2018 SECOND QUARTER INTERIM REPORT

Financial and Operating Results

For the three and six months ended June 30, 2018

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

ø	Second quarter production averaged 13,779 boepd (Egypt 11,912 bopd, Canada 1,867 boepd) with Canadian production impacted during May by a scheduled gas plant turnaround;
ø	Second quarter sales averaged 19,301 boepd due to increased cargo liftings during the quarter;
ø	Positive second quarter funds flow of $33.5 million ($0.46 per share). Before unrealized hedging losses, funds flow was $44.3 million ($0.61 per share);
ø	Second quarter net earnings of $7.4 million inclusive of an unrealized loss of $10.8 million and a realized loss of $5.8 million on derivative commodity contracts;
ø	Drilled three oil wells in Egypt (K45, Arta 54 & NWG 38A) and commissioned the K-station phase 2 expansion during the quarter;
ø	Subsequent to the quarter, drilled three wells in Egypt resulting in one oil well (M-North) and two dry holes (NWS 9X & SGZ 1X);
ø	Acquired 16 net sections (10,240 acres) of Crown exploratory Cardium rights year to date, south of the Harmattan Cardium pool and increased the 2018 Budget to drill a horizontal evaluation Cardium well on the newly acquired lands prior to year-end;
ø	Finalized the 2018 Canadian drilling plan, targeting 6 gross (5 net) Cardium horizontal development wells (including one extended reach 2 mile horizontal well) and one Cardium horizontal evaluation well;
ø	The Company's common shares were admitted to the AIM market of the London Stock Exchange and began trading under the ticker “TGL” on June 29, 2018. In addition, the Company intends to establish an executive office in London in September 2018.
ø	Sold two cargoes of TransGlobe's entitlement crude oil for net proceeds totaling $53.3 million (sale proceeds collected in May and July) and sold 82,361 barrels of inventoried entitlement crude oil to EGPC for $4.6 million;
ø	Ended the quarter with positive working capital of $60.5 million, including cash and cash equivalents of $38.1 million. The Company expects to fund its remaining 2018 capital program, accelerate debt repayments and explore business development opportunities with its working capital;
ø	Spent $5.9 million on exploration and development assets during the quarter;
ø	Subsequent to quarter-end, lifted the third cargo of 2018 on July 19th, a total of ~501 thousand barrels, for estimated proceeds of $32 million. The timing of the next cargo is expected to be finalized in Q3;
ø	Subsequent to quarter-end, the corporation declared a dividend of $0.035 per share payable September 14, 2018 to shareholders of record on August 31, 2018.

A conference call to discuss TransGlobe's 2018 second quarter results as presented was held on Tuesday, August 14, 2018 and can be accessed on the Company's website at http://www.trans-globe.com/investors/presentations-and-events/index.php

www.trans-globe.com

TSX & AIM: TGL NASDAQ: TGA

CONTENTS

Financial and Operating Results	Page 3
Corporate Summary	Page 4
Operations Update	Page 5
Management's Discussion and Analysis	Page 8
Condensed Consolidated Interim Financial Statements	Page 22
Notes to Condensed Consolidated Interim Financial Statements	Page 26

2 Q2-2018

FINANCIAL AND OPERATING RESULTS

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

	Three Months Ended June 30					Six Months Ended June 30
Financial	2018		2017		% Change	2018		2017		% Change
Petroleum and natural gas sales	99,220		64,711		53	152,171		111,265		37
Petroleum and natural gas sales, net of royalties	68,454		40,439		69	93,169		62,900		48
Realized derivative gain (loss) on commodity contracts	(5,781	)	1,529		(478)	(5,899	)	1,529		(486)
Unrealized derivative gain (loss) on commodity contracts	(10,816	)	6,578		(264)	(16,862	)	2,849		(692)
Production and operating expense	17,299		15,079		15	27,940		25,400		10
Selling costs	1,080		1,502		(28)	1,126		1,502		(25)
General and administrative expense	7,583		3,362		126	11,579		7,808		48
Depletion, depreciation and amortization expense	10,478		10,363		1	17,326		18,875		(8)
Income taxes expense	6,785		5,505		23	12,804		10,925		17
Cash flow generated (used) in operating activities	18,886		(2,753	)	786	11,731		(5,250	)	323
Funds flow from operations1	33,499		16,855		99	37,422		19,357		93
Basic per share	0.46		0.23			0.52		0.27
Diluted per share	0.46		0.23			0.52		0.27
Net earnings (loss)	7,361		(56,622	)	113	(2,759	)	(69,499	)	96
Basic per share	0.10		(0.78	)		(0.04	)	(0.96	)
Diluted per share	0.10		(0.78	)		(0.04	)	(0.96	)
Capital expenditures	5,855		8,230		(29)	10,490		18,948		(45)
Working capital	60,464		60,319		—	60,464		60,319		—
Long-term debt, including current portion	62,173		83,725		(26)	62,173		83,725		(26)
Common shares outstanding
Basic (weighted average)	72,206		72,206		—	72,206		72,206		—
Diluted (weighted average)	72,851		72,206		1	72,606		72,206		1
Total assets	329,542		337,596		(2)	329,542		337,596		(2)
Operating
Average production volumes (boepd)	13,779		16,465		(16)	14,076		16,597		(15)
Average sales volumes (boepd)	19,301		19,259		—	15,548		16,558		(6)
Inventory (bbls)	510,255		1,274,057		(60)	510,255		1,274,057		(60)
Average sales price ($ per Boe)	56.49		36.92		53	54.07		37.13		46
Operating expense ($ per Boe)	9.85		8.52		16	9.93		8.36		19
Notes:
1 Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies.

Average reference prices	2018	2017
	Q-2	Q-1	Q-4	Q-3	Q-2
Crude oil
Dated Brent average oil price (US$/bbl)	74.50	66.81	61.53	52.11	49.67
Edmonton Sweet index (US$/bbl)	62.43	56.98	54.26	45.32	46.03
Natural gas
AECO (C$/mmbtu)	1.18	2.08	1.69	1.45	2.78
US/Canadian Dollar average exchange rate	1.291	1.264	1.270	1.247	1.345

Q2-2018 3

CORPORATE SUMMARY

TransGlobe Energy Corporation ("TransGlobe" or the "Company") produced an average of 13,779 barrels of oil equivalent per day ("boepd") during the second quarter of 2018. Production was impacted by an extensive workover program in Egypt at West Bakr and a turnaround in Canada that occurred during the quarter. Egypt production was 11,912 barrels of oil per day ("bopd") and Canada production was 1,867 boepd.

During the quarter, the Company completed two cargo liftings for a total of 902,467 barrels of entitlement crude oil with net proceeds of $53.3 million. TransGlobe also sold 82,361 barrels of inventoried entitlement crude oil to EGPC during the quarter for $4.6 million. As at June 30, 2018 the Company had approximately 0.5 million barrels of inventoried entitlement crude oil. Subsequent to quarter-end, the Company lifted approximately 501,000 barrels ("bbls") of entitlement crude oil on July 19, for estimated net proceeds of $32 million to be received in mid-August. All Canadian production was sold during the quarter.

TransGlobe's Egyptian crude oil is sold at a quality discount to Dated Brent. The Company received an average price of $59.39 per barrel during the quarter. In Canada, the Company received an average of $60.87 per barrel of oil and $1.08 per thousand cubic feet ("mcf") of natural gas in the second quarter of 2018.

During the second quarter of 2018, the Company had funds flow from operations of $33.5 million and ended the quarter with positive working capital of $60.5 million, including cash and cash equivalents of $38.1 million. The Company had net earnings in the quarter of $7.4 million, which included a $10.8 million unrealized loss on derivative commodity contracts. The loss on derivative commodity contracts represents a fair value adjustment on the Company's hedging contracts as at June 30, 2018.

In Egypt, the Company drilled three development oil wells during the second quarter of 2018. In West Bakr, the K-45 well was the second South K-field well drilled this year; the well was completed during May 2018 and is currently producing at a rate of 380 bopd. In West Gharib, the Arta 54 well was the second well drilled this year in the boundary area between the Arta pool and offsetting NWG development lease #3. The well was completed and placed on production at a pre-frac rate of 60+ bopd. Arta 54 was fraced and placed back on production in early August. The NWG 38A Injector well was also completed and confirmed oil in the lower portion of the Red Bed and will require a frac prior to producing.

The Company completed a four well (Arta 48, Arta 54, NWG 1AX, NWG 5X) stimulation program during May/June 2018 targeting Nukhul and tight Red Bed conglomerate wells. The wells have all been fraced and are being placed on production for post frac clean-up. It is expected that each of the wells will produce at an initial 30 day average rate of 120 to 150 bopd after recovering frac fluid based on offsetting producers.

During the second quarter, the Company spud NWS 9 targeting a stacked Cretaceous prospect. Subsequent to the quarter, the well was drilled to a total depth of 5,950 feet with no signs of hydrocarbons and was abandoned. Subsequent to quarter-end, the Company has mobilized a 2,000 HP drilling rig to NWS 12 targeting a stacked Cretaceous/Jurassic prospect. The well has been spud and the Company anticipates drilling time of approximately 60 days for the prospect.

Subsequent to the quarter, the Company drilled the first of two planned exploration wells in the south western portion of South Ghazalat Concession (“SGZ”). SGZ 1X was drilled to a total depth of 3,068 feet with no hydrocarbon shows and abandoned for a total cost of ~$0.7 million. Based on the SGZ 1X results, the planned SGZ 2X well was cancelled in favour of an alternate exploration prospect (SGZ 6X) located on the eastern portion of the concession offsetting the Raml oil field in the Abu Gharadig basin. The SGZ 6X prospect is targeting stacked Cretaceous targets similar to the Raml and SW Raml fields. It is expected that SGZ 6X will be drilled in October following mine clearance and lease construction.

In Canada, a planned turnaround at the main third-party owned and operated natural gas processing plant in Harmattan resulted in the majority of the Company's Canadian production being shut-in during the month of May. During this period, the Company completed a 3 week maintenance program at its central oil processing battery and main natural gas compressor site. The 2018 production guidance numbers include the planned turnaround. The Cardium development drilling program is scheduled to commence in August 2018, consisting of six horizontal wells (5 net), including one two-mile horizontal, which will be drilled from a common pad to improve efficiencies and reduce costs.

