MANAGEMENT'S DISCUSSION AND ANALYSIS

March 13, 2019

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

READER ADVISORIES

Forward-Looking Statements

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

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

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

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

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

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

2018 1

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

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

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

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

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

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

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

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

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

NON-GAAP FINANCIAL MEASURES

Funds flow from operations

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

Reconciliation of funds flow from operations

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

Net debt-to-funds flow from operations ratio

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

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

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

Netback

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

2 2018

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

MANAGEMENT STRATEGY AND OUTLOOK

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

2019 Outlook

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

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

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

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

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

2019 Capital Budget

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

Egypt

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

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

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

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

2018 3

Canada

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

The 2019 capital program is summarized in the following table:

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

4 2018

SELECTED ANNUAL INFORMATION

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

In 2018 compared with 2017, TransGlobe:

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

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

2018 5

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

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

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

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

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

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

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

6 2018

SELECTED QUARTERLY FINANCIAL INFORMATION

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

During the fourth quarter of 2018, TransGlobe:

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

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

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

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

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

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

2018 7

BUSINESS ENVIRONMENT

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

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

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

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

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

OPERATING RESULTS AND NETBACK

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

Production Volumes

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

Sales Volumes (excludes volumes held as inventory)

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

8 2018

Netback

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

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

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

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

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

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

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

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

2018 9

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)

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

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

FINANCE COSTS

($000s)	2018		2017
Convertible debentures1	$	—	$	1,089
Long-term debt	4,275		3,994
Note payable2	—		532
Reserves based lending facility	440		289
Amortization of deferred financing costs	360		329
Finance costs	$	5,075	$	6,233
1  The convertible debentures matured on March 31, 2017 and were repaid in full on that date for their aggregate face value of C$97.8 million ($73.4 million).
2  The Company repaid the outstanding vendor take-back note balance of C$13.6 million ($10.0 million) on May 16, 2017.

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

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

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

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

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

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

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

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

IMPAIRMENT LOSS

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

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

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

For the year ended December 31, 2017 the Company recorded an impairment loss of $79.0 million on its E&E assets. The impairment loss was split between the South West Gharib concession ($1.2 million), the North West Gharib concession ($67.5 million) and the South Alamein concession ($10.3 million).

10 2018

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

CAPITAL EXPENDITURES

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

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

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

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

OUTSTANDING SHARE DATA

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

LIQUIDITY AND CAPITAL RESOURCES

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

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

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

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

As at December 31, 2018, the Company's cash equivalents balance consisted of short-term deposits with an original term to maturity at purchase of three months or less. All of the Company's cash and cash equivalents are on deposit with high credit-quality financial institutions.

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

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

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

2018 11

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

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

PRODUCT INVENTORY

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

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

Inventory reconciliation

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

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

COMMITMENTS AND CONTINGENCIES

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

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

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

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

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

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

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

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

12 2018

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

ASSET RETIREMENT OBLIGATION

As at December 31, 2018, TransGlobe had an asset retirement obligation ("ARO") of $12.1 million (December 31, 2017 - $12.3 million) for the future abandonment and reclamation costs of the Canadian assets. The estimated ARO liability includes assumptions of actual costs to abandon and/or reclaim wells and facilities, the time frame in which such costs will be incurred, as well as inflation factors in order to calculate the undiscounted total future liability. TransGlobe calculated the present value of the obligations using discount rates between 1.86% and 2.18% to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates.

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

DERIVATIVE COMMODITY CONTRACTS

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

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

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

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

OFF BALANCE SHEET ARRANGEMENTS

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

RISKS AND UNCERTAINTIES

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

Financial risk

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

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

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

2018 13

Market risk

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

Commodity price risk

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

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

Foreign currency exchange risk

As the Company’s business is conducted primarily in US dollars and its financial instruments are primarily denominated in US dollars, the Company’s exposure to foreign currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, long-term debt and accounts payable and accrued liabilities denominated in Canadian dollars. When assessing the potential impact of foreign currency exchange risk, the Company believes that 10% volatility is a reasonable measure. The Company estimates that a 10% increase in the value of the Canadian dollar against the US dollar would decrease the net earnings for the year ended December 31, 2018 by approximately $1.5 million and conversely a 10% decrease in the value of the Canadian dollar against the US dollar would increase net earnings by $1.2 million for the same period. The Company does not utilize derivative instruments to manage this risk.

The Company is also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while the Company is generally able to spend the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates, the average Egyptian pound cash balance for 2018 was $2.0 million (2017 - $0.8 million) in equivalent US dollars. The Company estimates that a 10% increase in the value of the Egyptian pound against the US dollar would decrease net earnings for the year ended December 31, 2018 by approximately $0.2 million and conversely a 10% decrease in the value of the Egyptian pound against the US dollar would increase net earnings by $0.2 million for the same period. The Company does not currently utilize derivative instruments to manage foreign currency exchange risk.

Interest rate risk

Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable interest debt. No derivative contracts were entered into during 2018 to mitigate interest rate risk. When assessing interest rate risk applicable to the Company’s variable interest, US dollar-denominated debt the Company believes 1% volatility is a reasonable measure. The effect of interest rates increasing by 1% would decrease the Company’s net earnings, for the year ended December 31, 2018, by $0.5 million and conversely the effect of interest rates decreasing by 1% would increase the Company’s net earnings, for the year ended December 31, 2018, by $0.5 million.

Credit risk

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

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

Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. Liquidity describes a company’s ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash to fund capital programs necessary to maintain and increase production and proved reserves, to acquire strategic oil and gas assets and to repay debt.

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

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

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

Operational risk

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

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

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

Safety, environmental, social and regulatory risk

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

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

Political risk

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

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

Oil and gas reserves

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

Production sharing concessions

International operations conducted pursuant to PSCs are reflected in the Consolidated Financial Statements based on the Company's working interest in such operations. Under the PSCs, the Company and other non-governmental partners pay all operating and capital costs for exploring and developing the concessions. Each PSC establishes specific terms for the Company to recover these costs and to share in the production sharing oil. Cost recovery oil is determined in accordance with a formula that is generally limited to a specified percentage of production during each quarter. Production sharing oil is that portion of production remaining after cost recovery oil and is shared between the joint interest partners and the government of each country, varying with the level of production. Production sharing oil that is attributable to the government includes an amount in respect of all income taxes payable by the Company under the laws of the respective country. Revenue represents the Company's share and is recorded net of royalty payments to government and other mineral interest owners. For the Company's international operations; all government

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interests, except for income taxes, are considered royalty payments. The Company's revenue also includes the recovery of costs paid on behalf of foreign governments in international locations.

FUTURE CHANGES IN ACCOUNTING POLICIES

IFRS 16 "Leases"

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

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

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

DISCLOSURE CONTROLS AND PROCEDURES

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

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

INTERNAL CONTROLS OVER FINANCIALREPORTING

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

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

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