MANAGEMENT'S DISCUSSION AND ANALYSIS

November 6, 2018

The following discussion and analysis is management’s opinion of TransGlobe’s 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 nine months ended September 30, 2018 and 2017, and the audited Consolidated Financial Statements and Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2017 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 ("TransGlobe" or the "Company") 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 2018, including expected 2018 average production, funds flow from operations, the 2018 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 Government 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.

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

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

Q3-2018 1

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. Brett Norris, M.Sc., P Geo, - Vice President Exploration 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. Norris obtained a Master’s of Science Degree in Geology from the University of Western Ontario. He is a Registered Professional Geoscientist in the province of Alberta 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.

MANAGEMENT STRATEGY AND OUTLOOK

The 2018 outlook provides information as to management’s expectation for results of operations for 2018. Readers are cautioned that the 2018 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").

2018 Outlook

The 2018 production outlook for the Company is provided as a range to reflect timing and performance contingencies. At mid-year 2018, the Company adjusted the 2018 capital program and production outlook to reflect project timing delays in Egypt and Canada. Total corporate production is expected to range between 14,200 and 14,800 barrels of oil equivalent per day ("boepd") for 2018 with a 94% weighting to oil and liquids. Egypt oil production is expected to range between 12,000 and 12,400 barrels of oil per day ("bopd") in 2018. Canadian production is expected to range between 2,200 and 2,400 boepd in 2018, inclusive of an adjustment for the Harmattan area plant and facility turnaround in May.

Production and operating expenses have increased to $9.18 per barrel of oil equivalent ("boe") in Q3-2018 (Q3-2017 - $8.76). The increase was mainly due to upward pressure on costs from strengthening oil prices. The increases in production and operating expenses are expected to moderate throughout the remainder of 2018.

Funds flow from operations in any given period will be dependent upon the timing of crude oil tanker liftings in Egypt and the market price of crude oil sold. As these factors are difficult to accurately predict, the Company has not provided funds flow from operations guidance for 2018. Funds flow from operations and inventory levels in Egypt are expected to fluctuate significantly from quarter to quarter due to the timing of liftings.

The Company’s 2018 budgeted capital program is $44.1 million (before capitalized G&A) which includes $27.7 million for Egypt and $16.4 million for Canada. The 2018 capital program is balanced to anticipated funds flow from operations using a Brent oil price forecast of $55/barrel ("bbl").

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

Netback sensitivity
Benchmark crude oil price (US$/bbl)	40		50	60	70	80
Benchmark natural gas price (C$/mcf)	0.95		1.15	1.35	1.55	1.75
Netback ($/boe)
Egypt - crude oil1	2.60		6.85	11.11	15.37	19.63
Canada - crude oil2	12.70		21.06	28.46	35.53	42.70
Canada - natural gas and NGLs2	(1.09	)	0.67	1.72	2.85	4.61
1  Egypt assumptions: using anticipated 2018 Egypt production profile, Ras Gharib price differential estimate of $10.50 per bbl applied consistently at all price points, concession    differentials of 4%/5%/3% applied to WG/WB/NWG respectively, operating costs estimated at ~$9.95/bbl, and maximum cost recovery resulting from accumulated cost pools.
2  Canada assumptions: using anticipated 2018 Canada production profile, Edmonton Light price differential estimate of $15.00 per bbl, Edmonton Light to Harmattan discount of C$2.50    per bbl, operating costs estimated at ~C$11.00/boe, NGL mixture price at 45% of Edmonton Light, and takes into consideration Canadian tax pools.

The Company aspires to pay a semi-annual dividend to shareholders determined at each period after consideration for: ongoing production maintenance; growth through acquisitions; maintaining a conservative balance sheet to manage for commodity price volatility; payment irregularity in Egypt and solvency requirements; and the cash flow generating capability of the business. The Company paid a dividend to shareholders of $0.035/share on September 14, 2018.

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.

2 Q3-2018

Reconciliation of funds flow from operations

	Three Months Ended September 30				Nine Months Ended September 30
($000s)	2018		2017		2018		2017
Cash flow from operating activities	47,639		20,437		59,370		15,187
Changes in non-cash working capital	(30,621	)	(1,220	)	(4,930	)	23,387
Funds flow from operations1	17,018		19,217		54,440		38,574
1  Funds flow from operations does not include interest costs. Interest expense is included in financing costs on the Condensed Consolidated Interim Statements of Loss and    Comprehensive Loss. Cash interest paid is reported as a financing activity on the Condensed Consolidated Interim Statements of Cash Flows.

Net debt-to-funds flow from operations ratio

Net debt-to-funds flow from operations is a measure that is used 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, plus 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 are recognized at production. 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.

TRANSGLOBE’S BUSINESS

TransGlobe is a Canadian publicly-traded oil and gas exploration and development company whose activities are concentrated in two geographic areas: the Arab Republic of Egypt (“Egypt”) and Alberta, Canada.

