2019 SECOND QUARTER INTERIM REPORT

Financial and Operating Results

For the three and six months ended June 30, 2019

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

u Second quarter production averaged 16,940 boe/d (Egypt 14,663 bbls/d, Canada 2,277 boe/d), an increase of 1,016 boe/d (6%) over the previous quarter, and sales averaged 15,973 boe/d. Production in July averaged 16,788 boe/d (Egypt 14,613 bbls/d, Canada 2,175 boe/d);

u Production for the six months endedJune 30, 2019 averaged 16,436 boe/d (Egypt 14,143 bbls/d, Canada 2,293 boe/d), which was above guidance and 17% higher than the same period in 2018;

u Guidance for 2019 production was increased by 1,000 boe/d (7%), and is now expected to range between 15,000 and 16,000 boe/d for full-year 2019 (mid-point of 15,500 boe/d);

u Positivesecond quarter funds flow of $19.1 million ($0.26 per share). Second quarter net earnings of $10.0 million ($0.14 per share);

u Ended the second quarter with positive working capital of $54.1 million, including cash and cash equivalents of $34.1 million;

u Drilled two development oil wells in Egypt (H-30 and K-63);

u Drilled two exploration wells in Egypt, resulting in one oil discovery (HW-2X) and one cased potential oil well (NWG 38 D-1);

u Relinquished the South Alamein concession which had been fully impaired in Q1-2019;

u Received approval for the South Ghazalat development lease from EGPC and the Ministry of Petroleum, targeting first oil of approximately 1,000 bbls/day prior to year end 2019;

u Paid a dividend of $0.035 per share on April 18, 2019 to shareholders of record on March 29, 2019;

u Subsequent to the quarter, the Company declared a dividend of $0.035 per share, payable September 13, 2019 to shareholders of record on August 30, 2019.

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 19
Notes to Condensed Consolidated Interim Financial Statements	Page 23

2 Q2-2019

FINANCIAL AND OPERATING RESULTS

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

	Three Months Ended June 30						Six Months Ended June 30
Financial	2019		2018		% change		2019		2018		% change
Petroleum and natural gas sales	81,123		99,220		(18	)	150,340		152,171		(1	)
Petroleum and natural gas sales, net of royalties	43,071		68,454		(37	)	80,423		93,169		(14	)
Realized derivative loss on commodity contracts	(707	)	(5,781	)	88		(929	)	(5,899	)	84
Unrealized derivative gain (loss) on commodity contracts	1,773		(10,816	)	116		(3,001	)	(16,862	)	82
Production and operating expense	12,410		17,299		(28	)	23,943		27,940		(14	)
Selling costs	98		1,080		(91	)	573		1,126		(49	)
General and administrative expense	3,774		7,583		(50	)	8,641		11,579		(25	)
Depletion, depreciation and amortization expense	9,245		10,478		(12	)	18,011		17,326		4
Income tax expense	7,476		6,785		10		13,679		12,804		7
Cash flow generated by operating activities	22,125		18,886		17		9,054		11,731		(23	)
Funds flow from operations1	19,116		33,499		(43	)	34,271		37,422		(8	)
Basic per share	0.26		0.46				0.47		0.52
Diluted per share	0.26		0.46				0.47		0.52
Net earnings (loss)	10,046		7,361		36		1,240		(2,759	)	145
Basic per share	0.14		0.10				0.02		(0.04	)
Diluted per share	0.14		0.10				0.02		(0.04	)
Capital expenditures	8,097		5,855		38		16,644		10,490		59
Dividends paid	2,539		—		—		2,539		—		—
Dividends paid per share	0.035		—		—		0.035		—		—
Working capital	54,078		60,464		(11	)	54,078		60,464		(11	)
Long-term debt, including current portion	48,109		62,173		(23	)	48,109		62,173		(23	)
Common shares outstanding
Basic (weighted average)	72,542		72,206		—		72,485		72,206		—
Diluted (weighted average)	72,548		72,851		—		72,629		72,206		1
Total assets	315,999		329,542		(4	)	315,999		329,542		(4	)
Operating
Average production volumes (boe/d)	16,940		13,779		23		16,436		14,076		17
Average sales volumes (boe/d)	15,973		19,301		(17	)	15,513		15,548		—
Inventory (mbbls)	735.0		510.2		44		735.0		510.2		44
Average price ($ per boe)	55.81		56.49		(1	)	53.54		54.07		(1	)
Operating expense ($ per boe)	8.54		9.85		(13	)	8.53		9.93		(14	)
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".

Q2-2019 3

CORPORATE SUMMARY

TransGlobe Energy Corporation ("TransGlobe" or the "Company") produced an average of 16,940 barrels of oil equivalent per day ("boe/d") during the second quarter of 2019. Egypt production was 14,663 barrels of oil per day ("bbls/d") and Canada production was 2,277 boe/d. Production for the quarter was 6% higher than the previous quarter.

TransGlobe's Egyptian crude oil is sold at a quality discount to Dated Brent. The Company received an average price of $60.58 per barrel in Egypt during the quarter. In Canada, the Company received an average of $55.35 per barrel of oil and $0.89 per thousand cubic feet ("mcf") of natural gas during the quarter.

During the quarter, the Company had funds flow from operations of $19.1 million and ended the quarter with positive working capital of $54.1 million, including cash and cash equivalents of $34.1 million. The Company had net earnings in the quarter of $10.0 million, including a $1.8 million unrealized derivative gain on commodity contracts which represents a fair value adjustment on the Company's hedging contracts as at June 30, 2019.

In Egypt, the Company sold 489.1 thousand barrels ("mbbls") of entitlement crude oil during the quarter and had 735.0 mbbls of entitlement crude oil inventory at June 30, 2019. The increase in inventoried crude oil is attributed to higher oil production than forecasted in the first half of 2019 due to successful drilling and well workover results. All Canadian production was sold during the quarter.

The Company continued its negotiations in Egypt with the government to amend, extend and consolidate its Eastern Desert operations.

In the Eastern Desert, the Company drilled two development wells during the quarter at West Bakr. The H-30 development well was drilled to a total depth of 1,655 meters (5,454 feet) and completed as a Yusr oil well. The well was placed on production at an initial field estimated rate of 70 bbls/d and is currently being optimized. The K-63 development well was drilled to a total depth of 1,445 meters (4,741 feet) and completed as an Asl oil well. The K-63 well was placed on production at an initial field estimated rate of 475 bbls/d.

In the Eastern Desert, the Company also drilled two exploration wells during the quarter. At West Bakr, the HW-2X exploration well was drilled to a total depth of 1,654 meters (5,425 feet) and was cased as a Yusr oil discovery. The well was completed and placed on production at a field estimated rate of 715 bbls/d. At North West Gharib, The NWG 38 D-1 exploration well was drilled to a total depth of 1,697 meters (5,570 feet) and cased as a potential Red Bed oil well. The well is scheduled for completion subsequent to the quarter.

In the Western Desert, the development lease and plan for the South Ghazalat SGZ 6X oil discovery were approved by EGPC and the Ministry of Petroleum. The Company is targeting first production from this concession prior to year end. In addition, the Company relinquished the South Alamein exploration concession during the quarter. The carrying value of the South Alamein intangible asset was fully impaired in Q1-2019.

In Canada, the Company finalized the 2019 drilling plan to commence Q3-2019. The drilling plan consists of three development wells drilled from existing pads, and one exploratory out-post well to appraise the land acquired south of Harmattan in 2018.

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

4 Q2-2019

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 second quarter of 2019, the Company drilled two development oil wells in the Eastern Desert at West Bakr. The H-30 development well was drilled to a total depth of 1,655 meters (5,454 feet) and completed as a Yusr oil well. The well was placed on production at a field estimated rate of 70 bbls/d and is currently being optimized. The K-63 development well was drilled to a total depth of 1,445 meters (4,741 feet). The well was completed in the main Asl A formation and placed on production at a field estimated rate of 475 bbls/d.

