2017 THIRD QUARTER INTERIM REPORT

Financial and Operating Results

For the three and nine month periods ended September 30, 2017

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

Highlights:
ø	Third quarter production averaged 14,912 boepd (18,020 boepd sales) versus 11,733 bopd (11,485 bopd sales) in Q3-2016, a 27% increase, reflecting increased volumes in Egypt and the December 2016 Canadian acquisition. Nine months ended September 30, 2017 average production was 16,029 boepd, which is within the full-year 2017 production guidance range of 15,500 to 16,500 boepd;
ø	Positive funds flow of $19.2 million and $38.6 million for the three and nine month periods ended September 30, 2017, respectively, (2016 - $2.3 million and $1.5 million);
ø	Completed one direct sale tanker-lifting of TransGlobe's entitlement oil for proceeds of $21.5 million ($19.6 million net of realized hedging loss); of which sale proceeds were collected in October. In addition, sold 351,002 barrels of inventoried entitlement crude oil to EGPC for $14.9 million to cover in-country expenditures during the third quarter;
ø	Inventory sales of 285,967 bbls and 276,990 bbls in excess of production for the three and nine month periods ended September 30, 2017, respectively, (2016 - Q3 production exceeded sales by 22,826 bbls and for the nine months ended Q3, sales exceeded production by 193,704 bbls);
ø	Inventory of 988,090 barrels of entitlement crude oil inventory at quarter-end, and next lifting is scheduled for November;
ø	Third quarter net loss of $6.9 million (includes a $10.3 million impairment loss and a $3.2 million unrealized loss on derivative commodity contracts). Excluding the impairment charge and the unrealized loss on derivative commodity contracts, the Company would have achieved a positive net profit for the quarter of $6.6 million;
ø	Spent $10.1 million on exploration and development during the quarter ($6.0 million in Egypt and $4.1 million in Canada);
ø	In the Western Desert, commenced testing at South Alamein; Boraq 2 flowed at 1,140 Bopd from the AR-E formation during a short test to confirm productivity, subsequent to the end of the quarter the AR-G and AR-E were tested unsuccessfully in the Boraq 5 appraisal well;
ø	In the Eastern Desert, the Company received approval for three development leases at North West Gharib ("NWG"). The discoveries at NWG development leases 2, 3 and 4 are scheduled to start production in Q4-2017 and Q1-2018;
ø	Drilled and began completions on three Cardium horizontal oil wells in Harmattan;
ø	Acquired 2.5 sections (1,600 acres) of Cardium rights in the Harmattan area. The new lands have increased the Company’s internally estimated Cardium drilling location inventory by 8-10 locations;
ø	Ended the quarter with positive working capital of $58.8 million, which includes cash and cash equivalents of $26.3 million (including restricted cash);
ø	Repaid $5.0 million of the amount outstanding under the prepayment agreement; and
ø	Long-term debt net of working capital was $21.0 million as at September 30, 2017.

A conference call to discuss TransGlobe's 2017 third quarter results as presented was held on Thursday, November 9, 2017 and can be accessed on the Company's website at http://www.trans-globe.com/investors/presentations-and-events.html

www.trans-globe.com

TSX: 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 24
Notes to Condensed Consolidated Interim Financial Statements	Page 28

2 Q3-2017

FINANCIAL AND OPERATING RESULTS

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

	Three months ended September 30					Nine months ended September 30
Financial	2017		2016		% Change	2017		2016		% Change
Petroleum and natural gas sales	68,372		36,376		88	179,637		97,859		84
Petroleum and natural gas sales, net of royalties	44,839		20,704		117	107,739		57,917		86
Realized derivative gain (loss) on commodity contracts	(1,904	)	—		—	(375	)	(956	)	—
Unrealized derivative gain (loss) on commodity contracts	(3,235	)	—		—	(386	)	—		—
Production and operating expense	14,310		10,945		31	39,356		34,706		13
Transportation costs	212		—		—	566		—		—
Selling costs	424		—		—	1,926		875		120
General and administrative expense	3,809		4,094		(7)	11,617		11,742		(1)
Depletion, depreciation and amortization expense	10,760		6,439		67	29,635		24,538		21
Income taxes	5,179		4,067		27	16,104		7,728		108
Cash flow generated by (used in) operating activities	20,437		(14,857	)	238	15,187		(7,420	)	305
Funds flow from operations1	19,217		2,347		719	38,574		1,543		2,400
Basic per share	0.27		0.03			0.53		0.02
Diluted per share	0.27		0.03			0.53		0.02
Net earnings (loss)	(6,855	)	(25,369	)	73	(76,354	)	(53,668	)	(42)
Net earnings (loss) - diluted	(6,855	)	(25,369	)	73	(76,354	)	(53,668	)	(42)
Basic per share	(0.09	)	(0.35	)		(1.06	)	(0.74	)
Diluted per share	(0.09	)	(0.35	)		(1.06	)	(0.74	)
Capital expenditures	10,133		8,692		17	29,081		17,794		63
Working capital	58,815		53,029		11	58,815		53,029		11
Long-term debt	79,839		—		—	79,839		—		—
Convertible debentures	—		74,854		(100)	—		74,854		(100)
Common shares outstanding
Basic (weighted average)	72,206		72,206		—	72,206		72,206		—
Diluted (weighted average)	72,206		72,206		—	72,206		72,206		—
Total assets	338,802		414,363		(18)	338,802		414,363		(18)
Operating
Average production volumes (boepd)	14,912		11,733		27	16,029		11,754		36
Average sales volumes (boepd)	18,020		11,485		57	17,050		12,461		37
Inventory (MBbls)	988		729		35	988		729		35
Average sales price ($ per boe)	41.24		34.43		20	38.59		28.66		35
Operating expense ($ per boe)	8.63		10.36		(17)	8.46		10.16		(17)
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	2017			2016
	Q-3	Q-2	Q-1	Q-4	Q-3
Crude oil
Dated Brent average oil price (US$/bbl)	52.11	49.67	53.68	49.19	45.79
Edmonton Sweet index (US$/bbl)	45.32	46.03	48.37	46.18	41.99
Natural gas
AECO (C$/mmbtu)	1.45	2.78	2.69	3.09	2.32
U.S./Canadian Dollar average exchange rate	1.247	1.345	1.323	1.334	1.305

Q3-2017 3

CORPORATE SUMMARY

TransGlobe Energy Corporation ("TransGlobe" or the "Company") produced an average of 14,912 barrels of oil equivalent per day ("boepd") during the third quarter of 2017. Egypt production was 12,268 barrels of oil per day ("bopd"), and Canada production was 2,644 boepd. The Company's production in the quarter was impacted by delays in well servicing in Egypt during August/September and shut-in Canadian gas production during September due to low spot gas prices at AECO. For the nine months ended September 30, 2017 the average production was 16,029 boepd, which is within the full-year 2017 production guidance range of 15,500 to 16,500 boepd.

In Egypt, the Company released the workover/completion rig supporting the Eastern Desert operations in early August due to escalating safety and performance issues. A replacement rig was contracted and mobilized in late September to begin restoring approximately 1,500+ bopd of shut-in production associated with pump/rod replacements. A second workover rig was contracted in early October for the Eastern Desert to accelerate removal of the backlog of well workovers. The second rig is expected to be operational in late November following mobilization and certification. 

In Canada, approximately 100 boepd (~600 Mcfd) of dry gas was shut-in August 30 due to low gas prices associated with system outages (expansion/maintenance) in the TransCanada system. In September, the Company hedged approximately 4,300 GJ/day (~4.1 MMcfd) of Q4-2017 gas production at $2.065 C/GJ.  The 600 Mcfd of dry gas will be put back online in November as a result of improved spot prices. The majority of the Company’s ~6.0 MMcfd of Canadian gas production is liquids rich gas or gas production associated with light oil production. This production will remain on stream as the majority of revenue is derived from oil and liquids sales.

The Company completed one direct sale tanker lifting during the quarter, consisting of 442,953 barrels of entitlement crude oil. Proceeds of $21.5 million ($19.6 million net of hedging) were received in October. The Company's next cargo lifting from Egypt, originally scheduled for December 2017, is now scheduled for late November 2017. In addition to the lifting the Company sold 351,002 barrels of inventoried entitlement crude oil to the Egyptian General Petroleum Company ("EGPC") during the third quarter for $14.9 million. The EGPC proceeds are used to cover in-country expenditures. Canadian production was sold during the quarter.

Dated Brent oil prices averaged $52.11 per barrel in the third quarter of 2017. The selling differential for the Ras Gharib heavy oil improved this year to approximately $8.00 per barrel as compared to the approximately $10.00 to $15.00 per barrel differentials experienced during 2015 and 2016. This has resulted in an improvement to the current netbacks and future economics of Eastern Desert developments. TransGlobe received a blended price of $44.82 per barrel during the quarter. TransGlobe's Canadian production received an average of $44.91 per barrel of oil and $1.65 per Mcf of natural gas during the third quarter.

The Company had funds flow of $19.2 million ($0.27 per share) and ended the quarter with positive working capital of $58.8 million, which includes cash and cash equivalents of $26.3 million (including restricted cash).

During the quarter the Company repaid $5.0 million of the amount outstanding under the prepayment agreement. Long-term debt net of working capital was $21.0 million as at September 30, 2017.

The Company experienced a net loss in the quarter of $6.9 million, which includes a $10.3 million non-cash impairment loss on the Company's exploration and evaluation assets at South Alamein and a $3.2 million unrealized derivative loss on commodity contracts. The $3.2 million loss on derivative commodity contracts represents a fair value adjustment on the Company's hedging contracts as at September 30, 2017.

In the Western Desert the Company mobilized a completion rig to South Alamein in September to commence a two well testing program at Boraq. The Boraq 2 well was re-entered and tested light oil from the AR-E channel to re-establish oil production prior to completing and testing the Boraq 5 appraisal well. The Boraq 5 well failed to produce any hydrocarbons from the two zones. The lower AR G zone, although very similar on open hole logs and drill cutting samples to the original Boraq 2 discovery well, tested tight with virtually no inflow of fluids from a 20 foot perforated interval in the AR G carbonate zone. The AR E zone was also perforated and tested wet from the E channel sand. The Boraq 5 well was plugged and abandoned. At this point, the Boraq 2 discovery does not have sufficient scale to proceed with development without additional exploration success on the South Alamein Concession. A number of exploration prospects have been identified that, if successful, could provide the addition reserves and productivity to bring forward a South Alamein development.

In the Eastern Desert, the Company received approval for three development leases at NWG in September. The discoveries at NWG development leases 2, 3 and 4 are scheduled to start production in Q4-2017 and Q1-2018. The NWG-38A1 was fractured stimulated and placed on production in October at an initial rate of 340 bopd. NWG 1X and NWG 5BX have been placed on production and are cleaning up at combined rates of approximately 300 bopd.

The Company drilled and completed three horizontal Cardium oil wells in Harmattan during the quarter. The three wells were drilled, completed and equipped for approximately $2.1 million (C$2.5 million) per well. In addition, the Company acquired 2.5 sections (1,600 acres) of Cardium rights in the Harmattan area at government land sales. The new lands have increased the Company’s internally estimated Cardium drilling location inventory by 8-10 locations.   

Brent oil prices strengthened during the quarter and firmed up to above $50.00 per barrel. The fundamentals seem to be slowly improving (lower world inventories, increasing demand). The Company’s cost structure for operating expenses and G&A has been improved significantly over the past three years. The devaluation of the Egyptian pound, which occurred in Q4 of 2016, also had a significant positive impact on operating expenses. The increased oil sales during the quarter resulted in a significant improvement to funds flow and net earnings, posting the highest result in ten quarters. Management will continue to steward the balance sheet conservatively and focus on a return to profitability.

The Company continues to investigate methods to increase its liquidity and general market support, including alternative listings.

4 Q3-2017

OPERATIONS UPDATE

ARAB REPUBLIC OF EGYPT

EASTERN DESERT

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

Operations and Exploration

No wells were drilled during the third quarter.

Production

Production from West Gharib averaged 5,741 Bopd to TransGlobe during the third quarter, a 10% (648 bopd) decrease from the previous quarter. Third quarter production was negatively impacted by well servicing delays. The Company has resumed servicing operations and has contracted a second workover rig for the Eastern Desert to accelerate well workovers. The second rig is expected to be operational in late November.

Production averaged 5,020 bopd during October, representing a 14% (721 Bopd) reduction from Q3-2017 production. The drop in production during October was primarily due to shut-in wells awaiting servicing and natural declines. With the addition of the second workover rig in November, it is expected that the backlog of shut-in production in the Eastern Desert will be back on stream by year end.

Sales

TransGlobe lifted and sold 442,953 barrels of Ras Gharib blend in September, all of which was allocated to West Gharib entitlement crude inventory (after royalties and tax). Subsequent to the quarter, the Company received $21.5 million ($19.6 million net of hedging) for the September lifting. TransGlobe sold 351,002 barrels of inventoried entitlement crude oil (after royalties and tax) to EGPC for $14.9 million in the third quarter of 2017 to cover in-country expenditures. TransGlobe held 109,645 barrels of West Gharib entitlement oil as inventory at the end of the third quarter.

Quarterly West Gharib Production (bopd)	2017					2016
	Q-3		Q-2		Q-1	Q-4
Gross production rate	5,741		6,389		6,683	6,601
TransGlobe working interest	5,741		6,389		6,683	6,601
TransGlobe inventory held (lifted)	(5,715	)	(92	)	3	3,339
Total sales	11,456		6,481		6,680	3,262
Government share (royalties and tax)	2,826		3,155		3,304	3,262
TransGlobe sales (after royalties and tax)1	8,630		3,326		3,376	—
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

Due to the backlog of well workovers and the impact of well service delays, the Company deferred all low cost, behind-pipe opportunities in the K and H fields. These opportunities are being scheduled as part of the 2018 production uplift program.

No wells were drilled during the third quarter.

Production

Production from West Bakr averaged 5,651 bopd to TransGlobe during the third quarter, a 7% (434 bopd) decrease from the previous quarter. The Company has resumed servicing operations and has contracted a second workover rig for the Eastern Desert to accelerate well workovers. The second rig is expected to be operational in late November.