3 Q3-2018

SELECTED QUARTERLY FINANCIAL INFORMATION

	2018					2017								2016
($000s, except per share,
price and volume amounts)	Q-3		Q-2	Q-1		Q-4		Q-3		Q-2		Q-1		Q-43
Operations
Average production volumes
Crude oil (bbls/d)	12,506		12,409	12,452		12,027		12,786		14,347		14,514		12,861
NGLs (bbls/d)	876		521	894		915		1,081		919		1,037		134
Natural gas (mcf/d)	5,695		5,094	6,176		6,059		6,268		7,191		7,075		916
Total (boe/d)	14,331		13,779	14,375		13,952		14,912		16,465		16,731		13,148
Average sales volumes
Crude oil (bbls/d)	12,665		17,931	9,830		14,324		15,894		17,141		11,610		7,018
NGLs (bbls/d)	876		521	894		915		1,081		919		1,037		134
Natural gas (mcf/d)	5,695		5,094	6,176		6,059		6,286		7,191		7,075		916
Total (boe/d)	14,490		19,301	11,753		16,249		18,020		19,259		13,826		7,305
Average realized sales prices
Crude oil ($/bbl)	61.79		59.39	56.26		53.25		44.82		39.46		41.66		37.38
NGLs ($/bbl)	22.64		38.39	27.72		26.86		18.90		21.08		19.08		12.33
Natural gas ($/mcf)	1.01		1.08	1.70		0.94		1.65		2.14		1.96		1.80
Total oil equivalent ($/boe)	55.77		56.49	50.06		48.80		41.24		36.92		37.41		36.45
Inventory (mbbls)	496		510	1,013		777		988		1,274		1,528		1,265
Petroleum and natural gas sales	74,345		99,220	52,951		72,954		68,372		64,712		46,553		24,501
Petroleum and natural gas sales, net of royalties	42,453		68,454	24,715		40,725		44,839		40,439		22,461		5,217
Cash flow from operating activities	47,639		18,886	(7,155	)	44,263		20,437		(2,753	)	(2,497	)	6,355
Funds flow from operations1	17,018		33,499	3,923		17,018		19,217		16,855		2,502		(9,904	)
Funds flow from operations per share:
- Basic	0.24		0.46	0.05		0.24		0.27		0.23		0.03		(0.14	)
- Diluted	0.23		0.46	0.05		0.24		0.27		0.23		0.03		(0.14	)
Net earnings (loss)	(12,283	)	7,361	(10,120	)	(2,382	)	(6,855	)	(56,622	)	(12,877	)	(33,997	)
Net earnings (loss) per share:
- Basic	(0.17	)	0.10	(0.14	)	(0.03	)	(0.09	)	(0.78	)	(0.18	)	(0.47	)
- Diluted	(0.17	)	0.10	(0.14	)	(0.03	)	(0.09	)	(0.78	)	(0.18	)	(0.49	)
Capital expenditures	12,783		5,855	4,635		9,078		10,133		8,230		10,718		8,863
Property expenditures	—		—	—		—		—		—		—		59,475
Total assets	314,203		329,542	312,691		327,702		338,802		337,596		403,686		406,142
Cash and cash equivalents	62,663		38,088	31,084		47,449		21,464		13,780		21,324		31,468
Working capital	52,351		60,464	45,252		50,639		58,815		60,319		42,759		(16,764	)
Convertible debentures	—		—	—		—		—		—		—		72,655
Note payable	—		—	—		—		—		—		11,259		11,162
Total long-term debt, including      current portion	52,532		62,173	67,167		69,999		79,839		83,725		73,549		—
Net debt-to-funds flow from operations ratio2	0.00		0.02	0.36		0.30		0.70		2.00		(13.90	)	(12.00	)
1  Funds flow from operations (before finance costs) is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be    comparable to measures used by other companies. See "Non-GAAP Financial Measures".
2  Net debt-to-funds flow from operations ratio is a measure that represents total long-term debt (including the current portion) plus convertible debentures and working capital over funds     flow from operations from the trailing 12 months and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
3  The Q4-2016 information includes the results of the operations of the Harmattan assets in Alberta, Canada from December 20, 2016 to December 31, 2016 (12 days). The Harmattan     assets were acquired in a transaction that closed on December 20, 2016 (effective December 1, 2016).

During the third quarter of 2018, TransGlobe:

• Reported a 4% increase in production volumes as compared to Q2-2018 primarily due to an increase in well production in Egypt and Canada;

• Sold one cargo of TransGlobe's entitlement crude oil of 502 thousand barrels ("mbbls") and ended Q3-2018 with crude oil inventory of 496 mbbls, a decrease of 281 mbbls over crude inventory levels at December 31, 2017;

• Increased petroleum and natural gas sales by 9% compared to Q3-2017, principally due to an improvement in commodity prices;

• Reported positive funds flow from operations of $17.0 million;

• Reported positive working capital of $52.4 million, including $62.7 million in cash and cash equivalents as at September 30, 2018;

4 Q3-2018

• Reported a net loss of $12.3 million, inclusive of a $3.3 million unrealized derivative loss on commodity contracts and a $14.1 million impairment loss on the Company's exploration and evaluation assets; and

• Spent $12.8 million on capital expenditures, funded entirely from funds flow from operations and cash on hand.

