% compared with the same period in 2018. This increase is primarily due to the Company's higher share price and performance metrics in Q1-2019, and the associated revaluation of share units granted by the Company.

FINANCE COSTS

	Three Months Ended March 31
($000s)	2019	2018
Interest on long-term debt	883	1,140
Interest on borrowing base facility	108	110
Amortization of deferred financing costs	90	98
Interest on lease obligations	60	—
Finance costs	1,141	1,348

Finance costs for the three month period ended March 31, 2019 decreased to $1.1 million from $1.3 million for the same period in 2018. This decrease is due to a lower balance of long-term debt from repayments, partially offset by higher borrowing costs due to an increase in LIBOR and ATB Prime.

At March 31, 2019, the Company had a prepayment arrangement with Mercuria that allows for a revolving balance of up to $75.0 million, of which $40.0 million is outstanding. During the first quarter of 2019, the Company made repayments of $5.0 million on this loan.

As at March 31, 2019, the Company had a revolving Canadian reserves-based lending facility with Alberta Treasury Branches ("ATB") totaling C$30.0 million ($22.4 million), of which C$11.3 million ($8.5 million) is outstanding.

The prepayment agreement and reserves-based lending facility are subject to certain covenants. The Company is in compliance with its covenants as at March 31, 2019.

DEPLETION, DEPRECIATION AND AMORTIZATION ("DD&A")

	Three Months Ended March 31
	2019		2018
($000s, except per boe amounts)	$	$/boe	$	$/boe
Egypt	6,659	5.81	4,544	5.51
Canada	1,908	9.19	2,226	9.52
Corporate	199	—	78	—
Total	8,766	6.47	6,848	6.47

In Egypt, DD&A fluctuates periodically due to changes in inventory volumes as a portion of DD&A is capitalized and expensed when sold. During the first quarter of 2019, DD&A increased by 5% on a per bbl basis compared to the same period in 2018. The increase is primarily due to a lower build in inventory in Q1-2019 (capitalized DD&A of $0.5 million) versus Q1-2018 (capitalized DD&A of $1.3 million).

In Canada, DD&A decreased by 14% compared to the same period in 2018 due to lower production volumes.

Q1-2019 13

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 and natural gas assets.

Subsequent to the quarter, the Company was unsuccessful in its attempts to secure military approval to access its desired drilling location in South Alamein. Based on the 2017 well results in the Boraq area, the limited commerciality of the original Boraq 2 discovery (2009) and continued access restrictions in the eastern area of the concession, the Company is exploring a variety of extension options with EGPC including partial, or possibly complete, relinquishment of the concession. In light of the high risk nature of the upside potential of the remaining concession area and restricted access issues, the Company fully impaired the remaining carrying value of the South Alamein intangible assets ($8.4 million) in Q1-2019. The Company will continue to negotiate access to the western portion of this concession. As at March 31, 2019, the recoverable amount of the South Alamein cash-generating unit is $nil.

CAPITAL EXPENDITURES

	Three Months Ended March 31
($000s)	2019	2018
Egypt	7,972	4,352
Canada	575	275
Corporate	—	8
Total	8,547	4,635

Capital expenditures in the first three months of 2019 were $8.5 million (2018 - $4.6 million).

In Egypt, the Company incurred $3.1 million of capitalized drilling costs, $0.8 million on workovers, $0.4 million in completion and tie-in costs and $1.4 million of facilities-related capital. During the first three months of 2019, the Company drilled two development wells in the Eastern Desert (one in West Bakr, M-10 Twin, and one in North West Gharib, NWG 38A-8).

In Canada, the Company incurred $0.6 million in completion costs during the first three months of 2019. The Company equipped and tied in six Cardium oil wells that were drilled during 2018 in the Harmattan area.

OUTSTANDING SHARE DATA

As at March 31, 2019, the Company had 72,542,071 common shares issued and outstanding and 5,191,935 stock options issued and outstanding, of which 2,699,318 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 cargo sales, and these fluctuations in cash flow impact the Company's liquidity. TransGlobe's management will continue to steward capital 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 is 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 March 31, 2019, the Company had a working capital surplus of $43.6 million (December 31, 2018 - surplus of $51.0 million). The decrease in working capital in Q1-2019 is primarily due to cash payments on Canadian capital expenditures and current liabilities, derivative commodity contracts returning to a liability position, and an increase in current liabilities from adopting IFRS 16. These decreases were partially offset by an increase in accounts receivable from the March 2019 cargo lifting, and a build in inventory.

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

Over 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 March 31, 2019, amounts owing from EGPC were $2.4 million. The Company considers there to be minimal credit risk associated with EGPC's delays.