Production averaged 5,046 bopd during October, representing an 12% (605 Bopd) reduction from Q3-2017 production. The drop in production during October was primarily due to shut-in wells awaiting servicing and natural declines. With the addition of the second workover rig in November, it is expected that the backlog of shut-in production in the Eastern Desert will be back on stream by year end.

Sales

TransGlobe did not sell its entitlement share of production (after royalties and tax) from West Bakr during the quarter which resulted in an ending inventory position (under-lift) of 769,909 barrels at the end of the third quarter.

Q3-2017 5

Quarterly West Bakr Production (bopd)	2017				2016
	Q-3	Q-2		Q-1	Q-4
Gross production rate	5,651	6,085		6,284	6,134
TransGlobe working interest	5,651	6,085		6,284	6,134
TransGlobe inventory held (lifted)	2,288	(3,202	)	2,545	2,484
Total sales	3,363	9,287		3,739	3,650
Government share (royalties and tax)	3,363	3,621		3,739	3,650
TransGlobe sales (after royalties and tax)1	—	5,666		—	—
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

No wells were drilled during the third quarter. Subsequent to quarter-end, the drilling rig was re-activated and re-entered NWG-3A targeting the Red Bed in an up-dip structural position. The NWG 3A ST 1 well encountered the targeted thick Red Bed formation in an up-dip position, however the zone was wet and subsequently abandoned. Following NWG 3A ST1, the drilling rig moved to the NWG 38A2 appraisal well offsetting the NWG 38 A discovery well which is currently producing ~550 Bopd.

The NWG-38A1 appraisal well was stimulated during the third quarter. Due to delays in well servicing, this well was not completed and placed on production until after the 3rd quarter. The well continues to clean up and is currently producing approximately 340 bopd.

In addition, the Company received approval for three development leases at NWG in September. The discoveries at NWG DL 2, 3 and 4 are scheduled to start production in Q4-2017 and Q1-2018. The NWG 1 and NWG 5 discoveries (discovered in 2014) wells were put on production in October.

The NWG 5 discovery is an upper Nukhul discovery similar to and located immediately south of the Arta Upper Nukhul pool in the West Gharib concession. The NWG 5 discovery wells (discovery well and one appraisal well) are expected to produce at similar rates to TransGlobe’s Arta Nukhul wells which typically have an initial 30 day production rate (IP 30) of 150-180 bopd with ultimate recoveries of 120-150 MBbls per well on primary production. The NWG 5x well was placed on production and continues to cleanup from the frac stimulation with a current production rate of 210 Bopd.

The NWG 1 discovery is located immediately north of the Arta Red Bed (Lower Nukhul) pool in the West Gharib concession. The NWG 1 wells (discovery well and one appraisal well) encountered a tight Red Bed conglomerate sequence which requires stimulation to produce. Longer-term production from the NWG 1 wells will be required to establish expected per well recoveries and the associated reserve assignments. NWG 1X was placed on production in late October and is continuing to clean-up following fracture stimulation with an initial rate of approximately 90 Bopd.

Production

Production from NWG averaged 876 bopd to TransGlobe during the third quarter, a 36% (501 bopd) decrease from the previous quarter, primarily due to well servicing delays at NWG 3.

Production averaged 985 bopd during October, with current production of approximately 1,600 bopd. The increase in current production levels is primarily due to the new wells (NWG 38A1, NWG 1x and NWG 5x) being placed on production during October.

Sales

TransGlobe did not sell its entitlement share of production (after royalties and tax) from NWG during the quarter, which resulted in an ending inventory position (under-lift) of 108,536 barrels.

Quarterly North West Gharib Production (bopd)	2017			2016
	Q-3	Q-2	Q-1	Q-4
Gross production rate	876	1,377	982	55
TransGlobe working interest	876	1,377	982	55
TransGlobe inventory held (lifted)	318	499	356	20
Total sales	558	878	626	35
Government share (royalties and tax)	558	878	626	35
TransGlobe sales (after royalties and tax)1	—	—	—	—
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

The Boraq 5 commenced drilling in May to test the down-dip extent of the two pools discovered at Boraq 2. The Boraq 5 well encountered significant drilling difficulties. The first attempt to reach the target encountered significant caving and lost circulation resulting in a requirement to sidetrack the well to a different location. The well reached a total depth of 8,900 feet measured depth and encounteredup to 15 feet of possible pay in the AR ‘G’ Cretaceous oil pool. The well missed the AR-E channel sands.  The well was therefore plugged back and again sidetracked to a structurally up-dip location targeting AR-E channel and the AR-G pool. The side track also encountered significant drilling difficulties but eventually reached a

6 Q3-2017

total depth of 8,755 feet measured depth and encountered six feet of AR E channel and 19 feet AR G formation. The well was cased as a potential oil well.

The Company mobilized a completion rig to South Alamein in September to commence a two well testing program at Boraq. The Boraq 2 well was re-entered and tested light oil from the AR-E channel to re-establish oil production from the well. The short retest of Boraq 2 produced 550 bbls of oil over a 14 hour period. The well was flowed at an average rate of 1,140 Bopd of 35 API oil on a 64/64 inch choke over an 8 hour flow period prior to being shut-in for buildup. Following the Boraq 2 re-test, the Company completed testing the Boraq 5 appraisal well which failed to produce any hydrocarbons from the two zones. The lower AR G zone, although very similar on open hole logs and drill cutting samples to the original Boraq 2 discovery well, tested tight with virtually no inflow of fluids from a 20 foot perforated interval in the AR G carbonate zone. The AR E zone was also perforated and tested wet from the E channel sand. The Boraq 5 well was plugged and abandoned. Based on the Boraq 5 test results, the Boraq 2 discovery does not have sufficient scale to proceed with development without additional exploration success on the South Alamein Concession. A number of exploration prospects that, if successful, could provide the additional reserves and productivity to bring forward a South Alamein development. These targets are being reviewed to determine if they should be added into the 2018 exploration program.

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

Operations and Exploration

At South Ghazalat, the Company has met all financial commitments for the first exploration phase and is targeting to have a drill-ready prospect inventory prepared during 2017. The Company is planning to drill two wells in South Ghazalat in conjunction with North West Sitra drilling in the 2018 exploration program.

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

At NW Sitra, the Company completed the 600 km² seismic acquisition program at the end of March. The processed data was received in September and prospect mapping is underway. The Company has a two well commitment in the current exploration phase. The Company is targeting to drill the two wells in 2018.

CANADA

Operations and Exploration

The Company drilled and initiated the completions on three horizontal Cardium oil wells in Harmattan during the quarter. The three horizontal wells were drilled during July/August and completed in September/October with 40 stage (15 t/stage) fracs. The number of stages and size of the fracs are more than double the average done on the Company’s existing Harmattan wells by the previous owners. The Company is optimistic the increased stimulation will result in higher production rates and ultimate oil recoveries for the project. The wells were equipped and placed into production in late October. The initial flow rates are very encouraging, although a 30 and 60 day average rate (IP 30/60) will be more representative of the ultimate potential of the wells. The Company expects to have initial production rates by year-end, following the frac flow back and clean up period. The three wells were drilled, completed and equipped for approximately $2.1 million (C$2.5 million) per well.

In addition, the Company acquired 2.5 sections (1,600 acres) of Cardium rights in the Harmattan area at government land sales. The new lands have increased the Company’s internally estimated Cardium drilling location inventory by 8-10 locations.

The Company continues to evaluate properties for acquisition in the greater Harmattan area.

Production

Production from Canada averaged 2,644 boepd to TransGlobe during the third quarter, a 1% (31 bopd) increase from the previous quarter. Approximately 100 boepd (~600 Mcfd) of dry gas was shut-in on August 30 due to low gas prices associated with system outages (expansion/maintenance) on the TransCanada system. In September, the Company hedged approximately 4,300 GJ/day (~4.1 MMcfd) of Q4-2017 gas production at $2.065 C/GJ. The 600 Mcfd of dry gas remains shut-in but will be put back online in November as a result of improved spot prices. The majority of the Company’s ~6.0 MMcfd of Canadian gas production is liquids rich gas or gas production associated with light oil production.This production will remain on stream as the majority of revenue is derived from oil and liquids sales.

Production averaged 2,633 bopd during October, which is essentially flat with Q3-2017 production. The three new Cardium Hz wells were tied in and placed on production during October. The initial flow-back and clean up rates, although very encouraging, contributed very little to the monthly October production numbers due to limited producing days during the month.

Quarterly Canada Production (boepd)	2017			2016
	Q-3	Q-2	Q-1	Q-4
Canada crude oil (bbls/d)	518	496	565	18
Canada NGLs (bbls/d)	1,081	919	1,037	34
Canada natural gas (mcf/d)	6,268	7,191	7,075	230
Total production (boe/d)	2,644	2,613	2,782	90

Q3-2017 7

MANAGEMENT'S DISCUSSION AND ANALYSIS

November 7, 2017

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 for the Company for the three and nine months ended September 30, 2017 and 2016 and the audited Consolidated Financial Statements and Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2016 included in the Company’s annual report. The Condensed Consolidated Interim Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board in the currency of the United States (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 the Company's 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, reserve estimates, management’s expectation for results of operations for 2017, including expected 2017 average production, funds flow from operations, the 2017 capital program for exploration and development, the timing and method of financing thereof, the terms of drilling commitments under the Egyptian PSCs and the method of funding such drilling commitments, the Company's beliefs regarding the reserve 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 reserve 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 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 reserve 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 U.S. securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), EDGAR website (www.sec.gov) and at 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 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 Q3-2017

MANAGEMENT STRATEGY AND OUTLOOK

The 2017 outlook provides information as to management’s expectation for results of operations for 2017. Readers are cautioned that the 2017 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 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 MD&A.

2017 Outlook

At mid-year 2017, the Company has adjusted the 2017 capital program and production outlook to reflect results to date, commodity prices and the forward plan for the balance of 2017.

The Company’s 2017 adjusted capital program of $40.7 million (before capitalized G&A) is within original guidance of $35.4 (Firm) and $56.4 million (Firm & Contingent). It is expected that 2017 production will average on the lower end of the 2017 guidance (15,500 and 16,500 boepd), representing a 28% increase over 2016 production (production in Q3-2017 was 14,912 boepd). Funds flow in any given period will be dependent upon the timing of crude oil tanker liftings in Egypt, the amount of entitlement oil sold to EGPC and the market price of the crude sold. Because these factors are difficult to accurately predict, the Company has not provided funds flow guidance for 2017. Funds flow and inventory levels in Egypt are expected to fluctuate significantly from quarter to quarter due to the timing of liftings. The Company expects positive funds flow for the last quarter of 2017 with one scheduled tanker lifting and the potential of additional sales of entitlement oil to EGPC.

Management will continue to steward the balance sheet conservatively and allocate future funds flow between capital expenditures and debt repayments.

NON-GAAP FINANCIAL MEASURES

Funds Flow from Operations

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

Reconciliation of Funds Flow from Operations

	Three months ended September 30				Nine months ended September 30
($000s)	2017		2016		2017	2016
Cash flow from operating activities	20,437		(14,857	)	15,187	(7,420	)
Changes in non-cash working capital	(1,220	)	17,204		23,387	8,963
Funds flow from operations1	19,217		2,347		38,574	1,543
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 and Comprehensive Income. Cash interest paid is reported as a financing activity on the Condensed Consolidated Interim         Statements of Cash Flows.

Debt-to-Funds Flow ratio

Debt-to-funds flow is a measure that is used to set the amount of capital in proportion to risk. The Company’s debt-to-funds flow ratio is computed as long-term debt, including the current portion over funds flow from operations for the trailing twelve months. Debt-to-funds flow 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 that represents sales net of royalties (all government interests, net of income taxes), operating expenses, current taxes and selling costs. 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-based, 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.

Q3-2017 9

SELECTED QUARTERLY FINANCIAL INFORMATION

	2017						2016								2015
(000s, except per share,
price and volume amounts)	Q-3		Q-2		Q-1		Q-43		Q-3		Q-2		Q-1		Q-4
Operations
Average production volumes
Crude oil (bbls/d)	12,786		14,347		14,514		12,861		11,733		11,472		12,058		13,425
NGLs (bbls/d)	1,081		919		1,037		134		—		—		—		—
Natural gas (mcf/d)	6,268		7,191		7,075		916		—		—		—		—
Total (boe/d)	14,912		16,465		16,731		13,148		11,733		11,472		12,058		13,425
Average sales volumes
Crude oil (bbls/d)	15,894		17,141		11,610		7,018		11,485		11,783		14,126		7,205
NGLs (bbls/d)	1,081		919		1,037		134		—		—		—		—
Natural gas (mcf/d)	6,268		7,191		7,075		916		—		—		—		—
Total (boe/d)	18,020		19,259		13,826		7,305		11,485		11,783		14,126		7,205
Average realized sales prices
Crude oil ($/bbl)	44.82		39.46		41.66		37.38		34.43		30.27		22.58		32.38
NGLs ($/bbl)	18.90		21.08		19.08		12.33		—		—		—		—
Natural gas ($/Mcf)	1.65		2.14		1.96		1.80		—		—		—		—
Total oil equivalent ($/boe)	41.24		36.92		37.41		36.45		34.43		30.27		22.58		32.38
Inventory (Mbbl)	988		1,274		1,528		1,265		729		707		735		923
Petroleum and natural gas sales	68,372		64,711		46,553		24,501		36,376		32,461		29,022		21,460
Petroleum and natural gas sales, net of royalties	44,839		40,439		22,461		5,217		20,704		19,786		17,427		3,979
Cash flow from operating activities	20,437		(2,753	)	(2,497	)	6,355		(14,857	)	6,011		1,426		6,414
Funds flow from operations1	19,217		16,855		2,502		(9,904	)	2,347		2,026		(2,830	)	(11,108	)
Funds flow from operations per share
- Basic	0.27		0.23		0.03		(0.14	)	0.03		0.03		(0.04	)	(0.15	)
- Diluted	0.27		0.23		0.03		(0.14	)	0.03		0.03		(0.04	)	(0.15	)
Net earnings (loss)	(6,855	)	(56,622	)	(12,877	)	(33,997	)	(25,369	)	(12,050	)	(16,249	)	(35,255	)
Net earnings (loss) - diluted	(6,855	)	(56,622	)	(12,877	)	(38,641	)	(25,369	)	(12,050	)	(16,249	)	(35,255	)
Net earnings per share
- Basic	(0.09	)	(0.78	)	(0.18	)	(0.47	)	(0.35	)	(0.17	)	(0.23	)	(0.49	)
- Diluted	(0.09	)	(0.78	)	(0.18	)	(0.49	)	(0.35	)	(0.17	)	(0.23	)	(0.49	)
Capital expenditures	10,133		8,229		10,718		8,863		8,692		4,838		4,265		4,877
Dividends paid	—		—		—		—		—		—		—		1,805
Dividends paid per share	—		—		—		—		—		—		—		0.03
Total assets	338,802		337,596		403,686		406,142		414,363		433,013		441,624		455,500
Cash and cash equivalents	21,464		13,780		21,324		31,468		100,405		124,308		122,031		126,910
Convertible debentures	—		—		—		72,655		74,854		70,639		66,506		63,848
Note payable	—		—		11,259		11,162		—		—		—		—
Total long-term debt, including      current portion	79,839		83,725		73,549		—		—		—		—		—
Debt-to-funds flow ratio2	2.8		7.1		(28.0	)	(10.0	)	(7.8	)	(5.3	)	(7.9	)	(7.2	)
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. See "Non-GAAP Financial Measures".
2  Debt-to-funds flow ratio is a measure that represents total long-term debt (including the current portion) plus convertible debentures 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.