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

2018 TO 2017 NET EARNINGS VARIANCES

			$ Per Share
	$000s		Diluted		% Variance
Net loss for the nine months ended September 30, 2017	(76,354	)	(1.06	)
Cash items
Volume variance	(27,726	)	(0.36	)	37
Price variance	74,605		1.02		(98	)
Royalties	(18,996	)	(0.26	)	25
Expenses:
Production and operating	(260	)	—		—
Selling costs	273		—		—
Cash general and administrative	(646	)	(0.01	)	1
Current income taxes	(3,624	)	(0.05	)	5
Realized foreign exchange loss	111		—		—
Realized derivative loss on commodity contracts	(7,954	)	(0.11	)	10
Interest on long-term debt	866		0.01		(1	)
Other income	340		—		—
Total cash items variance	16,989		0.24		(21	)
Non-cash items
Unrealized derivative loss on commodity contracts	(19,771	)	(0.27	)	26
Unrealized foreign exchange gain	(237	)	—		—
Unrealized loss on financial instruments	151		—		—
Depletion and depreciation	3,558		0.05		(5	)
Accretion	(14	)	—		—
Impairment loss	64,887		0.89		(85	)
Share-based compensation	(4,423	)	(0.06	)	6
Deferred lease inducement	3		—		—
Gain on asset disposition	207		—		—
Amortization of deferred financing costs	(38	)	—		—
Total non-cash items variance	44,323		0.61		(58	)
Net loss for the nine months ended September 30, 2018	(15,042	)	(0.21	)	(79	)

TransGlobe recorded a net loss of $15.0 million in the first nine months of 2018 compared to a net loss of $76.4 million in the same period of 2017. The average realized sales price in the first nine months of 2018 was $54.62 per boe versus $38.59 per boe in the same period of 2017. The 42% price increase resulted in a positive cash variance of $74.6 million. This increase was partially offset by a reduction in sales volumes, increased royalties and higher current income tax expense which created a combined negative earnings variance of $50.3 million. Operating expenses increased by $0.3 million in the first nine months of 2018 due to cost pressures from higher commodity prices. Cash general and administrative expenses increased by $0.6 million in the first nine months of 2018 primarily due to expenses incurred during the AIM listing process. Interest on long-term debt expense decreased by $0.9 million compared with the first nine months of 2017 due to a lower debt balance from repayments. The company also incurred an $8.0 million realized loss on its derivative commodity contracts in the first nine months of 2018 due to higher oil prices.

The largest positive non-cash earnings variance in the first nine months of 2018 compared to the same period of 2017 is a variance in impairment loss of $64.9 million. In the first nine months of 2017, the Company recorded a $79.0 million impairment loss (primarily on the exploration and evaluation assets of North West Gharib) compared to a $14.1 million impairment loss on the exploration and evaluation assets of North West Sitra in 2018. Additionally, there was a negative non-cash variance of $19.8 million related to an unrealized derivative loss on commodity contracts due to increased market oil prices. The Company incurred $4.4 million higher share-based compensation costs in the first nine months of 2018 due to an increase in the Company's share price and new share grants linked to long-term incentives.

Q3-2018 5

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	2018		2017
	Q-3	Q-2	Q-1	Q-4	Q-3
Crude oil
Dated Brent average oil price (US$/bbl)	75.22	74.50	66.81	61.53	52.11
Edmonton Sweet index (US$/bbl)	62.68	62.43	56.98	54.26	45.32
Natural gas
AECO (C$/mmbtu)	1.18	1.18	2.08	1.69	1.45
US/Canadian Dollar average exchange rate	1.29	1.29	1.26	1.27	1.25

In Q3-2018, the average price of Dated Brent oil was 44% and 1% higher than Q3-2017 and Q2-2018 respectively. Egypt production is priced based on Dated Brent, less a quality differential and is shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost oil or cost recovery barrels) which are assigned 100% to the Company. The contracts provide for cost recovery per quarter up to a maximum percentage of total production. Timing differences often exist between the Company's recognition of costs and their recovery as the Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSC, the Contractor's share of excess ranges between 0% and 30%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum cost oil ranges from 25% to 30% in Egypt. The balance of the production after maximum cost recovery is shared with the government (profit oil). Depending on the contract, the Egyptian government receives 70% to 86% of the profit oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of profit oil increases when production exceeds pre-set production levels in the respective contracts. During times of high oil prices, the Company receives less cost oil and may receive more production-sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil. For reporting purposes, the Company records the government’s share of production as royalties and taxes (all taxes are paid out of the government’s share of production) which will increase during times of rising oil prices and will decrease in times of declining oil prices. If oil prices are sufficiently low and the Ras Gharib/Dated Brent differential is high, the cost oil portion may not be sufficient to cover operating costs and capital costs, or even operating costs alone. When this occurs, the non-recovered costs accumulate in the Company’s cost pools and are available to be offset against future cost oil during the term of the PSC and any eligible extension periods.