During the second quarter of 2019, the Company drilled two exploration wells in the Eastern Desert. At West Bakr, the HW-2X exploration well was drilled to a total depth of 1,654 meters (5,425 feet). The well was an oil discovery that was completed and placed on production at a field estimated rate of 715 bbls/d. At North West Gharib, The NWG 38 D-1 exploration well was drilled to a total depth of 1,697 meters (5,570 feet) and cased as a potential Red Bed oil well. The well is scheduled for completion subsequent to the quarter.

The K Station Phase 3 project to increase gross fluid handling capacity from 30,000 barrels per day to 45,000 barrels per day is in progress with completion expected during the second half of 2019.

Production

Production averaged 14,663 bbls/d during the quarter, an increase of 8% (1,047 bbls/d) from the previous quarter, primarily due to the three new wells drilled and placed on production in West Bakr, in addition to successful well optimization projects in West Bakr.

Production in July averaged 14,613 bbls/d.

Sales

The Company sold 489.1 mbbls of inventoried entitlement crude oil to EGPC for $29.1 million during the quarter.

Quarterly Eastern Desert Production (bbls/d)	2019				2018
	Q-2		Q-1		Q-4		Q-3
Gross production rate1	14,663		13,616		12,970		11,939
TransGlobe production (inventoried) sold	(967	)	(877	)	(787	)	159
Total sales	13,696		12,739		12,183		12,098
Government share (royalties and tax)	8,320		7,711		7,292		6,645
TransGlobe sales (after royalties and tax)2	5,376		5,028		4,891		5,453
Total sales	13,696		12,739		12,183		12,098
1  Quarterly production by concession (bbls/d): West Gharib - 4,256 (Q2-2019), 4,238 (Q1-2019), 4,512 (Q4-2018), and 4,793 (Q3-2018) West Bakr - 9,389 (Q2-2019), 8,132 (Q1-2019), 7,323 (Q4-2018), and 6,126 (Q3-2018) North West Gharib - 1,018 (Q2-2019), 1,246 (Q1-2019), 1,135 (Q4-2018), and 1,020 (Q3-2018)
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 and South Alamein (100% working interest, operated)

Operations and Exploration

At South Ghazalat, the development lease was approved by EGPC and the Ministry of Petroleum. The Company is targeting first production prior to year end. Concurrent with the rental 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 seismic re-processing project to improve imaging over the development lease area in preparation for future drilling. In addition to the planned appraisal well, the Company is committed to drill one additional exploration well.

At South Alamein, the Company relinquished the concession during the quarter. The carrying value of the intangible asset had been fully impaired in Q1-2019.

Q2-2019 5

CANADA

Operations and Exploration

During the quarter, the Company finalized the 2019 drilling plan, consisting of three 100% development wells to be drilled from existing pads, and one 100% exploration out-post well to be drilled on the lands acquired in 2018.

Production

In Canada, oil production averaged 788 bbls/d during the quarter, a decrease of 106 bbls/d (12%) from the previous quarter, primarily due to natural declines. Lower oil production was partially offset by workovers completed during the quarter, and total Q2-2019 production was 1% (31 boe/d) lower than the previous quarter.

Production averaged 2,175 boe/d in July with 725 bbls/d of oil.

Quarterly Canada Production (boe/d)	2019		2018
	Q-2	Q-1	Q-4	Q-3
Canada crude oil (bbls/d)	788	894	495	567
Canada NGLs (bbls/d)	533	470	829	876
Canada natural gas (mcf/d)	5,733	5,663	5,865	5,695
Total production (boe/d)	2,277	2,308	2,302	2,392

6 Q2-2019

MANAGEMENT'S DISCUSSION AND ANALYSIS

August 12, 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 and six months ended June 30, 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).

Q2-2019 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 June 30			Six Months Ended June 30
($000s)	2019		2018	2019	2018
Cash flow from operating activities	22,125		18,886	9,054	11,731
Changes in non-cash working capital	(3,009	)	14,613	25,217	25,691
Funds flow from operations1	19,116		33,499	34,271	37,422
1  Funds flow from operations does not include interest costs. Interest expense is included in financing costs on the Condensed Consolidated Interim Statements of Earnings (Loss) and Comprehensive Income (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 Q2-2019

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 now expected to range between 15,000 and 16,000 boe/d for full-year 2019 (mid-point of 15,500 boe/d) with a 94% weighting to oil and liquids which represents an increase of 1,000 boe/d (7%) from original guidance. Egypt oil production is expected to average in a range between 12,950 and 13,750 bbls/d in 2019. Canadian production is expected to range between 2,050 and 2,250 boe/d in 2019, which includes 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 July) has averaged ~16,500 boe/d, which is ~1,500 boe/d (10%) above the upper range of the original guidance for the year. The current increased production against plan is primarily due to the majority of 2019 drilling activity having taken place in Q1/Q2 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 which is targeting first production prior to year end. The Company continues to pursue negotiations with the Egyptian government to amend, extend and consolidate its Eastern Desert operations

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 guidance of funds flow from operations for 2019. Funds flow from operations and inventory levels in Egypt may fluctuate significantly from quarter to quarter due to the timing of crude oil sales.

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		1.34	1.53	1.72
Netback ($/boe)
Egypt - crude oil1	1.86		6.01		10.15	14.29	17.51
Canada - crude oil2	19.84		27.84		35.56	43.37	51.19
Canada - natural gas and NGLs2	(1.82	)	(0.79	)	0.24	1.76	3.26
1 Egypt assumptions: using anticipated 2019 Egypt production profile, Gharib Blend 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 $C8.00 per bbl, Edmonton Light to Harmattan discount of $C2.50 per    bbl, operating costs estimated at ~$C12.25/boe, NGL mixture price at 45% of Edmonton Light, and takes into consideration Canadian tax pools.

Q2-2019 9

SELECTED QUARTERLY FINANCIAL INFORMATION

($000s, except per share, price and volumes amounts)