10 Q3-2017

During the third quarter of 2017, TransGlobe:

• Reported a net loss of $6.9 million, which include a $10.3 million non-cash impairment loss on the Company's exploration and evaluation assets at South Alamein and a $3.2 million unrealized derivative loss on commodity contracts (mark-to-market loss on the Company's hedging contracts);

• Experienced a 88% increase in petroleum and natural gas sales compared to Q3-2016, which was principally due to a 20% increase in realized prices along with a 57% increase in sales volumes. Sales volumes were higher due to crude oil entitlement sales to EGPC of 351,002 barrels, offset slightly by a smaller tanker lifting in Q3-2017 versus Q3-2016, and the sales contributed by the acquired Canadian assets;

• Achieved positive funds flow from operations of $19.2 million, which is a significant increase over the previous seven quarters;

• Reported a 27% increase in production volumes as compared to Q3-2016, which translates into an additional 3,179 boepd. The recently acquired Canadian assets contributed 2,644 boepd of additional production, and increased Egypt production accounted for the remaining variance. The increased Egypt production was primarily from NW Gharib, which contributed 876 bopd;

• Repaid $5.0 million of the amount outstanding under the prepayment agreement with cash on hand;

• Sold a tanker of entitlement crude of 442,953 barrels and an additional 351,002 barrels of inventoried entitlement crude oil to EGPC, resulting in a decrease in crude oil inventory of 0.3 million barrels from Q2-2017;

• Spent $10.1 million on capital programs, which was funded entirely from funds flow and cash on hand; and

• Ended the quarter with positive working capital of $58.8 million (including cash and cash equivalents of $21.5 million) at September 30, 2017.

Q3-2017 11

2017 TO 2016 NET EARNINGS VARIANCES

			$ Per Share
	$000s		Diluted		% Variance
Q3-2016 net earnings (loss)	(25,369	)	(0.35	)
Cash items
Volume variance	24,133		0.34		(95	)
Price variance	7,863		0.11		(31	)
Royalties	(7,861	)	(0.11	)	31
Expenses:
Production and operating	(3,365	)	(0.05	)	13
Transportation	(212	)	—		1
Selling costs	(424	)	(0.01	)	2
Cash general and administrative	(113	)	—		—
Current income taxes	(1,112	)	(0.02	)	4
Realized foreign exchange gain (loss)	1		—		—
Realized derivative gain (loss)	(1,904	)	(0.03	)	8
Interest on long-term debt	(40	)	—		—
Other income	(136	)	—		1
Total cash items variance	16,830		0.23		(66	)
Non-cash items
Unrealized derivative gain (loss)	(3,235	)	(0.04	)	13
Unrealized foreign exchange gain (loss)	(588	)	(0.01	)	2
Depletion and depreciation	(4,321	)	(0.06	)	17
Asset retirement obligation accretion	(74	)	—		—
Unrealized gain (loss) on financial instruments	4,881		0.07		(19	)
Impairment loss	4,598		0.06		(18	)
Stock-based compensation	399		0.01		(2	)
Deferred lease inducement	(1	)	—		—
Amortization of deferred financing costs	25		—		—
Total non-cash items variance	1,684		0.03		(7	)
Q3-2017 net earnings (loss)	(6,855	)	(0.09	)	(73	)

TransGlobe recorded a net loss of $6.9 million in Q3-2017 compared to a net loss of $25.4 million in Q3-2016. The largest positive earnings variance was a result of a 20% increase in the average realized sales price and a 57% increase in sales volumes totaling $32.0 million in aggregate compared to Q3-2016, which was partially offset by increased royalties and current income taxes of $9.0 million. The Company incurred $0.4 million in selling costs during the period. Operating expenditures increased in Q3-2017 compared to Q3-2016, due principally to recognizing capitalized operating costs associated with the previously inventoried entitlement crude oil barrels sold during the quarter.

The largest non-cash positive earnings variance item in Q3-2017 compared to Q3-2016 related to the mark-to-market adjustment on the convertible debentures of $4.9 million. A non-cash positive earnings swing of $4.6 million was created by the impairment loss recorded on the Company's South East Gharib exploration and evaluation assets in Q3-2016 in the amount of $14.9 million versus a corresponding $10.3 million impairment loss recorded in Q3-2017 related to the Company's South Alamein exploration and evaluation assets. The convertible debentures were repaid during the first quarter of 2017. The largest non-cash negative earnings variance in Q3-2017 compared to Q3-2016 related to the depletion, depreciation and amortization. The increase is principally a result of recognizing capitalized depletion costs associated with the previously inventoried entitlement crude oil barrels sold during the quarter and the depletion, depreciation and amortization on the recently acquired Canadian assets. The Company recorded a $3.2 million non-cash unrealized derivative loss on its outstanding hedging commodity contracts held at the end of Q3-2017, which was a result of marking the contracts to their respective market values. In Q3-2016, there were no hedging contracts outstanding.

BUSINESS ENVIRONMENT

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

Average reference prices	2017			2016
	Q-3	Q-2	Q-1	Q-4	Q-3
Crude oil
Dated Brent average oil price (US$/bbl)	52.11	49.67	53.68	49.19	45.79
Edmonton Sweet index (US$/bbl)	45.32	46.03	48.37	46.18	41.99
Natural gas
AECO (C$/mmbtu)	1.45	2.78	2.69	3.09	2.32
U.S./Canadian Dollar average exchange rate	1.247	1.345	1.323	1.334	1.305

12 Q3-2017

The price of Dated Brent oil averaged 5% higher in Q3-2017 compared with Q2-2017. Egypt production is priced based on Dated Brent, less a quality differential and shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (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 revenue. 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 recovery or cost oil ranges from 25% to 30% in Egypt. The balance of the production after maximum cost recovery is shared with the government (production sharing oil). Depending on the contract, the Egyptian government receives 70% to 86% of the production sharing oil or profit oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of production sharing oil increases when production exceeds pre-set production levels in the respective contracts. During times of increased 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.

Egypt has been experiencing significant financial challenges over the past six years. While exploration and development activities have generally been uninterrupted, the Company experienced delays in the collection of accounts receivable from the Egyptian government up to the end of 2013. Since the end of 2013, the Company has collected a total of $364.6 million from EGPC, reducing the balance due from EGPC to $25.5 million as at September 30, 2017. The Company's credit risk, as it relates to accounts receivable from EGPC, has now been reduced due to the significant collections from EGPC. EGPC owns the storage and export facilities where the Company's inventory is delivered, and the Company requires EGPC cooperation and approval to schedule liftings. Once liftings are scheduled, the Company enjoys 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, buyers may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings.

On December 20, 2016, the Company acquired producing oil and gas assets in the Harmattan area of west central Alberta, Canada. The Harmattan acquisition provided the Company with a meaningful re-entry into Canada with concentrated, high working interest assets in proven, low risk development light oil and liquid-rich gas play types. The acquisition provides ample drilling locations and running room to increase reserves and production through horizontal drilling and multi-stage frac technology. The Harmattan acquisition met the Company's strategy to diversify and expand operations into lower political risk OECD countries with attractive netbacks to support growth in the current oil price environment and plays to the Company's core strength of value creation through development drilling and reservoir management.

The price of Edmonton Sweet index oil averaged 2% lower in Q3-2017 compared with Q2-2017. The price of AECO averaged 48% lower in Q3-2017 compared with Q2-2017.

Q3-2017 13

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest before Royalties (Boepd)

Production Volumes

	Three months ended September 30		Nine months ended September 30
	2017	2016	2017	2016
Egypt crude oil (bbls/d)	12,268	11,733	13,351	11,754
Canada crude oil (bbls/d)	518	—	526	—
Canada natural gas (mcf/d)	6,268	—	6,842	—
Canada NGLs (bbls/d)	1,081	—	1,012	—
Total Company (boe/d)	14,912	11,733	16,029	11,754

Sales Volumes (excludes volumes held as inventory)

	Three months ended September 30		Nine months ended September 30
	2017	2016	2017	2016
Egypt crude oil (bbls/d)	15,376	11,485	14,372	12,461
Canada crude oil (bbls/d)	518	—	526	—
Canada natural gas (mcf/d)	6,268	—	6,842	—
Canada NGLs (bbls/d)	1,081	—	1,012	—
Total Company (boe/d)	18,020	11,485	17,050	12,461

Netback

Consolidated netback
	Nine months ended September 30
	2017		2016
(000s, except per boe amounts)1	$	$/boe	$	$/bbl
Petroleum and natural gas sales	179,637	38.59	97,859	28.66
Royalties and other	71,898	15.45	39,942	11.70
Current taxes	16,104	3.46	10,737	3.14
Production and operating expenses	39,356	8.46	34,706	10.16
Transportation	566	0.12	—	—
Selling costs	1,926	0.41	875	0.26
Netback	49,787	10.69	11,599	3.40
1   The Company achieved the netbacks above on sold barrels of oil equivalent for the nine months ended September 30, 2017 and September 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at September 30, 2017).

Consolidated netback
	Three months ended September 30
	2017		2016
(000s, except per boe amounts)1	$	$/boe	$	$/bbl
Petroleum and natural gas sales	68,372	41.24	36,376	34.43
Royalties and other	23,533	14.19	15,672	14.83
Current taxes	5,179	3.12	4,067	3.85
Production and operating expenses	14,310	8.63	10,945	10.36
Transportation	211	0.13	—	—
Selling costs	425	0.26	—	—
Netback	24,714	14.91	5,692	5.39
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the three months ended September 30, 2017 and September 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at September 30, 2017).

14 Q3-2017

Egypt
	Nine months ended September 30
	2017		2016
(000s, except per bbl amounts)1	$	$/bbl	$	$/bbl
Oil sales	163,984	41.79	97,859	28.66
Royalties	68,543	17.47	39,942	11.70
Current taxes	16,104	4.10	10,737	3.14
Production and operating expenses	35,344	9.01	34,706	10.16
Selling costs	1,926	0.49	875	0.26
Netback	42,067	10.72	11,599	3.40
1   The Company achieved the netbacks above on sold barrels of oil equivalent for the nine months ended September 30, 2017 and September 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at September 30, 2017).

Egypt
	Three months ended September 30
	2017		2016
(000s, except per bbl amounts)1	$	$/bbl	$	$/bbl
Oil sales	63,403	44.82	36,376	34.43
Royalties	22,506	15.91	15,672	14.83
Current taxes	5,179	3.66	4,067	3.85
Production and operating expenses	13,242	9.36	10,945	10.36
Selling costs	425	0.30	—	—
Netback	22,051	15.59	5,692	5.39
1   The Company achieved the netbacks above on sold barrels of oil equivalent for the three months ended September 30, 2017 and September 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at September 30, 2017).

The netback per bbl in Egypt increased 189% and 215%, respectively, in the three and nine months ended September 30, 2017 compared with the same periods of 2016. The increased netbacks were principally the result of an increase in previously inventoried entitlement barrels sold, (285,967 barrels and 276,990 barrels) realized oil prices of 30% and 46%, respectively, and a decrease in operating costs per barrel of 10% and 11%, respectively, in the three and nine months ended September 30, 2017 compared with the same periods of 2016.

Production and operating expenses increased by $2.3 million in the three months ended September 30, 2017 compared to the same period of 2016. This is principally the result of an increase in sales volumes in Q3-2017, resulting in recognizing the capitalized operating costs associated with the crude oil inventory in the period. Operating costs for the nine months ended September 30, 2017 are relatively consistent with the same period in 2016. On a per bbl basis, production and operating costs have decreased by 10% and 11%, respectively, in the three and nine months ended September 30, 2017 compared with the same periods of 2016. The most significant cost efficiencies were achieved in the areas of labour costs and well servicing. The devaluation of the Egyptian pound, which occurred in Q4 of 2016, also had a significant positive impact on operating expenses in the quarter as compared to Q3-2016. The gains realized from increased prices and lower operating costs were offset somewhat by higher transportation and marketing fees incurred on the direct sale of the Company's crude oil. TransGlobe completed one direct sale of crude oil during Q3-2017.

Royalties and taxes as a percentage of revenue were 44% and 52%, in the three and nine month periods ended September 30, 2017 respectively, compared with 54% and 52%, respectively, for the same periods of 2016. Royalties and taxes are settled on a production basis, so the correlation of royalties and taxes to oil sales fluctuates depending on the timing of entitlement oil sales. As such, 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 and 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. The Company sold 285,967 barrels and 276,990 barrels from inventory during the three and nine months ended September 30, 2017.

The average selling price during the three months ended September 30, 2017 was $44.82/bbl, which was $7.29/bbl lower than the average Dated Brent oil price of $52.11/bbl for the period (Q3-2016 - $45.79/bbl). Generally the difference in the average Dated Brent price and the Company's realized selling price is due to a gravity/quality differential and is impacted by the timing of direct sales.