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

In the third quarter of 2018, the average price of Edmonton Sweet index oil (expressed in USD) was 38% and 0% higher than Q3-2017 and Q2-2018 respectively. In Q3-2018, the average price of AECO natural gas decreased 19% compared with Q3-2017 and experienced no change from Q2-2018.

OPERATING RESULTS AND NETBACK

Daily volumes, working interest before royalties (boepd)

Production Volumes
	Three Months Ended September 30		Nine Months Ended September 30
	2018	2017	2018	2017
Egypt crude oil (bbls/d)	11,939	12,268	11,876	13,351
Canada crude oil (bbls/d)	567	518	579	526
Canada NGLs (bbls/d)	876	1,081	764	1,012
Canada natural gas (mcf/d)	5,695	6,268	5,653	6,842
Total Company (boe/d)	14,331	14,912	14,161	16,029

Sales Volumes (excludes volumes held as inventory)
	Three Months Ended September 30		Nine Months Ended September 30
	2018	2017	2018	2017
Egypt crude oil (bbls/d)	12,098	15,376	12,906	14,372
Canada crude oil (bbls/d)	567	518	579	526
Canada NGLs (bbls/d)	876	1,081	764	1,012
Canada natural gas (mcf/d)	5,695	6,268	5,653	6,842
Total Company (boe/d)	14,490	18,020	15,191	17,050

6 Q3-2018

Netback

Consolidated Netback
	Nine Months Ended September 30
	2018		2017
(000s, except per boe amounts)1	$	$/boe	$	$/boe
Petroleum and natural gas sales	226,516	54.62	179,637	38.59
Royalties and other2	90,894	21.92	71,898	15.45
Current taxes2	19,728	4.76	16,104	3.46
Production and operating expenses	40,182	9.69	39,922	8.58
Selling costs	1,653	0.40	1,926	0.41
Netback	74,059	17.85	49,787	10.69
1  The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended September 30, 2018 and September 30, 2017 (these figures do not include    TransGlobe's Egypt entitlement barrels held as inventory at September 30, 2018).
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.

Consolidated Netback
	Three Months Ended September 30
	2018		2017
(000s, except per boe amounts)1	$	$/boe	$	$/boe
Petroleum and natural gas sales	74,345	55.77	68,372	41.24
Royalties and other2	31,892	23.92	23,533	14.19
Current taxes2	6,924	5.19	5,179	3.12
Production and operating expenses	12,242	9.18	14,521	8.76
Selling costs	527	0.40	425	0.26
Netback	22,760	17.08	24,714	14.91
1  The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended September 30, 2018 and September 30, 2017 (these figures do not include    TransGlobe's Egypt entitlement barrels held as inventory at September 30, 2018).
2  Royalties and taxes are settled at the time of production. Fluctuations in royalty and tax costs per bbl are due to timing differences between the production and sale of the Company's    entitlement crude.

Egypt
	Nine Months Ended September 30
	2018		2017
(000s, except per bbl amounts)1	$	$/bbl	$	$/bbl
Oil sales	209,310	59.41	163,984	41.79
Royalties2	88,624	25.15	68,543	17.47
Current taxes2	19,728	5.60	16,104	4.10
Production and operating expenses	34,344	9.75	35,344	9.01
Selling costs	1,653	0.47	1,926	0.49
Netback	64,961	18.44	42,067	10.72
1  The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended September 30, 2018 and September 30, 2017 (these figures do not include    TransGlobe's Egypt entitlement barrels held as inventory at September 30, 2018).
2  Royalties and taxes are settled at the time of production. Fluctuations in royalty and tax costs per bbl are due to timing differences between the production and sale of the Company's    entitlement crude.

Egypt
	Three Months Ended September 30
	2018		2017
(000s, except per bbl amounts)1	$	$/bbl	$	$/bbl
Oil sales	68,861	61.87	63,403	44.82
Royalties2	31,278	28.10	22,506	15.91
Current taxes2	6,924	6.22	5,179	3.66
Production and operating expenses	10,677	9.59	13,242	9.36
Selling costs	527	0.47	425	0.30
Netback	19,455	17.49	22,051	15.59
1  The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended September 30, 2018 and September 30, 2017 (these figures do not include    TransGlobe's Egypt entitlement barrels held as inventory at September 30, 2018).
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.

Netbacks per bbl in Egypt increased by 12% and 72%, respectively, in the three and nine months ended September 30, 2018 compared with the same periods in 2017. The higher netbacks were primarily due to an increase in realized oil prices (38% and 42% respectively), offset by an increase

Q3-2018 7

in production and operating expenses per barrel (2% and 8% respectively) in the three and nine months ended September 30, 2018 compared with the same periods in 2017.