	2019				2018						2017
	Q-2		Q-1		Q-4	Q-3		Q-2	Q-1		Q-4		Q-3
Operations
Average production volumes
Crude oil (bbls/d)	15,451		14,510		13,463	12,506		12,409	12,452		12,027		12,786
NGLs (bbls/d)	533		470		829	876		521	894		915		1,081
Natural gas (mcf/d)	5,733		5,663		5,865	5,695		5,094	6,176		6,059		6,268
Total (boe/d)	16,940		15,924		15,270	14,331		13,779	14,375		13,952		14,912
Average sales volumes
Crude oil (bbls/d)	14,484		13,633		12,676	12,665		17,931	9,830		14,324		15,894
NGLs (bbls/d)	533		470		829	876		521	894		915		1,081
Natural gas (mcf/d)	5,733		5,663		5,865	5,695		5,094	6,176		6,059		6,286
Total (boe/d)	15,973		15,047		14,483	14,490		19,301	11,753		16,249		18,020
Average realized sales prices
Crude oil ($/bbl)	60.29		54.51		60.12	61.79		59.39	56.26		53.25		44.82
NGLs ($/bbl)	24.55		31.80		24.39	22.64		38.39	27.72		26.86		18.90
Natural gas ($/mcf)	0.89		1.94		1.22	1.01		1.08	1.70		0.94		1.65
Total oil equivalent ($/boe)	55.81		51.11		54.51	55.77		56.49	50.06		48.80		41.24
Inventory (mbbls)	735.0		647.0		568.1	495.6		510.3	1,012.7		776.8		988.1
Petroleum and natural gas sales	81,123		69,217		72,628	74,345		99,220	52,951		72,954		68,372
Petroleum and natural gas sales, net of royalties	43,071		37,352		40,605	42,453		68,454	24,715		40,725		44,839
Cash flow generated by (used in) operating activities	22,125		(13,071	)	9,822	47,639		18,886	(7,155	)	44,263		20,437
Funds flow from operations1	19,116		15,155		8,842	17,018		33,499	3,923		17,018		19,217
Funds flow from operations per share:
Basic	0.26		0.21		0.12	0.24		0.46	0.05		0.24		0.27
Diluted	0.26		0.21		0.12	0.23		0.46	0.05		0.24		0.27
Net earnings (loss)	10,046		(8,806	)	30,719	(12,283	)	7,361	(10,120	)	(2,382	)	(6,855	)
Net earnings (loss) per share:
Basic	0.14		(0.12	)	0.43	(0.17	)	0.10	(0.14	)	(0.03	)	(0.09	)
Diluted	0.14		(0.12	)	0.43	(0.17	)	0.10	(0.14	)	(0.03	)	(0.09	)
Capital expenditures	8,097		8,547		17,433	12,783		5,855	4,635		9,078		10,133
Dividends declared	—		2,539		—	2,527		—	—		—		—
Dividends declared per share	—		0.035		—	0.035		—	—		—		—
Total assets	315,999		308,113		318,296	314,203		329,542	312,691		327,702		338,802
Cash and cash equivalents	34,125		24,735		51,705	62,663		38,088	31,084		47,449		21,464
Working capital	54,078		43,600		50,987	52,351		60,464	45,252		50,639		58,815
Total long-term debt, including current portion	48,109		47,687		52,355	52,532		62,173	67,167		69,999		79,839
Net debt-to-funds flow from operations ratio2	(0.10	)	0.05		0.02	0.00		0.02	0.36		0.35		0.70
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 second quarter of 2019, TransGlobe:

• Increased production volumes by 23% compared to Q2-2018 primarily due to new wells in both Egypt and Canada, and higher comparative production in Canada attributable to a turnaround in Q2-2018 that shut in production for a three-week period;

• Sold 489.1 mbbls of entitlement crude oil in the second quarter and ended Q2-2019 with crude oil inventory of 735.0 mbbls, an increase of 166.9 mbbls from crude inventory levels at December 31, 2018;

• Reported positive funds flow from operations of $19.1 million;

• Ended Q2-2019 with positive working capital of $54.1 million, including $34.1 million in cash and cash equivalents;

• Reported net earnings of $10.0 million;

• Spent $8.1 million on capital expenditures;

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

10 Q2-2019

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-2	Q-1	Q-4	Q-3	Q-2
Crude oil
Dated Brent average oil price (US$/bbl)	68.92	63.17	67.71	75.22	74.50
Edmonton Sweet index (US$/bbl)	55.17	49.96	32.51	62.68	62.43
Natural gas
AECO (C$/mmbtu)	1.11	2.62	1.56	1.18	1.18
US/Canadian Dollar average exchange rate	1.34	1.33	1.32	1.30	1.29

In Q2-2019, the average price of Dated Brent oil was 7% lower and 9% higher than Q2-2018 and Q1-2019, 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 85% 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 Gharib Blend/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.

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.

In the second quarter of 2019, the average price of Edmonton Sweet index oil (expressed in USD) was 12% lower and 10% higher than Q2-2018 and Q1-2019, respectively. In Q2-2019, the average price of AECO natural gas was 6% and 58% lower than Q2-2018 and Q1-2019 respectively.

OPERATING RESULTS AND NETBACK

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

Production Volumes	Three Months Ended June 30		Six Months Ended June 30
	2019	2018	2019	2018
Egypt crude oil (bbls/d)	14,663	11,912	14,143	11,845
Canada crude oil (bbls/d)	788	497	841	585
Canada NGLs (bbls/d)	533	521	502	707
Canada natural gas (mcf/d)	5,733	5,094	5,698	5,632
Total Company (boe/d)	16,940	13,779	16,436	14,076

Sales Volumes (excludes volumes held as inventory)	Three Months Ended June 30		Six Months Ended June 30
	2019	2018	2019	2018
Egypt crude oil (bbls/d)	13,696	17,434	13,220	13,317
Canada crude oil (bbls/d)	788	497	841	585
Canada NGLs (bbls/d)	533	521	502	707
Canada natural gas (mcf/d)	5,733	5,094	5,698	5,632
Total Company (boe/d)	15,973	19,301	15,513	15,548

Q2-2019 11

Netback

Consolidated Netback	Three Months Ended June 30
	2019		2018
($000s, except per boe amounts)1	$	$/boe	$	$/boe
Petroleum and natural gas sales	81,123	55.81	99,220	56.49
Royalties and other2	38,052	26.18	30,766	17.52
Current taxes2	7,476	5.14	6,785	3.86
Production and operating expenses	12,410	8.54	17,299	9.85
Selling costs	98	0.07	1,080	0.61
Netback	23,087	15.88	43,290	24.65
1  The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended June 30, 2019 and June 30, 2018 (these figures do not include TransGlobe's Egypt     entitlement crude oil held as inventory at June 30, 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 oil.

Consolidated Netback	Six Months Ended June 30
	2019		2018
($000s, except per boe amounts)1	$	$/boe	$	$/boe
Petroleum and natural gas sales	150,340	53.54	152,171	54.07
Royalties and other2	69,917	24.90	59,002	20.97
Current taxes2	13,679	4.87	12,804	4.55
Production and operating expenses	23,943	8.53	27,940	9.93
Selling costs	573	0.20	1,126	0.40
Netback	42,228	15.04	51,299	18.22
1  The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended June 30, 2019 and June 30, 2018 (these figures do not include TransGlobe's Egypt     entitlement crude oil held as inventory at June 30, 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 oil.

Egypt	Three Months Ended June 30
	2019		2018
($000s, except per bbl amounts)1	$	$/bbl	$	$/bbl
Oil sales	75,498	60.58	94,147	59.34
Royalties and other2	37,807	30.33	30,375	19.15
Current taxes2	7,476	6.00	6,785	4.28
Production and operating expenses	10,411	8.35	15,205	9.58
Selling costs	98	0.08	1,080	0.68
Netback	19,706	15.82	40,702	25.65
1  The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended June 30, 2019 and June 30, 2018 (these figures do not include TransGlobe's Egypt    entitlement crude oil held as inventory at June 30, 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 oil.

Egypt	Six Months Ended June 30
	2019		2018
($000s, except per bbl amounts)1	$	$/bbl	$	$/bbl
Oil sales	138,478	57.87	140,449	58.27
Royalties and other2	68,794	28.75	57,346	23.79
Current taxes2	13,679	5.72	12,804	5.31
Production and operating expenses	20,182	8.43	23,667	9.82
Selling costs	573	0.24	1,126	0.47
Netback	35,250	14.73	45,506	18.88
1  The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended June 30, 2019 and June 30, 2018 (these figures do not include TransGlobe's Egypt     entitlement crude oil held as inventory at June 30, 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 oil.

Netbacks per bbl in Egypt decreased by 38% and 22%, respectively, for the three and six months endedJune 30, 2019 compared with the same periods in 2018. The decrease was primarily due to higher production volumes, 23% ($8.1 million) and 19% ($12.3 million), respectively, without a corresponding increase in sales volumes. Royalties and taxes are settled on a production basis, therefore netback is reduced in periods where production increases and when production is higher than sales. The decrease is partially offset by lower production and operating expenses per barrel (13% and 14%, respectively) due to a build in inventory compared to the prior period.

