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 1

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.

2 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 3

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.

4 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 5

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.

6 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 7

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.

8 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 9

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,

10 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 11

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.

12 Q2-2019