Production and operating expenses decreased by $2.6 million and $1.0 million, respectively, in the three and nine months ended September 30, 2018 compared with the same period in 2017. This decrease was primarily due to lower sales volumes in Q3-2018, resulting in lower operating costs from sales of crude oil inventory than the comparative period. This was partially offset by an extensive workover program in Q2-2018 and higher diesel, transportation and service costs due to stronger oil prices. On a per bbl basis, production and operating expenses increased by 2% and 8% for the three and nine month periods ended September 30, 2018 respectively.

Royalties and taxes as a percentage of revenue were 55% and 52%, in the three and nine month periods ended September 30, 2018, respectively, compared to 44% and 52% for the same periods in 2017. 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 nine month periods ended September 30, 2018, royalties and taxes as a percentage of revenue would have been 56% and 56%, respectively (2017 - 58% and 54%). In periods when the Company sells less than its entitlement production, royalties and taxes as a percentage of revenue will be higher than the terms of the PSCs dictate. In periods when the Company sells more than its entitlement production, royalties and taxes as a percentage of revenue will be lower than the terms of the PSCs dictate.

The average selling price during the three months ended September 30, 2018 was $61.87/bbl (Q3-2017 - $44.82), which was $13.35/bbl lower (Q3-2017 - $7.29) than the average Dated Brent oil price of $75.22/bbl for the period (Q3-2017 - $52.11/bbl). The difference between the average selling price in Q3-2018 and the Dated Brent price is due to a gravity/quality adjustment and is also impacted by the specific timing of direct sales.

Canada
	Nine Months Ended September 30
	2018		2017
(000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	9,356	59.19	6,635	46.21
Natural gas sales	1,975	7.68	3,594	11.54
NGL sales	5,875	28.17	5,424	19.63
Total sales	17,206	27.58	15,653	21.41
Royalties	2,270	3.64	3,355	4.59
Production and operating expenses	5,838	9.36	4,578	6.26
Netback	9,098	14.58	7,720	10.56

Canada
	Three Months Ended September 30
	2018		2017
(000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	3,131	60.02	2,140	44.91
Natural gas sales	528	6.05	949	9.87
NGL sales	1,825	22.64	1,880	18.90
Total sales	5,484	24.92	4,969	20.43
Royalties	614	2.79	1,027	4.22
Production and operating expenses	1,565	7.11	1,279	5.26
Netback	3,305	15.02	2,663	10.95

Netbacks in Canada were $15.02 and $14.58 per boe for the three and nine months ended September 30, 2018, respectively, which represents an increase of $4.07 and $4.02 per boe compared with the same periods of 2017. The increase is mainly due to an increase in the total realized sales price of $4.49 and $6.17 per boe from the comparative three and nine month periods of 2017. These were partially offset by increases of 35% and 50% in production and operating expenses on a per boe basis for the three and nine month periods respectively. The increase in production and operating expenses are primarily attributable to the three-week turnaround at Harmattan in Q2-2018, increased gas processing fees and higher costs associated with a colder than normal winter. For the three and nine months ended September 30, 2018, the Company's Canadian operations incurred $0.4 million and $1.1 million lower royalty costs than the respective periods in 2017. The reduction in royalties is due to Gas Cost Allowance (GCA) rebates received in 2018. Royalties amounted to 11% and 13% of petroleum and natural gas sales revenue during the three and nine months ended September 30, 2018 compared to 21% during both the three and nine month comparative periods.

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.

8 Q3-2018

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)

	Nine Months Ended September 30
	2018				2017
(000s, except boe amounts)	$		$/boe		$		$/boe
General and administrative (gross)	12,264		2.96		12,589		2.70
Share-based compensation	5,309		1.28		886		0.19
Capitalized G&A and overhead recoveries	(890	)	(0.21	)	(1,858	)	(0.40	)
General and administrative (net)	16,683		4.03		11,617		2.49

	Three Months Ended September 30
	2018				2017
(000s, except boe amounts)	$		$/boe		$		$/boe
General and administrative (gross)	3,780		2.84		4,209		2.54
Share-based compensation	1,624		1.22		236		0.14
Capitalized G&A and overhead recoveries	(300	)	(0.23	)	(636	)	(0.38	)
General and administrative (net)	5,104		3.83		3,809		2.30

General and administrative (gross) for the three and nine months ended September 30, 2018 decreased 10% and 3%, respectively, compared with the same periods in 2017. This decrease was primarily due to a reduction of certain expenses in 2018, offset by costs incurred in 2018 related to the AIM listing that were not incurred in the comparative period.

Share-based compensation expense for the three and nine months ended September 30, 2018 increased by 588% and 499%, respectively compared with the same periods in 2017. This increase is primarily due to an increase in the Company's share price in Q3-2018 and the associated revaluation of share units granted by the Company.