The Company completed one crude shipment to third-party buyers in Q1-2019; the lifting occurred in March for net proceeds of $24.5 million collected in April 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 March 31, 2019, the Company held 647.0 mbbls of entitlement oil as inventory.

At March 31, 2019, the Company had $97.4 million of revolving credit facilities with $48.5 million drawn and $48.9 million available. The Company had the prepayment agreement with Mercuria that allows for a revolving balance of up to $75.0 million, of which $40.0 million is drawn. During the first three months of 2019, the Company repaid $5.0 million of this facility. The Company also had a revolving Canadian reserves-based lending facility with ATB totaling C$30.0 million ($22.4 million), of which C$11.3 million ($8.5 million) was drawn. During the first three months of 2019, the Company had drawings of C$0.2 million ($0.1 million) on this facility.

The Company paid a dividend of $2.5 million ($0.035 per share) on April 18, 2019 to shareholders of record on March 29, 2019.

Q1-2019 14

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 from where the Company's product inventory is sold. The Company requires EGPC cooperation to schedule liftings and works with EGPC on a continuous basis to schedule cargoes. Crude oil inventory levels fluctuate from quarter to quarter depending on EGPC approvals, as well as the timing and size of cargoes in Egypt. As at March 31, 2019, the Company had 647.0 mbbls of entitlement oil stored as inventory, which represents approximately three 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 increased by 78.9 mbbls in Q1-2019 compared to December 31, 2018.

	Three Months ended		Year ended
(000 bbls)	March 31, 2019		December 31, 2018
Product inventory, beginning of period	568.1		776.8
TransGlobe entitlement production	531.5		1,963.8
Crude oil sales	(452.6	)	(2,172.5	)
Product inventory, end of period	647.0		568.1

Inventory reconciliation

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

	Three Months ended	Year ended
	March 31, 2019	December 31, 2018
Production and operating expenses ($/bbls)	11.07	9.98
Depletion ($/bbls)	5.49	5.32
Unit cost of inventory ($/bbls)	16.56	15.30
Product inventory, end of period (mbbls)	647.0	568.1
Product inventory, end of period ($000)	10,715	8,692

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 Period 1,2
	Recognized
	in Financial	Contractual	Less than
	Statements	Cash Flows	1 year	1-3 years
Accounts payable and accrued liabilities	Yes - Liability	25,701	25,701	—
Other long-term liabilities	Yes - Liability	857	—	857
Financial derivative instruments	Yes - Liability	3,405	2,244	1,161
Equipment leases (short-term)3	No	1,128	1,128	—
Total		31,091	29,073	2,018
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at March 31, 2019 exchange rates.
3 Equipment leases include one drilling rig contract.

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. The Company met its financial and operating commitments and based on well results did not elect to enter the second exploration phase. The concession was relinquished on January 7, 2019.

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 March 31, 2019.

Q1-2019 15

ASSET RETIREMENT OBLIGATION

As at March 31, 2019, TransGlobe had an asset retirement obligation ("ARO") of $12.7 million (December 31, 2018 - $12.1 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 1.52% and 1.90% (December 31, 2018 - 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 (December 31, 2018 - 2%).

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 tables summarize TransGlobe’s outstanding derivative commodity contract positions as at March 31, 2019, the fair values of which have been presented on the Condensed Consolidated Interim Balance Sheet:

Financial Brent Crude Oil Contracts
Period Hedged	Contract	Remaining 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
Apr 2019 - Dec 2019	3-Way Collar	148,500	16,500	53.00	62.10	46.00
Apr 2019 - Dec 2019	3-Way Collar	149,999	16,666.5	54.00	61.35	46.00
Apr 2019 - Dec 2019	Bear Put Spread	148,500	16,500	53.00	—	46.00
Apr 2019 - Dec 2019	Bear Put Spread	149,999	16,666.5	54.00	—	46.00

CHANGE IN ACCOUNTING POLICIES

New accounting standards

IFRS 16 "Leases"

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

TransGlobe adopted IFRS 16 as of January 1, 2019 using the modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as the cumulative effect is recognized as an adjustment to opening retained earnings and the Company applies the standard prospectively. There was no effect on the Company's retained earnings or prior period amounts as a result of adopting this standard. The cumulative effect of initially applying the standard was recognized as a $3.4 million increase to ROU assets (included in Property and equipment - "Petroleum and natural gas assets" and "Other asset") with a corresponding increase recorded in "Lease obligations". The ROU assets recognized were measured at amounts equal to the lease obligations. The weighted average incremental borrowing rate used to determine the lease obligation at adoption was approximately 9.9%. The assets and lease obligations recognized largely relate to the Company's head office lease in Calgary and drilling rigs in Egypt.