Q3-2017 15

Canada
	Nine months ended September 30
	2017		2016
(000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	6,635	46.21	—	—
Natural gas sales	3,594	11.54	—	—
NGL sales	5,424	19.63	—	—
Total sales	15,653	21.41
Royalties	3,355	4.59	—	—
Production and operating expenses	4,012	5.49	—	—
Transportation	566	0.77	—	—
Netback	7,720	10.56	—	—

Canada
	Three months ended September 30
	2017		2016
(000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	2,140	44.91	—	—
Natural gas sales	949	9.87	—	—
NGL sales	1,880	18.90	—	—
Total sales	4,969	20.43
Royalties	1,027	4.22	—	—
Production and operating expenses	1,068	4.39	—	—
Transportation	211	0.87	—	—
Netback	2,663	10.95	—	—

The Canadian financial information presented in the tables above represent the three and nine months ended September 30, 2017 activity for the Company's newly acquired Canadian assets.

Netbacks in Canada for the three months ended Q3-2017 were $10.95 per boe, which represents a decrease of $0.46 per boe as compared to the three months ended Q2-2017. This decrease in netback is primarily the result of an 10% and 23% decrease in the realized NGL and natural gas sales price on a per boe basis during the third quarter. Production and operating expenses and transportation costs have decreased by 18% in aggregate on a per boe basis, as compared to the three months ended Q2-2017.

TransGlobe pays royalties to the Alberta provincial government and landowners in accordance with an 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 typically have a finite period of time and are in place to promote drilling activity by reducing overall royalty expense.

For the three months ended September 30, 2017, the Company incurred $1.0 million in royalty costs. Royalties amounted to 21% of petroleum and natural gas sales revenue in the three months ended September 30, 2017.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)

	Nine months ended September 30
	2017				2016
(000s, except per bbl amounts)	$		$/bbl		$		$/bbl
G&A (gross)	12,589		2.70		12,393		3.63
Stock-based compensation	886		0.19		2,181		0.64
Capitalized G&A	(1,858	)	(0.40	)	(2,832	)	(0.83	)
G&A (net)	11,617		2.49		11,742		3.44

	Three months ended September 30
	2017				2016
(000s, except per bbl amounts)	$		$/bbl		$		$/bbl
G&A (gross)	4,209		2.54		4,352		4.12
Stock-based compensation	236		0.14		635		0.60
Capitalized G&A	(636	)	(0.38	)	(893	)	(0.85	)
G&A (net)	3,809		2.30		4,094		3.87

16 Q3-2017

G&A (gross) for the three months ended September 30, 2017 decreased 3% as compared with the same period in 2016 (38% decrease on a per boe basis). This was primarily due to slightly lower staff levels. For the nine months ended September 30, 2017 G&A (gross) is relatively flat versus the same period in 2016 (26% decrease on a per boe basis). G&A on a per boe basis decreased due to a 57% and 37% sales volume increase in the three and nine months ended September 30, 2017 compared with the same periods of 2016.

G&A expenses (net) for the three months ended September 30, 2017 decreased 7% as compared with the same period in 2016 (41% decrease on a per boe basis). For the nine months ended September 30, 2017 G&A (net) is relatively flat versus the same period in 2016 (28% decrease on a per boe basis).

Capitalized G&A for the three and nine months ended September 30, 2017 decreased 29% and 34%, respectively, as compared with the same periods in 2016 (55% and 52% decrease, respectively, on a per boe basis). In 2016, the Company's capital spending commitments in Egypt were secured by letters of credit drawn on the Company's borrowing base facility. Banking fees associated with these letters of credit in the amount of $0.2 million and $0.8 million were capitalized for the three and nine months ended September 30, 2016. In December 2016 the Company terminated its Egypt borrowing base facility, and the spending commitments are now secured by a cash collateralized letter of credit facility.

FINANCE COSTS

Finance costs for the three and nine months ended September 30, 2017 were $1.5 million and $4.8 million, respectively (2016 - $1.5 million and $4.4 million, respectively).

	Three months ended September 30				Nine months ended September 30
(000s)	2017		2016		2017		2016
Convertible debentures	$	—	$	1,125	$	1,089	$	3,303
Long-term debt	1,276		—		2,731		—
Note payable	—		—		532		—
Borrowing base facility	115		226		164		632
Amortization of deferred financing costs	94		119		234		420
Finance costs	$	1,485	$	1,470	$	4,750	$	4,355

Convertible Debentures

Interest expense on the convertible debentures for the three and nine month period ended September 30, 2017 was $nil and $1.1 million, respectively (2016 - $1.5 million and $4.4 million, respectively). Interest on the convertible debentures was paid in Canadian dollars, and therefore fluctuated from period to period depending on the strength of the Canadian dollar relative to the US dollar. The convertible debentures outstanding at December 31, 2016 were repaid in full on March 31, 2017 using the proceeds of the prepayment agreement.

Prepayment Agreement

On February 10, 2017, the Company completed a $75.0 million crude oil prepayment agreement between its wholly-owned subsidiary, TransGlobe Petroleum International Inc. ("TPI") and Mercuria Energy Trading S.A. ("Mercuria") of Geneva, Switzerland.

TPI's obligations under the prepayment agreement are guaranteed by the Company and the subsidiaries of TPI (the "Guarantors"). The obligations of TPI and the Guarantors will be supported by, among other things, a pledge of equity held by the Company in TPI and a pledge of equity held by TPI in its subsidiaries. The funding arrangement has a term of four years, maturing March 31, 2021 and advances bear interest at a rate of Libor plus 6.0%. The funding arrangement is revolving with each advance to be satisfied through the delivery of crude oil to Mercuria. Further advances become available upon delivery of crude oil to Mercuria up to a maximum of $75.0 million and subject to compliance with the other terms and conditions of the prepayment agreement. The prepayment agreement was initially recognized at fair value, net of financing costs, and has subsequently been measured at amortized cost. The prepayment agreement is classified as long-term debt in the Company's financial statements. Financing costs of $1.5 million will be amortized over the term of the prepayment agreement using the effective interest rate method. Interest expense on the prepayment agreement for the three and nine month period ended September 30, 2017 was $1.3 million and $2.7 million.

The prepayment agreement is subject to certain covenants, the details of which are outlined in Note 14 to the Company's Condensed Consolidated Interim Financial Statements.

Revolving Reserve-Based Lending Facility

As at September 30, 2017, the Company had in place a revolving Canadian reserve-based lending facility with Alberta Treasury Branches ("ATB") totaling C$30.0 million, of which C$13.9 million ($11.1 million) was drawn.

The facility is extendable on a semi-annual basis on May 31 and November 30 of each year, or as requested by the lender. Unless extended before May 11, 2018, any unutilized amount of the facility will be cancelled and the amount of the facility will be reduced to the aggregate borrowings outstanding on that date. The balance of all amounts owing under the facility are due and payable in full on the date falling one year after the term date.The Company may request an extension of the term date by no later than 90 days prior to the then current term date, and lender may in its sole discretion agree to extend the term date for a further period of 364 days. If no extension is granted by the lender, the amounts owing pursuant to the facility are due at the maturity date. The facility bears interest at a rate of either ATB Prime or CDOR (Canadian Dollar Offered Rate) plus applicable margins that vary from 1.25% to 3.25% depending on the Company's net debt to trailing cash flow ratio. The revolving reserve-based lending facility was initially recognized at fair value, net of financing costs, and has subsequently been measured at amortized cost. Interest expense on the revolving reserve-based lending facility for the three and nine month period ended September 30, 2017 was $0.1 million and $0.2 million.

Q3-2017 17

Note Payable

On December 20, 2016, the Company closed the acquisition of certain petroleum properties in west central Alberta, Canada. The acquisition was partially funded by a vendor take-back note of C$15.0 million ($11.3 million). The note payable had a 24-month term and bore interest at a rate of 10% per annum. The Company repaid the outstanding vendor take-back note balance of C$13.6 million ($10.0 million) on May 16, 2017. Repayment was made using the revolving reserve-based lending facility. Interest expense on the note payable for the three and nine month period ended September 30, 2017 was $nil and $0.5 million.

DEPLETION AND DEPRECIATION (“DD&A”)

	Nine months ended September 30
	2017		2016
(000s, except per bbl amounts)	$	$/bbl	$	$/bbl
Egypt	22,568	5.75	24,172	7.08
Canada	6,768	9.26	—	—
Corporate	299	—	366	—
	29,635	6.37	24,538	7.19

	Three months ended September 30
	2017		2016
(000s, except per bbl amounts)	$	$/bbl	$	$/bbl
Egypt	8,360	5.91	6,317	5.98
Canada	2,258	9.28	—	—
Corporate	142	—	122	—
	10,760	6.49	6,439	6.09

In Egypt, DD&A decreased 1% and 19%, respectively, on a per bbl basis in the three and nine months ended September 30, 2017 compared to the same periods in 2016. The decrease is primarily related to a lower depletable cost base, which is the result of a 24% reduction in future development costs.

In Canada, DD&A was $9.28 and $9.26 per bbl, respectively, on a per bbl basis in the three and nine months ended September 30, 2017, which was consistent with the DD&A rate for the three months ended Q2-2017.

IMPAIRMENT LOSS

The non-cash impairment loss recorded on the Company's exploration and evaluation assets amounted to $10.3 million and $79.0 million, in the three and nine month periods ended September 30, 2017 respectively, compared with $14.9 million for each of the same periods of 2016. The impairment loss was split between the South West Gharib concession ($1.2 million), the North West Gharib concession ($67.5 million) and the South Alamein concession of ($10.3 million).

At South West Gharib, it was determined during the first quarter that an impairment loss was necessary as no commercially viable quantities of oil were discovered, and no further drilling activities are planned.

At North West Gharib, the recoverable amount of the North West Gharib cash-generating unit was $4.4 million. The remaining North West Gharib exploration and evaluation assets were written down to nil during the second quarter. The North West Gharib exploration lands have been fully evaluated and all commitments have been met at the end of the first exploration phase. The Company elected not to enter the second exploration period. The Company filed for and received four development leases in the North West Gharib concession, all remaining exploration lands that are not covered by development leases were relinquished.

The impairment was taken after consideration of the uncertainly of the timing of additional exploration and development on the existing and pending development leases and the current forward outlook for Gharib blend pricing. TransGlobe signed the North West Gharib Production Sharing Agreement ("PSC") (won in the EGPC bid round in 2011/2012) on November 7, 2013. The Company entered into these exploration commitments when the oil price environment was significantly stronger. Brent oil prices averaged between $108/bbl to $112/bbl from 2011 to 2013.

At South Alamein, it was determined for the three months ended September 30, 2017 that an impairment loss was necessary, due to the results of the Boraq 5 well and the uncertainty of an economic development of Boraq in the future. The Company completed testing two zones in the Boraq 5 appraisal well. The Boraq 5 well failed to produce any hydrocarbons from the two zones and was plugged and abandoned.

18 Q3-2017

CAPITAL EXPENDITURES

	Nine months ended September 30
($000s)	2017	2016
Egypt	24,667	17,794
Canada	4,384	—
Corporate	30	—
Total	29,081	17,794

In Egypt, total capital expenditures in the first nine months of 2017 were $24.7 million (2016 - $17.8 million). During the first nine months of the year, the Company drilled nine exploration wells and four development wells. Six exploration wells were drilled at NW Gharib resulting in two oil discoveries (NWG 26 and NWG 27) and four dry holes (NWG 28, NWG 39, NWG 40 and NWG 42). At SW Gharib the Company drilled two exploration wells, both of which were dry and abandoned. At South Alamein the Company drilled one exploration well, Boraq 5, resulting in a dry hole. At West Gharib, the second of two infill development oil wells in the Arta Red Bed pool was drilled and at West Bakr the K-47 development well was drilled and cased as an Asl A oil well in the South-K field. In addition, the Company drilled two appraisal wells, NWG 3A and NWG 38A. During the nine months ended September 30, 2017 the Company spent $12.0 million in drilling, $4.9 million on seismic acquisition in NW Sitra, $2.1 million on completions and $2.7 million on facilities construction and maintenance. An addition $1.0 million related to the approval for three development leases at NWG.

In Canada, the Company drilled and initiated the completions on three horizontal Cardium oil wells in Harmattan during the quarter. The three wells were drilled, completed and equipped for approximately $2.1 million (C$2.5 million).

OUTSTANDING SHARE DATA

As at September 30, 2017, the Company had 72,205,369 common shares issued and outstanding and 5,344,520 stock options issued and outstanding, which 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 necessary to 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. TransGlobe’s debt-to-funds flow from operations ratio deteriorated significantly from late 2014 as a direct result of a continued lower oil price environment. As of September 30, 2017, debt-to-funds flow improved to 2.8 (December 31, 2016 - negative 10.0) as a result of positive funds flow for the trailing 12 months. The Company's funds flow from operations can vary significantly from quarter to quarter depending on the timing of tanker liftings, and these fluctuations in funds flow impact the Company's debt-to-funds flow from operations ratio. TransGlobe's management will continue to steward capital programs and focus on cost reductions in order to maintain balance sheet strength through the current low oil price environment.

The table below illustrates TransGlobe’s sources and uses of cash during the periods ended September 30, 2017 and 2016:

Sources and Uses of Cash
	Nine months ended September 30
($000s)	2017		2016
Cash sourced
Funds flow from operations1	38,574		1,543
Transfer from restricted cash	13,511		289
Increase in long-term debt	85,265		—
Other	465		—
	137,815		1,832
Cash used
Capital expenditures	29,081		17,794
Deferred financing costs	1,555		—
Repayment of long-term debt	5,000		—
Repayment of convertible debentures	73,375		—
Repayment of note payable	11,041		—
Finance costs	5,453		5,007
Other	—		1,128
	125,505		23,929
	12,310		(22,097	)
Changes in non-cash working capital	(22,314	)	(4,408	)
Increase (decrease) in cash and cash equivalents	(10,004	)	(26,505	)
Cash and cash equivalents – beginning of period	31,468		126,910
Cash and cash equivalents – end of period	21,464		100,405
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.

Q3-2017 19

Funding for the Company’s capital expenditures was provided by funds flow from operations and cash on hand. The Company expects to fund its 2017 exploration and development program of $40.7 million, including contractual commitments, through the use of working capital and funds flow from operations. 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 September 30, 2017, the Company had a working capital surplus of $58.8 million (December 31, 2016 - deficiency of $16.8 million). The increase to working capital in Q3-2017 is principally due to the repayment of the convertible debt, which was a current liability at year-end 2016, (using the proceeds from the prepayment agreement) and increased sales of inventoried entitlement oil, as well as marginally better crude pricing and lower Gharib blend differentials, offset by lower natural gas prices in Canada. During Q3-2017 the Company repaid $5.0 million of the amount outstanding under the prepayment agreement with cash on hand.