TransGlobe was admitted to the London Stock Exchange’s AIM under the ticker “TGL” on June 29, 2018. TransGlobe retained Canaccord Genuity as its nominated advisor (“NOMAD”) to support the listing on the AIM.

4 Q2-2018

OPERATIONS UPDATE

ARAB REPUBLIC OF EGYPT

EASTERN DESERT

West Gharib, Arab Republic of Egypt (100% working interest, operated)

Operations and Exploration

During the second quarter of 2018, the Arta-54 development well in the Arta Red Bed pool was drilled to a depth of 3,711 feet and encountered approximately 128 feet of Nukhul/Red Bed formation with an internally estimated 24.5 feet of net oil pay. The well was completed and placed on production at a pre-frac rate of 60+ bopd. The well was fraced and is currently producing at a rate of 205 bopd. This is the second well drilled this year in the boundary area between the Arta pool and the offsetting NWG development lease #3.

The Arta-48 development well that was originally drilled in the first quarter, had a fracture stimulation completed in May and is currently producing at a rate of 200 bopd.

Production

Production from West Gharib averaged 5,015 bopd to TransGlobe during the second quarter of 2018, a 2% (89 bopd) decrease from the previous quarter primarily due to natural declines which were partially offset by the new stimulated wells at Arta 48 and 54.

Production averaged 5,068 bopd during July.

Sales

The Company sold 82,361 barrels of inventoried entitlement crude to EGPC for $4.6 million and sold an additional 123,251 barrels of inventoried entitlement crude to a third-party for $7.7 million in Q2-2018.

Quarterly West Gharib Production (bopd)	2018			2017
	Q-2	Q-1		Q-4	Q-3
Gross production rate	5,015	5,104		5,015	5,741
TransGlobe working interest	5,015	5,104		5,015	5,741
TransGlobe production inventoried (sold)	297	(21	)	774	(5,715	)
Total sales	4,718	5,125		4,241	11,456
Government share (royalties and tax)	2,459	2,504		2,459	2,826
TransGlobe sales (after royalties and tax)1	2,259	2,621		1,782	8,630
Note:
1 Under the terms of the West Gharib Production Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing oil.

West Bakr, Arab Republic of Egypt (100% working interest, operated)

Operations and Exploration

During the second quarter of 2018, the K-45 development well was drilled to a total depth of 5,831 feet and encountered the main Asl A sand approximately 66 feet structurally higher than the K-46 well and is structurally the highest well in South K-field Asl A & B pools. The well encountered an internally estimated 195 feet of net oil pay, comprising of 120 feet of net oil pay in the Asl A pool (A1, A2, and A3) and 75 feet in the Asl B pool. The well was completed in May and is currently producing at a rate of 380 bopd from the Asl B pool.

Subsequent to the quarter, drilling commenced on a two well infill program (M-North and M-South) targeting the main Asl A formation in the M pool inside the reduced buffer zone between the West Bakr M field and the adjacent GPC Mesada field to the west. M-North was drilled to a total depth of 1,559 meters and cased as an Asl A oil well. M-North encountered an internally estimated 132 feet of net Asl A oil pay. The M-North well is scheduled for completion in August. Drilling will commence on the M-South location in mid-August. Following M-South, the rig is scheduled to move to NW Gharib to drill a potential water injector in the NWG 38A pool.

During the quarter, the Company completed construction of the Phase 2 K-field facility expansion to double the current fluid handling capacity from 15,000 bpd to 30,000 bpd of fluid and initiated a well optimization campaign targeting wells with excess production capacity that had been constrained due to fluid handling at K station.  The Phase 2 K-field facility expansion was commissioned during the quarter along with additional water handling capacity to handle the increased fluid production. Concurrently the H station phase 2 facility expansion to increase fluid handling capacity from 10,000 bpd to 20,000 bpd is nearing completion with commissioning scheduled for August. The Phase 2 expansions at K and H stations will allow for accelerated fluid withdrawal rates supporting incremental production volumes and additional reserves from the K and M fields in K station; and the H fields in H station.

Construction will commence on Phase 3 expansions to add a third process train and triple the respective original facility capacities in K and H stations by early 2019.

Q2-2018 5

Production

Production from West Bakr averaged 5,747 bopd to TransGlobe during the second quarter, representing a 9% (473 bopd) increase from the previous quarter due to increased production associated with the K station phase 2 facility expansion and the successful K-45 development well.

Production averaged 6,160 bopd during July primarily due to the facility expansion at K station and associated well optimization.

Sales

The Company sold 779,217 barrels of inventoried entitlement crude to third parties through two cargo liftings for $45.6M million in Q2-2018.

Quarterly West Bakr Production (bopd)	2018			2017
	Q-2		Q-1	Q-4		Q-3
Gross production rate	5,747		5,274	5,024		5,651
TransGlobe working interest	5,747		5,274	5,024		5,651
TransGlobe production inventoried (sold)	(6,235	)	2,136	(3,511	)	2,288
Total sales	11,982		3,138	8,535		3,363
Government share (royalties and tax)	3,419		3,138	2,990		3,363
TransGlobe sales (after royalties and tax)1	8,563		—	5,545		—
Note:
1 Under the terms of the West Bakr Production Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing oil.

North West Gharib, Arab Republic of Egypt (100% working interest, operated)

Operations and Exploration

During the second quarter of 2018 the NWG 38A-Inj injector well was drilled to a total depth of 5,552 feet and was initially planned as a water injector well. The well encountered 92 feet of Red Bed with an internally estimated net oil pay of 34 feet. The NWG-38A-Inj well has extended the NWG 38 pool Red Bed zone to the south by 0.4 kilometers and is approximately 83 feet structurally lower than the NWG 38A-2 well, which was the previous lowest known oil in the pool. The well was completed in June and has confirmed oil in the lower portion of the Red Bed. The well is currently under evaluation as stimulation alternatives are considered.

Following the M-South well in West Bakr, the Company has scheduled an additional well (NWG 38A-7) targeting the Red Bed pool in a structurally lower position approximately 0.4 kilometers southeast of NWG 38A-Inj. Should the NWG 38A-7 well also encounter additional oil column, the Company has planned an additional well further south at NWG 38A-8 as a contingency for reservoir pressure support.

Production

Production from NW Gharib averaged 1,151 bopd to TransGlobe during the second quarter, a 18% (247 bopd) decrease from the previous quarter, primarily due to natural declines and curtailed production from the NWG 38A pool to manage pressure declines prior to water injection.

Production averaged 1,083 bopd during July.

Sales

TransGlobe did not sell its entitlement share of production from NW Gharib during the quarter.

Quarterly North West Gharib Production (bopd)	2018		2017
	Q-2	Q-1	Q-4	Q-3
Gross production rate	1,151	1,399	1,212	876
TransGlobe working interest	1,151	1,399	1,212	876
TransGlobe production inventoried (sold)	417	507	439	318
Total sales	734	892	773	558
Government share (royalties and tax)	734	892	773	558
TransGlobe sales (after royalties and tax)1	—	—	—	—
Note:
1 Under the terms of the North West Gharib Production Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing oil.

WESTERN DESERT

South Alamein, Arab Republic of Egypt (100% working interest, operated)

Operations and Exploration

No wells were drilled during the quarter.

The Company received a seven-month extension (January 2019) to the final exploration phase to reapply for access to drill the SA-24X prospect, which has been submitted.

6 Q2-2018

No production is currently budgeted from the South Alamein exploration asset in 2018.

North West Sitra, Arab Republic of Egypt (100% working interest, operated)

Operations and Exploration

During the second quarter of 2018, the Company commenced drilling the first of two planned exploration wells in North West Sitra (“NWS”) at NWS 9X targeting a stacked Cretaceous prospect. Subsequent to the quarter, the well was drilled to a total depth of 5,950 feet with no signs of hydrocarbons and was abandoned for a total cost of ~$1.0 million.

Subsequent to the quarter, the Company commenced drilling NWS 12X in late July following acceptance testing of a larger drilling rig (2,000 hp). NWS 12X is targeting a stacked Cretaceous/Jurassic prospect with an estimated drilling time of approximately 60 days.

No production is currently budgeted from the Western Desert exploration assets in 2018.

South Ghazalat, Arab Republic of Egypt (100% working interest, operated)

Operations and Exploration

No wells were drilled during the second quarter of 2018.

Subsequent to the quarter, the Company drilled the first of two planned exploration wells in the south western portion of South Ghazalat Concession (“SGZ”). SGZ 1X was drilled to a total depth of 3,068 feet with no hydrocarbon shows and abandoned for a total cost of ~$0.7 million. Based on the SGZ 1X results, the planned SGZ 2X well was cancelled in favour of an alternate exploration prospect (SGZ 6X) located on the eastern portion of the concession offsetting the Raml oil field in the Abu Gharadig basin. The drilling rig was released following SGZ 1X. The SGZ 6X prospect is targeting stacked Cretaceous targets similar to the Raml and SW Raml fields. It is expected that SGZ 6X will be drilled in October following mine clearance and lease construction.

CANADA

Operations and Exploration

No wells were drilled during the second quarter of 2018.

During May, the Company completed a three week turnaround/maintenance program on the Company’s central oil processing battery and the main natural gas compressor. The work was planned to coincide with a scheduled turnaround at the main natural gas processing plant in the Harmattan area, which is operated by a third-party. The majority of the Canadian production was shut-in during May to accommodate this outage. Production was brought back online on May 26th, 2018. The third-party operated gas plant should not require a similar scheduled shutdown for a five-year period. The 2018 production guidance numbers included the planned turnaround.

The Company has finalized the 2018 Cardium development drilling program, anticipated to commence in late August/early September. The program will include six gross (five net) horizontal Cardium development wells to be drilled from a common pad to improve efficiencies and reduce costs. The Company is planning to drill one two-mile extended reach horizontal (“ERH”) well to evaluate the performance of ERH wells in the Harmattan area. The remainder of the 2018 drilling program will consist of one-mile horizontal wells.