Royalties and taxes as a percentage of revenue were 60% in both the three and six months endedJune 30, 2019, compared to 39% and 50% in the same periods in 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 and six months endedJune 30, 2019, royalties and taxes as a percentage of revenue would have been both 56% (2018 - 58% and 56%). 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. 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.

12 Q2-2019

The average selling price was $60.58 and $57.87, respectively, during the three and six months endedJune 30, 2019 which represents an increase of 2% and a decrease of 1% compared to the same periods in 2018. The difference between the average selling price and the Dated Brent price is due to a gravity/quality adjustment and is also impacted by the specific timing of direct sales.

In Egypt, production and operating expenses fluctuate periodically due to changes in inventory volumes as a portion of costs are capitalized and expensed when sold. Production and operating expenses decreased by 32% ($4.8 million) and 15% ($3.5 million), respectively, in the three and six months endedJune 30, 2019 compared with the same periods in 2018. The decrease was primarily related to a build in crude oil inventory ($6.3 million and $5.3 million, respectively), lower workover costs ($0.6 million and $0.7 million, respectively), and the impact of the adoption of IFRS 16 ($0.2 million and $0.4 million, respectively). This is partially offset by higher service and fuel costs ($2.3 million and $2.9 million, respectively) due to higher production and stronger oil prices.

Canada	Three Months Ended June 30
	2019		2018
($000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	3,970	55.35	2,753	60.87
Natural gas sales	463	5.32	500	6.47
NGL sales	1,192	24.55	1,820	38.39
Total sales	5,625	27.15	5,073	29.86
Royalties	245	1.18	391	2.30
Production and operating expenses	1,999	9.65	2,094	12.31
Netback	3,381	16.32	2,588	15.25

Canada	Six Months Ended June 30
	2019		2018
($000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	7,875	51.75	6,225	58.79
Natural gas sales	1,450	8.44	1,447	8.52
NGL sales	2,537	27.92	4,050	31.65
Total sales	11,862	28.59	11,722	29.03
Royalties	1,123	2.71	1,656	4.10
Production and operating expenses	3,761	9.06	4,273	10.58
Netback	6,978	16.82	5,793	14.35

Netbacks per boe in Canada increased by 7% and 17%, respectively, for the three and six months endedJune 30, 2019 compared with the same periods in 2018. The increase is mainly due to lower production and operating expenses (22% and 14%, respectively).

The average selling price was $27.15 and $28.59, respectively, during the three and six months endedJune 30, 2019 which represents a decrease of 9% and 2% compared to the same periods in 2018.

Royalties decreased by $0.1 million and $0.5 million, respectively, for the three and six months endedJune 30, 2019 compared to the same periods in 2018 primarily due to higher Gas Cost Allowance (GCA) rebates received in 2019. Royalties amounted to 4% and 9% of petroleum and natural gas sales revenue during the three and six months endedJune 30, 2019 compared to 8% and 14% during the comparative period.

The decrease in production and operating expenses is primarily attributed to the planned turn around in 2018, and certain costs being recorded as depletion, depreciation and amortization due to the adoption of IFRS 16.

GENERAL AND ADMINISTRATIVE EXPENSES ("G&A")

	Three Months Ended June 30
	2019				2018
($000s, except boe amounts)	$		$/boe		$		$/boe
G&A (gross)	3,642		2.51		4,461		2.54
Stock-based compensation	428		0.29		3,418		1.95
Capitalized G&A and overhead recoveries	(296	)	(0.20	)	(296	)	(0.17	)
G&A (net)	3,774		$2.60		7,583		$4.32

	Six Months Ended June 30
	2019				2018
($000s, except boe amounts)	$		$/boe		$		$/boe
G&A (gross)	7,877		2.81		8,484		3.01
Stock-based compensation	1,343		0.48		3,685		1.31
Capitalized G&A and overhead recoveries	(579	)	(0.21	)	(590	)	(0.21	)
G&A (net)	8,641		$3.08		11,579		$4.11

General and administrative (gross) decreased by 18% and 7%, respectively, for the three and six months endedJune 30, 2019 compared with the same periods in 2018. These decreases were primarily due to higher professional fees in the comparative period related to the 2018 AIM listing fees.

Q2-2019 13

Stock-based compensation decreased by 87% and 64% for the three and six months endedJune 30, 2019, respectively, compared with the same periods in 2018. These decreases were due to a decrease in Company's Q2-2019 share price and the associated revaluation of share units granted by the Company.

Capitalized G&A remained flat for the three and six months ended June 30, 2019 as compared to the same periods in 2018.

FINANCE COSTS

	Three Months Ended June 30		Six Months Ended June 30
($000s)	2019	2018	2019	2018
Interest on long-term debt	856	1,163	1,739	2,302
Interest on borrowing base facility	121	103	229	213
Amortization of deferred financing costs	90	87	180	186
Interest on lease obligations	73	—	133	—
Finance costs	1,140	1,353	2,281	2,701

Finance costs decreased by $0.2 million and $0.4 million, respectively, for the three and six months endedJune 30, 2019, compared to the same periods in 2018. These decreases were due to a lower balance of long-term debt, partially offset by higher borrowing costs due to an increase in LIBOR and ATB Prime, and additional interest from the adoption of IFRS 16.

As at June 30, 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 was outstanding. During the six months ended June 30, 2019, the Company made repayments of $5.0 million on this loan. Subsequent to the quarter, an additional $5.0 million was repaid on the prepayment agreement.

As at June 30, 2019, the Company had a revolving Canadian reserves-based lending facility with Alberta Treasury Branches ("ATB") totaling C$25.0 million ($19.1 million), of which C$11.5 million ($8.8 million) was outstanding.

The prepayment agreement and reserves-based lending facility are subject to certain covenants. The Company was in compliance with its covenants as at June 30, 2019.

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

	Three Months Ended June 30
	2019		2018
($000s, except per boe amounts)	$	$/boe	$	$/boe
Egypt	7,154	5.74	8,820	5.56
Canada	1,889	9.12	1,579	9.30
Corporate	202	—	79	—
Total	9,245	6.36	10,478	5.97

	Six Months Ended June 30
	2019		2018
($000s, except per boe amounts)	$	$/boe	$	$/boe
Egypt	13,813	5.77	13,364	5.54
Canada	3,797	9.15	3,805	9.42
Corporate	401	—	157	—
Total	18,011	6.41	17,326	6.16

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 three and six months endedJune 30, 2019, DD&A decreased by 19% ($1.7 million) and increased by 3% ($0.5 million) compared to the same periods in 2018. DD&A increased due to higher production ($1.4 million and $2.4 million, respectively) and additional depreciation from the adoption of IFRS 16 ($0.3 million and $0.5 million, respectively), and was offset by a build in inventory ($3.4 million and $2.4 million, respectively).

In Canada, DD&A increased by 20% ($0.3 million) and was flat, respectively, during the three and six months endedJune 30, 2019. During the three months ended June 30, 2019 DD&A was higher due to increased production in the quarter.

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.

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 relinquished the concession in the quarter. The Company had fully impaired the remaining carrying value of South Alamein ($8.4 million) in Q1-2019.

14 Q2-2019

CAPITAL EXPENDITURES

	Six Months Ended June 30
($000s)	2019	2018
Egypt	15,700	9,950
Canada	811	506
Corporate	133	34
Total	16,644	10,490

Capital expenditures in the first six months of 2019 were $16.6 million (2018 - $10.5 million).

In Egypt, the Company incurred $15.7 million in capital expenditures during the six months endedJune 30, 2019 (June 30, 2018 - $10.0 million) associated with drilling eight wells, performing twelve completions and workovers, and facility expansion.

In Canada, the Company incurred $0.8 million in capital expenditures during the six months endedJune 30, 2019 (June 30, 2018 - $0.5 million) associated with initial 2019 drilling costs and equipping and tying-in six Cardium oil wells that were drilled during 2018.