FINANCE COSTS

	Three Months Ended September 30		Nine Months Ended September 30
(000s)	2018	2017	2018	2017
Interest on convertible debenture	—	—	—	1,089
Interest on long-term debt	1,018	1,276	3,320	2,731
Interest on note payable	—	—	—	532
Interest on borrowing base facility	118	115	331	164
Amortization of deferred financing costs	86	94	272	234
Finance costs	1,222	1,485	3,923	4,750

Finance costs for the three and nine month period ended September 30, 2018 decreased to $1.2 million and $3.9 million, respectively, from $1.5 million and $4.8 million for the same period in 2017. This decrease is due to the reduction in balances of long-term debt from repayments, partially offset by higher borrowing costs due to an increase in LIBOR and ATB Prime.

At September 30, 2018, the Company had a prepayment arrangement with Mercuria that allows for a revolving balance of up to $75.0 million, of which $45.0 million is outstanding. During the third quarter of 2018, the Company made repayments of $10.0 million on this loan.

As at September 30, 2018, the Company had a revolving Canadian reserves-based lending facility with Alberta Treasury Branches ("ATB") totaling C$30.0 million ($24.0 million), of which C$11.0 million ($8.5 million) is outstanding.

The prepayment agreement and reserves-based lending facility are subject to certain covenants. The Company is in compliance with its covenants as at September 30, 2018. Refer to the related description of TransGlobe's debt included in the December 31, 2017 Consolidated Financial Statements.

DEPLETION AND DEPRECIATION (“DD&A”)

	Nine Months Ended September 30
	2018		2017
(000s, except per boe amounts)	$	$/boe	$	$/boe
Egypt	20,043	5.69	22,568	5.75
Canada	5,800	9.30	6,768	9.26
Corporate	234	—	299	—
Total	26,077	6.29	29,635	6.37

Q3-2018 9

	Three Months Ended September 30
	2018		2017
(000s, except per boe amounts)	$	$/boe	$	$/boe
Egypt	6,679	6.00	8,360	5.91
Canada	1,995	9.07	2,258	9.28
Corporate	77	—	142	—
Total	8,751	6.56	10,760	6.49

In Egypt, DD&A increased 2% and decreased 1% on a per bbl basis in the three and nine months ended September 30, 2018, respectively, compared to the same period in 2017.

In Canada, DD&A decreased 2% and was flat on a per boe basis in the three and nine months ended September 30, 2018, respectively, compared to the same period in 2017.

IMPAIRMENT LOSS

The Company recorded a non-cash impairment loss of $14.1 million on its exploration and evaluation assets during the third quarter of 2018. The impairment relates to the North West Sitra concession in Egypt and represents the entire intangible exploration and evaluation asset balance of this concession as at September 30, 2018. It was determined that an impairment loss was necessary as no commercially viable quantities of oil were discovered at North West Sitra, and no further drilling activities are planned.

All commitments have been met in advance of the end of the first exploration phase. Prior to January 7, 2019, the expiration date of the concession, the Company can elect to enter the second and final exploration phase (3.0 years after the extension of phase one). The Company does not intend to enter the second phase of the exploration concession.

During the first nine months of 2017, the Company recorded an impairment loss of $79.0 million. The 2017 impairment primarily related to the exploration and evaluation assets of the North West Gharib concession in Egypt. The company relinquished the remaining North West Gharib exploration lands in 2017 that were are not covered by development leases.

CAPITAL EXPENDITURES

	Nine Months Ended September 30
($000s)	2018	2017
Egypt	20,063	24,667
Canada	3,142	4,384
Corporate	68	30
Total	23,273	29,081

Capital expenditures in the first nine months of 2018 were $23.3 million (2017 - $29.1 million).

In Egypt, the Company incurred $11.8 million of capitalized drilling costs and $3.9 million of facilities-related capital. During the first nine months of 2018, the Company drilled seven development wells in the Eastern Desert and three exploration wells in the Western Desert. Four development wells were drilled at West Bakr (K-46, K-45, M-North and M-South), two development wells were drilled at West Gharib (Arta 48 and Arta 54) and one development well was drilled at NW Gharib (NWG 38A-Inj). Drilling of a second development well at NW Gharib (NWG 38A-7) began during the quarter, with the well being scheduled to be put on production in November. Two exploration wells were drilled at North West Sitra (NWS 9 and NWS 12X) and one was drilled at South Ghazalat (SGZ 1X).

In Canada, the Company incurred $2.6 million of capitalized drilling costs and $0.5 million in land acquisition costs. During the first nine months of 2018, the Company drilled and cased three gross (2.5 net) one-mile horizontal wells and acquired 16 net sections (10,240 acres) of Cardium prospective exploration lands to the south/south west of the Harmattan pool.

OUTSTANDING SHARE DATA

As at September 30, 2018, the Company had 72,205,369 common shares issued and outstanding and 4,875,382 stock options issued and outstanding, of which 2,765,569 are exercisable in accordance with their terms into an equal number of common shares of the Company.

LIQUIDITY AND CAPITAL RESOURCES

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

Funding for the Company’s capital expenditures was provided by funds flow from operations and cash on hand. The Company expects to fund its remaining 2018 exploration and development program through the use of working capital and funds 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.