Year to date, the Company has acquired 16 net sections (10,240 acres) of Cardium prospective exploration lands to the south/south west of the Harmattan pool during 2018. These lands were acquired at Crown land sales at an average cost of less than C$63.00/acre ($49.4/acre). The Company has approved an increase to the 2018 capital program to drill an exploratory horizontal well on the new lands to evaluate a portion of the newly acquired Cardium rights. If successful, the new lands could provide a significant development opportunity which is proximal to the Company's Harmattan production and facilities. The Harmattan Cardium pool has typically been developed by drilling four horizontal wells per section.

Production

Production from Canada averaged 1,867 boepd to TransGlobe during the second quarter, a 28% (731 boepd) decrease from the previous quarter, primarily due to the planned shut-in for the turnaround program in May.

Production has averaged 2,383 boepd during July.

Quarterly Canada Production (boepd)	2018		2017
	Q-2	Q-1	Q-4	Q-3
Canada crude oil (bbls/d)	497	675	775	518
Canada NGLs (bbls/d)	521	894	915	1,081
Canada natural gas (mcf/d)	5,094	6,176	6,058	6,268
Total production (boe/d)	1,867	2,598	2,700	2,644

Q2-2018 7

MANAGEMENT'S DISCUSSION AND ANALYSIS

August 14, 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 six months ended June 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, collection of accounts receivable from the Egyptian Government, 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, 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.

8 Q2-2018

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. The Company has reduced the upper end of production guidance due to minor 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 (mid-point of 14,500 boepd) 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 $9.85 per barrel of oil equivalent ("boe") in Q2-2018. The increase was mainly due to workovers and 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 Company’s capital program includes drilling six gross Cardium horizontal development wells in Canada during the remainder of 2018. 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)	1.25	1.50	1.75	2.00	2.25
Netback ($/boe)
Egypt - crude oil1	2.92	7.15	11.39	15.63	19.87
Canada - crude oil2	21.12	28.41	35.29	42.31	49.35
Canada - natural gas and NGLs2	0.71	1.79	2.89	4.66	6.42
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 ~$9.60/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 $5.50 per bbl, Edmonton Light to Harmattan discount of C$2.50 per bbl, operating costs estimated at ~C$10.25/boe, NGL mixture price at 45% of Edmonton Light, and takes into consideration Canadian tax pools.

The Board has decided to resume dividend payments to shareholders.  The Company will aspire 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 Board has approved a dividend payment to shareholders of $0.035/share payable 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.

Q2-2018 9

Reconciliation of funds flow from operations

	Three Months Ended June 30			Six Months Ended June 30
($000s)	2018	2017		2018	2017
Cash flow from operating activities	18,886	(2,753	)	11,731	(5,250	)
Changes in non-cash working capital	14,613	19,608		25,691	24,607
Funds flow from operations1	33,499	16,855		37,422	19,357
Note:
1  Funds flow from operations does not include interest costs. Interest expense is included in financing costs on the Condensed Consolidated Interim Statements of Earnings (Loss) and Comprehensive Income (Loss). Cash interest paid is reported as a financing activity on the Condensed Consolidated Interim Statements of Cash Flows.

Net debt-to-funds flow from operations ratio

Net debt-to-funds flow from operations is a measure that is used 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.

10 Q2-2018

SELECTED QUARTERLY FINANCIAL INFORMATION

	2018			2017								2016
($000s, except per share,
price and volume amounts)	Q-2	Q-1		Q-4		Q-3		Q-2		Q-1		Q-43		Q-3
Operations
Average production volumes
Crude oil (bbls/d)	12,409	12,452		12,027		12,786		14,347		14,514		12,861		11,733
NGLs (bbls/d)	521	894		915		1,081		919		1,037		134		—
Natural gas (mcf/d)	5,094	6,176		6,059		6,268		7,191		7,075		916		—
Total (boe/d)	13,779	14,375		13,952		14,912		16,465		16,731		13,148		11,733
Average sales volumes
Crude oil (bbls/d)	17,931	9,830		14,324		15,894		17,141		11,610		7,018		11,485
NGLs (bbls/d)	521	894		915		1,081		919		1,037		134		—
Natural gas (mcf/d)	5,094	6,176		6,059		6,286		7,191		7,075		916		—
Total (boe/d)	19,301	11,753		16,249		18,020		19,259		13,826		7,305		11,485
Average realized sales prices
Crude oil ($/bbl)	59.39	56.26		53.25		44.82		39.46		41.66		37.38		34.43
NGLs ($/bbl)	38.39	27.72		26.86		18.90		21.08		19.08		12.33		—
Natural gas ($/mcf)	1.08	1.70		0.94		1.65		2.14		1.96		1.80		—
Total oil equivalent ($/boe)	56.49	50.06		48.80		41.24		36.92		37.41		36.45		34.43
Inventory (mbbls)	510	1,013		777		988		1,274		1,528		1,265		729
Petroleum and natural gas sales	99,220	52,951		72,954		68,372		64,712		46,553		24,501		36,376
Petroleum and natural gas sales, net of royalties	68,454	24,715		40,725		44,839		40,439		22,461		5,217		20,704
Cash flow from operating activities	18,886	(7,155	)	44,263		20,437		(2,753	)	(2,497	)	6,355		(14,857	)
Funds flow from operations1	33,499	3,923		17,018		19,217		16,855		2,502		(9,904	)	2,347
Funds flow from operations per share:
- Basic	0.46	0.05		0.24		0.27		0.23		0.03		(0.14	)	0.03
- Diluted	0.46	0.05		0.24		0.27		0.23		0.03		(0.14	)	0.03
Net earnings (loss)	7,361	(10,120	)	(2,382	)	(6,855	)	(56,622	)	(12,877	)	(33,997	)	(25,369	)
Net earnings (loss) per share:
- Basic	0.10	(0.14	)	(0.03	)	(0.09	)	(0.78	)	(0.18	)	(0.47	)	(0.35	)
- Diluted	0.10	(0.14	)	(0.03	)	(0.09	)	(0.78	)	(0.18	)	(0.49	)	(0.35	)
Capital expenditures	5,855	4,635		9,078		10,133		8,230		10,718		8,863		8,692
Property expenditures	—	—		—		—		—		—		59,475		—
Total assets	329,542	312,691		327,702		338,802		337,596		403,686		406,142		414,363
Cash and cash equivalents	38,088	31,084		47,449		21,464		13,780		21,324		31,468		100,405
Working capital	60,464	45,252		50,639		58,815		60,319		42,759		(16,764	)	53,029
Convertible debentures	—	—		—		—		—		—		72,655		74,854
Note payable	—	—		—		—		—		11,259		11,162		—
Total long-term debt, including      current portion	62,173	67,167		69,999		79,839		83,725		73,549		—		—
Net debt-to-funds flow from operations ratio2	0.02	0.36		0.30		0.70		2.00		(13.90	)	(12.00	)	(2.30	)
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 second quarter of 2018, TransGlobe:

• Reported positive working capital of $60.5 million, including $38.1 million in cash and cash equivalents, as at June 30, 2018;

• Reported net earnings of $7.4 million, inclusive of a $10.8 million unrealized derivative loss on commodity contracts (mark-to-market loss on the Company's hedging contracts);

• Experienced a 53% increase in petroleum and natural gas sales compared with Q2-2017, which was principally due to an overall improvement in commodity prices and the completion sale of two cargoes of entitlement crude oil during the quarter (one cargo Q2-2017). This increase was partially offset by the three-week turnaround at Harmattan and 80 boepd of natural gas production shut-in since May due to low commodity prices;

• Reported positive funds flow from operations of $33.5 million;

Q2-2018 11

• Reported a 16% decrease in production volumes as compared to Q2-2017 primarily due to natural declines in well production and workovers in Egypt, and to the May turnaround in Canada.

• Sold 82,361 bbls of inventoried entitlement crude oil to EGPC and ended Q2-2018 with crude oil inventory of 510 thousand barrels ("mbbls"); a decrease of 266 mbbls over crude inventory levels at December 31, 2017; and

• Spent $5.9 million on capital, which was funded entirely from funds flow from operations and cash on hand.

2018 TO 2017 NET EARNINGS VARIANCES

			$ Per Share
	$000s		Diluted		% Variance
Q2-2017 net loss	(69,499	)	(0.96	)
Cash items
Volume variance	(9,890	)	(0.13	)	14
Price variance	50,796		0.70		(73	)
Royalties	(10,637	)	(0.15	)	15
Expenses:
Production and operating	(2,540	)	(0.04	)	4
Selling costs	376		0.01		(1	)
Cash general and administrative	(738	)	(0.01	)	1
Current income taxes	(1,879	)	(0.03	)	3
Realized foreign exchange loss	87		—		—
Realized derivative loss	(7,428	)	(0.10	)	11
Interest on long-term debt	610		0.01		(1	)
Other income	175		—		—
Total cash items variance	18,932		0.26		(27	)
Non-cash items
Unrealized derivative loss	(19,711	)	(0.27	)	28
Unrealized foreign exchange gain	1		—		—
Unrealized loss on financial instruments	151		—		—
Depletion and depreciation	1,549		0.02		(2	)
Accretion	(16	)	—		—
Impairment loss	68,711		0.95		(99	)
Share-based compensation	(3,035	)	(0.04	)	4
Deferred lease inducement	2		—		—
Gain on asset disposition	202		—		—
Amortization of deferred financing costs	(46	)	—		—
Total non-cash items variance	47,808		0.66		(69	)
Q2-2018 net loss	(2,759	)	(0.04	)	(96	)

TransGlobe recorded a net loss of $2.8 million in the first six months of 2018 compared to a net loss of $69.5 million in the first six months of 2017. The average realized sales price in the first six months of 2018 was $54.07 per boe versus $37.13 per boe in the same period of the prior year. The 46% increase resulted in a positive cash variance of $50.8 million. The increase was partially offset by a reduction in sales volumes as well as increased royalties and current income tax expense, which created a combined negative earnings variance of $22.4 million. Operating expenses increased $2.5 million in Q2-2018 compared with Q2-2017 primarily as a result of workovers performed in both Egypt and Canada and cost pressures due to higher commodity prices. Cash general and administrative expenses increased $0.7 million in Q2-2018 compared with Q2-2017, principally related to expenses incurred during the process of listing on AIM. Interest on long-term debt expense decreased $0.6 million in the first six months of 2018 compared with 2017 mainly due to reduced debt balances through repayments and replacing its note payable with a lower-rate reserves-based facility. The company also incurred a large realized loss on its derivative commodity contracts in the first six months of 2018 due to higher oil prices.