OUTSTANDING SHARE DATA

As at June 30, 2019, the Company had 72,542,071 common shares issued and outstanding and 4,480,935 stock options issued and outstanding, of which 2,585,572 are exercisable 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. As at June 30, 2019, the Company had a working capital surplus of $54.1 million (December 31, 2018 - surplus of $51.0 million). The increase in working capital in Q2-2019 is primarily due increasing accounts receivable in Egypt, and lower current liabilities in Canada.

As at June 30, 2019, the Company's cash equivalents balance consisted of short-term deposits with an original term to maturity at purchase of one month 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 June 30, 2019, amounts owing from EGPC were $22.6 million. The Company considers there to be minimal credit risk associated with amounts receivable from EGPC.

The Company sold 489.1 mbbls of entitlement crude oil to EGPC in June for net proceeds of $29.1 million. As at June 30, 2019 the Company had collected $6.9 million, subsequent to the quarter an additional $6.0 million has been collected. The Company 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 purchasers, they may be required to post irrevocable letters of credit to support the sale prior to the cargo lifting, which has significantly reduced the Company's credit risk profile. As at June 30, 2019, the Company held 735.0 mbbls of entitlement crude oil as inventory.

As at June 30, 2019, the Company had $94.1 million of revolving credit facilities with $48.8 million drawn and $45.3 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 was drawn. During the first six 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$25.0 million ($19.1 million), of which C$11.5 million ($8.8 million) was drawn. During the first six months of 2019, the Company had drawings of C$0.2 million ($0.1 million) on this facility. During the quarter, the ATB facility was renewed for C$25.0 million ($19.1 million). The reduction in the ATB facility is a result of lower forecasted commodity prices and the associated impact on the Canadian reserves value.

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.

Q2-2019 15

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. EGPC 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 June 30, 2019, the Company had 735.0 mbbls of entitlement crude oil stored as inventory, which represents approximately four months of entitlement oil production. Since the Company began directly marketing its oil on January 1, 2015, crude oil inventory levels have both increased and decreased from year to year. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows. Depending on the timing of sales and production during 2019, it is expected that 2019 year end inventory will be similar to 2018.

	Three Months Ended		Six Months Ended		Year ended
(000 bbls)	June 30, 2019		June 30, 2019		December 31, 2018
Product inventory, beginning of period	647.0		568.1		776.8
TransGlobe entitlement production	577.1		1,108.6		1,963.8
Crude oil sales	(489.1	)	(941.7	)	(2,172.5	)
Product inventory, end of period	735.0		735.0		568.1

Inventory reconciliation

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

	Six Months Ended	Year ended
	June 30, 2019	December 31, 2018
Production and operating expenses ($/bbls)	12.23	9.98
Depletion ($/bbls)	5.49	5.32
Unit cost of inventory ($/bbls)	17.72	15.3
Product inventory, end of period (mbbls)	735.0	568.1
Product inventory, end of period ($000)	13,022	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:

		Payment Due by Period 1,2
($000s)	Recognized in Financial Statements	Contractual Cash Flows	Less than 1 year	1-3 years
Accounts payable and accrued liabilities	Yes - Liability	19,531	19,531	—
Other long-term liabilities	Yes - Liability	364	—	364
Financial derivative instruments	Yes - Liability	1,633	1,321	312
Total		21,528	20,852	676
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at June 30, 2019 exchange rates.

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 in Q1-2019.

Pursuant to the approved South Ghazalat development lease, the Company is committed to drill one exploration well during the initial four year period of the 20 year development lease. The Company has issued a production guarantee in the amount of $1 million which will be released when the commitment well has been drilled.

In the normal course of its operations, the Company may be subject to litigation and claims. Although it is not possible to estimate the extent of

potential costs, if any, management believes that the ultimate resolution of such contingencies would not have a material adverse impact on the

results of operations, financial position or liquidity of the Company.

The Company is not aware of any material provisions or other contingent liabilities as at June 30, 2019.

ASSET RETIREMENT OBLIGATION

As at June 30, 2019, TransGlobe had an asset retirement obligation ("ARO") of $13.5 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 1.39% and 1.68% (December 31,

16 Q2-2019

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 crude oil 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 June 30, 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
Jul 2019 - Dec 2019	3-Way Collar	99,000	16,500	53.00	62.10	46.00
Jul 2019 - Dec 2019	3-Way Collar	99,999	16,666.5	54.00	61.35	46.00
Jul 2019 - Dec 2019	Bear Put Spread	99,000	16,500	53.00	—	46.00
Jul 2019 - Dec 2019	Bear Put Spread	99,999	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.

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.

Q2-2019 17

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 June 30, 2019 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

18 Q2-2019

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

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

		Three Months Ended				Six Months Ended
				June 30				June 30
	Notes	2019		2018		2019		2018
REVENUE
Petroleum and natural gas sales, net of royalties	18	43,071		68,454		80,423		93,169
Finance revenue		133		126		316		219
		43,204		68,580		80,739		93,388
EXPENSES
Production and operating		12,410		17,299		23,943		27,940
Selling costs		98		1,080		573		1,126
General and administrative		3,774		7,583		8,641		11,579
Foreign exchange loss (gain)		32		(18	)	(55	)	(21	)
Finance costs	5	1,140		1,353		2,281		2,701
Depletion, depreciation and amortization	9	9,245		10,478		18,011		17,326
Asset retirement obligation accretion	10	49		66		105		133
(Gain) loss on financial instruments	4	(1,066	)	16,597		3,930		22,761
Impairment loss	8	—		—		8,391		—
Gain on disposition of assets		—		(4	)	—		(202	)
		25,682		54,434		65,820		83,343
Net earnings before income taxes		17,522		14,146		14,919		10,045
Income tax expense – current		7,476		6,785		13,679		12,804
NET EARNINGS (LOSS) FOR THE PERIOD		10,046		7,361		1,240		(2,759	)
OTHER COMPREHENSIVE INCOME (LOSS)
Currency translation adjustments		1,119		(675	)	1,660		(1,679	)
COMPREHENSIVE INCOME (LOSS) FOR THE PERIOD		11,165		6,686		2,900		(4,438	)
Net earnings (loss) per share	16
Basic		0.14		0.10		0.02		(0.04	)
Diluted		0.14		0.10		0.02		(0.04	)

See accompanying notes to the Condensed Consolidated Interim Financial Statements

Q2-2019 19

Condensed Consolidated Interim Balance Sheets

(Unaudited - Expressed in thousands of US Dollars)

		As at	As at
	Notes	June 30, 2019	December 31, 2018
ASSETS
Current
Cash and cash equivalents	6	34,125	51,705
Accounts receivable	4	26,515	12,014
Derivative commodity contracts	4	—	1,198
Prepaids and other		2,848	5,385
Product inventory	7	13,022	8,692
		76,510	78,994
Non-Current
Derivative commodity contracts	4	—	171
Intangible exploration and evaluation assets	8	28,663	36,266
Property and equipment
Petroleum and natural gas assets	9	197,463	195,263
Other assets	9	4,659	3,079
Deferred taxes		8,704	4,523
		315,999	318,296
LIABILITIES
Current
Accounts payable and accrued liabilities		19,531	28,007
Derivative commodity contracts	4	1,321	—
Current portion of lease obligations	11	1,580	—
		22,432	28,007
Non-Current
Derivative commodity contracts	4	312	—
Long-term debt	12	48,109	52,355
Asset retirement obligation	10	13,491	12,113
Other long-term liabilities		364	1,007
Lease obligations	11	1,051	—
Deferred taxes		8,704	4,523
		94,463	98,005
SHAREHOLDERS’ EQUITY
Share capital	14	152,805	152,084
Accumulated other comprehensive income (loss)		721	(939	)
Contributed surplus		24,358	24,195
Retained earnings		43,652	44,951
		221,536	220,291
		315,999	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

