2017 SECOND QUARTER INTERIM REPORT

Financial and Operating Results

For the three and six month periods ended June 30, 2017

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

Financial Highlights:
ø	Second quarter production averaged 16,465 Boepd (19,259 Boepd sales) versus 11,472 Bopd (11,783 Bopd sales) in Q2-2016, a 44% increase, reflecting increased volumes in Egypt and the December 2016 Canadian acquisition;
ø	Completed one direct sale tanker-lifting of TransGlobe's entitlement oil for proceeds of $18.5 million (sale proceeds collected in July) and sold 302,648 barrels of inventoried entitlement crude oil to EGPC for $12.5 million to cover in-country expenditures during the second quarter;
ø	Inventory of 1,274,057 barrels of entitlement crude oil at quarter-end, and next lifting is scheduled for mid September;
ø	Positive second quarter funds flow of $16.9 million ($0.23 per share);
ø	Second quarter net loss of $56.6 million (includes a $67.5 million impairment loss and a $6.6 million unrealized gain on derivative commodity contracts). Excluding the impairment charge and the unrealized gain on derivative commodity contracts, the Company would have achieved a positive net profit for the quarter of $4.3 million;
ø	Spent $8.2 million on exploration and development during the quarter;
ø	Ended the quarter with positive working capital of $60.3 million, which includes cash and cash equivalents of $21.6 million (including restricted cash);
ø	Finalized C$30.0 million revolving Canadian reserve-based lending facility, of which $10.0 million (C$13.6 million) was drawn on May 16, 2017 to repay the remaining outstanding vendor take-back note;
Operational Highlights:
ø	Drilled five wells in Egypt (two exploration and three development), resulting in three dry holes and two oil wells (K-47 and NWG 38A); and
ø	Drilled and cased the Boraq 5 appraisal well as a potential Abu Roash oil well.

A conference call to discuss TransGlobe's 2017 second quarter results as presented was held on Monday, August 14, 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 Q2-2017

FINANCIAL AND OPERATING RESULTS

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

	Three months ended June 30					Six months ended June 30
Financial	2017		2016		% Change	2017		2016		% Change
Petroleum and natural gas sales	64,711		32,461		99	111,265		61,483		81
Petroleum and natural gas sales, net of royalties	40,439		19,786		104	62,900		37,213		69
Realized derivative gain (loss) on commodity contracts	1,529		(698	)	—	1,529		(956	)	—
Unrealized derivative gain (loss) on commodity contracts	6,578		—		—	2,849		—		—
Production and operating expense	14,923		10,640		40	25,046		23,761		5
Transportation costs	156		—		—	354		—		—
Selling costs	1,502		47		3,096	1,502		875		72
General and administrative expense	3,362		4,125		(18)	7,808		7,648		2
Depletion, depreciation and amortization expense	10,363		8,083		28	18,875		18,099		4
Income taxes	5,505		2,683		105	10,925		3,661		198
Cash flow generated by (used in) operating activities	(2,753	)	6,011		—	(5,250	)	7,437		—
Funds flow from operations1	16,855		2,026		732	19,357		(804	)	2,508
Basic per share	0.23		0.03			0.26		(0.01	)
Diluted per share	0.23		0.03			0.26		(0.01	)
Net earnings (loss)	(56,622	)	(12,050	)	(370)	(69,499	)	(28,299	)	(146)
Basic per share	(0.78	)	(0.17	)		(0.96	)	(0.39	)
Diluted per share	(0.78	)	(0.17	)		(0.96	)	(0.39	)
Capital expenditures	8,230		4,837		70	18,948		9,102		108
Working capital	60,319		65,413		(8)	60,319		65,413		(8)
Long-term debt	83,725		—		—	83,725		—		—
Convertible debentures	—		70,639		(100)	—		70,639		(100)
Note payable	—		—		—	—		—		—
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	337,596		433,013		(22)	337,596		433,013		(22)
Operating
Average production volumes (Boepd)	16,465		11,472		44	16,597		11,765		41
Average sales volumes (Boepd)	19,259		11,783		63	16,558		12,955		28
Inventory (MBbls)	1,274		707		67	1,274		707		67
Average sales price ($ per Boe)	36.92		30.27		22	37.13		26.08		42
Operating expense ($ per Boe)	8.51		9.92		(14)	8.36		10.08		(17)
Note:
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-2	Q-1	Q-4	Q-3	Q-2
Crude oil
Dated Brent average oil price (US$/Bbl)	49.67	53.68	49.19	45.79	45.52
Edmonton Sweet index (US$/bbl)	46.03	48.37	46.18	41.99	42.51
Natural gas
AECO (C$/mmbtu)	2.78	2.69	3.09	2.32	1.40
U.S./Canadian Dollar average exchange rate	1.345	1.323	1.334	1.305	1.289

Q2-2017 3

CORPORATE SUMMARY

TransGlobe Energy Corporation ("TransGlobe" or the "Company") produced an average of 16,465 barrels of oil equivalent per day ("boepd") during the second quarter of 2017, which was within the full-year 2017 production guidance range of 15,500 to 16,500 boepd. Egypt production was 13,851 barrels of oil per day ("bopd"), and Canada production was 2,614 boepd.

The Company completed one direct sale tanker lifting during the quarter, consisting of 515,626 barrels of entitlement crude oil. The tanker lifting was marketed by Mercuria Energy Trading S.A., ("Mercuria") in June. Proceeds of $18.5 million were received in July. The Company's next cargo lifting from Egypt is scheduled for mid-September 2017. In addition to the lifting the Company sold 302,648 barrels of inventoried entitlement crude oil to the Egyptian General Petroleum Company ("EGPC") during the second quarter for $12.5 million. The EGPC proceeds were used to cover in-country expenditures during the first half of 2017. All Canadian production was sold during the quarter.