The largest non-cash positive earnings variance item in 2018 compared to 2017 is an impairment loss of $68.7 million recorded on the Company's exploration and evaluation assets at North West Gharib in Q2-2017; no such impairment was made in in the first six months of 2018. There was a negative non-cash variance of $19.7 million related to the unrealized derivative loss on commodity contracts resulting from changes in the market price of oil causing fluctuations in the mark-to-market amount of the Company's oil derivatives. The Company incurred larger share-based compensation costs in the first six months of 2018 resulting in a negative earnings variance of $3.0 million. The increase in share-based compensation was the result of a significant increase in the price of TransGlobe's shares during 2018 and new grants occurring during the quarter.

12 Q2-2018

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-2	Q-1	Q-4	Q-3	Q-2
Crude oil
Dated Brent average oil price (US$/bbl)	74.50	66.81	61.53	52.11	49.67
Edmonton Sweet index (US$/bbl)	62.43	56.98	54.26	45.32	46.03
Natural gas
AECO (C$/mmbtu)	1.18	2.08	1.69	1.45	2.78
US/Canadian Dollar average exchange rate	1.291	1.264	1.270	1.247	1.345

In Q2-2018, the price of Dated Brent oil averaged 50% and 12% higher than Q2-2017 and Q1-2018, 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.

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 June 30, 2018, amounts owing from EGPC were $10.0 million. The Company considers there to be minimal credit risk associated with EGPC's delays.

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 second quarter of 2018, the price of Edmonton Sweet index oil expressed in USD averaged 36% and 10% higher compared with Q2-2017 and Q1-2018, respectively. In Q2-2018, the price of the AECO natural gas average decreased 58% and 43% compared with Q2-2017 and Q1-2018, respectively.

Q2-2018 13

OPERATING RESULTS AND NETBACK

Daily volumes, working interest before royalties (boepd)

Production Volumes
	Three Months Ended June 30		Six Months Ended June 30
	2018	2017	2018	2017
Egypt crude oil (bbls/d)	11,912	13,851	11,845	13,900
Canada crude oil (bbls/d)	497	496	585	530
Canada NGLs (bbls/d)	521	919	707	978
Canada natural gas (mcf/d)	5,094	7,191	5,632	7,133
Total Company (boe/d)	13,779	16,465	14,076	16,597

Sales Volumes (excludes volumes held as inventory)
	Three Months Ended June 30		Six Months Ended June 30
	2018	2017	2018	2017
Egypt crude oil (bbls/d)	17,434	16,645	13,317	13,861
Canada crude oil (bbls/d)	497	496	585	530
Canada NGLs (bbls/d)	521	919	707	978
Canada natural gas (mcf/d)	5,094	7,191	5,632	7,133
Total Company (boe/d)	19,301	19,259	15,548	16,558

Netback

Consolidated Netback
	Six Months Ended June 30
	2018		2017
(000s, except per boe amounts)1	$	$/boe	$	$/boe
Petroleum and natural gas sales	152,171	54.07	111,265	37.13
Royalties and other2	59,002	20.97	48,365	16.14
Current taxes2	12,804	4.55	10,925	3.65
Production and operating expenses	27,940	9.93	25,400	8.48
Selling costs	1,126	0.40	1,502	0.50
Netback	51,299	18.22	25,073	8.36
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the six month periods ended June 30, 2018 and June 30, 2017 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 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 June 30
	2018		2017
(000s, except per boe amounts)1	$	$/boe	$	$/boe
Petroleum and natural gas sales	99,220	56.49	64,712	36.92
Royalties and other2	30,766	17.52	24,273	13.85
Current taxes2	6,785	3.86	5,505	3.14
Production and operating expenses	17,299	9.85	15,079	8.60
Selling costs	1,080	0.61	1,502	0.86
Netback	43,290	24.65	18,353	10.47
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the three month periods ended June 30, 2018 and June 30, 2017 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 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.

14 Q2-2018

Egypt
	Six Months Ended June 30
	2018		2017
(000s, except per bbl amounts)1	$	$/bbl	$	$/bbl
Oil sales	140,449	58.27	100,581	40.09
Royalties2	57,346	23.79	46,037	18.35
Current taxes2	12,804	5.31	10,925	4.35
Production and operating expenses	23,667	9.82	22,102	8.81
Selling costs	1,126	0.47	1,502	0.60
Netback	45,506	18.88	20,015	7.98
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended June 30, 2018 and June 30, 2017 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 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 June 30
	2018		2017
(000s, except per bbl amounts)1	$	$/bbl	$	$/bbl
Oil sales	94,147	59.34	59,541	39.31
Royalties2	30,375	19.15	23,122	15.27
Current taxes2	6,785	4.28	5,505	3.63
Production and operating expenses	15,205	9.58	13,556	8.95
Selling costs	1,080	0.68	1,502	0.99
Netback	40,702	25.65	15,856	10.47
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended June 30, 2018 and June 30, 2017 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 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 145% and 137%, respectively, in the three and six months ended June 30, 2018 compared with the same periods in 2017. The increased netbacks were principally the result of sales of inventory and an increase in realized oil prices of 51% and 45%, respectively, partially offset by an increase in operating costs per barrel of 7% and 11%, respectively, in the three and six months ended June 30, 2018 compared with the same periods in 2017.

Production and operating expenses increased by $1.6 million in both the three and six months ended June 30, 2018, compared with the same period in 2017. The increase was principally due to an extensive workover program in Q2-2018 as well as upward pressure on diesel, transportation and service costs due to stronger oil prices. On a per bbl basis, production and operating costs increased by 7% and 11% for the three and six month periods ended June 30, 2018, respectively. TransGlobe completed two direct sales of crude oil to third-party buyers during Q2-2018.

Royalties and taxes as a percentage of revenue were 39% and 50%, in the three and six month periods ended June 30, 2018, respectively, compared to 48% and 57% for the comparative 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 six month periods ended June 30, 2018, royalties and taxes as a percentage of revenue would have been 58% and 56%, respectively (2017 - 58% and 56%). In periods when the Company sells less than its entitlement production, royalties and taxes as a percentage of revenue will be higher than the terms of the PSCs 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 June 30, 2018 was $59.34/bbl (Q2-2017 - $39.31), which was $15.16/bbl lower than the average Dated Brent oil price of $74.50/bbl for the period (Q2-2017 - $49.67/bbl). The difference between the average selling price in Q2-2018 and the Dated Brent price is due to a gravity/quality adjustment and is also impacted by the specific timing of direct sales.

Canada
	Six Months Ended June 30
	2018		2017
(000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	6,225	58.79	4,494	46.85
Natural gas sales	1,447	8.52	2,645	12.29
NGL sales	4,050	31.65	3,545	20.02
Total sales	11,722	29.03	10,684	21.89
Royalties	1,656	4.10	2,328	4.77
Production and operating expenses	4,273	10.58	3,298	6.76
Netback	5,793	14.35	5,058	10.36

Q2-2018 15

Canada
	Three Months Ended June 30
	2018		2017
(000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	2,753	60.87	2,007	44.47
Natural gas sales	500	6.47	1,400	12.84
NGL sales	1,820	38.39	1,763	21.08
Total sales	5,073	29.86	5,170	21.74
Royalties	391	2.30	1,151	4.84
Production and operating expenses	2,094	12.31	1,523	6.41
Netback	2,588	15.25	2,496	10.49

Netbacks in Canada were $15.25 and $14.35 per boe for the three and six months ended June 30, 2018 respectively, which represents an increase of $4.76 and $3.99 per boe compared with the same periods of 2017. The increase is mainly due to an increase in the total realized sales price of $8.12 and $7.14 per boe from the comparative three and six month periods of 2017, respectively. These were partially offset by increases of 92% and 57% in production and operating expenses on a per boe basis for the three and six month periods, respectively. The increase in operating costs is primarily attributed to the three-week turnaround at Harmattan and increased costs associated with a colder than normal winter. For the three and six months ended June 30, 2018, the Company's Canadian operations incurred $0.4 million and $1.7 million in royalty costs, respectively, compared with $1.2 million and $2.3 million for the same periods in 2017. The reduction in royalties is primarily due to Gas Cost Allowance (GCA) rebates received in Q2-2018. Royalties amounted to 8% and 14% of petroleum and natural gas sales revenue during the three and six months ended June 30, 2018 compared to 22% during both the three and six 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.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)

	Six Months Ended June 30
	2018				2017
(000s, except boe amounts)	$		$/boe		$		$/boe
G&A (gross)	8,484		3.01		8,380		2.80
Share-based compensation	3,685		1.31		650		0.22
Capitalized G&A and overhead recoveries	(590	)	(0.21	)	(1,222	)	(0.41	)
G&A (net)	11,579		4.11		7,808		2.61

	Three Months Ended June 30
	2018				2017
(000s, except boe amounts)	$		$/boe		$		$/boe
G&A (gross)	4,461		2.54		3,631		2.07
Share-based compensation	3,418		1.95		421		0.24
Capitalized G&A and overhead recoveries	(296	)	(0.17	)	(690	)	(0.39	)
G&A (net)	7,583		4.32		3,362		1.92

G&A (gross) for the three months ended June 30, 2018 increased 23% compared with the same period in 2017. This increase was primarily due to costs related to the AIM listing that were not incurred in the comparative period. For the six months ended June 30, 2018 G&A (gross) is flat versus the same period in 2017 due to the increase in G&A related to the 2018 AIM listing offset by a reduction of certain expenses in 2017.

Share-based compensation expense for the three and six months ended June 30, 2018 increased by 712% and 467%, respectively compared with the same periods in 2017. This increase is primarily due to an increase in the Company's share price in Q2-2018 and the associated revaluation of share units granted by the Company.

Capitalized G&A decreased 57% and 52% in the three and six months ended June 30, 2018, respectively, as compared with the same periods in 2017. This is consistent with the decrease in capital expenditures in Q2-2018 relative to Q2-2017.