TransGlobe applied the following expedients in adopting IFRS 16:

• Certain short-term leases and leases of low value assets identified at January 1, 2019 were not recognized on the balance sheet.

• At January 1, 2019, TransGlobe recognized the lease payments due within one year as current lease obligations, and those payments outside of one year as non-current lease obligations.

• At initial measurement, a single discount rate was applied to leases with similar characteristics.

Q1-2019 16

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

Leases

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

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 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. Key areas where management has made judgments, estimates, and assumptions related to the application of IFRS 16 include:

• Incremental borrowing rate: The incremental borrowing rates are based on judgments including economic environment, term, currency, and the underlying risk inherent to the asset. The carrying amount of the right-of-use assets, lease obligations, and the resulting interest and depletion and depreciation expense, may differ due to changes in the market conditions and lease term.

• Lease term: Lease terms are based on assumptions regarding extension terms that allow for operational flexibility and future market conditions.

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.

No changes were made to the Company's internal controls over financial reporting during the three months ended March 31, 2019 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

Q1-2019 17

Condensed Consolidated Interim Statements of Loss and Comprehensive Loss

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

		Three Months Ended March 31
	Notes	2019			2018
REVENUE
Petroleum and natural gas sales, net of royalties	18	$	37,352		$	24,715
Finance revenue		183			93
		37,535			24,808
EXPENSES
Production and operating		11,533			10,641
Selling costs		475			46
General and administrative		4,867			3,996
Foreign exchange gain		(87		)	(3		)
Finance costs	5	1,141			1,348
Depletion, depreciation and amortization	9	8,766			6,848
Asset retirement obligation accretion	10	56			67
Loss on financial instruments	4	4,996			6,164
Impairment loss	8	8,391			—
Gain on disposition of assets		—			(198		)
		40,138			28,909
Net loss before income taxes		(2,603		)	(4,101		)
Income tax expense – current		6,203			6,019
NET LOSS FOR THE PERIOD		$	(8,806	)	$	(10,120	)
OTHER COMPREHENSIVE LOSS
Currency translation adjustments		541			(1,004		)
COMPREHENSIVE LOSS FOR THE PERIOD		$	(8,265	)	$	(11,124	)
Net loss per share	16
Basic		$	(0.12	)	$	(0.14	)
Diluted		$	(0.12	)	$	(0.14	)

See accompanying notes to the Condensed Consolidated Interim Financial Statements

18 Q1-2019

Condensed Consolidated Interim Balance Sheets

(Unaudited - Expressed in thousands of US Dollars)

		As at			As at
	Notes	March 31, 2019			December 31, 2018
ASSETS
Current
Cash and cash equivalents	6	$	24,735		$	51,705
Accounts receivable	4	34,363			12,014
Derivative commodity contracts	4	—			1,198
Prepaids and other		3,402			5,385
Product inventory	7	10,715			8,692
		73,215			78,994
Non-Current
Derivative commodity contracts	4	—			171
Intangible exploration and evaluation assets	8	23,729			36,266
Property and equipment
Petroleum and natural gas assets	9	201,930			195,263
Other assets	9	4,716			3,079
Deferred taxes		4,523			4,523
		$	308,113		$	318,296
LIABILITIES
Current
Accounts payable and accrued liabilities		$	25,701		$	28,007
Derivative commodity contracts	4	2,244			—
Current portion of lease obligations	11	1,670			—
		29,615			28,007
Non-Current
Derivative commodity contracts	4	1,161			—
Long-term debt	12	47,687			52,355
Asset retirement obligation	10	12,711			12,113
Other long-term liabilities		857			1,007
Lease obligations	11	1,379			—
Deferred taxes		4,523			4,523
		97,933			98,005
SHAREHOLDERS’ EQUITY
Share capital	14	152,805			152,084
Accumulated other comprehensive Loss		(398		)	(939		)
Contributed surplus		24,167			24,195
Retained earnings		33,606			44,951
		210,180			220,291
		$	308,113		$	318,296

Commitments and Contingencies (Note 13)

See accompanying notes to the Condensed Consolidated Interim Financial Statements

Approved on behalf of the Board:

Signed by:

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

Q1-2019 19

Condensed Consolidated Interim Statements of Changes in Shareholders’ Equity

(Unaudited - Expressed in thousands of US Dollars)