During the quarter TransGlobe entered into a credit agreement for a revolving Canadian reserve-based lending facility (“RBL”) with Alberta Treasury Branches (“ATB”). The Company utilized funds available under the RBL to repay the remaining C$13.6 million vendor-take-back loan outstanding. Long-term debt net of working capital was $23.4 million as at June 30, 2017.

Dated Brent oil prices averaged $49.67 per barrel in the second quarter of 2017. TransGlobe's Gulf of Suez crude is sold at a quality discount to Dated Brent and received a blended price of $39.31 per barrel during the quarter. TransGlobe's Canadian production received an average of $44.47 per barrel of oil and $2.14 per mcf of natural gas during the second quarter. The Company had funds flow of $16.9 million ($0.23 per share) and ended the quarter with positive working capital of $60.3 million, which includes cash and cash equivalents of $21.6 million (including restricted cash).

The Company experienced a net loss in the quarter of $56.6 million, which includes a $67.5 million non-cash impairment loss on the Company's exploration and evaluation assets at NW Gharib and a $6.6 million unrealized derivative gain on commodity contracts (mark-to-market gain on the Company's hedging contracts). The recoverable amount of the North West Gharib cash-generating unit is $4.4 million. The Company's remaining NW Gharib exploration and evaluation assets were written down to nil. The impairment loss recognized in the quarter is a result of reducing the overall carrying value of the North West Gharib concession to the discounted present value of the internally estimated proved plus probable reserves recognized as at the end of the quarter. This 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.

The Company drilled five wells in Egypt during the quarter resulting in three dry holes and two oil wells. The second rig operating in the Eastern desert was released and is currently stacked on the NWG license waiting to drill a side track to NWG # 3A. There are three development leases pending approval on the NWG license. The Company anticipates these will be approved during the third quarter and expects to recommence a drilling program in the Eastern desert when approval is granted. Following the quarter end the Company commenced a three well drilling program on the Harmattan property in Canada. The Canadian program was reduced to three wells (from a four to eight program) in response to lower commodity prices in Q2/Q3. With two of the three wells drilled and cased, drilling costs are trending 20% to 30% below plan due to drilling performance. Following the quarter the Company completed the drilling and cased the Boraq 5 well in the South Alamein concession in Egypt.  Two potential oil zones were encountered.  The Company plans to retest Boraq 2 and to test Boraq 5 in September/October.

Brent oil prices were weaker during the quarter but have since firmed up to above $50 per barrel. The fundamentals seem to be slowly improving (lower world inventories, increasing demand). The selling differential for the Ras Gharib heavy oil also is showing signs of improvement. The Company’s cost structure for operating expenses and G&A has been improved significantly over the past three years. The increased oil sales during the quarter resulted in a significant improvement to funds flow, posting the highest number in eight quarters. Management will continue to steward the balance sheet conservatively and focus on a return to profitability in this low oil price environment.

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

4 Q2-2017

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 second quarter.

Production

Production from West Gharib averaged 6,389 Bopd to TransGlobe during the second quarter, a 4% (293 Bopd) decrease from the previous quarter. First quarter production additions from the infill development wells in the Arta Red Bed pool were offset by natural declines and well servicing of high volume producers.

Production averaged 6,036 Bopd during July.

Sales

TransGlobe sold 302,648 barrels of inventoried entitlement crude oil (after royalties and tax) to EGPC for $12.5 million in the second quarter of 2017 to cover in-country expenditures. TransGlobe held 635,414 barrels of West Gharib entitlement oil as inventory at the end of the second quarter.

Quarterly West Gharib Production (Bopd)	2017			2016
	Q-2		Q-1	Q-4	Q-3
Gross production rate	6,389		6,683	6,601	6,629
TransGlobe working interest	6,389		6,683	6,601	6,629
TransGlobe inventory held (lifted)	(92	)	3	3,339	(1,819	)
Total sales	6,481		6,680	3,262	8,448
Government share (royalties and tax)	3,155		3,304	3,262	3,277
TransGlobe sales (after royalties and tax)1	3,326		3,376	—	5,171
1 Under the terms of the West Gharib Production Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing oil.

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

Operations and Exploration

During the second quarter, the K-47 development well was drilled and cased as an Asl A oil well in the South-K field. K-47 was drilled to a total depth of 1,372 meters (4,500 feet) and encountered an internally estimated 23.5 meters (77 feet) of net oil pay in the targeted Asl A formation. The well was completed and put on production in late May and produced at an average initial 30-day rate of 235 Bopd.

Further, the Company recompleted two wells in the K field in late June, producing at a combined rate of 370 Bopd. Additional low cost, behind-pipe opportunities in the K and H fields are being scheduled, with related production volumes projected in the third and fourth quarter of 2017.

Production

Production from West Bakr averaged 6,085 Bopd to TransGlobe during the second quarter, a 3% (199 Bopd) decrease from the previous quarter, primarily due to well servicing and natural declines.

Production averaged 5,751 Bopd during July.

Sales

TransGlobe lifted and sold 515,626 barrels of Ras Gharib blend in June, all of which was allocated to West Bakr entitlement crude inventory (after royalties and tax). Subsequent to the quarter, the Company received $18.5 million (~$37.72/barrel) for the June lifting, prior to hedging gains of an additional $1.5 million. TransGlobe held 559,310 barrels of West Bakr entitlement oil as inventory at the end of the second quarter.

Quarterly West Bakr Production (Bopd)	2017			2016
	Q-2		Q-1	Q-4	Q-3
Gross production rate	6,085		6,284	6,134	5,104
TransGlobe working interest	6,085		6,284	6,134	5,104
TransGlobe inventory held (lifted)	(3,202	)	2,545	2,484	2,067
Total sales	9,287		3,739	3,650	3,037
Government share (royalties and tax)	3,621		3,739	3,650	3,037
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.