20 Q2-2019

Condensed Consolidated Interim Statements of Changes in Shareholders’ Equity

(Unaudited - Expressed in thousands of US Dollars)

		Three Months Ended				Six Months Ended
				June 30				June 30
	Notes	2019		2018		2019		2018
Share Capital
Balance, beginning of period	14	152,805		152,084		152,084		152,084
Stock options exercised	14	—		—		547		—
Transfer from contributed surplus on exercise of options	14	—		—		174		—
Balance, end of period		152,805		152,084		152,805		152,084
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of period		(398	)	1,789		(939	)	2,793
Currency translation adjustment		1,119		(675	)	1,660		(1,679	)
Balance, end of period		721		1,114		721		1,114
Contributed Surplus
Balance, beginning of period		24,167		23,471		24,195		23,329
Share-based compensation expense	15	191		357		337		499
Transfer to share capital on exercise of options	14	—		—		(174	)	—
Balance, end of period		24,358		23,828		24,358		23,828
Retained Earnings
Balance, beginning of period		33,606		21,681		44,951		31,801
Net earnings (loss)		10,046		7,361		1,240		(2,759	)
Dividends	17	—		—		(2,539	)	—
Balance, end of period		43,652		29,042		43,652		29,042

See accompanying notes to the Condensed Consolidated Interim Financial Statements

Q2-2019 21

Condensed Consolidated Interim Statements of Cash Flows

(Unaudited - Expressed in thousands of US Dollars)

		Three Months Ended				Six Months Ended
				June 30				June 30
	Notes	2019		2018		2019		2018
OPERATING
Net earnings (loss)		10,046		7,361		1,240		(2,759	)
Adjustments for:
Depletion, depreciation and amortization	9	9,245		10,478		18,011		17,326
Asset retirement obligation accretion	10	49		66		105		133
Deferred lease inducement		—		(22	)	—		(45	)
Impairment loss	8	—		—		8,391		—
Share-based compensation	15	428		3,418		1,343		3,685
Finance costs	5	1,140		1,353		2,281		2,701
Unrealized loss (gain) on financial instruments	4	(1,773	)	10,816		3,001		16,862
Unrealized loss (gain) on foreign currency translation		(18	)	(7	)	(70	)	(22	)
Gain on asset dispositions		—		(4	)	—		(202	)
Asset retirement obligations settled	10	(1	)	40		(31	)	(257	)
Changes in non-cash working capital	19	3,009		(14,613	)	(25,217	)	(25,691	)
Net cash generated by operating activities		22,125		18,886		9,054		11,731
INVESTING
Additions to intangible exploration and evaluation assets	8	(788	)	(673	)	(788	)	(1,581	)
Additions to petroleum and natural gas assets	9	(6,877	)	(5,084	)	(15,424	)	(8,674	)
Additions to other assets	9	(432	)	(98	)	(432	)	(235	)
Proceeds from asset dispositions		—		4		—		202
Changes in non-cash working capital	19	(834	)	159		(301	)	(635	)
Net cash used in investing activities		(8,931	)	(5,692	)	(16,945	)	(10,923	)
FINANCING
Issue of common shares for cash	14	—		—		547		—
Interest paid	5	(986	)	(1,233	)	(1,981	)	(2,481	)
Increase in long-term debt	12	135		108		256		249
Payments on lease obligations	11	(491	)	—		(890	)	—
Repayments of long-term debt	12	—		(5,000	)	(5,000	)	(7,797	)
Dividends paid	17	(2,539	)	—		(2,539	)	—
Changes in non-cash working capital	19	—		—		(200	)	—
Net cash used in financing activities		(3,881	)	(6,125	)	(9,807	)	(10,029	)
Currency translation differences relating to cash and cash equivalents		77		(65	)	118		(140	)
NET INCREASE (DECREASE) IN CASH AND CASHEQUIVALENTS		9,390		7,004		(17,580	)	(9,361	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		24,735		31,084		51,705		47,449
CASH AND CASH EQUIVALENTS, END OF PERIOD		34,125		38,088		34,125		38,088

See accompanying notes to the Condensed Consolidated Interim Financial Statements

22 Q2-2019

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

As at June 30, 2019 and December 31, 2018 and for the three and six month periods ended June 30, 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 August 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:

Q2-2019 23

• 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:

	As at June 30, 2019		As at December 31, 2018
($000s)	Carrying	Fair	Carrying	Fair
Classification	Value	Value	Value	Value
Financial assets at fair value through profit or loss	34,125	34,125	53,074	53,074
Financial assets at amortized cost	26,515	26,515	12,014	12,014
Financial liabilities at fair value through profit or loss	1,633	1,633	—	—
Financial liabilities at amortized cost	67,640	68,325	80,362	81,228

Assets and liabilities as at June 30, 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 crude oil 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 June 30, 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
Jul 2019 - Dec 2019	3-Way Collar	99,000	16,500	53.00	62.10	46.00
Jul 2019 - Dec 2019	3-Way Collar	99,999	16,666.5	54.00	61.35	46.00
Jul 2019 - Dec 2019	Bear Put Spread	99,000	16,500	53.00	—	46.00
Jul 2019 - Dec 2019	Bear Put Spread	99,999	16,666.5	54.00	—	46.00

24 Q2-2019

The gains and losses on financial instruments for the three and six months ended June 30, 2019 and 2018 are comprised as follows:

	Three Months Ended			Six Months Ended
			June 30		June 30
($000s)	2019		2018	2019	2018
Realized derivative loss on commodity contracts settled during the period	707		5,781	929	5,899
Unrealized derivative (gain) loss on commodity contracts outstanding at period end	(1,773	)	10,816	3,001	16,862
(Gain) loss on financial instruments	(1,066	)	16,597	3,930	22,761

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)	As at June 30, 2019	As at December 31, 2018
Neither impaired nor past due	24,497	5,540
Not impaired and past due in the following period:
Within 30 days	88	829
31-60 days	23	212
61-90 days	917	102
Over 90 days	990	5,331
Accounts receivable	26,515	12,014

The Company did not complete any direct crude sale shipments to third-party buyers during the three months ended June 30, 2019. Depending on the Company's assessment of the credit of crude purchasers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. During the second quarter of 2019 the Company sold 489.1 mbbls of inventoried entitlement crude oil to EGPC for $29.1 million. The Company collected $6.9 million of accounts receivable from EGPC during the first six months of 2019. As at June 30, 2019, $22.6 million (December 31, 2018 - $7.2 million) of the total accounts receivable balance of $26.5 million (December 31, 2018 - $12.0 million) is due from EGPC. All accounts receivable are in good standing and collection is not considered to be at risk.

5. FINANCE COSTS

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

	Three Months Ended June 30				Six Months Ended June 30
($000s)	2019		2018		2019		2018
Interest on long-term debt	856		1,163		1,739		2,302
Interest on borrowing base facility	121		103		229		213
Amortization of deferred financing costs	90		87		180		186
Interest on lease obligations	73		—		133		—
Finance costs	1,140		1,353		2,281		2,701
Interest paid	(986	)	(1,233	)	(1,981	)	(2,481	)

6. CASH AND CASH EQUIVALENTS

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

($000s)	As at June 30, 2019	As at December 31, 2018
Cash	20,625	33,893
Cash equivalents	13,500	17,812
Cash and cash equivalents	34,125	51,705

As at June 30, 2019, the Company's cash equivalents balance consisted of short-term deposits with an original term to maturity at purchase of one month or less. All of the Company's cash and cash equivalents are on deposit with high credit-quality financial institutions.