The Company's second cargo lifting of the year was completed in September and proceeds from the lifting were received in October. TransGlobe's third tanker-lifting of 2017 is scheduled for late November. The Company now enjoys 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, buyers may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings, which has significantly reduced the Company's credit risk profile. As at September 30, 2017, the Company held 988,090 barrels of entitlement oil as inventory.

The Company now has a receivable balance of $25.5 million due from EGPC. During the first nine months of 2017, the Company sold 957,467 barrels of inventoried entitlement crude oil to EGPC for $40.1 million to cover in-country expenditures. The Company collected $28.1 million of accounts receivable from EGPC during the first nine months of 2017.

At September 30, 2017, the Company had in place a revolving Canadian reserve-based lending facility with ATB totaling C$30.0 million, of which C$13.6 million was drawn on May 16, 2017 to repay the remaining outstanding vendor take-back note balance in full for $C13.6 million ($10.0 million). As at September 30, 2017, C$13.9 million ($11.1 million) was drawn.

As at September 30, 2017, the Company had restricted cash of $4.8 million (December 31, 2016 - $18.3 million). Restricted cash represents a cash collateralized letter of credit facility that is used to guarantee the Company's commitments on its Egyptian exploration concessions.

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

PRODUCT INVENTORY

Product inventory consists of the Company's Egypt entitlement crude oil barrels, which are valued at the lower of cost or net realizable value. Cost includes operating expenses and depletion associated with the unsold entitlement crude oil as determined on a concession by concession basis. All oil produced is delivered to EGPC facilities, and EGPC also owns the storage and export facilities where the Company's product inventory is sold from. 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 granted and the timing and size of tanker liftings in Egypt. As at September 30, 2017, the Company had 988,090 barrels of entitlement oil as inventory, which represents approximately six months of entitlement oil production. Since the Company began directly marketing its oil on January 1, 2015, both increases and decreases in crude oil inventory levels have been experienced from 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 2017, and anticipates that 2017 year-end crude oil inventory will be less than 1 million barrels, subject to the current tanker lifting schedule. One additional tanker lifting is currently scheduled for the remainder of 2017, with expected total shipment volumes of approximately 1.5 MMbbl for 2017, inclusive of the June, September and scheduled November tanker liftings. Inventoried entitlement crude oil has been reduced by 276,990 in the first three quarters of 2017.

	Nine months ended		Year ended
(bbls)	September 30, 2017		December 31, 2016
Product inventory, beginning of period	1,265,080		923,106
TransGlobe entitlement production	1,639,056		2,036,483
Tanker liftings	(958,579	)	(1,694,509	)
EGPC sales	(957,467	)	—
Product inventory, end of period	988,090		1,265,080

20 Q3-2017

COMMITMENTS AND CONTINGENCIES

As part of its normal business, the Company has 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	32,532	32,532
Long-term debt	Yes - Liability	79,839	—	11,128	68,711
Financial derivative instruments	Yes - Liability	465	465	—	—
Office and equipment leases3	No	3,922	1,819	2,103	—
Minimum work commitments4	No	5,129	5,129	—	—
Total		121,887	39,945	13,231	68,711
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at September 30, 2017 exchange rates.
3 Office and equipment leases includes all drilling rig contracts.
4 Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

The Company is subject to certain office and equipment leases.

Pursuant to the PSC for North West Gharib in Egypt, the Company had a minimum financial commitment of $35.0 million and a work commitment for 30 wells and 200 square kilometers of 3-D seismic during the initial-three year exploration period, which commenced on November 7, 2013. The Company received a six month extension to the initial exploration period, extending the initial exploration period to May 7, 2017. The Company completed the initial exploration period work program and met all financial commitments during the second quarter of 2017. The Company elected not to enter the second exploration period and has relinquished the remaining exploration lands that are not covered by the four development leases.

Pursuant to the PSC for South West Gharib in Egypt, the Company had a minimum financial commitment of $10.0 million and a work commitment for four wells and 200 square kilometers of 3-D seismic during the initial three-year exploration period, which commenced on November 7, 2013. The Company received a six month extension, which extended the initial exploration period to May 7, 2017. As no commercially viable quantities of oil were discovered at South West Gharib, the Company relinquished its interest in the concession on May 7, 2017. The Company met its financial commitment during the first quarter of 2017.

Pursuant to the PSC for South Ghazalat in Egypt, the Company had a minimum financial commitment of $8.0 million and a work commitment for two wells and 400 square kilometers of 3-D seismic during the initial three-year exploration period, which commenced on November 7, 2013 and reached its primary term on November 7, 2016. Prior to expiry, the Company elected to enter the first two-year extension period (expiry November 7, 2018). The Company had met its financial commitment for the first phase ($8.0 million) and the first extension ($4.0 million), however the Company had not completed the first phase work program. Prior to entering the first extension the Company posted a $4.0 million performance bond with EGPC to carry forward two exploration commitment wells into the first extension period. The $4.0 million performance bond is supported by a production guarantee from the Company's producing concessions which will be released when the commitment wells have been drilled. In accordance with the concession agreement the Company relinquished 25% of the original exploration acreage prior to entering the first extension period. In addition, the first extension period has an additional financial commitment of $4.0 million, which has been met, and two additional exploration wells.

Pursuant to the PSC for North West Sitra in Egypt, the Company has a minimum financial commitment of $10.0 million ($5.1 million 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. As at September 30, 2017, the Company had expended $4.9 million towards meeting the financial and operating commitment, with the acquisition of 600 km² of 3-D seismic in 2017.

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

The Company is not aware of any material provisions or other contingent liabilities as at September 30, 2017.

Q3-2017 21

ASSET RETIREMENT OBLIGATION

At September 30, 2017, TransGlobe recorded an asset retirement obligation ("ARO") of $12.7 million (December 31, 2016 - $12.1 million) for the future abandonment and reclamation costs associated with the Harmattan assets in Canada. The estimated ARO includes assumptions in respect of actual costs to abandon wells and/or reclaim the properties, the time frame in which such costs will be incurred, as well as annual inflation factors in order to calculate the undiscounted total future liability. TransGlobe calculated the present value of the obligations using discount rates between 1.52% and 2.47% 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 Production Sharing Contracts TransGlobe is not responsible for ARO in Egypt.

DERIVATIVE COMMODITY CONTRACTS

In conjunction with the recently executed prepayment agreement, TPI has also entered into a marketing contract with Mercuria to market nine million barrels of TPI’s Egypt entitlement production. The pricing of the crude oil sales will be based on market prices at the time of sale. In conjunction with the prepayment and marketing agreements, the Company committed to enter into hedging arrangements for 60% of its 1P forecasted entitlement production.

The nature of TransGlobe’s operations results in exposure 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.

There were eight outstanding derivative commodity contracts as at September 30, 2017 (December 31, 2016 - nil), the fair values of which have been presented as assets and liabilities on the Condensed Consolidated Interim Balance Sheet.

The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at September 30, 2017:

Financial Brent Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume bbl	Sold Swap US$/bbl	Bought Put US$/bbl	Sold Call US$/bbl	Sold Put US$/bbl
28-Mar-17	Dec-17	Collar	300,000	—	45.00	56.00	—
7-Apr-17	Mar-18	3-Way Collar	250,000	—	53.00	61.15	44.00
12-Apr-17	Jun-18	3-Way Collar	250,000	—	54.00	63.10	45.00
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
1 50,000 bbl per calendar month through Jul 2020 - Dec 2020
2 50,000 bbl per calendar month through Jan 2020 - Jun 2020

Financial AECO North American Natural Gas Contracts
Transaction Date	Period Hedged	Contract	Volume GJ	Sold Swap CAD$/GJ	Bought Put CAD$/GJ	Sold Call CAD$/GJ	Sold Put CAD$/GJ
14-Sep-17	Oct 2017 - Dec 20171	Swap	12,900	2.065	—	—	—
1 4,300 GJ per day through Oct 2017 - Dec 2017

Subsequent to the third quarter, the Company entered into the following derivative commodity contract positions:

Financial Brent Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume bbl	Sold Swap US$/bbl	Bought Put US$/bbl	Sold Call US$/bbl	Sold Put US$/bbl
12-Oct-17	Jan 2019 - Dec 20191	3-Way Collar	396,000	—	53.00	62.10	46.00
26-Oct-17	Jan 2019 - Dec 20191	3-Way Collar	396,000	—	54.00	61.35	46.00
1 33,000 bbl per calendar month through Jan 2019 - Dec 2019

Q3-2017 22

INTERNAL CONTROLS OVER FINANCIAL REPORTING

TransGlobe's management designed and implemented internal controls over financial reporting, as defined under National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings, of the Canadian Securities Administrators and as defined in Rule 13a-15 under the US Securities Exchange Act of 1934. Internal controls over financial reporting is a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS, 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 period ended September 30, 2017 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

Q3-2017 23

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

(Unaudited – Expressed in thousands of U.S. Dollars, except per share amounts)

		Three Months Ended						Nine months ended
		September 30						September 30
	Notes	2017			2016			2017			2016
REVENUE
Petroleum and natural gas sales, net of royalties	5	$	44,839		$	20,704		$	107,739		$	57,917
Finance revenue		15			151			59			525
		44,854			20,855			107,798			58,442
EXPENSES
Production and operating		14,310			10,945			39,356			34,706
Transportation costs		212			—			566			—
Selling costs	7	424			—			1,926			875
General and administrative		3,809			4,094			11,617			11,742
Foreign exchange (gain) loss		3			(584		)	70			4,762
Finance costs	6	1,485			1,470			4,750			4,355
Depletion, depreciation and amortization	12	10,760			6,439			29,635			24,538
Accretion	13	74			—			191			—
Realized derivative (gain) loss on commodity contracts		1,904			—			375			956
Unrealized derivative (gain) loss on commodity contracts	4	3,235			—			386			—
Unrealized (gain) loss on financial instruments	15	—			4,881			151			7,536
Impairment of exploration and evaluation assets	11	10,314			14,912			79,025			14,912
		46,530			42,157			168,048			104,382
Earnings (loss) before income taxes		(1,676		)	(21,302		)	(60,250		)	(45,940		)
Income tax expense (recovery) - current		5,179			4,067			16,104			10,737
- deferred		—			—			—			(3,009		)
		5,179			4,067			16,104			7,728
NET EARNINGS (LOSS) FOR THE PERIOD		$	(6,855	)	$	(25,369	)	$	(76,354	)	$	(53,668	)
OTHER COMPREHENSIVE (LOSS) INCOME
Currency translation adjustments		4,070			—			3,455			—
COMPREHENSIVE INCOME (LOSS) FOR THE PERIOD		$	(2,785	)	$	(25,369	)	$	(72,899	)	$	(53,668	)
Earnings (loss) per share
Basic		$	(0.09	)	$	(0.35	)	$	(1.06	)	$	(0.74	)
Diluted		$	(0.09	)	$	(0.35	)	$	(1.06	)	$	(0.74	)

See accompanying notes to the Condensed Consolidated Interim Financial Statements.

24 Q3-2017

Condensed Consolidated Interim Balance Sheets

(Unaudited - Expressed in thousands of U.S. Dollars)

		As at		As at
	Notes	September 30, 2017		December 31, 2016
ASSETS
Current
Cash and cash equivalents	8	$	21,464	$	31,468
Restricted cash	9	4,812		18,323
Accounts receivable	4	49,707		14,836
Derivative commodity contracts	4	79		—
Prepaids and other		2,485		1,772
Product inventory	10	13,265		19,602
		91,812		86,001
Non-Current
Intangible exploration and evaluation assets	11	40,945		105,869
Property and equipment
Petroleum and natural gas assets	12	202,378		210,027
Other assets	12	3,667		4,245
		$	338,802	$	406,142
LIABILITIES
Current
Accounts payable and accrued liabilities		$	32,532	$	24,529
Convertible debentures	15	—		72,655
Derivative commodity contracts		465		—
Current portion of note payable	14	—		5,581
		32,997		102,765
Non-Current
Note payable	14	—		5,581
Long-term debt	14	79,839		—
Asset retirement obligation	13	12,684		12,099
Other long-term liabilities		315		381
		125,835		120,826
SHAREHOLDERS’ EQUITY
Share capital	17	152,084		152,084
Accumulated other comprehensive income		3,455		—
Contributed surplus		23,245		22,695
Retained earnings		34,183		110,537
		212,967		285,316
		$	338,802	$	406,142

See accompanying notes to the Condensed Consolidated Interim Financial Statements.

Approved on behalf of the Board:

Signed by:

“Ross G. Clarkson”	“Fred J. Dyment”
Ross G. Clarkson	Fred J. Dyment
Director	Director

Q3-2017 25

Condensed Consolidated Interim Statements of Changes in Shareholders’ Equity

(Unaudited – Expressed in thousands of U.S. Dollars)

		Three Months Ended						Nine months ended
		September 30						September 30
	Notes	2017			2016			2017			2016
Share Capital
Balance, beginning of period	17	$	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		$	(615	)	$	—		$	—		$	—
Currency translation adjustment		4,070			—			3,455			—
Balance, end of period		$	3,455		$	—		$	3,455		$	—
Contributed Surplus
Balance, beginning of period		$	23,081		$	22,167		$	22,695		$	21,398
Stock-based compensation expense	18	164			264			550			1,033
Balance, end of period		$	23,245		$	22,431		$	23,245		$	22,431
Retained Earnings
Balance, beginning of period		$	41,038		$	169,903		$	110,537		$	198,202
Net earnings (loss) and total comprehensive income (loss)		(6,855		)	(25,369		)	(76,354		)	(53,668		)
Balance, end of period		$	34,183		$	144,534		$	34,183		$	144,534

See accompanying notes to the Condensed Consolidated Interim Financial Statements.