Q2-2017 5

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

Operations and Exploration

During the second quarter, the Company drilled one exploration well and two appraisal wells resulting in one Red bed oil well and two dry holes.

NWG 38A1 was drilled as an appraisal well to the NWG-38A Red Bed oil producer (~600 Bopd) in the NWG Development Lease #1 (“NWG DL #1”).  The NWG 38A1 appraisal well was drilled to a total depth of 5,100 ft.  The wellcame in 115 feet structurally higher than NWG-38-A, and is internally estimated to have 36.5 feet of tight Red Bed conglomerate oil pay.  The well started production in late June for an unstimulated production test. The well is scheduled for stimulation during the third quarter.

NWG 3A1 was drilled as an appraisal well to NWG-3X Red Bed oil producer (~600 Bopd) in NWG DL #1.  NWG 3A appraisal was drilled to a total depth of 5,150 feet.  NWG-3A encountered a thick Red Bed sequence (~270 feet) in a structurally low position with an estimated 80 feet of high quality Red Bed reservoir which was wet.  NWG-3A was plugged back to the base of surface casing and suspended for a future sidetrack. The drilling rig was shut down and stacked on location following the NWG 3A well which concluded the planned eastern desert drilling program for the first half of 2017. It is expected that drilling in the eastern desert could commence by the fourth quarter, starting with a side track from NWG 3A 1 targeting the Red Bed in an up dip structural position.

The NWG 40 B exploration well, was drilled to a depth of 5,322 feet, fully satisfying all first phase work commitments for the NWG Concession.  The well was abandoned after encountering wet Red Bed reservoir.

Subsequent to the quarter, NWG 16X (tight Red Bed conglomerate discovery in 2014) in NWG DL #1 was stimulated, tied into the NWG early production facility (EPF) and placed on production averaging approximately 100 Bopd over the first 30 days (IP30).

In addition, the Company completed and stimulated one well on each of the NWG 1 and NWG 5 discoveries (discovered in 2014) in late March. Both wells were put on short term pump production tests to partially recover the stimulation fluid and establish new oil production from the discoveries. The wells produced ~150 to 180 Bopd. Following the short production tests, the wells were shut-in pending approval of the respective development leases. The Company filed development lease applications for the NWG 1 and NWG 5 discoveries prior to May 6^th, which was the expiry date of the first exploration phase on NWG. It is expected that new development leases could receive approval from the Minister of Oil during the third quarter.

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 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.

In addition, the Company filed a development lease application for the area immediately north of NWG DL #1 on May 3 which includes the NWG 26 and 27 discovery wells.

TransGlobe has fully evaluated the NWG exploration lands and all commitments have been met at the end of the first exploration period (May 6, 2017). The Company has elected not to enter the second exploration period and has filed development lease applications on the discovery areas. The Company has relinquished the remaining exploration lands that are not covered by development lease applications.

Production

Production from NW Gharib averaged 1,377 Bopd to TransGlobe during the second quarter, a 40% (395 Bopd) increase from the previous quarter, primarily due to well optimization at NWG 3.

Production has averaged 1,187 Bopd during July.

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 79,334 barrels.

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

6 Q2-2017

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

Operations and Exploration

No wells were drilled during the second quarter. The Company elected to relinquish the concession following completion of the first phase exploration commitment work program.

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 has 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 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, which will be tested following the Boraq 2 test. The drilling rig is now released and a work over rig will be mobilized for the two well testing program.

The initial drilling campaign consists of one well (Boraq 5) on the Boraq structural complex plus re-entering the Boraq 2 discovery well for additional testing. Successful appraisal wells could lead to filing a Boraq development plan as early as Q3/Q4-2017 with first production targeted to year-end 2017/early 2018. In parallel, the Company is evaluating the remaining exploration prospects on the concession, targeting an exploration drilling program commencing in late 2017 and extending into 2018. The South Alamein concession contains the Boraq 2X discovery and several additional exploration targets. The Boraq 2X discovery tested approximately 1,600 Bopd from two zones. The primary Cretaceous zone tested at a rate of 800 to 1,323 Bopd of 34 API oil with no water and a 13% pressure drawdown during a 28 hour drill stem test (DST). A secondary Cretaceous zone tested at a rate of 274 Bopd of 32-35 API oil and 4% water during a 23 hour DST. Test rates are not necessarily indicative of long-term performance or ultimate recovery.

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. South Ghazalat could be drilled (two wells) in conjunction with North West Sitra 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 new data is being processed with prospect mapping planned for the second half of 2017.

CANADA

Operations and Exploration

No wells were drilled during the second quarter.

TransGlobe took over field operations on February 1^st and initiated surface land acquisition/permitting for up to eight wells in the Harmattan area. The initially planned 2017 program consisted of up to eight horizontals (multi-stage frac) wells targeting the Cardium light oil resource at Harmattan. In light of reduced commodity prices in Q2 the Company reduced the initial program to three wells which, commenced July 19^th. The first well was drilled to a total depth of 3,541 meters (11,579 feet) measured depth and cased as a potential Cardium oil well. The second well was drilled to a total depth of 3,703 meters (12,146 feet) measured depth and cased as a potential Cardium oil well. The third well is currently drilling. The three wells are being drilled from the same well pad with one mile horizontals. The planned completion program for each well is a 40 stage frac with approximately 15 tonnes of proppant per stage. The Company is targeting to have the wells completed and place on production by the end of the third quarter.

The wells were estimated to cost C$2.5 - C$2.7 million per well to drill, completed and place on production.

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

Production

Production from Canada averaged 2,613 Boepd to TransGlobe during the second quarter, a 6% (169 Bopd) decrease from the previous quarter.

Production has averaged 2,636 Boepd during July.