		Three Months Ended March 31
	Notes	2019			2018
Share Capital
Balance, beginning of period	14	$	152,084		$	152,084
Stock options exercised	15	547			—
Transfer from contributed surplus on exercise of options	15	174			—
Balance, end of period		$	152,805		$	152,084
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of period		$	(939	)	$	2,793
Currency translation adjustment		541			(1,004		)
Balance, end of period		$	(398	)	$	1,789
Contributed Surplus
Balance, beginning of period		24,195			23,329
Share-based compensation expense	15	146			142
Transfer to share capital on exercise of options	15	(174		)	—
Balance, end of period		$	24,167		$	23,471
Retained Earnings
Balance, beginning of period		$	44,951		$	31,801
Net loss		(8,806		)	(10,120		)
Dividends	17	(2,539		)	—
Balance, end of period		$	33,606		$	21,681

See accompanying notes to the Condensed Consolidated Interim Financial Statements

20 Q1-2019

Condensed Consolidated Interim Statements of Cash Flows

(Unaudited - Expressed in thousands of US Dollars)

		Three Months Ended March 31
	Notes	2019			2018
CASH FLOWS RELATED TO THE FOLLOWINGACTIVITIES:
OPERATING
Net loss		$	(8,806	)	$	(10,120	)
Adjustments for:
Depletion, depreciation and amortization	9	8,766			6,848
Asset retirement obligation accretion	10	56			67
Deferred lease inducement		—			(23		)
Impairment loss		8,391			—
Share-based compensation	15	915			267
Finance costs	5	1,141			1,348
Unrealized loss on financial instruments	4	4,774			6,046
Unrealized gain on foreign currency translation		(52		)	(15		)
Gain on asset dispositions		—			(198		)
Asset retirement obligations settled	10	(30		)	(297		)
Changes in non-cash working capital	19	(28,226		)	(11,078		)
Net cash used in operating activities		(13,071		)	(7,155		)
INVESTING
Additions to intangible exploration and evaluation assets	8	—			(908		)
Additions to petroleum and natural gas assets	9	(8,547		)	(3,589		)
Additions to other assets	9	—			(138		)
Proceeds from asset dispositions		—			198
Changes in non-cash working capital	19	533			(794		)
Net cash used in investing activities		(8,014		)	(5,231		)
FINANCING
Issue of common shares for cash	14	547			—
Interest paid	5	(995		)	(1,248		)
Increase in long-term debt	12	121			141
Payments on lease obligations		(399		)	—
Repayments of long-term debt	12	(5,000		)	(2,797		)
Changes in non-cash working capital	19	(200		)	—
Net cash used in financing activities		(5,926		)	(3,904		)
Currency translation differences relating to cash and cash equivalents		41			(75		)
NET DECREASE IN CASH AND CASHEQUIVALENTS		(26,970		)	(16,365		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		51,705			47,449
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	24,735		$	31,084

See accompanying notes to the Condensed Consolidated Interim Financial Statements

Q1-2019 21

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

As at March 31, 2019 and December 31, 2018 and for the three month periods ended March 31, 2019 and 2018

(Unaudited - 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

These Condensed Consolidated Interim Financial Statements have been prepared in accordance with International Accounting Standard 34, Interim Financial Reporting, using accounting policies consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board. The accounting policies used in the preparation of these Condensed Consolidated Interim Financial Statements were the same as those used in the preparation of the most recent audited Consolidated Financial Statements for the year ended December 31, 2018, except for the adoption of a new accounting standard discussed in Note 3.

These Condensed Consolidated Interim Financial Statements were authorized for issue by the Board of Directors on May 9, 2019.

These Condensed Consolidated Interim Financial Statements do not contain all the disclosures required for full annual financial statements and should be read in conjunction with the December 31, 2018 audited Consolidated Financial Statements.

3. CHANGES IN ACCOUNTING POLICIES

New accounting standards

IFRS 16 "Leases"

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

TransGlobe adopted IFRS 16 as of January 1, 2019 using the modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information as the cumulative effect is recognized as an adjustment to opening retained earnings and the Company applies the standard prospectively. There was no effect on the Company's retained earnings or prior period amounts as a result of adopting this standard. The cumulative effect of initially applying the standard was recognized as a $3.4 million increase to ROU assets (included in Property and equipment - "Petroleum and natural gas assets" and "Other assets") with a corresponding increase recorded in "Lease obligations". The ROU assets recognized were measured at amounts equal to the lease obligations. The weighted average incremental borrowing rate used to determine the lease obligation at adoption was approximately 9.9%. The assets and lease obligations recognized largely relate to the Company's head office lease in Calgary and drilling rigs in Egypt.

TransGlobe applied the following expedients in adopting IFRS 16:

• Certain short-term leases and leases of low value assets identified at January 1, 2019 were not recognized on the balance sheet.