10 Q3-2018

Working capital is the amount by which current assets exceed current liabilities. At September 30, 2018, the Company had a working capital surplus of $52.4 million (December 31, 2017 - surplus of $50.6 million). The increase in working capital in Q3-2018 is due to an increase in cash from stronger crude pricing on sales and a decrease in accounts receivable and inventory, slightly offset by higher current liabilities since December 31, 2017.

As at September 30, 2018, the Company's cash equivalents balance consisted of short-term deposits with an original term to maturity at purchase of three months or less. All of the Company's cash and cash equivalents are on deposit with high credit-quality financial institutions.

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 (pre-2011) delays of up to four to six months in 2017, and has now decreased to a historical low. As at September 30, 2018, amounts owing from EGPC were $6.7 million. The Company considers there to be minimal credit risk associated with EGPC's delays.

The Company completed one direct crude sale shipment to third-party buyers in Q3-2018; the lifting occurred in July and total proceeds of $31.7 million were collected in August. The Company now incurs a 30-day collection cycle as a result of direct marketing to third-party international buyers. Depending on the Company's assessment of the credit of crude cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings, which has significantly reduced the Company's credit risk profile. As at September 30, 2018, the Company held 496 thousand barrels of entitlement oil as inventory.

At September 30, 2018, the Company had $99.0 million of revolving credit facilities with $52.5 million drawn and $46.5 million available. The Company had a revolving Canadian reserves-based lending facility with ATB totaling C$30.0 million ($24.0 million), of which C$11.0 million ($8.5 million) was outstanding. During the first nine months of 2018, the Company had drawings of C$0.5 million ($0.4 million) and repayments of C$3.6 million ($2.8 million) on this facility. The Company also had the prepayment agreement with Mercuria that allows for a revolving balance of up to $75.0 million, of which $45 million is outstanding. During the first nine months of 2018, the Company repaid $15.0 million on this loan.

The Company paid out a dividend of $2.6 million ($0.035 per share) on September 14, 2018 to shareholders of record on August 31, 2018.

PRODUCT INVENTORY

Product inventory consists of the Company's Egypt entitlement crude oil barrels, which are valued at the lower of cost or net realizable value. Cost includes operating expenses and depletion associated with the unsold entitlement crude oil as determined on a concession by concession basis. All oil produced is delivered to EGPC facilities and EGPC also owns the storage and export facilities from where the Company's product inventory is sold. The Company requires EGPC approval to schedule liftings and works with EGPC on a continuous basis to schedule tanker liftings. Crude oil inventory levels fluctuate from quarter to quarter depending on EGPC approvals, as well as the timing and size of tanker liftings in Egypt. As at September 30, 2018, the Company had 496 mbbls of entitlement oil as inventory, which represents approximately three months of entitlement oil production. Inventoried entitlement crude oil decreased by 281,126 barrels at September 30, 2018 compared with December 31, 2017. Since the Company began direct marketing of its oil on January 1, 2015, crude oil inventory levels have fluctuated quarter to quarter. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows. The Company expects to complete both external sales (tanker liftings) and internal sales to EGPC in 2018, and anticipates that 2018 year-end crude oil inventory will be reduced from 2017 year-end levels, subject to the current lifting schedule. One additional lifting is scheduled in 2018 for a total of four liftings expected in 2018.

	Three Months Ended		Nine Months Ended		Year ended
(000 bbls)	September 30, 2018		September 30, 2018		December 31, 2017
Product inventory, beginning of period	510		777		1,265
TransGlobe entitlement production	488		1,441		2,102
EGPC sales	—		(318	)	(1,121	)
Tanker liftings	(502	)	(1,404	)	(1,469	)
Product inventory, end of period	496		496		777

COMMITMENTS AND CONTINGENCIES

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

($000s)		Payment Due by Period 1,2
	Recognized
	in Financial	Contractual	Less than
	Statements	Cash Flows	1 year	1-3 years
Accounts payable and accrued liabilities	Yes - Liability	28,488	28,488	—
Long-term debt	Yes - Liability	52,532	—	52,532
Other long-term liabilities	Yes - Liability	1,315	—	1,315
Financial derivative instruments	Yes - Liability	28,124	4,417	23,707
Office and equipment leases3	No	3,413	2,203	1,210
Total		113,872	35,108	78,764
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at September 30, 2018 exchange rates.
3 Office and equipment leases include all drilling rig contracts.

Pursuant to the PSC for North West Sitra in Egypt, the Company had a minimum financial commitment of $10.0 million and a work commitment for two wells and 300 square kilometers of 3-D seismic during the initial three-and-a-half year exploration period, which commencedon January 8, 2015. The Company requested and received a six month extension of the initial exploration period to January 7, 2019. As at September 30,

Q3-2018 11

2018, the Company has met its financial and operating commitments, with the acquisition of 600 square kilometers of 3-D seismic in 2017 and the drilling of two wells in the first nine months of 2018. The Company has now completed the initial exploration period work program and based on well results in not planning to enter the second exploration phase.

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 September 30, 2018.