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

Q2-2017 7

MANAGEMENT'S DISCUSSION AND ANALYSIS

August 11, 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 six months ended June 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 Q2-2017

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 $41.5 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 between 15,500 and 16,500 boepd, representing a 30% to 40% increase over 2016 production (production in Q2-2017 was 16,465 boepd).  The 2017 production mid-year outlook is provided as a range to reflect the timing of projects and the associated results. 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 remainder of 2017 with the two scheduled tanker liftings and 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.

2017 Capital Budget

The Company's 2017 capital program of $41.5 million (before capitalized G&A) includes $35.4 million for Egypt and $6.1 million (C$7.9 million) for Canada. The $41.5 million capital program is approximately $14.9 million lower (26%) than the original Firm and Contingent budget of $56.4 million due to lower commodity prices, results to date and the timing of projects in Egypt.

Egypt

The $35.4 million Egypt program has $19.5 million (55%) allocated to exploration and $15.9 million (45%) to development. The $19.5 million exploration program includes drilling up to 10 wells in the Eastern Desert, one Boraq well at South Alamein in the Western Desert and a large (600 km²) 3-D seismic acquisition program at NW Sitra in the Western Desert. The $15.9 million 2017 development program includes drilling up to 6 development wells in the Eastern Desert (2 wells at WG, 1 well at WB and 3 wells at NWG) and development/maintenance projects at West Gharib, West Bakr and NW Gharib.

Canada

The $6.1 million (C$7.9 million) Canada program consists of three horizontal (multi-stage frac) wells targeting the Cardium light oil resource at Harmattan and additional maintenance/development capital for potential workover/refracs. The initial Cardium well program is designed to provide a current benchmark for well costs and improved frac design/performance in the Harmattan area (no drilling has been conducted on the acquired lands since 2013). Based on historical offset wells and third party engineering estimates, it is expected that the horizontal wells will cost approximately $2.0 million (C$2.7 million) per well targeting a one mile lateral with approximately 600 tonnes of sand (40 stages) per well. The 2017 program was scaled back to a three well program (on an existing pad) due to reduced commodity prices in the 2^nd and 3^rd quarter. The remaining five wells planned for 2017 will be added to the 2018 program.

The 2017 capital program is summarized in the following table:

	TransGlobe 2017 Capital ($MM)			Gross Well Count
			Total	(Wells)
Concession	Development	Exploration		Development	Exploration	Total
West Gharib	5.4	—	5.4	2	—	2
West Bakr	6.8	—	6.8	1	—	1
NW Gharib	3.7	9.9	13.6	3	8	11
SW Gharib	—	1.2	1.2	—	2	2
South Alamein	—	3.1	3.1	—	1	1
South Ghazalat	—	0.2	0.2	—	—	—
NW Sitra	—	5.1	5.1	—	—	—
Egypt	$15.9	$19.5	$35.4	6	11	17
Canada	$6.1	—	$6.1	3	—	3
2017 Total	$22.0	$19.5	41.5*	9	11	20
Splits (%)	53%	47%	100%	45%	55%	100%
*Before capitalized G&A.

Q2-2017 9

NON-GAAP FINANCIAL MEASURES

Funds Flow from Operations

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

Reconciliation of Funds Flow from Operations

	Three months ended June 30				Six months ended June 30
($000s)	2017		2016		2017		2016
Cash flow from operating activities	(2,753	)	6,011		(5,250	)	7,437
Changes in non-cash working capital	19,608		(3,985	)	24,607		(8,241	)
Funds flow from operations1	16,855		2,026		19,357		(804	)
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.

10 Q2-2017

SELECTED QUARTERLY FINANCIAL INFORMATION

	2017				2016								2015
($000s, except per share,
price and volume amounts)	Q-2		Q-1		Q-43		Q-3		Q-2		Q-1		Q-4		Q-3
Operations
Average production volumes
Crude oil (bbls/d)	14,347		14,514		12,861		11,733		11,472		12,058		13,425		14,683
NGLs (bbls/d)	919		1,037		134		—		—		—		—		—
Natural gas (mcf/d)	7,191		7,075		916		—		—		—		—		—
Total (boe/d)	16,465		16,731		13,148		11,733		11,472		12,058		13,425		14,683
Average sales volumes
Crude oil (bbls/d)	17,141		11,610		7,018		11,485		11,783		14,126		7,205		13,620
NGLs (bbls/d)	919		1,037		134		—		—		—		—		—
Natural gas (mcf/d)	7,191		7,075		916		—		—		—		—		—
Total (boe/d)	19,259		13,826		7,305		11,485		11,783		14,126		7,205		13,620
Average realized sales prices
Crude oil ($/Bbl)	39.46		41.66		37.38		34.43		30.27		22.58		32.38		39.35
NGLs ($/Bbl)	21.08		19.08		12.33		—		—		—		—		—
Natural gas ($/Mcf)	2.14		1.96		1.80		—		—		—		—		—
Total oil equivalent ($/boe)	36.92		37.41		36.45		34.43		30.27		22.58		32.38		39.35
Inventory (MBbl)	1,274		1,528		1,265		729		707		735		923		351
Petroleum and natural gas sales	64,711		46,553		24,501		36,376		32,461		29,022		21,460		49,307
Petroleum and natural gas sales, net of royalties	40,439		22,461		5,217		20,704		19,786		17,427		3,979		24,700
Cash flow from operating activities	(2,753	)	(2,497	)	6,355		(14,857	)	6,011		1,426		6,414		28,741
Funds flow from operations1	16,855		2,502		(9,904	)	2,347		2,026		(2,830	)	(11,108	)	(1,497	)
Funds flow from operations per share
- Basic	0.23		0.03		(0.14	)	0.03		0.03		(0.04	)	(0.15	)	(0.02	)
- Diluted	0.23		0.03		(0.14	)	0.03		0.03		(0.04	)	(0.15	)	(0.02	)
Net earnings (loss)	(56,622	)	(12,877	)	(33,997	)	(25,369	)	(12,050	)	(16,249	)	(35,255	)	(46,568	)
Net earnings (loss) - diluted	(56,622	)	(12,877	)	(38,641	)	(25,369	)	(12,050	)	(16,249	)	(35,255	)	(54,159	)
Net earnings per share
- Basic	(0.78	)	(0.18	)	(0.47	)	(0.35	)	(0.17	)	(0.23	)	(0.49	)	(0.64	)
- Diluted	(0.78	)	(0.18	)	(0.49	)	(0.35	)	(0.17	)	(0.23	)	(0.49	)	(0.68	)
Capital expenditures	8,229		10,718		8,863		8,692		4,838		4,265		4,877		3,587
Dividends paid	—		—		—		—		—		—		1,805		3,594
Dividends paid per share	—		—		—		—		—		—		0.025		0.05
Total assets	337,596		403,686		406,142		414,363		433,013		441,624		455,500		501,808
Cash and cash equivalents	13,780		21,324		31,468		100,405		124,308		122,031		126,910		126,874
Convertible debentures	—		—		72,655		74,854		70,639		66,506		63,848		65,682
Note payable	—		11,259		11,162		—		—		—		—		—
Total long-term debt, including      current portion	83,725		73,549		—		—		—		—		—		—
Debt-to-funds flow ratio2	7.1		(28.0	)	(10.0	)	(7.8	)	(5.3	)	(7.9	)	(7.2	)	3.6
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.