26 Q3-2017

Condensed Consolidated Interim Statements of Cash Flows

(Unaudited - Expressed in thousands of U.S. Dollars)

		Three Months Ended						Nine months ended
		September 30						September 30
	Notes	2017			2016			2017			2016
CASH FLOWS RELATED TO THE FOLLOWINGACTIVITIES:
OPERATING
Net earnings (loss) for the period		$	(6,855	)	$	(25,369	)	$	(76,354	)	$	(53,668	)
Adjustments for:
Depletion, depreciation and amortization	12	10,760			6,439			29,635			24,538
Accretion	13	74			—			191			—
Deferred lease inducement		(22		)	(23		)	(65		)	(74		)
Impairment of exploration and evaluation assets	11	10,314			14,912			79,025			14,912
Stock-based compensation	18	236			635			886			2,181
Finance costs	6	1,485			1,470			4,750			4,355
Income tax expense		5,179			4,067			16,104			7,728
Unrealized (gain) loss on commodity contracts	4	3,235			—			386			—
Unrealized (gain) loss on financial instruments	15	—			4,881			151			7,536
Unrealized (gain) loss on foreign currency translation		(10		)	(598		)	(31		)	4,772
Income taxes paid		(5,179		)	(4,067		)	(16,104		)	(10,737		)
Changes in non-cash working capital		1,220			(17,204		)	(23,387		)	(8,963		)
Net cash generated by (used in) operating activities		20,437			(14,857		)	15,187			(7,420		)
INVESTING
Additions to intangible exploration and evaluation assets	11	(2,257		)	(6,445		)	(16,372		)	(10,707		)
Additions to petroleum and natural gas assets	12	(7,678		)	(2,238		)	(12,151		)	(6,622		)
Additions to other assets	12	(198		)	(9		)	(558		)	(465		)
Changes in restricted cash	9	3,046			—			13,511			289
Changes in non-cash working capital		557			2,224			1,073			4,555
Net cash generated by (used in) investing activities		(6,530		)	(6,468		)	(14,497		)	(12,950		)
FINANCING
Repayment of note payable	14	—			—			(11,041		)	—
Financing costs	6	—			—			(1,555		)	—
Interest paid		(1,426		)	(2,477		)	(5,453		)	(5,007		)
Increase in long-term debt		125			—			85,265			—
Repayment of convertible debentures	15	—			—			(73,375		)	—
Repayments of long-term debt		(5,000		)	—			(5,000		)	—
Net cash generated by (used in) financing activities		(6,301		)	(2,477		)	(11,159		)	(5,007		)
Currency translation differences relating to cash and cash equivalents		78			(101		)	465			(1,128		)
NET INCREASE (DECREASE) IN CASH AND CASHEQUIVALENTS		7,684			(23,903		)	(10,004		)	(26,505		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		13,780			124,308			31,468			126,910
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	21,464		$	100,405		$	21,464		$	100,405

See accompanying notes to the Condensed Consolidated Interim Financial Statements.

Q3-2017 27

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

As at September 30, 2017 and December 31, 2016 and for the periods ended September 30, 2017 and 2016

(Unaudited - Expressed in U.S. Dollars)

1. CORPORATE INFORMATION

TransGlobe Energy Corporation is a publicly listed company incorporated in Alberta, Canada and its shares are listed on the Toronto Stock Exchange (“TSX”) and the Global Select Market of the NASDAQ Stock Market (“NASDAQ”). The address of its registered office is 2300, 250 – 5th Street SW, Calgary, Alberta, Canada, T2P 0R4. TransGlobe together with its subsidiaries ("TransGlobe" or the "Company") is engaged primarily in oil and gas exploration, development and production and the acquisition of properties.

2. BASIS OF PREPARATION

Statement of compliance

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 effective as of September 30, 2017. 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, 2016 Consolidated Financial Statements.

These Condensed Consolidated Interim Financial Statements were authorized for issue by the Board of Directors on November 7, 2017.

Basis of measurement

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 Financial Statements for the year ended December 31, 2016, with the exception of the change in functional currency of TransGlobe Energy Corporation, as described below.

The Company prepared these Condensed Consolidated Interim Financial Statements on a going concern basis, which contemplates the realization of assets and liabilities in the normal course of business as they become due. Accordingly, these Condensed Consolidated Interim Financial Statements have been prepared on a historical cost basis, except for cash and cash equivalents that have been measured at fair value.

Functional and presentation currency

In these Condensed Consolidated Interim Financial Statements, unless otherwise indicated, all dollar amounts are presented and expressed in United States (U.S.) dollars. All references to $ are to United States dollars and references to C$ are to Canadian dollars and all values are rounded to the nearest thousand except when otherwise indicated.

Effective January 1, 2017, TransGlobe Energy Corporation's functional currency is the Canadian dollar, and the functional currency of all subsidiaries is the U.S. dollar. It was determined that TransGlobe Energy Corporation's functional currency is now the Canadian dollar mainly because the parent company now owns Canadian producing assets, and therefore generates revenues and incurs costs that are denominated predominantly in Canadian dollars.

Foreign currency translations include the translation of foreign currency transactions and the translation of the Canadian functional currency operation. Foreign currency translations occur when translating transactions in foreign currencies to the applicable functional currency of TransGlobe Energy Corporation and its subsidiaries. Gains and losses from foreign currency transactions are recorded as foreign exchange gains or losses. Translations occur as follows:

• Income and expenses are translated at the prevailing rates on the date of the transaction

• Non-monetary assets or liabilities are carried at the prevailing rates on the date of the transaction

• Monetary items are translated at the prevailing rates at the balance sheet date

Canadian operation translation gains and losses occur when translating the financial statements of TransGlobe Energy Corporation (non-U.S. functional currency) to the U.S. dollar. These translation gains and losses are recorded as currency translation adjustments and presented as other comprehensive income on the Condensed Consolidated Interim Statements of Earnings (Loss) and Comprehensive Income (Loss). Translations occur as follows:

• Income and expenses are translated at the average exchange rates for the period

• Assets and liabilities are translated at the prevailing rates on the balance sheet date

28 Q3-2017

3. NEW STANDARDS AND INTERPRETATIONS NOT YET ADOPTED

As at the date of authorization of the Consolidated Financial Statements the following pronouncements from the International Accounting Standards Board ("ISAB") are applicable to TransGlobe and will become effective for future reporting periods, but have not yet been adopted:

IFRS 9 (revised) "Financial Instruments: Classification and Measurement"

In July 2014, the IASB issued the final version of IFRS 9 Financial Instruments to replace 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 and replaces the multiple rules in IAS 39. 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 the financial assets. For financial liabilities, IFRS 9 retains most of the IAS 39 requirements; however, 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, a new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model 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. The Company does not currently apply hedge accounting. IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. This amendment will be adopted by the Company on January 1, 2018 and the Company does not expect the adoption of IFRS 9 amendments to have a material effect on its Consolidated Financial Statements.

IFRS 15 "Revenue from Contracts with Customers"

IFRS 15 was issued in May 2014 and replaces IAS 18 Revenue, IAS 11 Construction Contracts and related interpretations. The standard is required to be adopted either retrospectively or using a modified transaction approach. In September 2015, the IASB amended IFRS 15, deferring the effective date of the standard by one year to annual periods beginning on or after January 1, 2018 with early adoption still permitted. IFRS 15 will be adopted by the Company on January 1, 2018. The Company is finalizing the review of its sales contracts with customers and does not expect IFRS 15 to have a material impact on the consolidated financial statements. Upon adoption, the Company will expand its disclosures in the notes to the consolidated financial statements including disaggregated revenue streams by product type and any impairment losses recognized on receivables arising from contracts with customers.

IFRS 16 "Leases"

In January 2016, the IASB issued IFRS 16 Leases, replacing IAS 17 Leases. IFRS 16 establishes a set of principles that both parties to a contract apply to provide relevant information about leases in a manner that faithfully represents those transactions. The current standard (IAS 17) requires lessees and lessors to classify their leases as either finance leases or operating leases, with separate accounting treatment depending on the classification of the lease. Under the new standard, the accounting treatment associated with an operating lease will no longer exist, and lessees will be required to recognize assets and liabilities associated with all leased items. The standard is effective for fiscal years beginning on or after January 1, 2019 with early adoption permitted if the Company is also applying IFRS 15 Revenue from Contracts with Customers. IFRS 16 will be adopted by the Company on January 1, 2019 and the Company is currently reviewing contracts that are identified as leases and does not expect that the adoption of the standard will have a material impact on the consolidated financial statements.

4. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair Values of Financial Instruments

The Company has classified its cash and cash equivalents and derivative commodity contracts as assets at fair value through profit or loss, its derivative commodity contracts and former convertible debentures as financial liabilities at fair value through profit or loss, which are both measured at fair value with changes being recognized through earnings. Accounts receivable and restricted cash are classified as loans and receivables; accounts payable and accrued liabilities, long-term debt and the previous note payable are classified as other liabilities, all of which are measured initially at fair value, then at amortized cost after initial recognition. Transaction costs attributable to financial instruments classified as other than held-for-trading are included in the recognized amount of the related financial instrument and recognized over the life of the resulting financial instrument using the effective interest rate method.

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

	September 30, 2017				December 31, 2016
	Carrying		Fair		Carrying		Fair
Classification (000s)	Value		Value		Value		Value
Financial assets at fair value through profit or loss	$	21,543	$	21,543	$	31,468	$	31,468
Loans and receivables	54,519		54,519		33,159		33,159
Financial liabilities at fair value through profit or loss	465		465		72,655		72,655
Other liabilities	112,371		113,693		35,691		35,691

Assets and liabilities at September 30, 2017 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.

Q3-2017 29

The Company’s cash and cash equivalents, derivative commodity contracts and prior convertible debentures are assessed on the fair value hierarchy described above. TransGlobe’s cash and cash equivalents and former convertible debentures 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

In conjunction with the prepayment agreement (Note 14), TPI has also entered into a marketing contract with Mercuria Energy Trading S.A. ("Mercuria") to market nine million barrels of TPI’s Egypt entitlement production. The pricing of the crude oil sales will be based on market prices at the time of sale.

The nature of TransGlobe’s operations results in exposure 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.

There were eight outstanding derivative commodity contracts as at September 30, 2017 (December 31, 2016 - nil), the fair values of which have been presented as assets and liabilities on the Condensed Consolidated Interim Balance Sheet.

The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at September 30, 2017:

Financial Brent Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume bbl	Sold Swap US$/bbl	Bought Put US$/bbl	Sold Call US$/bbl	Sold Put US$/bbl
28-Mar-17	Dec-17	Collar	300,000	—	45.00	56.00	—
7-Apr-17	Mar-18	3-Way Collar	250,000	—	53.00	61.15	44.00
12-Apr-17	Jun-18	3-Way Collar	250,000	—	54.00	63.10	45.00
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
1. 50,000 bbl per calendar month through Jul 2020 - Dec 2020
2.50,000 bbl per calendar month through Jan 2020 - Jun 2020

Financial AECO North American Natural Gas Contracts
Transaction Date	Period Hedged	Contract	Volume GJ	Sold Swap CAD$/GJ	Bought Put CAD$/GJ	Sold Call CAD$/GJ	Sold Put CAD$/GJ
14-Sep-17	Oct 2017 - Dec 20171	Swap	12,900	2.065	—	—	—
1. 4,300 GJ per day through Oct 2017 - Dec 2017

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 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 on the 25^th day of the month following production. 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 the creditworthiness of its counterparties, including financial institutions.

Trade and other receivables are analyzed in the table below. The majority of the overdue receivables are due from the Egyptian General Petroleum Company ("EGPC"). The political transition and resultant economic malaise in the country that began in 2011 resulted in irregular collection of accounts receivable from EGPC and generally a larger receivable balance, which increased TransGlobe's credit risk. Despite these factors, the Company expects to collect in full all receivables outstanding from EGPC.

30 Q3-2017

In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. The Company completed three separate direct crude sale shipments to third party buyers in 2016, and two shipments during the first nine months of 2017. Depending on the Company's assessment of the credit of crude cargo buyers, buyers may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. During the first nine months of 2017, the Company sold 957,467 barrels of inventoried entitlement crude oil to EGPC for $40.1 million to cover in-country expenditures. The Company collected $28.1 million of accounts receivable from EGPC during the first nine months of 2017. As at September 30, 2017 the accounts receivable balance is primarily due from EGPC of $25.5 million and the third quarter direct sale tanker-lifting of TransGlobe's entitlement oil for proceeds of $21.5 million.

(000s)	September 30, 2017		December 31, 2016
Neither impaired nor past due	$	34,672	$	620
Impaired (net of valuation allowance)
Not impaired and past due in the following period:
Within 30 days	3,696		—
31-60 days	4,204		—
61-90 days	4,175		—
Over 90 days	2,960		14,216
	$	49,707	$	14,836

5. PETROLEUM AND NATURAL GAS SALES

	Three months ended September 30				Nine months ended September 30
(000s)	2017		2016		2017		2016
Petroleum and natural gas sales	$	68,372	$	36,376	$	179,637	$	97,859
Less: Royalties	23,533		15,672		71,898		39,942
Petroleum and natural gas sales, net of royalties	$	44,839	$	20,704	$	107,739	$	57,917

6. FINANCE COSTS

Finance revenue relates to interest earned on the Company’s bank account balances and term deposits.

Finance costs recognized in earnings were as follows:

	Three months ended September 30				Nine months ended September 30
(000s)	2017		2016		2017		2016
Interest on convertible debenture	$	—	$	1,125	$	1,089	$	3,303
Interest on long-term debt	1,276		—		2,731		—
Interest on note payable	—		—		532		—
Interest on borrowing base facility	115		226		164		632
Amortization of deferred financing costs	94		119		234		420
Finance costs	$	1,485	$	1,470	$	4,750	$	4,355

7. SELLING COSTS

Selling costs include transportation and marketing costs associated with the sale of the Company's Egyptian crude oil production to third party buyers and EGPC. The Company completed two direct crude sales to third party buyers, which was marketed by Mercuria during the first nine months of 2017; and three direct crude sales to third party buyers during the year ended December 31, 2016.

8. CASH AND CASH EQUIVALENTS

(000s)	September 30, 2017		December 31, 2016
Cash	$	21,424	$	31,392
Cash equivalents	40		76
	$	21,464	$	31,468

As at September 30, 2017 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.