ASSET RETIREMENT OBLIGATION

At September 30, 2018, TransGlobe held an asset retirement obligation ("ARO") of $11.3 million (December 31, 2017 - $12.3 million) for the future abandonment and reclamation costs of the Canadian assets. The estimated ARO liability includes assumptions of actual costs to abandon and/or reclaim wells and facilities, the time frame in which such costs will be incurred, as well as inflation factors in order to calculate the undiscounted total future liability. TransGlobe calculated the present value of the obligations using discount rates between 2.21% and 2.42% to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates.

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

DERIVATIVE COMMODITY CONTRACTS

The nature of TransGlobe’s operations exposes it to fluctuations in commodity prices, interest rates and foreign currency exchange rates. TransGlobe monitors and when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by TransGlobe are related to an underlying financial position or to future crude oil and natural gas production. TransGlobe does not use derivative financial instruments for speculative purposes. TransGlobe has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in net earnings 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 in this MD&A, TransGlobe has also entered into a marketing contract with Mercuria Energy Trading S.A. ("Mercuria") to market nine million barrels of TransGlobe's Egypt entitlement production. The pricing of the crude oil sales will be based on market prices at the time of sale.

There were 5 outstanding derivative commodity contracts as at September 30, 2018 (December 31, 2017 - 11 contracts), the fair values of which have been presented as liabilities on the Company's Condensed Consolidated Interim Balance Sheets.

12 Q3-2018

The following tables summarize TransGlobe’s outstanding derivative commodity contract positions as at September 30, 2018:

Financial Brent Crude Oil Contracts
Period Hedged	Contract	Volume (bbls)	Bought Put USD$/bbl	Sold Call USD$/bbl	Sold Put USD$/bbl
Jul 2020 - Dec 20201	3-Way Collar	300,000	54.00	63.45	45.00
Jan 2020 - Jun 20202	3-Way Collar	300,000	54.00	61.25	46.50
Jan 2019 - Dec 20193	3-Way Collar	396,000	53.00	62.10	46.00
Jan 2019 - Dec 20194	3-Way Collar	399,996	54.00	61.35	46.00
Oct-2018	3-Way Collar	250,000	54.00	65.30	45.00
1  50,000 barrels ("bbls") per calendar month through Jul 2020 - Dec 2020
2  50,000 bbls per calendar month through Jan 2020 - Jun 2020
3  33,000 bbls per calendar month through Jan 2019 - Dec 2019
4  33,333 bbls per calendar month through Jan 2019 - Dec 2019

Subsequent to the quarter, the Company closed out its Oct-18 hedge position for a net cost of $3.96 million.

CHANGE IN ACCOUNTING POLICIES

New accounting standards

IFRS 9 "Financial Instruments: Classification and Measurement"

Effective January 1, 2018, the Company adopted IFRS 9 Financial Instruments, which replaced IAS 39 Financial Instruments: Recognition and Measurement. IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of its financial assets. For financial liabilities, IFRS 9 stipulates that where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in other comprehensive income rather than net earnings, unless this creates an accounting mismatch. In addition, it incorporates a new expected credit loss model for calculating impairment on financial assets, which will result in more timely recognition of expected credit losses. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management.

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

• Fair value through profit or loss - financial instruments under this classification include cash and cash equivalents, and derivative commodity contracts; and

• Amortized cost - financial instruments under this classification include accounts receivable, accounts payable and accrued liabilities, other long-term liabilities, and long-term debt.

Refer to Note 4 for the classification and measurement of these financial instruments.

The Company does not apply hedge accounting. TransGlobe also does not require a provision for credit losses, as discussed further in Note 4. As a result of adopting IFRS 9, there was no effect on the Company's retained earnings or prior period amounts.

IFRS 15 "Revenue from Contracts with Customers"

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

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

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

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

13 Q3-2018

received. TransGlobe pays royalties to the Alberta provincial government and other mineral rights owners in accordance with the established royalty regime.

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

Standards issued but not yet effective

IFRS 16 "Leases"

In January 2016, the IASB issued IFRS 16 Leases, replacing IAS 17 Leases. IFRS 16 establishes a set of principles that both parties to a contract apply to provide relevant information about leases in a manner that faithfully represents those transactions. The current standard (IAS 17) requires lessees and lessors to classify their leases as either finance leases or operating leases, with separate accounting treatment depending on the classification of the lease. Under the new standard, the accounting treatment associated with an operating lease will no longer exist, and lessees will be required to recognize assets and liabilities associated with all leased items. The standard is effective for fiscal years beginning on or after January 1, 2019 with early adoption permitted if the Company is also applying IFRS 15 Revenue from Contracts with Customers.

IFRS 16 will be adopted by the Company on January 1, 2019. TransGlobe is currently evaluating the impact of the standard including identifying and reviewing contracts that are impacted. The Company expects that the standard will have a material impact on the consolidated financial statements and additional new disclosures.

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 the IASB, focusing in particular on controls over information contained in the annual and interim financial statements. 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 control over financial reporting during the three months ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

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