Q2-2017 11

During the second quarter of 2017, TransGlobe:

• Reported positive working capital of $60.3 million (including cash and cash equivalents of $13.8 million) at June 30, 2017;

• Reported a net loss of $(56.6) million, which include a $67.5 million non-cash impairment loss on the Company's exploration and evaluation assets at NW Gharib and a $6.6 million unrealized derivative gain on commodity contracts (mark-to-market gain on the Company's hedging contracts). The recoverable amount of the North West Gharib cash-generating unit is $4.4 million. The Company's remaining NW Gharib exploration and evaluation assets were written down to nil;

• Experienced a 99% increase in petroleum and natural gas sales compared to Q2-2016, which was principally due to a 22% increase in realized prices along with a 63% increase in sales volumes. Realized pricing for the Company's petroleum and natural gas products are market driven. The tanker lifting sale of entitlement crude oil during the quarter and the recently acquired Canadian assets also contributed to the petroleum and natural gas sales increase;

• Achieved positive funds flow from operations of $16.9 million, which is a significant increase over the previous seven quarters;

• Reported a 44% increase in production volumes as compared to Q2-2016, which translates into an additional 4,993 boepd. The recently acquired Canadian assets contributed 2,614 boepd of additional production, and increased Egypt production accounted for the remaining variance. The increased Egypt production was the result of the production recovery plan undertaken in the second half of 2016, along with the production from NW Gharib, which contributed 1,377 bopd.

• Repaid the $11.0 million (C$15.0 million) vendor take-back note with the revolving reserve-based lending facility and cash;

• Sold 515,526 barrels of entitlement crude oil marketed by Mercuria and an additional 302,648 barrels of inventoried entitlement crude oil to EGPC, resulting in a decrease in crude oil inventory of 0.3 million barrels from Q1-2017; and

• Spent $8.2 million on capital programs, which was funded entirely from funds flow and cash on hand.

12 Q2-2017

2017 TO 2016 NET EARNINGS VARIANCES

			$ Per Share
	$000s		Diluted		% Variance
Q2-2016 net earnings (loss)	(12,050	)	(0.17	)
Cash items
Volume variance	25,275		0.35		(209	)
Price variance	6,978		0.10		(58	)
Royalties	(11,599	)	(0.16	)	96
Expenses:
Production and operating	(4,283	)	(0.06	)	36
Transportation	(156	)	—		1
Selling costs	(1,455	)	(0.02	)	12
Cash general and administrative	63		—		(1	)
Current income taxes	(2,010	)	(0.03	)	17
Realized foreign exchange gain (loss)	(92	)	—		1
Realized derivative gain (loss)	2,227		0.03		(18	)
Interest on long-term debt	(315	)	—		3
Other income	(118	)	—		1
Total cash items variance	14,515		0.21		(119	)
Non-cash items
Unrealized derivative gain (loss)	6,578		0.09		(55	)
Unrealized foreign exchange gain (loss)	(35	)	—		—
Depletion and depreciation	(2,280	)	(0.03	)	19
Asset retirement obligation accretion	(57	)	—		—
Unrealized gain (loss) on financial instruments	4,286		0.06		(36	)
Impairment loss	(67,520	)	(0.94	)	560
Stock-based compensation	703		0.01		(6	)
Deferred income taxes	(812	)	(0.01	)	7
Deferred lease inducement	(3	)	—		—
Amortization of deferred financing costs	53		—		—
Total non-cash items variance	(59,087	)	(0.82	)	489
Q2-2017 net earnings (loss)	(56,622	)	(0.78	)	370

TransGlobe recorded a net loss of $56.6 million in Q2-2017 compared to a net loss of $12.1 million in Q2-2016. The largest positive earnings variance was a result of a 22% increase in the average realized sales price and a 63% increase in sales volumes totaling $32.3 million in aggregate compared to Q2-2016, which was partially offset by increased royalties and current income taxes of $13.6 million. The Company incurred $1.5 million in selling costs during the period, principally associated with the cargo of entitlement oil sold in June. Operating expenditures increased in Q2-2017 compared to Q2-2016, due principally to recognizing capitalized operating costs associated with the previously inventoried entitlement crude oil barrels sold during the quarter.