Q3-2017 31

9. RESTRICTED CASH

As at September 30, 2017, the Company had restricted cash of $4.8 million (December 31, 2016 - $18.3 million). Restricted cash represents a cash collateralized letter of credit facility that is used to guarantee the Company's commitments on its Egyptian exploration concessions.

10. PRODUCT INVENTORY

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

As at September 30, 2017, the Company had 988,090 barrels of entitlement oil in inventory valued at $13.42 per barrel (December 31, 2016 - 1,265,080 barrels valued at $15.49 per barrel).

11. INTANGIBLE EXPLORATION AND EVALUATION ASSETS

(000s)
Balance at December 31, 2016	$	105,869
Additions	16,372
Transfers to petroleum properties	(2,271		)
Impairment loss	(79,025		)
Balance at September 30, 2017	$	40,945

For the nine months ended September 30, 2017 the Company recorded an impairment loss of $79.0 million on its exploration and evaluation assets. The impairment loss was split between the South West Gharib concession ($1.2 million), the North West Gharib concession ($67.5 million) and the South Alamein concession of ($10.3 million).

At South West Gharib, it was determined during the first quarter that an impairment loss was necessary as no commercially viable quantities of oil were discovered, and no further drilling activities are planned.

At North West Gharib, the recoverable amount of the North West Gharib cash-generating unit was $4.4 million. The remaining North West Gharib exploration and evaluation assets were written down to nil during the second quarter. The North West Gharib exploration lands have been fully evaluated and all commitments have been met at the end of the first exploration phase. The Company elected not to enter the second exploration period. The Company filed for and received four development leases in the North West Gharib concession, all remaining exploration lands that are not covered by development leases were relinquished.

At South Alamein, it was determined for the three months ended September 30, 2017 that an impairment loss was necessary, due to the results of the Boraq 5 well and the uncertainty of an economic development of Boraq in the future. The Company completed testing two zones in the Boraq 5 appraisal well. The Boraq 5 well failed to produce any hydrocarbons from the two zones and was plugged and abandoned.

During the nine months ended September 30, 2017 the Company spent $6.6 million at North West Gharib, $5.2 million at North West Sitra, $3.1 million at South Alamein, $1.2 million at South West Gharib and $0.3 million at South Ghazalat.

32 Q3-2017

12. PROPERTY AND EQUIPMENT

(000s)	PNG Assets			Other Assets		Total
Balance at December 31, 2016	$	625,893		$	14,572	$	640,465
Additions	12,151			558		12,709
Changes in estimate for asset retirement obligations	(522		)	—		(522		)
Transfer from exploration and evaluation assets	2,271			—		2,271
Foreign exchange	5,469			—		5,469
Balance at September 30, 2017	$	645,262		$	15,130	$	660,392
Accumulated depletion, depreciation, amortization and impairment losses at December 31, 2016	$	415,866		$	10,327	$	426,193
Depletion, depreciation and amortization for the period	27,018			1,136		28,154
Balance at September 30, 2017	$	442,884		$	11,463	$	454,347
Net Book Value
At December 31, 2016	$	210,027		$	4,245	$	214,272
At September 30, 2017	$	202,378		$	3,667	$	206,045

At September 30, 2017, the significant decrease in forecast natural gas benchmark prices as compared to December 31, 2016 was a indicator of impairment for the Canadian assets. As a result, impairment testing was required and the Company prepared a estimate of future cash flows to determine the recoverable amount of the respective asset. For the purposes of determining whether impairment of the asset has occurred, and the extent of any impairment, management exercises their judgment in estimating future cash flows for the recoverable amount, being the higher of fair value less costs to sell and value in use. These key judgments include estimates about recoverable reserves, forecast benchmark commodity prices, royalties, operating costs, capital costs and discount rates. At September 30, 2017, the Company determined that the carrying amount of the Canadian cash-generating unit ("CGU") did not exceed the fair value less costs of sale.

13. ASSET RETIREMENT OBLIGATION

(000s)
Balance at December 31, 2016	$	12,099
Asset retirement obligation accretion	191
Changes in discount rates	(522		)
Effect of movements in foreign exchange rates	916
Balance at September 30, 2017	$	12,684

TransGlobe has estimated the net present value of its asset retirement obligation to be $12.7 million as at September 30, 2017 (December 31, 2016 - $12.1 million) based on a total undiscounted future liability, after inflation adjustment, of $20.0 million (December 31, 2016 - $19.0 million). These payments are expected to be made between 2018 and 2066. TransGlobe calculated the present value of the obligations using discount rates between 1.52% and 2.47% 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.

The entire asset retirement obligation balance related to the Company's Canadian operations at September 30, 2017 and December 31, 2016.

14. LONG-TERM DEBT

The Company's interest-bearing loans and borrowings are measured at amortized cost. As at September 30, 2017, the only significant interest-bearing loans and borrowings are related to the Prepayment Agreement and the Revolving Credit Facility as described below.

The following table summarizes TransGlobe's outstanding long-term debt:

(000s)	September 30, 2017		December 31, 2016
Prepayment agreement	$	68,711	$	—
Revolving credit facility	11,128		—
Note payable	—		11,162
	79,839		11,162
Current portion of long-term debt	—		(5,581		)
	$	79,839	$	5,581

Q3-2017 33

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

(000s)
Balance at January 1, 2017	$	11,162
Increase in long-term debt - prepayment agreement	73,500
Increase in long-term debt - revolving credit facility	10,209
Repayment of long-term debt	(16,162		)
Amortization of deferred financing costs	234
Effect of movements in foreign exchange rates	896
Balance at September 30, 2017	$	79,839

Prepayment Agreement

(000s)	September 30, 2017			December 31, 2016
Prepayment agreement	$	75,000		$	—
Repayment of prepayment agreement	(5,000		)	—
Deferred financing costs	(1,289		)	—
	68,711			—
Current portion of long-term debt	—			—
	$	68,711		$	—

On February 10, 2017, the Company completed a $75 million crude oil prepayment agreement between its wholly owned subsidiary, TransGlobe Petroleum International Inc. ("TPI") and Mercuria.

The initial advance under the prepayment agreement was used to repay the 6.0% convertible debentures of the Company, which matured on March 31, 2017 (Note 15).

TPI's obligations under the prepayment agreement are guaranteed by the Company and the subsidiaries of TPI (the "Guarantors"). The obligations of TPI and the Guarantors will be supported by, among other things, a pledge of equity held by the Company in TPI and a pledge of equity held by TPI in its subsidiaries. The funding arrangement has a term of four years, maturing March 31, 2021 and advances bear interest at a rate of Libor plus 6.0%. The funding arrangement is revolving with each advance to be satisfied through the delivery of crude oil to Mercuria. Further advances become available upon delivery of crude oil to Mercuria up to a maximum of $75.0 million and subject to compliance with the other terms and conditions of the prepayment agreement. The prepayment agreement was initially recognized at fair value, net of financing costs, and has subsequently been measured at amortized cost. Financing costs of $1.5 million will be amortized over the term of the prepayment agreement using the effective interest rate method.

The Company is subject to certain financial covenants in accordance with the terms of the prepayment agreement. These covenants are tested on June 30 and December 31 of each year for the life of the prepayment agreement. The financial covenants include financial measures defined within the prepayment agreement that are not defined under IFRS. These financial measures are defined by the prepayment agreement as follows:

• the ratio of the Company's total consolidated indebtedness (calculated by including any outstanding letters of credit or bank guarantees and adding back any cash held by the Company on a consolidated basis) on each financial covenant test date to the Company's consolidated net cash generated by (used in) operating activities (where net cash generated includes the fair market value of crude oil inventory held as at the financial covenant test date) for the trailing 12 month period period ending on that financial covenant test date will not exceed 4.00:1.00. The ratio as at September 30, 2017 is 0.82:1.00, the Company is in compliance with the ratio;

• the ratio of Current Assets of the Company on a consolidated basis (calculated, in the case of crude oil inventory, by adjusting the value to market value) to Current Liabilities of the Company on a consolidated basis on each financial covenant test date will not be less than 1.00:1.00. The ratio as at September 30, 2017 is 3.72:1.00, the Company is in compliance with the ratio; and

• the ratio of the parent's non-consolidated asset value to the aggregate amount of indebtedness outstanding under the advance documents on each financial covenant test date will not be less than 2.00:3.00. The ratio as at September 30, 2017 is 3.77:3.00, the Company is in compliance with the ratio.

As at September 30, 2017, the Company was in compliance with all the financial covenants.

The Company is also subject to a cover ratio provision. The cover ratio, defined as the value of the Company's Egyptian forecasted entitlement crude oil production on a forward 12 month basis to the prepayment service obligations, must not be less than 1.25:1.0. In the event the cover ratio falls below 1.25:1.00, TransGlobe must:

• reimburse in cash the relevant portion of the advances such that the cover ratio becomes equal to or greater than 1.25:1.0; and/or

• amend the initial commercial contract to extend its duration and amend the maturity date under the agreement.

34 Q3-2017

The cover ratio as at September 30, 2017 is 1.44:1.00, the Company is in compliance with the ratio.

Based on the Company's current forecast of future production and current Brent Crude prices the estimated future debt payments on long-term debt as of September 30, 2017 are as follows:

(000s)
2017	$	—
2018	—
2019	—
2020	11,132
2021	58,868
	$	70,000

Revolving Reserve-Based Lending Facility

C$(000s)	September 30, 2017			December 31, 2016
Total facility amount	$	30,000		$	—
Amount drawn	(13,907		)	—
Unutilized capacity	$	16,093		$	—

As at September 30, 2017, the Company had in place a revolving Canadian reserve-based lending facility with Alberta Treasury Branches ("ATB") totaling C$30.0 million, of which C$13.9 million ($11.1 million) was drawn.

The facility is extendable on a semi-annual basis on May 31 and November 30 of each year, or as requested by the lender. Unless extended, before May 11, 2018, any unutilized amount of the facility will be cancelled, and the amount of the facility will be reduced to the aggregate borrowings outstanding on that date. The balance of all amounts owing under the facility are due and payable in full on the date falling one year after the term date.The Company may request an extension of the term date by no later than 90 days prior to the then current term date, and lender may in its sole discretion agree to extend the term date for a further period of 364 days. If no extension is granted by the lender, the amounts owing pursuant to the facility are due at the maturity date. The facility bears interest at a rate of either ATB Prime or CDOR (Canadian Dollar Offered Rate) plus applicable margins that vary from 1.25% to 3.25% depending on the Company's net debt to trailing cash flow ratio. The revolving reserve-based lending facility was initially recognized at fair value, net of financing costs, and has subsequently been measured at amortized cost. Financing costs of $0.1 million will be amortized over the term of the agreement using the effective interest rate method.

The Company is subject to certain financial covenants in accordance with the terms of the agreement. These financial measures are defined by the agreement as follows:

• the Company shall not permit the working capital ratio (calculated as current assets plus any undrawn availability under the facility, to current liabilities less any amount drawn under the facility) to fall below 1:00:1:00. The working capital ratio as at September 30, 2017 is 1.34:1.00, the Company is in compliance with the ratio; and

• permit the ratio of net debt to trailing cash flows as at the end of any fiscal quarter to exceed 3:00:1:00. According to the agreement net debt is, as of the end of any fiscal quarter and as determined in accordance with GAAP on an non-consolidated basis, and without duplication, an amount equal to the amount of total debt less current assets. Trailing cash flow is defined as the two most recently completed fiscal quarters, annualized. The net debt to trailing cash flows ratio as at September 30, 2017 is 0.31:1.00, the Company is in compliance with the ratio.

Note Payable

On December 20, 2016, the Company closed the acquisition of certain petroleum properties in west central Alberta, Canada. The acquisition was partially funded by a vendor take-back note of C$15.0 million ($11.3 million). The note payable had a 24-month term and bore interest at a rate of 10% per annum. The Company repaid the outstanding vendor take-back note balance of C$13.6 million ($10.0 million) on May 16, 2017. Repayment was made using the revolving reserve-based lending facility.

(000s)	September 30, 2017		December 31, 2016
Note payable	$	—	$	11,162
Current portion of note payable	—		(5,581		)
	$	—	$	5,581

Q3-2017 35

15. CONVERTIBLE DEBENTURES

(000s)
Balance at December 31, 2016	$	72,655
Repayment	(73,375		)
Fair value adjustment	151
Foreign exchange adjustment	569
Balance at September 30, 2017	$	—

The convertible debentures matured on March 31, 2017 and were repaid in full on that date for their aggregate face value of C$97.8 million ($73.4 million). Repayment was made using the proceeds from the prepayment agreement (Note 14).

16. COMMITMENTS AND CONTINGENCIES

The Company is subject to certain office and equipment leases.

Pursuant to the PSC for North West Gharib in Egypt, the Company had a minimum financial commitment of $35.0 million and a work commitment for 30 wells and 200 square kilometers of 3-D seismic during the initial-three year exploration period, which commenced on November 7, 2013. The Company received a six month extension to the initial exploration period, extending the initial exploration period to May 7, 2017. The Company completed the initial exploration period work program and met all financial commitments during the second quarter of 2017. The Company elected not to enter the second exploration period and has relinquished the remaining exploration lands that are not covered by the four development leases.

Pursuant to the PSC for South West Gharib in Egypt, the Company had a minimum financial commitment of $10.0 million and a work commitment for four wells and 200 square kilometers of 3-D seismic during the initial three-year exploration period, which commenced on November 7, 2013. The Company received a six month extension, which extended the initial exploration period to May 7, 2017. As no commercially viable quantities of oil were discovered at South West Gharib, the Company relinquished its interest in the concession on May 7, 2017. The Company met its financial commitment during the first quarter of 2017.

Pursuant to the PSC for South Ghazalat in Egypt, the Company had a minimum financial commitment of $8.0 million and a work commitment for two wells and 400 square kilometers of 3-D seismic during the initial three-year exploration period, which commenced on November 7, 2013 and reached its primary term on November 7, 2016. Prior to expiry, the Company elected to enter the first two-year extension period (expiry November 7, 2018). The Company had met its financial commitment for the first phase ($8.0 million) and the first extension ($4.0 million), however the Company had not completed the first phase work program. Prior to entering the first extension the Company posted a $4.0 million performance bond with EGPC to carry forward two exploration commitment wells into the first extension period. The $4.0 million performance bond is supported by a production guarantee from the Company's producing concessions which will be released when the commitment wells have been drilled. In accordance with the concession agreement the Company relinquished 25% of the original exploration acreage prior to entering the first extension period. In addition, the first extension period has an additional financial commitment of $4.0 million, which has been met, and two additional exploration wells.