• At January 1, 2019, TransGlobe recognized the lease payments due within one year as current lease obligations, and those payments outside of one year as non-current lease obligations.

• At initial measurement, a single discount rate was applied to leases with similar characteristics.

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

Leases

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

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 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. Key areas where management has made judgments, estimates, and assumptions related to the application of IFRS 16 include:

22 Q1-2019

• Incremental borrowing rate: The incremental borrowing rates are based on judgments including economic environment, term, currency, and the underlying risk inherent to the asset. The carrying amount of the right-of-use assets, lease obligations, and the resulting interest and depletion and depreciation expense, may differ due to changes in the market conditions and lease term.

• Lease term: Lease terms are based on assumptions regarding extension terms that allow for operational flexibility and future market conditions.

4. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair values of financial instruments

The Company has classified its cash and cash equivalents as assets at fair value through profit or loss and its derivative commodity contracts as financial liabilities at fair value through profit or loss. Both are measured at fair value with subsequent changes recognized through 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:

	March 31, 2019		December 31, 2018
	Carrying	Fair	Carrying	Fair
Classification ($000s)	Value	Value	Value	Value
Financial assets at fair value through profit or loss	24,735	24,735	53,074	53,074
Financial assets at amortized cost	34,363	34,363	12,014	12,014
Financial liabilities at fair value through profit or loss	3,405	3,405	—	—
Financial liabilities at amortized cost	73,388	74,164	80,362	81,228

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

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

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 12), 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 March 31, 2019, the fair values of which have been presented on the Condensed Consolidated Balance Sheet:

Financial Brent Crude Oil Contracts
Period Hedged	Contract	Remaining 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
Apr 2019 - Dec 2019	3-Way Collar	148,500	16,500	53.00	62.10	46.00
Apr 2019 - Dec 2019	3-Way Collar	149,998.5	16,666.5	54.00	61.35	46.00
Apr 2019 - Dec 2019	Bear Put Spread	148,500	16,500	53.00	—	46.00
Apr 2019 - Dec 2019	Bear Put Spread	149,998.5	16,666.5	54.00	—	46.00

Q1-2019 23

The gains and losses on financial instruments for the three months ended March 31, 2019 and 2018 comprised the following:

	Three Months Ended March 31
($000s)	2019		2018
Realized derivative loss on commodity contracts settled during the period	$	222	$	118
Unrealized derivative loss on commodity contracts outstanding at period end	4,774		6,046
	$	4,996	$	6,164

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	March 31, 2019		December 31, 2018
Neither impaired nor past due	$	30,978	$	5,540
Not impaired and past due in the following period:
Within 30 days	112		829
31-60 days	18		212
61-90 days	55		102
Over 90 days	3,200		5,331
	$	34,363	$	12,014

The Company sold one crude cargo during the three months ended March 31, 2019 for net proceeds of $25.4 million (fully collected in April 2019). Depending on the Company's assessment of the credit of crude cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. The Company collected $5.3 million of accounts receivable from EGPC during the first three months of 2019. As at March 31, 2019, $2.4 million (December 31, 2018 - $7.2 million) of the total accounts receivable balance of $34.4 million (December 31, 2018 - $12.0 million) is due from EGPC.

5. FINANCE COSTS

Finance costs recognized in net loss were as follows:

	Three Months Ended March 31
($000s)	2019			2018
Interest on long-term debt	$	883		$	1,140
Interest on borrowing base facility	108			110
Amortization of deferred financing costs	90			98
Interest on lease obligations	60			—
Finance costs	$	1,141		$	1,348
Interest paid	$	(995	)	$	(1,248	)

6. CASH AND CASH EQUIVALENTS

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

($000s)	March 31, 2019		December 31, 2018
Cash	$	8,235	$	33,893
Cash equivalents	16,500		17,812
	$	24,735	$	51,705

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

24 Q1-2019

7. 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.

As at March 31, 2019, the Company held 647.0 mbbls of entitlement oil in inventory valued at approximately $16.56 per barrel (December 31, 2018 - 568.1 mbbls valued at approximately $15.30 per barrel). During Q1-2019, $2.0 million was capitalized (Q1-2018 - $3.7 million) to reflect the cost of crude oil inventoried during the period.