The largest non-cash earnings variance item in Q2-2017 compared to Q2-2016 relates to the $67.5 million negative variance caused by an impairment loss recorded on the Company's exploration and evaluation assets at North West Gharib. The $67.5 million impairment loss recognized in the quarter is a result of reducing the overall carrying value of the North West Gharib concession to the discounted present value of the proved plus probable reserves recognized as at the end of the quarter. This 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. The largest non-cash positive earnings variance in Q2-2017 compared to Q2-2016 related to the unrealized derivative gain on commodity contracts recorded in Q2-2017. The Company recorded a $6.6 million non-cash gain on its outstanding hedging contracts as at June 30, 2017, which was a result of marking the contracts to their respective market values. In Q2-2016, there were no hedging contracts outstanding. The mark-to-market adjustment on the convertible debentures created a positive earnings swing of $4.3 million. The convertible debentures were repaid during the first quarter of 2017.

Q2-2017 13

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-2	Q-1	Q-4	Q-3	Q-2
Crude oil
Dated Brent average oil price (US$/Bbl)	49.67	53.68	49.19	45.79	45.52
Edmonton Sweet index (US$/bbl)	46.03	48.37	46.18	41.99	42.51
Natural gas
AECO (C$/mmbtu)	2.78	2.69	3.09	2.32	1.40
U.S./Canadian Dollar average exchange rate	1.345	1.323	1.334	1.305	1.289

The price of Dated Brent oil averaged 7% lower in Q2-2017 compared with Q1-2017. Egypt production is priced based on Dated Brent 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 $356.4 million from EGPC, reducing the balance due from EGPC to $18.8 million as at June 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 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.

On December 20, 2016, the Company acquired producing oil and gas assets in the Harmattan area of west central Alberta, Canada. The Harmattan acquisition provides 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 meets 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 5% lower in Q2-2017 compared with Q1-2017. The price of AECO averaged 3% higher in Q2-2017 compared with Q1-2017.

14 Q2-2017

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest before Royalties (Boepd)

Production Volumes

	Three months ended June 30		Six months ended June 30
	2017	2016	2017	2016
Egypt crude oil (bbls/d)	13,851	11,472	13,900	11,765
Canada crude oil (bbls/d)	496	—	530	—
Canada natural gas (mcf/d)	7,191	—	7,133	—
Canada NGLs (bbls/d)	919	—	978	—
Total Company (boe/d)	16,465	11,472	16,597	11,765

Sales Volumes (excludes volumes held as inventory)

	Three months ended June 30		Six months ended June 30
	2017	2016	2017	2016
Egypt crude oil (bbls/d)	16,645	11,783	13,861	12,955
Canada crude oil (bbls/d)	496	—	530	—
Canada natural gas (mcf/d)	7,191	—	7,133	—
Canada NGLs (bbls/d)	919	—	978	—
Total Company (boe/d)	19,259	11,783	16,558	12,955

Netback

Consolidated netback
	Six months ended June 30
	2017		2016
(000s, except per Boe amounts)1	$	$/Boe	$	$/Bbl
Petroleum and natural gas sales	111,265	37.13	61,483	26.08
Royalties and other	48,365	16.14	24,270	10.29
Current taxes	10,925	3.65	6,670	2.83
Production and operating expenses	25,046	8.36	23,761	10.08
Transportation	354	0.12	—	—
Selling costs	1,502	0.50	875	0.37
Netback	25,073	8.36	5,907	2.51
1   The Company achieved the netbacks above on sold barrels of oil equivalent for the six months ended June 30, 2017 and June 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 30, 2017).

Consolidated netback
	Three months ended June 30
	2017		2016
(000s, except per Boe amounts)1	$	$/Boe	$	$/Bbl
Petroleum and natural gas sales	64,711	36.92	32,461	30.27
Royalties and other	24,272	13.85	12,675	11.82
Current taxes	5,505	3.14	3,495	3.26
Production and operating expenses	14,923	8.51	10,640	9.92
Transportation	156	0.09	—	—
Selling costs	1,502	0.86	47	0.04
Netback	18,353	10.47	5,604	5.23
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the three months ended June 30, 2017 and June 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 30, 2017).

Q2-2017 15

Egypt
	Six months ended June 30
	2017		2016
(000s, except per Bbl amounts)1	$	$/Bbl	$	$/Bbl
Oil sales	100,581	40.09	61,483	26.08
Royalties	46,037	18.35	24,270	10.29
Current taxes	10,925	4.35	6,670	2.83
Production and operating expenses	22,102	8.81	23,761	10.08
Selling costs	1,502	0.60	875	0.37
Netback	20,015	7.98	5,907	2.51
1   The Company achieved the netbacks above on sold barrels of oil equivalent for the six months ended June 30, 2017 and June 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 30, 2017).

Egypt
	Three months ended June 30
	2017		2016
(000s, except per Bbl amounts)1	$	$/Bbl	$	$/Bbl
Oil sales	59,541	39.31	32,461	30.27
Royalties	23,122	15.27	12,675	11.82
Current taxes	5,505	3.63	3,495	3.26
Production and operating expenses	13,556	8.95	10,640	9.92
Selling costs	1,502	0.99	47	0.04
Netback	15,856	10.47	5,604	5.23
1   The Company achieved the netbacks above on sold barrels of oil equivalent for the three months ended June 30, 2017 and June 30, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at June 30, 2017).

The netback per Bbl in Egypt increased 100% and 218%, respectively, in the three and six months ended June 30, 2017 compared with the same periods of 2016. The increased netbacks were principally the result of an increase in realized oil prices of 30% and 54%, respectively, and a decrease in operating costs per barrel of 10% and 13%, respectively, in the three and six months ended June 30, 2017 compared with the same periods of 2016.

Production and operating expenses increased by $2.9 million in the three months ended June 30, 2017 compared to the same period of 2016. This is principally the result of an increase in sales volumes in Q2-2017, resulting in recognizing the capitalized operating costs associated with the crude oil inventory in the period. Operating costs for the six months ended June 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 13%, respectively, in the three and six months ended June 30, 2017 compared with the same periods of 2016. The most significant cost efficiencies were achieved in the areas of labour costs and equipment rentals. 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 Q2 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 to third party buyers marketed by Mercuria during Q2-2017.