Pursuant to the PSC for North West Sitra in Egypt, the Company has a minimum financial commitment of $10.0 million ($5.1 million 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. As at September 30, 2017, the Company had expended $4.9 million towards meeting the financial and operating commitment, with the acquisition of 600 km² of 3-D seismic in 2017.

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

The Company is not aware of any material provisions or other contingent liabilities as at September 30, 2017.

17. SHARE CAPITAL

Authorized

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

Issued

	Nine months ended			Year Ended
	September 30, 2017			December 31, 2016
000’s	Shares	Amount		Shares	Amount
Balance, beginning of period	72,206	$	152,084	72,206	$	152,084
Balance, end of period	72,206	$	152,084	72,206	$	152,084

36 Q3-2017

18. SHARE-BASED PAYMENTS

Stock option plan

The Company operates a stock option plan (the “Plan”) to provide equity-settled share-based remuneration to directors, officers and employees. The number of common shares that may be issued pursuant to the exercise of options awarded under the Plan and all other security based compensation arrangements of the Company is 10% of the common shares outstanding from time to time. All incentive stock options granted under the Plan have a per-share exercise price equal to the weighted average trading price of the common shares for the five trading days prior to the date of grant. Each tranche of an award with different vesting dates is considered a separate grant for the calculation of fair value and the resulting fair value is amortized over the vesting period of the respective tranches.

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

	Nine months ended			Year Ended
	September 30, 2017			December 31, 2016
			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	6,046		6.87	5,348		9.05
Granted	1,043		2.16	1,470		2.19
Forfeited	(982	)	6.66	(54	)	11.84
Expired	(763	)	11.46	(718	)	12.95
Options outstanding, end of period	5,344		5.30	6,046		6.87
Options exercisable, end of period	3,311		6.99	3,527		9.14

Compensation expense of $0.2 million and $0.5 million was recorded as general and administrative expense in the Condensed Consolidated Interim Statements of Earnings (loss) and Comprehensive Income (loss) and Changes in Shareholders’ Equity during the three and nine month period ended September 30, 2017 (2016 - $0.3 million and $1.0 million, respectively) in respect of 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 over a three-year period and expire five years after the grant date. During the three and nine month period ended September 30, 2017, no stock options were exercised (2016 – nil). As at September 30, 2017 and December 31, 2016, the entire balance in contributed surplus was related to previously recognized share-based compensation expense on equity-settled stock options.

Restricted share unit, performance share unit and deferred share unit plans

In May 2014, the Company implemented a restricted share unit ("RSU") plan, a performance share unit ("PSU") plan and a deferred share unit ("DSU") plan. RSUs may be issued to directors, officers and employees of the Company, and each RSU entitles the holder to a cash payment equal to the fair market value of a TransGlobe common share on the vesting date of the RSU. All RSUs granted vest annually over a three-year period, and all must be settled within 30 days of their respective vesting dates.

PSUs are similar to RSUs, except that the number of PSUs that ultimately vest is dependent on achieving certain performance targets and objectives as set by the board of directors. Depending on performance, vested PSUs granted prior to 2017 can range between 50% and 150% of the original PSU grant, and 0% to 200% for PSUs granted in 2017. All PSUs granted vest on the third anniversary of their grant date, and all must be settled within 60 days of their vesting dates.

DSUs are similar to RSUs, except that they become fully vested on the date of grant and to date have only been issued to directors of the Company. Distributions under the DSU plan do not occur until the retirement of the DSU holder from the Company's board of directors.

The number of RSUs, PSUs and DSUs outstanding as at September 30, 2017 are as follows:

	Restricted		Performance		Deferred
	Share		Share		Share
(000s, except per share amounts)	Units		Units		Units
Units outstanding, beginning of period	546		1,366		437
Granted	792		573		181
Vested	(240	)	(249	)	(56	)
Forfeited	(122	)	(283	)	—
Units outstanding, end of period	976		1,407		562

Compensation expense of$0.1 millionand$0.3 millionwas recorded in general and administrative expenses in theCondensed Consolidated Interim Statement of Earnings (Loss) and Comprehensive Income (Loss) and Changes in Shareholders' Equityduring the three and nine month period endedSeptember 30, 2017(2016 -$0.4 millionand1.1 million, respectively) in respect of 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 Sheet. Until the liability is ultimately settled, it is re-measured at each reporting date with changes to fair value recognized in earnings.

Q3-2017 37

19. PER SHARE AMOUNTS

The weighted-average number of common shares outstanding (basic and diluted) for the three and nine month periods ended September 30, 2017 was 72,205,369 (2016 – 72,205,369). These outstanding share amounts were used to calculate earnings (loss) per share in the respective periods.

In determining diluted earnings (loss) per share, the Company assumes that the proceeds received from the exercise of “in-the-money” stock options are used to repurchase common shares at the average market price. In calculating the weighted average number of diluted common shares outstanding for the three and nine month periods ended September 30, 2017, the Company excluded 5,344,520 stock options (2016 – 4,576,100 and 4,576,100, respectively) as their exercise price was greater than the average common share market price in the respective periods.

38 Q3-2017

20. SEGMENTED INFORMATION

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

In presenting information on the basis of operating segments, segment revenue is based on the geographical location of assets which is also consistent with the location of the segment customers. Segmented assets are also based on the geographical location of the assets and there are no inter-segment sales.

The accounting policies of the operating segments are the same as the Company’s accounting policies.

	Egypt						Canada					Total
	Nine months ended						Nine months ended					Nine months ended
	September 30						September 30					September 30
(000s)	2017			2016			2017			2016		2017			2016
Revenue
Petroleum and natural gas sales, net of royalties	95,441			57,917			12,298			—		107,739			57,917
Finance revenue	3			102			2			—		5			102
Total segmented revenue	95,444			58,019			12,300			—		107,744			58,019
Segmented expenses
Production and operating	35,344			34,706			4,012			—		39,356			34,706
Transportation costs	—			—			566			—		566			—
Selling costs	1,926			875			—			—		1,926			875
General and administrative	4,577			5,390			884			—		5,461			5,390
Finance costs	3,012			1,052			721			—		3,733			1,052
Depletion, depreciation and amortization	22,568			24,172			6,768			—		29,336			24,172
Asset retirement obligation accretion	—			—			191			—		191			—
Realized derivative (gain) loss on commodity contracts	375			956			—			—		375			956
Unrealized derivative (gain) loss on commodity contracts	465			—			(79		)	—		386			—
Income taxes - current	16,104			10,737			—			—		16,104			10,737
Income taxes - deferred	—			(3,009		)	—			—		—			(3,009		)
Impairment of exploration and evaluation assets	79,025			14,912			—			—		79,025			14,912
Total segmented expenses	163,396			89,791			13,063			—		176,459			89,791
Segmented earnings (loss)	$	(67,952	)	$	(31,772	)	$	(763	)	$	—	$	(68,715	)	(31,772		)
Non-segmented expenses (income)
General and administrative												6,156			6,352
Foreign exchange (gain) loss												70			4,762
Depreciation and amortization												299			366
Unrealized (gain) loss on financial instruments												151			7,536
Finance revenue												(54		)	(423		)
Finance costs												1,017			3,303
Total non-segmented expenses												7,639			21,896
Net earnings (loss) for the year												$	(76,354	)	$	(53,668	)
Capital expenditures
Exploration and development	24,667			17,794			4,384			—		29,051			17,794
Corporate	—			—			—			—		30			—
Total capital expenditures												$	29,081		$	17,794

Q3-2017 39

	Egypt						Canada					Total
	Three months ended						Three months ended					Three months ended
	September 30						September 30					September 30
(000s)	2017			2016			2017			2016		2017			2016
Revenue
Petroleum and natural gas sales, net of royalties	40,897			20,704			3,942			—		44,839			20,704
Finance revenue	1			1			2			—		3			1
Total segmented revenue	40,898			20,705			3,944			—		44,842			20,705
Segmented expenses
Production and operating	13,242			10,945			1,068			—		14,310			10,945
Transportation costs	—			—			212			—		212			—
Selling costs	424			—			—			—		424			—
General and administrative	1,621			1,624			318			—		1,939			1,624
Finance costs	1,429			345			128			—		1,557			345
Depletion, depreciation and amortization	8,360			6,317			2,258			—		10,618			6,317
Asset retirement obligation accretion	—			—			74			—		74			—
Realized derivative (gain) loss on commodity contracts	1,904			—			—			—		1,904			—
Unrealized derivative (gain) loss on commodity contracts	3,314			—			(79		)	—		3,235			—
Income taxes - current	5,179			4,067			—			—		5,179			4,067
Income taxes - deferred	—			—			—			—		—			—
Impairment of exploration and evaluation assets	10,314			14,912			—			—		10,314			14,912
Total segmented expenses	45,787			38,210			3,979			—		49,766			38,210
Segmented earnings (loss)	$	(4,889	)	$	(17,505	)	$	(35	)	$	—	$	(4,924	)	(17,505		)
Non-segmented expenses (income)
General and administrative												1,870			2,470
Foreign exchange (gain) loss												3			(584		)
Depreciation and amortization												142			122
Unrealized (gain) loss on financial instruments												—			4,881
Finance revenue												(12		)	(150		)
Finance costs												(72		)	1,125
Total non-segmented expenses												1,931			7,864
Net earnings (loss) for the year												$	(6,855	)	$	(25,369	)
Capital expenditures
Exploration and development	6,070			8,692			4,060			—		10,130			8,692
Corporate												3			—
Total capital expenditures												$	10,133		$	8,692

40 Q3-2017

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

September 30, 2017
(000s)	Egypt		Canada		Total
Assets
Accounts receivable	$	47,349	$	1,909	$	49,258
Derivative commodity contracts	—		79		79
Intangible exploration and evaluation assets	40,945		—		40,945
Property and equipment					—
Petroleum and natural gas assets	128,545		73,833		202,378
Other assets	2,475		16		2,491
Other	26,354		2,448		28,802
Segmented assets	245,668		78,285		323,953
Non-segmented assets					14,849
Total assets					$	338,802
Liabilities
Accounts payable and accrued liabilities	$	23,411	$	3,878	$	27,289
Derivative commodity contracts	465		—		465
Current and long-term note payable	—		—		—
Long-term debt	68,711		11,128		79,839
Asset retirement obligation	—		12,684		12,684
Segmented liabilities	92,587		27,690		120,277
Non-segmented liabilities					5,558
Total liabilities					$	125,835

December 31, 2016
(000s)	Egypt		Canada		Total
Assets
Accounts receivable	$	13,778	$	620	$	14,398
Intangible exploration and evaluation assets	105,869		—		105,869
Property and equipment
Petroleum and natural gas assets	138,757		71,270		210,027
Other assets	2,785		—		2,785
Other	62,049		—		62,049
Segmented assets	323,238		71,890		395,128
Non-segmented assets					11,014
Total assets					$	406,142
Liabilities
Accounts payable and accrued liabilities	$	15,827	$	432	$	16,259
Current and long-term note payable	—		11,162		11,162
Asset retirement obligation	—		12,099		12,099
Segmented liabilities	15,827		23,693		39,520
Non-segmented liabilities					81,306
Total liabilities					$	120,826

Q3-2017 41

21. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended September 30						Nine months ended September 30
(000s)	2017			2016			2017			2016
Operating activities
(Increase) decrease in current assets
Accounts receivable	$	(7,797	)	$	(16,294	)	$	(34,871	)	$	(8,991	)
Prepaids and other	(625		)	(1,323		)	(903		)	(264		)
Product inventory1	2,820			(380		)	4,856			1,364
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	6,822			793			7,531			(1,072		)
	$	1,220		$	(17,204	)	$	(23,387	)	$	(8,963	)
Note:
1 The change in non-cash working capital associated with product inventory represents the change in operating costs capitalized as product inventory in the respective periods.

Investing Activities
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	557		2,224		1,073		4,555
	$	557	$	2,224	$	1,073	$	4,555

42 Q3-2017

CORPORATE & SHAREHOLDER INFORMATION
DIRECTORS	TRANSFER AGENT
	Computershare Trust Company of Canada
Robert G. Jennings (1)	600, 530 8th Avenue S.W.
Chairman	Calgary, Alberta T2P 3S8
Ross G. Clarkson	LEGAL COUNSEL
President & CEO	Burnet, Duckworth & Palmer LLP
	Calgary, Alberta
Lloyd W. Herrick
Vice President & COO	AUDITORS
	Deloitte LLP
Matthew Brister (3)	Calgary, Alberta
David B. Cook (1)(2)	EVALUATION ENGINEERS
	DeGoyler & MacNaughton Canada Limited (Jan-May 2017)
Fred J. Dyment (1)(2)	GLJ Petroleum Consultants Ltd. (effective Aug 1, 2017)
G. R. (Bob) MacDougall (3)	BANKS
	Sumitomo Mitsui Banking Corporation Europe Limited
Susan M. MacKenzie (2)(3)	London, Great Britain
Steven W. Sinclair (1)	Alberta Treasury Branches
	Calgary, Alberta, Canada
(1) Audit Committee
(2) Compensation Human Resources and Governance Committee	INVESTOR RELATIONS
(3) Reserves, Health, Safety, Environment and Social Responsibility Committee	Telephone: (403) 264-9888
	Email: investor.relations@trans-globe.com
OFFICERS	PUBLIC RELATIONS
	FTI Consulting Inc.
Ross G. Clarkson	Telephone: +44 (0)203 727 1000
President & Chief Executive Officer	Email : energy@fticonsulting.com
Lloyd W. Herrick	WEBSITE
Vice President & Chief Operating Officer	www.trans-globe.com
Randy C. Neely	HEAD OFFICE
Vice President, Finance & Chief Financial Officer	2300, 250 – 5th Street S.W.
	Calgary, Alberta, Canada T2P 0R4
Brett Norris	Telephone: (403) 264-9888, Facsimile: 403-770-8855
Vice President, Exploration
	EGYPT OFFICE
Marilyn A. Vrooman-Robertson	10 Rd 261
Corporate Secretary	New Maadi, Cairo, Egypt

www.trans-globe.com

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