16 Q2-2018

FINANCE COSTS

	Three Months Ended June 30		Six Months Ended June 30
(000s)	2018	2017	2018	2017
Interest on convertible debenture	—	—	—	1,089
Interest on long-term debt	1,163	1,327	2,302	1,455
Interest on note payable	—	250	—	532
Interest on borrowing base facility	103	49	213	49
Amortization of deferred financing costs	87	91	186	140
Finance costs	1,353	1,717	2,701	3,265

Finance costs for the three and six month period ended June 30, 2018 decreased to $1.4 million and $2.7 million, respectively, from $1.7 million and $3.3 million for the same period in 2017. This decrease is due to the reduction in balances of long-term debt by repayments completed in previous quarters, slightly offset by higher borrowing costs due to an increase in LIBOR and ATB Prime.

At June 30, 2018, the Company had in place the prepayment arrangement with Mercuria that allows for a revolving balance of up to $75.0 million, of which $55.0 million is outstanding. During the second quarter of 2018, the Company had repayments of $5.0 million on this loan.

As at June 30, 2018, the Company had in place a revolving Canadian reserves-based lending facility with Alberta Treasury Branches ("ATB") totaling C$30.0 million ($24.0 million), of which C$10.8 million ($8.2 million) is outstanding.

Refer to the related description of TransGlobe's debt included in the December 31, 2017 Consolidated Financial Statements.

The prepayment agreement and reserves-based lending facility are subject to certain covenants. The Company is in compliance with such covenants as at June 30, 2018.

DEPLETION AND DEPRECIATION (“DD&A”)

	Six Months Ended June 30
	2018		2017
(000s, except per boe amounts)	$	$/boe	$	$/boe
Egypt	13,364	5.54	14,208	5.66
Canada	3,805	9.42	4,510	9.24
Corporate	157	—	157	—
	17,326	6.16	18,875	6.30

	Three Months Ended June 30
	2018		2017
(000s, except per boe amounts)	$	$/boe	$	$/boe
Egypt	8,820	5.56	8,094	5.34
Canada	1,579	9.30	2,208	9.28
Corporate	79	—	61	—
	10,478	5.97	10,363	5.91

In Egypt, DD&A increased 4% and decreased 2% on a per bbl basis in the three and six months ended June 30, 2018, respectively, compared to the same period in 2017. Depletion in Egypt is relatively flat versus the comparative periods in 2017.

In Canada, DD&A per bbl slightly increased by 0.2% and 2% in the three and six months ended June 30, 2018, respectively.

IMPAIRMENT LOSS

In the first six months of 2018, TransGlobe determined that there were no indicators of impairment and therefore did not record an impairment charge for any of its assets. During the first six months of 2017, the Company recorded an impairment loss of $68.7 million. The 2017 impairment primarily related to the exploration and evaluation assets for the North West Gharib concession in Egypt. The company relinquished the remaining exploration lands in 2017 that were are not covered by development leases.

CAPITAL EXPENDITURES

	Six Months Ended June 30
($000s)	2018	2017
Egypt	9,950	18,597
Canada	506	324
Corporate	34	27
Total	10,490	18,948

Capital expenditures in the first six months of 2018 were $10.5 million (2017 - $18.9 million). In Egypt, the Company incurred $4.8 million of capitalized drilling costs and $2.6 million of facilities-related capital. During the first six months of 2018, the Company drilled five development wells in the Eastern Desert. Two wells were drilled at West Bakr (K-46 and K-45), two wells were drilled at West Gharib (Arta 48 and Arta 54) and one well was drilled at NW Gharib (NWG 38A-Inj). TransGlobe began drilling its first exploration well of 2018 at the end of June (NWS 9) for which $0.4 million in drilling costs had been incurred prior to quarter-end.

OUTSTANDING SHARE DATA

As at June 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 2018 exploration and development program of $44.1 million, including contractual commitments, through the use of working capital and funds flow from operations. The Company also expects to accelerate debt repayments 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 June 30, 2018, the Company had a working capital surplus of $60.5 million (December 31, 2017 - surplus of $50.6 million). The increase to working capital in Q2-2018 is principally due to the completion of two separate direct crude sale shipments to third-party buyers during the quarter.

The Company completed two separate direct crude sale shipments to third-party buyers during Q2-2018, with a third occurring in July. Proceeds from the first lifting were collected in June and proceeds from the second were collected in July 2018. 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 June 30, 2018, the Company held 510,255 barrels of entitlement oil as inventory.

At June 30, 2018, the Company had $99.0 million of revolving credit facilities with $63.2 million drawn and $35.8 million available. The Company had in place a revolving Canadian reserves-based lending facility with ATB totaling C$30.0 million ($24.0 million), of which C$10.8 million ($8.2 million) was outstanding. During the first six months of 2018, the Company had drawings of C$0.3 million ($0.2 million) and repayments of C$3.7 million ($2.8 million) on this facility. The Company also had in place the prepayment agreement with Mercuria that allows for a revolving balance of up to $75.0 million, of which $55.0 million is outstanding. During the second quarter of 2018, the Company repaid $5.0 million on this loan. Subsequent to the quarter, the Company repaid an additional $5.0 million on the prepayment agreement.

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 June 30, 2018, the Company had 510,255 barrels of entitlement oil as inventory, which represents approximately three months of entitlement oil production. Inventoried entitlement crude oil decreased by 266,499 barrels at June 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. Two additional liftings are scheduled in 2018 (one of which occurred in July) for a total of four liftings expected in 2018.

	Three Months Ended		Six Months Ended		Year ended
(bbls)	June 30, 2018		June 30, 2018		December 31, 2017
Product inventory, beginning of period	1,012,730		776,754		1,265,080
TransGlobe entitlement production	482,353		954,259		2,101,792
EGPC sales	(82,361	)	(318,291	)	(1,121,391	)
Tanker liftings	(902,467	)	(902,467	)	(1,468,727	)
Product inventory, end of period	510,255		510,255		776,754

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	4-5 years
Accounts payable and accrued liabilities	Yes - Liability	24,694	24,694	—	—
Long-term debt	Yes - Liability	62,173	—	62,173	—
Financial derivative instruments	Yes - Liability	24,829	6,777	18,052	—
Office and equipment leases3	No	12,195	10,797	1,398	—
Minimum work commitments4	No	4,955	4,955	—	—
Total		128,846	47,223	81,623	—
Notes:
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at June 30, 2018 exchange rates.
3 Office and equipment leases include all drilling rig contracts.
4 Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

Pursuant to the PSC for North West Sitra in Egypt, the Company has a minimum financial commitment of $10.0 million, of which $5.0 million is remaining, 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 June 30, 2018, the Company had expended $5.0 million towards meeting the financial and operating commitment, with the acquisition of 600 square kilometers of 3-D seismic in 2017.

In the normal course of its operations, the Company may be subject to litigation and claims. Although it is not possible to estimate the extent of potential costs, if any, management believes that the ultimate resolution of such contingencies would not have a material adverse impact on the results of operations, financial position or liquidity of the Company.

The Company is not aware of any material provisions or other contingent liabilities as at June 30, 2018.

Q2-2018 17

ASSET RETIREMENT OBLIGATION

At June 30, 2018, TransGlobe held an asset retirement obligation ("ARO") of $11.5 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 1.91% and 2.20% 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 6 outstanding derivative commodity contracts as at June 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.

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

Financial Brent Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume (bbls)	Bought Put USD$/bbl	Sold Call USD$/bbl	Sold Put USD$/bbl
12-Apr-17	Sep-18	3-Way Collar	250,000	54.00	64.15	45.00
12-Apr-17	Dec-18	3-Way Collar	250,000	54.00	65.45	45.00
23-May-17	Jul 2020 - Dec 20201	3-Way Collar	300,000	54.00	63.45	45.00
31-Aug-17	Jan 2020 - Jun 20202	3-Way Collar	300,000	54.00	61.25	46.50
12-Oct-17	Jan 2019 - Dec 20193	3-Way Collar	396,000	53.00	62.10	46.00
26-Oct-17	Jan 2019 - Dec 20194	3-Way Collar	399,996	54.00	61.35	46.00
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 Sep-18 hedge position for a net cost of $2.43 million.

NEW ACCOUNTING STANDARDS ADOPTED

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, 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.

Q2-2018 18

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 associated with the sale of the Company’s petroleum and natural gas in Canada are recognized when the significant risks and rewards of ownership of the petroleum product have been transferred to the customer. 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 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.

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 June 30, 2018 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

Q2-2018 19

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

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

		Three Months Ended						Six Months Ended
		June 30						June 30
	Notes	2018			2017			2018			2017
REVENUE
Petroleum and natural gas sales, net of royalties	16	$	68,454		$	40,439		$	93,169		$	62,900
Finance revenue		126			19			219			44
		68,580			40,458			93,388			62,944
EXPENSES
Production and operating		17,299			15,079			27,940			25,400
Selling costs		1,080			1,502			1,126			1,502
General and administrative		7,583			3,362			11,579			7,808
Foreign exchange loss (gain)		(18		)	82			(21		)	67
Finance costs	5	1,353			1,717			2,701			3,265
Depletion, depreciation and amortization	9	10,478			10,363			17,326			18,875
Asset retirement obligation accretion	10	66			57			133			117
Loss (gain) on financial instruments	4	16,597			(8,107		)	22,761			(4,227		)
Impairment loss		—			67,520			—			68,711
Gain on disposition of assets		(4		)	—			(202		)	—
		54,434			91,575			83,343			121,518
Net earnings (loss) before income taxes		14,146			(51,117		)	10,045			(58,574		)
Income tax expense – current		6,785			5,505			12,804			10,925
NET EARNINGS (LOSS) FOR THE PERIOD		$	7,361		$	(56,622	)	$	(2,759	)	$	(69,499	)
OTHER COMPREHENSIVE INCOME (LOSS)
Currency translation adjustments		(675		)	(32		)	(1,679		)	(615		)
COMPREHENSIVE INCOME (LOSS) FOR THE PERIOD		$	6,686		$	(56,654	)	$	(4,438	)	$	(70,114	)
Earnings (loss) per share
Basic	15	$	0.10		$	(0.78	)	$	(0.04	)	$	(0.96	)
Diluted	15	$	0.10		$	(0.78	)	$	(0.04	)	$	(0.96	)

See accompanying notes to the Condensed Consolidated Interim Financial Statements.