Royalties and taxes as a percentage of revenue were 48% and 57%, in the three and six month periods ended June 30, 2017 respectively, compared with 50% for each of 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 average selling price during the three months ended June 30, 2017 was $39.31/Bbl, which was $10.36/Bbl lower than the average Dated Brent oil price of $49.67/Bbl for the period (Q2-2016 - $45.52/Bbl). The difference was due to a gravity/quality adjustment and was also impacted by the timing of the direct sale.

16 Q2-2017

Canada
	Six months ended June 30
	2017		2016
(000s, except per Boe amounts)	$	$/Boe	$	$/Boe
Crude oil sales	4,494	46.85	—	—
Natural gas sales	2,645	12.29	—	—
NGL sales	3,544	20.02	—	—
Total sales	10,683	21.89
Royalties	2,328	4.77	—	—
Production and operating expenses	2,944	6.03	—	—
Transportation	354	0.73	—	—
Netback	5,057	10.36	—	—

Canada
	Three months ended June 30
	2017		2016
(000s, except per Boe amounts)	$	$/Boe	$	$/Boe
Crude oil sales	2,007	44.47	—	—
Natural gas sales	1,400	12.84	—	—
NGL sales	1,763	21.08	—	—
Total sales	5,170	21.74
Royalties	1,150	4.84	—	—
Production and operating expenses	1,367	5.75	—	—
Transportation	156	0.66	—	—
Netback	2,497	10.49	—	—

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

Netbacks in Canada for the three months ended Q2-2017 were $10.49 per Boe, which represents an increase of $0.26 per Boe as compared to the three months ended Q1-2017. This increase in netback is mainly due to a 10% decrease in production and operating expenses on a per Boe basis.

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 June, 2017, the Company incurred $1.2 million in royalty costs. Royalties amounted to 22% of petroleum and natural gas sales revenue in the three months ended June 30, 2017.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)

	Six months ended June 30
	2017				2016
(000s, except per Bbl amounts)	$		$/Bbl		$		$/Bbl
G&A (gross)	8,380		2.80		8,041		3.41
Stock-based compensation	650		0.22		1,546		0.66
Capitalized G&A	(1,222	)	(0.41	)	(1,939	)	(0.82	)
G&A (net)	7,808		2.61		7,648		3.25

	Three months ended June 30
	2017				2016
(000s, except per Bbl amounts)	$		$/Bbl		$		$/Bbl
G&A (gross)	3,631		2.07		3,909		3.65
Stock-based compensation	421		0.24		1,124		1.05
Capitalized G&A	(690	)	(0.39	)	(908	)	(0.85	)
G&A (net)	3,362		1.92		4,125		3.85

Q2-2017 17

G&A (gross) for the three months ended June 30, 2017 decreased 7% as compared with the same period in 2016 (43% decrease on a per boe basis). Primarily due to slightly lower staff levels and foreign exchange. For the six months ended June 30, 2017 G&A (gross) is relatively flat versus the same period in 2016.

G&A expenses (net) for the three months ended June 30, 2017 decreased 18% as compared with the same period in 2016 (50% decrease on a per boe basis). For the six months ended June 30, 2017 G&A (net) is relatively flat versus the same period in 2016 (20% decrease on a per boe basis).

Capitalized G&A for the three and six months ended June 30, 2017 decreased 24% and 37%, respectively, as compared with the same periods in 2016 (54% and 50% 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 $0.3 million and $0.7 million were capitalized for the three and six months ended June 30, 2016. In December 2016 the Company terminated its 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 six months ended June 30, 2017 were $1.7 million and $3.3 million, respectively (2016 - $1.5 million and $2.9 million, respectively).

	Three months ended June 30				Six months ended June 30
(000s)	2017		2016		2017		2016
Convertible debentures	$	—	$	1,125	$	1,089	$	2,178
Long-term debt	1,327		—		1,455		—
Note payable	250		—		532		—
Borrowing base facility	49		188		49		406
Issue costs for convertible debentures	—		—		—		—
Amortization of deferred financing costs	91		143		140		301
Finance costs	$	1,717	$	1,456	$	3,265	$	2,885

Convertible Debentures

Interest expense on the convertible debentures for the three and six month period ended June 30, 2017 was $nil and $1.1 million, respectively (2016 - $1.1 million and $2.2 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 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 six month period ended June 30, 2017 was $1.3 million and $1.5 million.

The prepayment agreement is subject to certain covenants, the details of which are outlined in Note 13 to the Company's Condensed Consolidated Interim Financial Statements.

Revolving Reserve-Based Lending Facility

As at June 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.

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 month period ended June 30, 2017 was $0.1 million.

18 Q2-2017

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 six month period ended June 30, 2017 was $0.2 million and $0.5 million.

DEPLETION AND DEPRECIATION (“DD&A”)

	Six months ended June 30
	2017		2016
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Egypt	14,208	5.66	17,855	7.57
Canada	4,510	9.24	—	—
Corporate	157	—	244	—
	18,875	6.30	18,099	7.68

	Three months ended June 30
	2017		2016
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Egypt	8,094	5.34	7,961	7.42
Canada	2,208	9.28	—	—
Corporate	61	—	122	—
	10,363	5.91	8,083	7.54

In Egypt, DD&A decreased 28% and 25%, respectively, on a per Bbl basis in the three and six months ended June 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 29% reduction in future development costs.

In Canada, DD&A was $9.28 and $9.24 per Bbl, respectively, on a per Bbl basis in the three and six months ended June 30, 2017, which was consistent with the DD&A rate for the three months ended Q1-2017.