Q2-2019 25

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 June 30, 2019, the Company held 735.0 mbbls of entitlement crude oil in inventory valued at approximately $17.72 per barrel (December 31, 2018 - 568.1 mbbls valued at approximately $15.30 per barrel).

8. INTANGIBLE EXPLORATION AND EVALUATIONASSETS

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

($000s)
Balance as at December 31, 2018	36,266
Additions	788
Impairment loss	(8,391	)
Balance as at June 30, 2019	28,663

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 relinquished the concession in the quarter. The Company had fully impaired the remaining carrying value of South Alamein ($8.4 million) in Q1-2019.

The ending balance of intangible exploration and evaluation assets as at June 30, 2019 includes, $28.1 million in South Ghazalat (December 31, 2018 - $23.2 million), $0.5 million in Canada (December 31, 2018 - $0.5 million), and $nil in South Alamein (December 31, 2018 - $12.5 million).

9. PROPERTY AND EQUIPMENT

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

($000s)
Cost	Petroleum and Natural Gas Assets		Other Assets	Total
Balance as 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	15,424		432	15,856
Changes in estimate for asset retirement obligations	832		—	832
Balance as at June 30, 2019	697,468		18,625	716,093
Accumulated depletion, depreciation, amortization and impairment losses
Balance as at December 31, 2018	483,272		13,032	496,304
Depletion, depreciation and amortization for the period1	18,088		934	19,022
Balance as at June 30, 2019	501,360		13,966	515,326
Foreign exchange
Balance as at December 31, 2018	(1,370	)	—	(1,370	)
Currency translation adjustments	2,725		—	2,725
Balance as at June 30, 2019	1,355		—	1,355
Net book value
As at December 31, 2018	195,263		3,079	198,342
As at June 30, 2019	197,463		4,659	202,122
1  Depletion, depreciation and amortization for the period includes amounts capitalized to product inventory for barrels produced but not sold in the period.

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 June 30, 2019:

($000s)	Petroleum and Natural Gas Assets	Other Assets	Total
Depreciation for the six months ended June 30, 2019	452	466	918
Net Book Value as at June 30, 2019	878	1,618	2,496

26 Q2-2019

10. ASSET RETIREMENT OBLIGATION

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

($000s)
Balance as at December 31, 2018	12,113
Changes in estimates for asset retirement obligations and additional obligations recognized	832
Obligations settled	(31	)
Asset retirement obligation accretion	105
Effect of movements in foreign exchange rates	472
Balance as at June 30, 2019	13,491

TransGlobe has estimated the net present value of its asset retirement obligation to be $13.5 million as at June 30, 2019 (December 31, 2018 - $12.1 million) based on a total undiscounted future liability of $18.4 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 1.39% and 1.68% (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)	As at June 30, 2019
Less than 1 year	1,974
1 - 3 years	1,221
Total lease payments	3,195
Amounts representing interest	564
Present value of net lease payments	2,631
Current portion of lease obligations	1,580
Non-current portion of lease obligations	1,051

During the six months ended, the Company spent $0.1 million (June 30, 2018 - $nil) on interest expense and paid a total cash outflow of $0.9 million (June 30, 2018 - $nil) relating to lease obligations.

12. LONG-TERM DEBT

As at June 30, 2019, interest-bearing debt was comprised as follows:

($000s)	As at June 30, 2019	As at December 31, 2018
Prepayment agreement	39,315	44,134
Reserves-based lending facility	8,794	8,221
Balance, end of period	48,109	52,355

As at June 30, 2019 and December 31, 2018, the Company had in place a $75.0 million crude oil prepayment agreement with Mercuria, of which $40.0 million was drawn (December 31, 2018 - $45.0 million). Subsequent to the quarter, the Company repaid $5.0 million on the Mercuria prepayment agreement.

As at December 31, 2018, the Company had in place a revolving Canadian reserves-based lending facility with ATB totaling C$30.0 million ($22.0 million). As at June 30, 2019, the ATB facility was renewed for C$25.0 million ($19.1 million), of which C$11.5 million was drawn (December 31, 2018 - C$11.2 million).

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

($000s)
Balance as at December 31, 2018	52,355
Draws on facility	256
Repayment of long-term debt	(5,000	)
Amortization of deferred financing costs	180
Effect of movements in foreign exchange rates	318
Balance as at June 30, 2019	48,109

The Company's interest-bearing loans and borrowings are measured at amortized cost. The prepayment agreement and reserves-based lending facility are subject to certain covenants. The Company was in compliance with its covenants as at June 30, 2019.

Q2-2019 27

Based on the Company's current forecast of future production and prices the estimated future debt payments on long-term debt as of June 30, 2019 are as follows:

($000s)	Prepayment Agreement	Reserves Based Lending Facility	Total
2019	—	—	—
2020	—	—	—
2021	39,315	8,794	48,109
Total	39,315	8,794	48,109

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:

		Payment Due by Period 1,2
($000s)	Recognized in Financial Statements	Contractual Cash Flows	Less than 1 year	1-3 years
Accounts payable and accrued liabilities	Yes - Liability	19,531	19,531	—
Other long-term liabilities	Yes - Liability	364	—	364
Financial derivative instruments	Yes - Liability	1,633	1,321	312
Total		21,528	20,852	676
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at June 30, 2019 exchange rates.

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 in Q1-2019.

Pursuant to the approved South Ghazalat development lease, the Company is committed to drill one exploration well during the initial four year period of the 20 year development lease. The Company has issued a production guarantee in the amount of $1 million which will be released when the commitment well has been drilled.

In the normal course of its operations, the Company may be subject to litigation and claims. Although it is not possible to estimate the extent of

potential costs, if any, management believes that the ultimate resolution of such contingencies would not have a material adverse impact on the

results of operations, financial position or liquidity of the Company.

The Company is not aware of any material provisions or other contingent liabilities as at June 30, 2019.

14. SHARE CAPITAL

Authorized

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

Issued

	Six Months Ended		Year Ended
	June 30, 2019		December 31, 2018
(000s)	Shares	Amount ($)	Shares	Amount ($)
Balance, beginning 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

28 Q2-2019

15. SHARE-BASED PAYMENTS

Stock options

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

	Six Months Ended			Year ended
	June 30, 2019			December 31, 2018
(000s except per share amounts)	Number of Options		Weighted-average Exercise Price (C$)	Number of Options		Weighted-average Exercise Price (C$)
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	(1,034	)	6.55	(1,154	)	9.13
Options outstanding, end of period	4,481		2.86	4,876		3.60
Options exercisable, end of period	2,586		3.01	2,766		4.52

Compensation expense of $0.3 million was recorded in general and administrative expenses in the Condensed Consolidated Interim Statements of Earnings (Loss) and Comprehensive Income (Loss) and Contributed Surplus during the six month period ended June 30, 2019 (June 30, 2018 - $0.5 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 six month period ended June 30, 2019 employees exercised 337 thousand stock options (June 30, 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 June 30, 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 June 30, 2019 are as follows:

(000s)	RSU		PSU		DSU
Units outstanding, beginning of period	864		1,683		828
Granted	344		520		190
Vested / released	(331	)	(636	)	(454	)
Forfeited	(43	)	(8	)	—
Expired	(15	)	—		—
Reinvested	21		39		11
Units outstanding, end of period	840		1,598		575

During the six month period ended June 30, 2019, compensation expense of $1.0 million (June 30, 2018 - $3.2 million) was recorded in general and administrative expenses in net earnings (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 earnings (loss).