8. INTANGIBLE EXPLORATION AND EVALUATIONASSETS

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

($000s)
Balance at December 31, 2018	$	36,266
Impairment loss	(8,391		)
Transfer of materials	(4,146		)
Balance at March 31, 2019	$	23,729

Subsequent to the quarter, the Company was unsuccessful in its attempts to secure military approval to access its desired drilling location in South Alamein. Based on the 2017 well results in the Boraq area, the limited commerciality of the original Boraq 2 discovery (2009) and continued access restrictions in the eastern area of the concession, the Company is exploring a variety of extension options with EGPC including partial, or possibly complete, relinquishment of the concession. In light of the high risk nature of the upside potential of the remaining concession area and restricted access issues, the Company fully impaired the remaining carrying value of the South Alamein intangible assets ($8.4 million) in Q1-2019. The Company will continue to negotiate access to the western portion of this concession. As at March 31, 2019, the recoverable amount of the South Alamein cash-generating unit is $nil.

The ending balance of intangible exploration and evaluation assets as at March 31, 2019 includes $nil in South Alamein (December 31, 2018 - $12.5 million), $23.2 million in South Ghazalat (December 31, 2018 - $23.2 million), and $0.5 million in Canada (December 31, 2018 - $0.5 million).

9. PROPERTY AND EQUIPMENT

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

($000s)
Cost	PNG Assets		Other Assets		Total
Balance at December 31, 2018	$	679,905	$	16,111	$	696,016
Increase in right-of-use assets (Note 3)	1,307		2,082		3,389
Additions	8,547		—		8,547
Transfer of materials	4,146		—		4,146
Changes in estimate for asset retirement obligations	392		—		392
Balance at March 31, 2019	$	694,297	$	18,193	$	712,490
Accumulated depletion, depreciation, amortization and impairment losses
Accumulated depletion, depreciation, amortization and impairment losses    at December 31, 2018	$	483,272	$	13,032	$	496,304
Depletion, depreciation and amortization for the period1	8,853		445		9,298
Balance at March 31, 2019	$	492,125	$	13,477	$	505,602
1  Depletion, depreciation and amortization for the period includes amounts capitalized to product inventory for barrels produced but not sold in the period.

Foreign exchange
Balance at December 31, 2018	$	(1,370	)	$	—	$	(1,370	)
Currency translation adjustments	$	1,128		$	—	$	1,128
Balance at March 31, 2019	$	(242	)	$	—	$	(242	)

Net book value
At December 31, 2018	$	195,263	$	3,079	$	198,342
At March 31, 2019	$	201,930	$	4,716	$	206,646

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

($000s)	PNG Assets	Other Assets	Total
Depreciation	224	213	437
Net Book Value at March 31, 2019	1,083	1,869	2,952

Q1-2019 25

10. ASSET RETIREMENT OBLIGATION

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

($000s)
Balance at December 31, 2018	$	12,113
Changes in estimates for asset retirement obligations and additional obligations recognized	392
Obligations settled	(30		)
Asset retirement obligation accretion	56
Effect of movements in foreign exchange rates	180
Balance at March 31, 2019	$	12,711

TransGlobe has estimated the net present value of its asset retirement obligation to be $12.7 million as at March 31, 2019 (December 31, 2018 - $12.1 million) based on a total undiscounted future liability of $16.9 million (December 31, 2018 - $17.5 million). These payments are expected to be made between 2020 and 2066. TransGlobe calculated the present value of the obligations using discount rates between 1.52% and 1.90% (December 31, 2018 - 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 (December 31, 2018 - 2%).

11. LEASE OBLIGATIONS

The following table reconciles TransGlobe's lease obligations:

($000s)	At March 31, 2019
Less than 1 year	$	1,979
1 - 3 years	1,510
Total lease payments	3,489
Amounts representing interest	440
Present value of net lease payments	3,049
Current portion of lease obligations	1,670
Non-current portion of lease obligations	$	1,379

During the three months ended March 31, 2019, the Company spent $0.1 million on interest expense and paid a total cash outflow of $0.4 million relating to lease obligations.

12. LONG-TERM DEBT

As at March 31, 2019, the significant interest-bearing loans and borrowings are comprised as follows:

($000s)	March 31, 2019		December 31, 2018
Prepayment agreement	$	39,224	$	44,134
Reserves-based lending facility1	8,463		8,221
Balance at March 31, 2019	$	47,687	$	52,355
1  As at March 31, 2019 and December 31, 2018, the Company had in place a revolving Canadian reserves-based lending facility totaling C$30.0 million ($22.4 million), of which C$11.3    million was drawn (December 31, 2018 - C$11.2 million).

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

($000s)
Balance at December 31, 2018	$	52,355
Draws on facility	121
Repayment of long-term debt	(5,000		)
Amortization of deferred financing costs	90
Effect of movements in foreign exchange rates	121
Balance at March 31, 2019	$	47,687

The Company's interest-bearing loans and borrowings are measured at amortized cost. As at March 31, 2019, the Company was in compliance with all debt covenants.