20 Q2-2018

Condensed Consolidated Interim Balance Sheets

(Unaudited - Expressed in thousands of US Dollars)

		As at		As at
	Notes	June 30, 2018		December 31, 2017
ASSETS
Current
Cash and cash equivalents	6	$	38,088	$	47,449
Accounts receivable	4	41,490		18,090
Prepaids and other		4,450		4,745
Product inventory	7	7,907		11,474
		91,935		81,758
Non-Current
Intangible exploration and evaluation assets	8	43,059		41,478
Property and equipment
Petroleum and natural gas assets	9	191,314		200,981
Other assets	9	3,234		3,485
		$	329,542	$	327,702
LIABILITIES
Current
Accounts payable and accrued liabilities		$	24,694	$	27,104
Derivative commodity contracts	4	6,777		4,015
		31,471		31,119
Non-Current
Derivative commodity contracts	4	18,052		3,955
Long-term debt	11	62,173		69,999
Asset retirement obligation	10	11,533		12,332
Other long-term liabilities		245		290
		123,474		117,695
SHAREHOLDERS’ EQUITY
Share capital	13	152,084		152,084
Accumulated other comprehensive income		1,114		2,793
Contributed surplus		23,828		23,329
Retained earnings		29,042		31,801
		206,068		210,007
		$	329,542	$	327,702

Commitments and Contingencies (Note 12)

See accompanying notes to the Condensed Consolidated Interim Financial Statements.

Approved on behalf of the Board:

Signed by:

“Ross G. Clarkson”	“Steven Sinclair”
Ross G. Clarkson	Steven Sinclair
CEO	Director
Director

Q2-2018 21

Condensed Consolidated Interim Statement of Changes in Shareholders’ Equity

(Unaudited - Expressed in thousands of US Dollars)

		Three Months Ended						Six Months Ended
		June 30						June 30
	Notes	2018			2017			2018			2017
Share Capital
Balance, beginning of period	13	$	152,084		$	152,084		$	152,084		$	152,084
Balance, end of period		$	152,084		$	152,084		$	152,084		$	152,084
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of period		$	1,789		$	(583	)	$	2,793		$	—
Currency translation adjustment		(675		)	(32		)	(1,679		)	(615		)
Balance, end of period		$	1,114		$	(615	)	$	1,114		$	(615	)
Contributed Surplus
Balance, beginning of period		23,471			22,914			23,329			22,695
Share-based compensation expense	14	357			167			499			386
Balance, end of period		$	23,828		$	23,081		$	23,828		$	23,081
Retained Earnings
Balance, beginning of period		$	21,681		$	97,660		$	31,801		$	110,537
Net earnings (loss) and comprehensive income (loss)		7,361			(56,622		)	(2,759		)	(69,499		)
Balance, end of period		$	29,042		$	41,038		$	29,042		$	41,038

See accompanying notes to the Condensed Consolidated Interim Financial Statements.

22 Q2-2018

Condensed Consolidated Interim Statements of Cash Flows

(Unaudited - Expressed in thousands of US Dollars)

		Three Months Ended						Six Months Ended
		June 30						June 30
	Notes	2018			2017			2018			2017
CASH FLOWS RELATED TO THE FOLLOWINGACTIVITIES:
OPERATING
Net earnings (loss)		$	7,361		$	(56,622	)	$	(2,759	)	$	(69,499	)
Adjustments for:
Depletion, depreciation and amortization	9	10,478			10,363			17,326			18,875
Asset retirement obligation accretion	10	66			57			133			117
Deferred lease inducement		(22		)	(21		)	(45		)	(43		)
Impairment loss		—			67,520			—			68,711
Share-based compensation	14	3,418			421			3,685			650
Finance costs	5	1,353			1,717			2,701			3,265
Unrealized (gain) loss on financial instruments	4	10,816			(6,578		)	16,862			(2,698		)
Unrealized loss on foreign currency translation		(7		)	(2		)	(22		)	(21		)
Gain on asset dispositions		(4		)	—			(202		)	—
Asset retirement obligations settled	10	40			—			(257		)	—
Changes in non-cash working capital	17	(14,613		)	(19,608		)	(25,691		)	(24,607		)
Net cash generated by (used in) operating activities		18,886			(2,753		)	11,731			(5,250		)
INVESTING
Additions to intangible exploration and evaluation assets	8	(673		)	(3,667		)	(1,581		)	(14,115		)
Additions to petroleum properties	9	(5,084		)	(4,279		)	(8,674		)	(4,473		)
Additions to other assets	9	(98		)	(284		)	(235		)	(360		)
Proceeds from asset dispositions		4			—			202			—
Changes in restricted cash		—			8,515			—			10,465
Changes in non-cash working capital	17	159			(2,436		)	(635		)	516
Net cash used in investing activities		(5,692		)	(2,151		)	(10,923		)	(7,967		)
FINANCING
Interest paid	5	(1,233		)	(1,891		)	(2,481		)	(5,582		)
Increase in long-term debt	11	108			10,140			249			85,140
Repayment of convertible debentures		—			—			—			(73,375		)
Repayments of long-term debt	11	(5,000		)	(11,041		)	(7,797		)	(11,041		)
Net cash used in financing activities		(6,125		)	(2,792		)	(10,029		)	(4,858		)
Currency translation differences relating to cash and cash equivalents		(65		)	152			(140		)	387
NET INCREASE (DECREASE) IN CASH AND CASHEQUIVALENTS		7,004			(7,544		)	(9,361		)	(17,688		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		31,084			21,324			47,449			31,468
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	38,088		$	13,780		$	38,088		$	13,780

See accompanying notes to the Condensed Consolidated Interim Financial Statements.

Q2-2018 23

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

As at June 30, 2018 and December 31, 2017 and for the three and six month periods ended June 30, 2018 and 2017

(Unaudited - Expressed in US Dollars)

1. CORPORATE INFORMATION

TransGlobe Energy Corporation ("TransGlobe" or the "Company") and its subsidiaries are engaged in oil and natural gas exploration, development and production, and the acquisition of oil and natural gas properties. The Company's shares are traded on the Toronto Stock Exchange (“TSX”), the London Stock Exchange's Alternative Investment Market ("AIM") and the Global Select Market of the NASDAQ Stock Market (“NASDAQ”). TransGlobe is incorporated in Alberta, Canada and the address of its registered office is 2300, 250 – 5th Street SW, Calgary, Alberta, Canada, T2P 0R4.

2. BASIS OF PREPARATION

These Condensed Consolidated Interim Financial Statements have been prepared in accordance with International Accounting Standard 34, Interim Financial Reporting using accounting policies consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board. The accounting policies used in the preparation of these Condensed Consolidated Interim Financial Statements were the same as those used in the preparation of the most recent Annual Consolidated Financial Statements for the year ended December 31, 2017, except for the adoption of new accounting standards as noted in Note 3.

These Condensed Consolidated Interim Financial Statements were authorized for issue by the Board of Directors on August 14, 2018.

These Condensed Consolidated Interim Financial Statements do not contain all the disclosures required for full annual financial statements and should be read in conjunction with the December 31, 2017 Consolidated Financial Statements.

3. NEW ACCOUNTING STANDARDS ADOPTED

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, 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

24 Q2-2018

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 associated with the sale of the Company’s petroleum and natural gas in Canada are recognized when the significant risks and rewards of ownership of the petroleum product have been transferred to the customer. 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 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.

Revenue segregated by product type and geographical market is disclosed in Note 16.

4. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair values of financial instruments

The Company has classified its cash and cash equivalents as assets at fair value through profit or loss and its derivative commodity contracts as financial liabilities at fair value through profit or loss. Both are measured at fair value with subsequent changes recognized through earnings. Accounts receivable are classified as assets at amortized cost; accounts payable and accrued liabilities, and long-term debt are classified as liabilities at amortized cost, all of which are measured initially at fair value, and subsequently at amortized cost. Transaction costs attributable to financial instruments carried at amortized cost are included in the initial measurement of the financial instrument and are subsequently amortized using the effective interest rate method.

Carrying value and fair value of financial assets and liabilities are summarized as follows:

	June 30, 2018		December 31, 2017
	Carrying	Fair	Carrying	Fair
Classification ($000s)	Value	Value	Value	Value
Financial assets at fair value through profit or loss	38,088	38,088	47,449	47,449
Financial assets at amortized cost	41,490	41,490	18,090	18,090
Financial liabilities at fair value through profit or loss	24,829	24,829	7,970	7,970
Financial liabilities at amortized cost	86,867	87,907	97,103	98,329

Assets and liabilities at June 30, 2018 that are measured at fair value are classified into levels reflecting the method used to make the measurements. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant inputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair value measurement.

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

Derivative commodity contracts

The nature of TransGlobe’s operations exposes it to fluctuations in commodity prices, interest rates and foreign currency exchange rates. TransGlobe monitors and, when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by TransGlobe are related to an underlying financial position or to future crude oil and natural gas production. TransGlobe does not use derivative financial instruments for speculative purposes. TransGlobe has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in 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 Note 11), TransGlobe has also entered into a marketing contract with Mercuria Energy Trading S.A. ("Mercuria") to market nine million barrels of TransGlobe's entitlement production. The pricing of the crude oil sales will be based on market prices at the time of sale.

There were 6 outstanding derivative commodity contracts as at June 30, 2018 (December 31, 2017 - 11 contracts), the fair values of which have been presented as liabilities on the Condensed Consolidated Interim Balance Sheet.