16. PER SHARE AMOUNTS

The basic weighted-average number of common shares outstanding for the three and six months endedJune 30, 2019 was 72,542,071 (June 30, 2018 - 72,205,369) and 72,484,773 (June 30, 2018 - 72,205,369), respectively. The diluted weighted-average number of common shares outstanding for the three and six months endedJune 30, 2019 was 72,547,938 (June 30, 2018 - 72,850,266) and 72,629,523 (June 30, 2018 - 72,205,369), respectively. These outstanding share amounts were used to calculate net earnings (loss) per share in the respective periods.

In determining diluted net earnings (loss) per share, the Company assumes that the proceeds received from the exercise of “in-the-money” stock options are used to repurchase common shares at the average market price. In calculating the weighted-average number of diluted common shares outstanding for the period ended June 30, 2019, the Company excluded 2,653,284 stock options (June 30, 2018 – 2,710,829) as their exercise price was greater than the average common share market price in the period.

17. DIVIDENDS

During the three and six months ended June 30, 2019, the Company paid a dividend of $0.035 per share on April 18, 2019 to shareholders of record on March 29, 2019.

Q2-2019 29

18. SEGMENTED INFORMATION

The Company has two reportable operating segments for the three and six months ended June 30, 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.

	Three Months Ended June 30
	2019		2018		2019		2018		2019		2018		2019		2018
($000s)	Egypt				Canada				Corporate				Total
Revenue
Oil sales	75,498		94,147		3,970		2,753		—		—		79,468		96,900
Natural gas sales	—		—		463		500		—		—		463		500
Natural gas liquids sales	—		—		1,192		1,820		—		—		1,192		1,820
Less: royalties	(37,807	)	(30,375	)	(245	)	(391	)	—		—		(38,052	)	(30,766	)
Petroleum and natural gas sales, net of royalties	37,691		63,772		5,380		4,682		—		—		43,071		68,454
Finance revenue	—		27		—		—		133		99		133		126
Total segmented revenue	37,691		63,799		5,380		4,682		133		99		43,204		68,580
Segmented expenses
Production and operating	10,411		15,205		1,999		2,094		—		—		12,410		17,299
Selling costs	98		1,080		—		—		—		—		98		1,080
General and administrative	1,495		1,245		193		226		2,086		6,112		3,774		7,583
Foreign exchange (gain) loss	—		(26	)	—		(268	)	32		276		32		(18	)
Finance costs	1,002		1,251		129		102		9		—		1,140		1,353
Depletion, depreciation and amortization	7,154		8,820		1,889		1,579		202		79		9,245		10,478
Asset retirement obligation accretion	—		—		49		66		—		—		49		66
Loss (gain) on financial instruments	(1,066	)	16,556		—		41		—		—		(1,066	)	16,597
Gain on disposition of assets	—		—		—		(4	)	—		—		—		(4	)
Income tax expense	7,476		6,785		—		—		—		—		7,476		6,785
Segmented net earnings (loss)	11,121		12,883		1,121		846		(2,196	)	(6,368	)	10,046		7,361
Capital expenditures
Exploration and development	7,728		5,598		236		231		—		—		7,964		5,829
Corporate	—		—		—		—		133		26		133		26
Total capital expenditures	7,728		5,598		236		231		133		26		8,097		5,855

30 Q2-2019

	Six Months Ended June 30
	2019		2018		2019		2018		2019		2018		2019		2018
($000s)	Egypt				Canada				Corporate				Total
Revenue
Oil sales	138,478		140,449		7,875		6,225		—		—		146,353		146,674
Natural gas sales	—		—		1,450		1,447		—		—		1,450		1,447
Natural gas liquids sales	—		—		2,537		4,050		—		—		2,537		4,050
Less: royalties	(68,794	)	(57,346	)	(1,123	)	(1,656	)	—		—		(69,917	)	(59,002	)
Petroleum and natural gas sales, net of royalties	69,684		83,103		10,739		10,066		—		—		80,423		93,169
Finance revenue	25		50		—		—		291		169		316		219
Total segmented revenue	69,709		83,153		10,739		10,066		291		169		80,739		93,388
Segmented expenses
Production and operating	20,182		23,667		3,761		4,273		—		—		23,943		27,940
Selling costs	573		1,126		—		—		—		—		573		1,126
General and administrative	3,092		2,526		403		526		5,146		8,527		8,641		11,579
Foreign exchange (gain) loss	—		(26	)	—		(268	)	(55	)	273		(55	)	(21	)
Finance costs	2,021		2,474		244		227		16		—		2,281		2,701
Depletion, depreciation and amortization	13,813		13,364		3,797		3,805		401		157		18,011		17,326
Asset retirement obligation accretion	—		—		105		133		—		—		105		133
Loss on financial instruments	3,930		22,465		—		296		—		—		3,930		22,761
Impairment loss	8,391		—		—		—		—		—		8,391		—
Gain on disposition of assets	—		—		—		(202	)	—		—		—		(202	)
Income tax expense	13,679		12,804		—		—		—		—		13,679		12,804
Segmented net earnings (loss)	4,028		4,753		2,429		1,276		(5,217	)	(8,788	)	1,240		(2,759	)
Capital expenditures
Exploration and development	15,700		9,950		811		506		—		—		16,511		10,456
Corporate	—		—		—		—		133		34		133		34
Total capital expenditures	15,700		9,950		811		506		133		34		16,644		10,490

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

	As at June 30, 2019			As at December 31, 2018
($000s)	Egypt	Canada	Total	Egypt	Canada	Total
Assets
Accounts receivable	23,239	2,796	26,035	9,031	2,525	11,556
Derivative commodity contracts	—	—	—	1,369	—	1,369
Intangible exploration and evaluation assets	28,132	531	28,663	35,735	531	36,266
Property and equipment
Petroleum and natural gas assets	124,160	73,303	197,463	123,043	72,220	195,263
Other assets	2,974	17	2,991	2,222	22	2,244
Other	43,131	2,320	45,451	58,518	1,296	59,814
Deferred taxes	8,704	—	8,704	4,523	—	4,523
Segmented assets	230,340	78,967	309,307	234,441	76,594	311,035
Non-segmented assets			6,692			7,261
Total assets			315,999			318,296
Liabilities
Accounts payable and accrued liabilities	13,769	1,697	15,466	13,407	8,010	21,417
Derivative commodity contracts	1,633	—	1,633	—	—	—
Long-term debt	39,315	8,794	48,109	44,134	8,221	52,355
Asset retirement obligation	—	13,491	13,491	—	12,113	12,113
Lease obligations	1,216	403	1,619	—	—	—
Deferred taxes	8,704	—	8,704	4,523	—	4,523
Segmented liabilities	64,637	24,385	89,022	62,064	28,344	90,408
Non-segmented liabilities			5,441			7,597
Total liabilities			94,463			98,005

Q2-2019 31

19. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended				Six Months Ended
	June 30				June 30
($000s)	2019		2018		2019		2018
Operating activities
(Increase) decrease in current assets
Accounts receivable	7,848		(18,239	)	(14,501	)	(23,400	)
Prepaids and other	472		(1,475	)	2,210		674
Product inventory	(1,829	)	4,435		(3,320	)	2,037
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	(2,989	)	666		(9,163	)	(5,002	)
Other long-term liabilities	(493	)	—		(443	)	—
Total changes in non-cash working capital	3,009		(14,613	)	(25,217	)	(25,691	)
Investing activities
(Increase) decrease in current assets
Prepaids and other	33		—		4		(3	)
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	(867	)	159		(305	)	(632	)
Total changes in non-cash working capital	(834	)	159		(301	)	(635	)
Financing activities
Decrease in current liabilities
Other liabilities	—		—		(200	)	—
Total changes in non-cash working capital	—		—		(200	)	—

20. SUBSEQUENT EVENTS

On August 9, 2019, the Company declared a dividend of $0.035 per share, payable September 13, 2019 to shareholders of record on August 30, 2019.

32 Q2-2019

Q2-2019 33

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