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

($000s)	Prepayment Agreement		Reserves Based Lending Facility		Total
2019	$	—	$	—	$	—
2020	—		—		—
2021	39,224		8,463		47,687
	$	39,224	$	8,463	$	47,687

26 Q1-2019

13. 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 Period 1,2
	Recognized
	in Financial	Contractual	Less than
	Statements	Cash Flows	1 year	1-3 years
Accounts payable and accrued liabilities	Yes - Liability	25,701	25,701	—
Other long-term liabilities	Yes - Liability	857	—	857
Financial derivative instruments	Yes - Liability	3,405	2,244	1,161
Equipment leases (short-term)3	No	1,128	1,128	—
Total		31,091	29,073	2,018
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at March 31, 2019 exchange rates.
3 Equipment leases include one drilling rig contract.

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. The Company met its financial and operating commitments and based on well results did not elect to enter the second exploration phase. The concession was relinquished on January 7, 2019.

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 March 31, 2019.

14. SHARE CAPITAL

Authorized

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

Issued

	Three Months Ended			Year Ended
	March 31, 2019			December 31, 2018
(000s)	Shares	Amount		Shares	Amount
Balance, beginning and end of period	72,206	$	152,084	72,206	$	152,084
Stock options exercised	337	547		—	—
Contributed surplus re-class on exercise	—	174		—	—
Balance, end of period	72,543	$	152,805	72,206	$	152,084

15. SHARE-BASED PAYMENTS

Stock options

The following table summarizes information about the stock options outstanding and exercisable at the dates indicated:

	Three Months Ended			Year ended
	March 31, 2019			December 31, 2018
			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 period	4,876		3.60	4,959		5.10
Granted	976		2.83	1,071		2.62
Exercised	(337	)	2.18	—		—
Expired	(323	)	4.99	(1,154	)	9.13
Options outstanding, end of period	5,192		3.46	4,876		3.60
Options exercisable, end of period	2,699		4.26	2,766		4.52

Q1-2019 27

Compensation expense of $0.1 million was recorded in general and administrative expenses in the Condensed Consolidated Interim Statements of Loss and Comprehensive Loss and Contributed Surplus during the three month period ended March 31, 2019 (March 31, 2018 - $0.1 million) for equity-settled share-based payment transactions. The fair value of all common stock options granted is estimated on the date of grant using the lattice-based trinomial option pricing model.

All options granted vest annually in equal installments over a three-year period and expire five years after the grant date. During the three month period ended March 31, 2019 employees exercised 337 thousand stock options (2018 - nil). The fair value related to these options was $0.5 million at the time of grant and has been transferred from contributed surplus to share capital. As at March 31, 2019 and December 31, 2018, the entire balance in contributed surplus related to previously recognized share-based compensation expense on equity-settled stock options.

Restricted share unit (RSU), performance share unit (PSU) and deferred share unit (DSU) plans

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

	Restricted		Performance		Deferred
	Share		Share		Share
(000s)	Units		Units		Units
Units outstanding, beginning of period	864		1,683		828
Granted	335		520		—
Vested / released	(28	)	(154	)	(231	)
Forfeited	(19	)	—		—
Expired	(15	)	—		—
Units outstanding, end of period	1,137		2,049		597

During the three month period ended March 31, 2019, compensation expense of $0.8 million (March 31, 2018 - $0.1 million) was recorded in general and administrative expenses in net loss for share units granted under the three plans described above. 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 in the Condensed Consolidated Interim Balance Sheet. Until the liability is ultimately settled, it is re-measured at each reporting date with changes to fair value recognized in net loss.

16. PER SHARE AMOUNTS

The basic weighted-average number of common shares outstanding for the three months ended March 31, 2019 was 72,426,839 (March 31, 2018 - 72,205,369). The diluted weighted-average number of common shares outstanding for the three months ended March 31, 2019 was 72,693,773 (March 31, 2018 - 72,205,369). These outstanding share amounts were used to calculate net loss per share in the respective periods.

In determining diluted net 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 period ended March 31, 2019, the Company excluded 3,364,284 stock options (March 31, 2018 – 3,804,553) as their exercise price was greater than the average common share market price in the period.

17. DIVIDENDS

The Company declared a dividend of $0.035 per share paid on April 18, 2019 to shareholders of record on March 29, 2019.

18. SEGMENTED INFORMATION

The Company has two reportable operating segments for the three months ended March 31, 2019 and 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.