Q2-2018 25

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

Financial Brent Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume (bbls)	Bought Put USD$/bbl	Sold Call USD$/bbl	Sold Put USD$/bbl
12-Apr-17	Sep-18	3-Way Collar	250,000	54.00	64.15	45.00
12-Apr-17	Dec-18	3-Way Collar	250,000	54.00	65.45	45.00
23-May-17	Jul 2020 - Dec 20201	3-Way Collar	300,000	54.00	63.45	45.00
31-Aug-17	Jan 2020 - Jun 20202	3-Way Collar	300,000	54.00	61.25	46.50
12-Oct-17	Jan 2019 - Dec 20193	3-Way Collar	396,000	53.00	62.10	46.00
26-Oct-17	Jan 2019 - Dec 20194	3-Way Collar	399,996	54.00	61.35	46.00
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

The gains and losses on financial instruments for the three and six months ended June 30, 2018 and 2017 comprised the following:

	Three Months Ended June 30					Six Months Ended June 30
(000s)	2018		2017			2018		2017
Realized derivative loss on commodity contracts settled during the period	$	5,781	$	(1,529	)	$	5,899	$	(1,529	)
Unrealized derivative loss on commodity contracts outstanding at period end	10,816		(6,578		)	16,862		(2,849		)
Unrealized loss on financial instruments	—		—			—		151
	$	16,597	$	(8,107	)	$	22,761	$	(4,227	)

Credit risk

Credit risk is the risk of financial loss if a customer or counterparty to a financial instrument fails to fulfill their contractual obligations. The Company’s exposure to credit risk primarily relates to cash equivalents and accounts receivable, the majority of which are in respect of oil and natural gas operations. The Company generally extends unsecured credit to these parties and therefore the collection of these amounts may be affected by changes in economic or other conditions. The Company has not experienced any material credit losses in its cash investments or in the collection of accounts receivable to date.

TransGlobe's accounts receivable related to the Canadian operations are with customers and joint interest partners in the petroleum and natural gas industry, and are subject to normal industry credit risks. Receivables from petroleum and natural gas marketers are normally collected in due course. The Company currently sells its production to several purchasers under standard industry sale and payment terms. Purchasers of TransGlobe's natural gas, crude oil and natural gas liquids are subject to a periodic internal credit review to minimize the risk of non-payment. The Company has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions.

Trade and other receivables are analyzed in the table below.

(000s)
Trade receivables	June 30, 2018		December 31, 2017
Neither impaired nor past due	$	30,157	$	10,534
Not impaired and past due in the following period:
Within 30 days	4,749		3,804
31-60 days	4,149		2,575
61-90 days	1,332		—
Over 90 days	1,103		1,177
	$	41,490	$	18,090

The Company sold two cargoes of crude oil during the three months ended June 30, 2018. 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. During the first six months of 2018, the Company sold 318,291 barrels of inventoried entitlement crude oil to EGPC for $17.9 million. The Company collected $22.0 million of accounts receivable from EGPC during the first six months of 2018. As at June 30, 2018, $10.0 million (December 31, 2017 - $14.2 million) of the total accounts receivable balance of $41.5 million (January 1, 2018 - $18.1 million) is due from EGPC.

26 Q2-2018

5. FINANCE COSTS

Finance costs recognized in earnings were as follows:

	Three Months Ended June 30						Six Months Ended June 30
(000s)	2018			2017			2018			2017
Interest on convertible debenture	$	—		$	—		$	—		$	1,089
Interest on long-term debt	1,163			1,327			2,302			1,455
Interest on note payable	—			250			—			532
Interest on borrowing base facility	103			49			213			49
Amortization of deferred financing costs	87			91			186			140
Finance costs	$	1,353		$	1,717		$	2,701		$	3,265
Interest paid	$	(1,233	)	$	(1,891	)	$	(2,481	)	$	(5,582	)

6. CASH AND CASH EQUIVALENTS

(000s)	June 30, 2018		December 31, 2017
Cash	$	24,738	$	46,051
Cash equivalents	13,350		1,398
	$	38,088	$	47,449

As at June 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.

7. PRODUCT INVENTORY

Product inventory consists of the Company's entitlement crude oil barrels, which are valued at the lower of cost or net realizable value. Cost includes operating expenses and depletion associated with the unsold entitlement crude oil as determined on a concession by concession basis.

As at June 30, 2018, the Company had 510,255 barrels of entitlement oil in inventory valued at approximately $15.50 per barrel (December 31, 2017 - 776,754 barrels valued at approximately $14.77 per barrel).

8. INTANGIBLE EXPLORATION AND EVALUATIONASSETS

(000s)
Balance at December 31, 2017	$	41,478
Additions	1,581
Balance at June 30, 2018	$	43,059

9. PROPERTY AND EQUIPMENT

	Petroleum & Natural Gas Assets			Other Assets
(000s)						Total
Balance at December 31, 2017	$	652,831		$	15,525	$	668,356
Additions	8,674			235		8,909
Changes in estimate for asset retirement obligations	7			—		7
Effect of movement in foreign exchange rates	(3,037		)	—		(3,037		)
Balance at June 30, 2018	$	658,475		$	15,760	$	674,235
Accumulated depletion, depreciation, amortization and impairment losses at December 31, 2017	$	451,850		$	12,040	$	463,890
Depletion, depreciation and amortization for the period1	15,311			486		15,797
Balance at June 30, 2018	$	467,161		$	12,526	$	479,687
1. Depletion, depreciation and amortization for the period include amounts capitalized to product inventory for barrels produced but not sold in the period.

Net Book Value
At December 31, 2017	$	200,981	$	3,485	$	204,466
At June 30, 2018	$	191,314	$	3,234	$	194,548

Q2-2018 27

10. ASSET RETIREMENT OBLIGATION

(000s)
Balance at December 31, 2017	$	12,332
Changes in estimates for asset retirement obligation	7
Obligations settled	(257		)
Asset retirement obligation accretion	133
Effect of movements in foreign exchange rates	(682		)
Balance at June 30, 2018	$	11,533

TransGlobe has estimated the net present value of its asset retirement obligation to be $11.5 million as at June 30, 2018 (December 31, 2017 - $12.3 million) based on a total undiscounted future liability, after inflation adjustment, of $15.1 million (December 31, 2017 - $19.6 million). These payments are expected to be made between 2018 and 2066. TransGlobe calculated the present value of the obligations using discount rates between 1.91% and 2.20% to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates. The inflation rate used in determining the cash flow estimate was 2% per annum.

11. LONG-TERM DEBT

As at June 30, 2018, the significant interest-bearing loans and borrowings are comprised as follows:

(000s)	June 30, 2018		December 31, 2017
Prepayment agreement	$	53,960	$	58,792
Reserves-based lending facility1	8,213		11,207
Balance at June 30, 2018	$	62,173	$	69,999
1 As at June 30, 2018 and December 31, 2017, the Company had in place a revolving Canadian reserves-based lending facility totaling C$30.0 million ($24.0 million), of which C$10.8 million was drawn (December 31, 2017 - C$14.0 million).

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

(000s)
Balance at December 31, 2017	$	69,999
Draws on facility	249
Repayment of long-term debt	(7,797		)
Amortization of deferred financing costs	186
Effect of movements in foreign exchange rates	(464		)
Balance at June 30, 2018	$	62,173

The Company's interest-bearing loans and borrowings are measured at amortized cost. As at June 30, 2018, the Company was in compliance with all debt covenants.

The estimated future debt payments on long-term debt as of June 30, 2018 are as follows:

(000s)
2020	8,213
2021	53,960
	$	62,173

28 Q2-2018

12. 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	4-5 years
Accounts payable and accrued liabilities	Yes - Liability	24,694	24,694	—	—
Long-term debt	Yes - Liability	62,173	—	62,173	—
Financial derivative instruments	Yes - Liability	24,829	6,777	18,052	—
Office and equipment leases3	No	12,195	10,797	1,398	—
Minimum work commitments4	No	4,955	4,955	—	—
Total		128,846	47,223	81,623	—
Notes:
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at June 30, 2018 exchange rates.
3 Office and equipment leases include all drilling rig contracts.
4 Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

Pursuant to the PSC for North West Sitra in Egypt, the Company has a minimum financial commitment of $10.0 million, of which $5.0 million is remaining, 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 June 30, 2018, the Company had expended $5.0 million towards meeting the financial and operating commitment, with the acquisition of 600 square kilometers of 3-D seismic in 2017.

In the normal course of its operations, the Company may be subject to litigation and claims. Although it is not possible to estimate the extent of potential costs, if any, management believes that the ultimate resolution of such contingencies would not have a material adverse impact on the results of operations, financial position or liquidity of the Company.

The Company is not aware of any material provisions or other contingent liabilities as at June 30, 2018.

13. SHARE CAPITAL

Authorized

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

Issued

	Six months ended			Year ended
	June 30, 2018			December 31, 2017
(000s)	Shares	Amount		Shares	Amount
Balance, beginning and end of period	72,206	$	152,084	72,206	$	152,084

14. SHARE-BASED PAYMENTS

Stock options

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

	Six Months Ended			Year ended
	June 30, 2018			December 31, 2017
			Weighted-			Weighted-
	Number		Average	Number		Average
	of		Exercise	of		Exercise
(000s except per share amounts)	Options		Price (C$)	Options		Price (C$)
Options outstanding, beginning of period	4,959		5.10	6,046		6.87
Granted	1,071		2.62	1,043		2.16
Forfeited	—		—	(1,281	)	6.75
Expired	(1,154	)	9.13	(849	)	11.43
Options outstanding, end of period	4,876		3.60	4,959		5.10
Options exercisable, end of period	2,766		4.52	2,925		6.87

Q2-2018 29

Compensation expense of $0.5 million was recorded in general and administrative expenses in the Condensed Consolidated Interim Statements of Earnings (Loss) and Comprehensive Income (Loss) and Contributed Surplus during the six month period ended June 30, 2018 (Q2-2017 - $0.4 million) for equity-settled share-based payment transactions. The fair value of all common stock options granted is estimated on the date of grant using the lattice-based trinomial option pricing model.

All options granted vest annually in equal installments over a three-year period and expire five years after the grant date. No employee stock options were exercised during the six month periods ended June 30, 2018 and 2017. As at June 30, 2018 and December 31, 2017, the entire balance in Contributed Surplus related to previously recognized share-based compensation expense on equity-settled stock options.

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

The number of RSUs, PSUs and DSUs outstanding as at June 30, 2018 are as follows:

	Restricted		Performance		Deferred
	Share		Share		Share
(000s)	Units		Units		Units
Units outstanding, beginning of period	970		1,376		595
Granted	387		672		225
Exercised	(323	)	(316	)	—
Forfeited	(84	)	(36	)	—
Units outstanding, end of period	950		1,696		820

During the six month period ended June 30, 2018, compensation expense of $3.2 million (Q2-2017 - $0.3 million) was recorded in general and administrative expenses in the Condensed Consolidated Interim Statements of Earnings (Loss) and Comprehensive Income (Loss) for share units granted under the three plans described above. The expense related to the share units granted under these plans is measured at fair value using the lattice-based trinomial pricing model and is recognized over the vesting period, with a corresponding liability recognized on the Condensed Consolidated Interim Balance Sheets. Until the liability is ultimately settled, it is re-measured at each reporting date with changes to fair value recognized in earnings.

15. PER SHARE AMOUNTS

The basic weighted-average number of common shares outstanding for the six months ended June 30, 2018 and 2017 was 72,205,369. The diluted weighted-average number of common shares outstanding for the six months ended June 30, 2018 was 72,605,232 (Q2-2017 - 72,205,369). These outstanding share amounts were used to calculate earnings (loss) per share in the respective periods.

In determining diluted earnings per share, the Company assumes that the proceeds received from the exercise of “in-the-money” stock options are used to repurchase common shares at the average market price. In calculating the weighted-average number of diluted common shares outstanding for the period ended June 30, 2018, the Company excluded 2,710,829 stock options (June 30, 2017 – 5,638,053) as their exercise price was greater than the average common share market price in the period.

16. SEGMENTED INFORMATION

The Company has two reportable operating segments for the three and six months ended June 30, 2018 and 2017: the Arab Republic of Egypt and Canada. The Company, through its operating segments, is engaged primarily in oil exploration, development and production, and the acquisition of oil and gas properties.

TransGlobe's management regularly reviews funds flow from operations generated by each of TransGlobe's operating segments. Funds flow from operations is a measure of profit or loss that provides TransGlobe's management with the ability to assess the operating segments’ profitability and, correspondingly, the ability of each operating segment to sustain capital, enable future growth through capital investment and to repay debt.

30 Q2-2018

	Egypt						Canada						Corporate						Total
	Six Months Ended						Six Months Ended						Six Months Ended						Six Months Ended
	June 30						June 30						June 30						June 30
(000s)	2018			2017			2018			2017			2018			2017			2018			2017
Revenue
Oil sales	$	140,449		$	100,581		$	6,225		$	4,494		$	—		$	—		$	146,674		$	105,075
Natural gas sales	—			—			1,447			2,645			—			—			1,447			2,645
Natural gas liquids sales	—			—			4,050			3,545			—			—			4,050			3,545
Less: Royalties	(57,346		)	(46,037		)	(1,656		)	(2,328		)	—			—			(59,002		)	(48,365		)
Petroleum and natural gas sales, net of royalties	83,103			54,544			10,066			8,356			—			—			93,169			62,900
Finance revenue	50			2			—			—			169			42			219			44
Total segmented revenue	83,153			54,546			10,066			8,356			169			42			93,388			62,944
Segmented expenses
Production and operating	23,667			22,102			4,273			3,298			—			—			27,940			25,400
Selling costs	1,126			1,502			—			—			—			—			1,126			1,502
G&A	2,526			2,494			526			566			8,527			4,748			11,579			7,808
Share-based compensation	—			—			—			—			(3,685		)	(650		)	(3,685		)	(650		)
Lease inducement	—			—			—			—			45			43			45			43
Settlement of ARO	—			—			257			—			—			—			257			—
Realized foreign exchange loss	—			—			—			—			1			88			1			88
Realized derivative (gain) loss on commodity contracts	5,449			(1,529		)	450			—			—			—			5,899			(1,529		)
Gain on asset dispositions	—			—			(202		)	—			—			—			(202		)	—
Proceeds from asset dispositions	—			—			202			—			—			—			202			—
Income tax expense	12,804			10,925			—			—			—			—			12,804			10,925
Segmented funds flow from operations	$	37,581		$	19,052		$	4,560		$	4,492		$	(4,719	)	$	(4,187	)	$	37,422		$	19,357
																			Total
																			Six Months Ended
																			June 30
																			2018			2017
Reconciliation of funds flow from operations to net loss:
Funds flow from operations																			$	37,422		$	19,357
Depletion, depreciation and amortization																			(17,326		)	(18,875		)
Accretion																			(133		)	(117		)
Deferred lease inducement																			45			43
Impairment of exploration and evaluation assets																			—			(68,711		)
Stock-based compensation																			(3,685		)	(650		)
Finance costs																			(2,701		)	(3,265		)
Unrealized gain (loss) on financial instruments																			(16,862		)	2,698
Unrealized gain on foreign currency translation																			22			21
Asset retirement obligations settled																			257			—
Proceeds from asset dispositions																			202			—
Net earnings (loss)																			$	(2,759	)	$	(69,499	)
Capital expenditures
Exploration and development	$	9,950		$	18,597		$	506		$	324		$	—		$	—		$	10,456		$	18,921
Corporate	—			—			—			—			34			27			34			27
Total capital expenditures	$	9,950		$	18,597		$	506		$	324		$	34		$	27		$	10,490		$	18,948

Q2-2018 31

	Egypt						Canada						Corporate						Total
	Three Months Ended						Three Months Ended						Three Months Ended						Three Months Ended
	June 30						June 30						June 30						June 30
(000s)	2018			2017			2018			2017			2018			2017			2018			2017
Revenue
Oil sales	$	94,147		$	59,541		$	2,753		$	2,007		$	—		$	—		$	96,900		$	61,548
Natural gas sales	—			—			500			1,400			—			—			500			1,400
Natural gas liquids sales	—			—			1,820			1,764			—			—			1,820			1,764
Less: Royalties	(30,375		)	(23,122		)	(391		)	(1,151		)	—			—			(30,766		)	(24,273		)
Petroleum and natural gas sales, net of royalties	63,772			36,419			4,682			4,020			—			—			68,454			40,439
Finance revenue	27			—			—			—			99			19			126			19
Total segmented revenue	63,799			36,419			4,682			4,020			99			19			68,580			40,458
Segmented expenses
Production and operating	15,205			13,556			2,094			1,523			—			—			17,299			15,079
Selling costs	1,080			1,502			—			—			—			—			1,080			1,502
G&A	1,245			804			226			315			6,112			2,243			7,583			3,362
Share-based compensation	—			—			—			—			(3,418		)	(421		)	(3,418		)	(421		)
Lease inducement	—			—			—			—			22			21			22			21
Settlement of ARO	—			—			(40		)	—			—			—			(40		)	—
Realized foreign exchange loss (gain)	—			—			—			—			(11		)	84			(11		)	84
Realized derivative (gain) loss on commodity contracts	5,469			(1,529		)	312			—			—			—			5,781			(1,529		)
Gain on asset dispositions	—			—			(4		)	—			—			—			(4		)	—
Proceeds from asset dispositions	—			—			4			—			—			—			4			—
Income tax expense	6,785			5,505			—			—			—			—			6,785			5,505
Segmented funds flow from operations	$	34,015		$	16,581		$	2,090		$	2,182		$	(2,606	)	$	(1,908	)	$	33,499		$	16,855
																			Total
																			Three Months Ended
																			June 30
																			2018			2017
Reconciliation of funds flow from operations to net loss:
Funds flow from operations																			$	33,499		$	16,855
Depletion, depreciation and amortization																			(10,478		)	(10,363		)
Accretion																			(66		)	(57		)
Deferred lease inducement																			22			21
Impairment of exploration and evaluation assets																			—			(67,520		)
Stock-based compensation																			(3,418		)	(421		)
Finance costs																			(1,353		)	(1,717		)
Unrealized gain (loss) on financial instruments																			(10,816		)	6,578
Unrealized gain on foreign currency translation																			7			2
Asset retirement obligations settled																			(40		)	—
Proceeds from asset dispositions																			4			—
Net earnings (loss)																			$	7,361		$	(56,622	)
Capital expenditures
Exploration and development	$	5,598		$	7,927		$	231		$	276		$	—		$	—		$	5,829		$	8,203
Corporate	—			—			—			—			26			27			26			27
Total capital expenditures	$	5,598		$	7,927		$	231		$	276		$	26		$	27		$	5,855		$	8,230

32 Q2-2018

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

	June 30, 2018						December 31, 2017
(000s)	Egypt		Canada		Total		Egypt		Canada		Total
Assets
Accounts receivable	$	38,188	$	2,854	$	41,042	$	14,956	$	2,684	$	17,640
Intangible exploration and evaluation assets	43,059		—		43,059		41,478		—		41,478
Property and equipment
Petroleum and natural gas assets	124,515		66,799		191,314		127,363		73,618		200,981
Other assets	2,257		26		2,283		2,381		27		2,408
Other	40,204		1,811		42,015		49,769		3,467		53,236
Segmented assets	248,223		71,490		319,713		235,947		79,796		315,743
Non-segmented assets					9,829						11,959
Total assets					$	329,542					$	327,702
Liabilities
Accounts payable and accrued liabilities	$	14,835	$	1,884	$	16,719	$	17,035	$	4,004	$	21,039
Derivative commodity contracts	24,829		—		24,829		7,813		157		7,970
Long-term debt	53,960		8,213		62,173		58,792		11,207		69,999
Asset retirement obligation	—		11,533		11,533		—		12,332		12,332
Segmented liabilities	93,624		21,630		115,254		83,640		27,700		111,340
Non-segmented liabilities					8,220						6,355
Total liabilities					$	123,474					$	117,695

17. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended June 30						Six Months Ended June 30
(000s)	2018			2017			2018			2017
Operating Activities
(Increase) decrease in current assets:
Accounts receivable	$	(18,239	)	$	(20,068	)	$	(23,400	)	$	(27,074	)
Prepaids and other	(1,475		)	(146		)	674			(278		)
Product inventory	4,435			3,506			2,037			2,036
(Decrease) increase in current liabilities:
Accounts payable and accrued liabilities	666			(2,900		)	(5,002		)	709
	$	(14,613	)	$	(19,608	)	$	(25,691	)	$	(24,607	)

Investing Activities
Increase in current assets:
Prepaids and other	$	—	$	—		$	(3	)	$	—
Increase (decrease) in current liabilities:
Accounts payable and accrued liabilities	159		(2,436		)	(632		)	516
	$	159	$	(2,436	)	$	(635	)	$	516

Q2-2018 33

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

www.trans-globe.com

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