28 Q1-2019

	Egypt						Canada						Corporate						Total
	Three Months Ended						Three Months Ended						Three Months Ended						Three Months Ended
	March 31						March 31						March 31						March 31
($000s)	2019			2018			2019			2018			2019			2018			2019			2018
Revenue
Oil sales	$	62,980		$	46,302		$	3,905		$	3,472		$	—		$	—		$	66,885		$	49,774
Natural gas sales	—			—			987			947			—			—			987			947
Natural gas liquids sales	—			—			1,345			2,230			—			—			1,345			2,230
Less: Royalties	(30,987		)	(26,971		)	(878		)	(1,265		)	—			—			(31,865		)	(28,236		)
Petroleum and natural gas sales, net of royalties	31,993			19,331			5,359			5,384			—			—			37,352			24,715
Finance revenue	25			23			—			—			158			70			183			93
Total segmented revenue	32,018			19,354			5,359			5,384			158			70			37,535			24,808
Segmented expenses
Production and operating	9,771			8,462			1,762			2,179			—			—			11,533			10,641
Selling costs	475			46			—			—			—			—			475			46
General and administrative	1,597			1,281			210			300			3,060			2,415			4,867			3,996
Foreign exchange (gain) loss	—			—			—			—			(87		)	(3		)	(87		)	(3		)
Finance costs	1,019			1,223			115			125			7			—			1,141			1,348
Depletion, depreciation and amortization	6,659			4,544			1,908			2,226			199			78			8,766			6,848
Asset retirement obligation accretion	—			—			56			67			—			—			56			67
Loss on financial instruments	4,996			5,909			—			255			—			—			4,996			6,164
Impairment loss	8,391			—			—			—			—			—			8,391			—
Gain on disposition of assets	—			—			—			(198		)	—			—			—			(198		)
Income tax expense	6,203			6,019			—			—			—			—			6,203			6,019
Segmented net earnings (loss)	$	(7,093	)	$	(8,130	)	$	1,308		$	430		$	(3,021	)	$	(2,420	)	$	(8,806	)	$	(10,120	)
Capital expenditures
Exploration and development	$	7,972		$	4,352		$	575		$	275		$	—		$	—		$	8,547		$	4,627
Corporate	—			—			—			—			—			8			—			8
Total capital expenditures	$	7,972		$	4,352		$	575		$	275		$	—		$	8		$	8,547		$	4,635

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

	At March 31, 2019						At December 31, 2018
($000s)	Egypt		Canada		Total		Egypt		Canada		Total
Assets
Accounts receivable	$	29,935	$	3,975	$	33,910	$	9,031	$	2,525	$	11,556
Derivative commodity contracts	—		—		—		1,369		—		1,369
Intangible exploration and evaluation assets	23,198		531		23,729		35,735		531		36,266
Property and equipment
Petroleum and natural gas assets	129,012		72,918		201,930		123,043		72,220		195,263
Other assets	2,961		18		2,979		2,222		22		2,244
Other	32,250		875		33,125		58,518		1,296		59,814
Deferred taxes	4,523		—		4,523		4,523		—		4,523
Segmented assets	221,879		78,317		300,196		234,441		76,594		311,035
Non-segmented assets					7,917						7,261
Total assets					$	308,113					$	318,296
Liabilities
Accounts payable and accrued liabilities	$	15,494	$	2,424	$	17,918	$	13,407	$	8,010	$	21,417
Derivative commodity contracts	3,405		—		3,405		—		—		—
Long-term debt	39,224		8,463		47,687		44,134		8,221		52,355
Asset retirement obligation	—		12,711		12,711		—		12,113		12,113
Lease obligations	639		453		1,092		—		—		—
Deferred taxes	4,523		—		4,523		4,523		—		4,523
Segmented liabilities	63,285		24,051		87,336		62,064		28,344		90,408
Non-segmented liabilities					10,597						7,597
Total liabilities					$	97,933					$	98,005

Q1-2019 29

19. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended March 31
($000s)	2019			2018
Operating Activities
(Increase) decrease in current assets:
Accounts receivable	$	(22,349	)	$	(5,161	)
Prepaids and other	1,738			2,149
Product inventory	(1,491		)	(2,398		)
(Decrease) increase in current liabilities:
Accounts payable and accrued liabilities	(6,174		)	(5,668		)
Other long-term liabilities	50			—
	$	(28,226	)	$	(11,078	)

Investing Activities
Increase in current assets:
Prepaids and other	$	(29	)	$	(3	)
Increase in current liabilities:
Accounts payable and accrued liabilities	562			(791		)
	$	533		$	(794	)

Financing Activities
Decrease in current liabilities:
Other long-term liabilities	$	(200	)	$	—
	$	(200	)	$	—

30 Q1-2019

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

www.trans-globe.com

TSX & AIM: TGL NASDAQ: TGA

Q1-2019 31