IMPAIRMENT LOSS

The Company recorded an impairment loss of $68.7 million on its exploration and evaluation assets as at June 30, 2017. The impairment primarily related to the North West Gharib concession in Egypt. The recoverable amount of the North West Gharib cash-generating unit is $4.4 million. The remaining North West Gharib exploration and evaluation assets were written down to nil as at June 30, 2017. 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 and has filed development lease applications on its discoveries. The Company has relinquished the remaining exploration lands that are not covered by development lease applications.

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.

CAPITAL EXPENDITURES

	Six months ended June 30
($000s)	2017	2016
Egypt	18,597	9,102
Canada	324	—
Acquisitions	—	—
Corporate	27	—
Total	18,948	9,102

In Egypt, total capital expenditures in the first six months of 2017 were $18.6 million (2016 - $9.1 million). During the first six months of the year, the Company drilled eight 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 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. The Company spudded Boraq 5 during the second quarter and was still drilling through the end of the quarter. During the six months ended June 30, 2017 the Company spent $10.5 million in drilling, $4.7 million on seismic acquisition in NW Sitra, $1.8 million on completions and $1.6 million on facilities construction and maintenance.

Q2-2017 19

OUTSTANDING SHARE DATA

As at June 30, 2017, the Company had 72,205,369 common shares issued and outstanding and 5,638,053 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 has deteriorated significantly since late 2014 as a direct result of a continued lower oil price environment. As of June 30, 2017 debt-to-funds flow improved to 7.1 (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 varies 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 June 30, 2017 and 2016:

Sources and Uses of Cash
	Six months ended June 30
($000s)	2017		2016
Cash sourced
Funds flow from operations1	19,357		(804	)
Transfer from restricted cash	10,465		289
Proceeds from corporate dispositions	—		—
Increase in long-term debt	85,140		—
Other	387		—
	115,349		(515	)
Cash used
Capital expenditures	18,948		9,102
Deferred financing costs	1,555		—
Repayment of convertible debentures	73,375		—
Repayment of note payable	11,041		—
Finance costs	4,027		2,530
Other	—		1,027
	108,946		12,659
	6,403		(13,174	)
Changes in non-cash working capital	(24,091	)	10,572
Increase (decrease) in cash and cash equivalents	(17,688	)	(2,602	)
Cash and cash equivalents – beginning of period	31,468		126,910
Cash and cash equivalents – end of period	13,780		124,308
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.

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 $41.5 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 June 30, 2017, the Company had a working capital surplus of $60.3 million (December 31, 2016 - deficiency of $16.8 million). The increase to working capital in Q2-2017 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 as at March 31, 2017. The Company's working capital continues to be negatively impacted by low oil prices.

The Company's first cargo lifting of the year was completed in June and proceeds from the lifting were received in July. TransGlobe's second and third tanker-liftings of 2017 are scheduled for September and December. 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 June 30, 2017, the Company held 1,274,057 barrels of entitlement oil as inventory.

The Company now has a receivable balance of $18.8 million due from EGPC. During the first six months of 2017, the Company sold 606,465 barrels of inventoried entitlement crude oil to EGPC for $25.2 million to cover in-country expenditures. The Company collected $19.9 million of accounts receivable from EGPC during the first six months of 2017.

20 Q2-2017

At June 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 June 30, 2017, the Company had restricted cash of $7.9 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 June 30, 2017, the Company had 1,274,057 barrels of entitlement oil as inventory, which represents approximately seven 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. Throughout 2015 there was a steady increase in crude oil inventory levels, as production outpaced sales. In Q1-2016 and Q2-2016, crude oil inventory levels dropped as a result of crude oil sales being greater than our production. Through the second half of 2016 and Q1-2017, crude oil inventory levels once again grew as production was greater than sales. 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. Two additional tanker liftings are currently scheduled for the remainder of 2017, with expected total shipment volumes of 1.5 MMBbl to approximate for 2017, inclusive of the June tanker lifting.

	Six months ended		Year ended
(bbls)	June 30, 2017		December 31, 2016
Product inventory, beginning of period	1,265,080		923,106
TransGlobe entitlement production	1,131,068		2,036,483
Tanker liftings	(515,626	)	(1,694,509	)
EGPC sales	(606,465	)	—
Product inventory, end of period	1,274,057		1,265,080

COMMITMENTS AND CONTINGENCIES

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

($000s)		Payment Due by Period 1,2
	Recognized
	in Financial	Contractual	Less than
	Statements	Cash Flows	1 year	1-3 years	4-5 years
Accounts payable and accrued liabilities	Yes - Liability	25,116	25,116	—	—
Long-term debt	Yes - Liability	83,725	—	10,094	73,631
Note payable	Yes - Liability	—	—	—	—
Office and equipment leases3	No	4,130	1,908	2,222	—
Minimum work commitments4	No	5,129	5,129	—	—
Total		118,100	32,153	12,316	73,631
Notes:
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at June 30, 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 lease applications.

Q2-2017 21

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. Since 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 June 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 June 30, 2017.

ASSET RETIREMENT OBLIGATION

At June 30, 2017, TransGlobe recorded an asset retirement obligation ("ARO") of $12.8 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 1.09% and 2.13% 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 twelve outstanding derivative commodity contracts as at June 30, 2017 (December 31, 2016 - nil), the fair values of which have been presented as assets on the Condensed Consolidated Interim Balance Sheet.

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

22 Q2-2017

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
27-Mar-2017	Sep 2017	Swap	425,000	51.00	—	—	—
28-Mar-2017	Dec 2017	Collar	300,000	—	45.00	56.00	—
7-Apr-2017	Mar 2018	3-Way Collar	250,000	—	53.00	61.15	44.00
12-Apr-2017	Jun 2018	3-Way Collar	250,000	—	54.00	63.10	45.00
12-Apr-2017	Sep 2018	3-Way Collar	250,000	—	54.00	64.15	45.00
12-Apr-2017	Dec 2018	3-Way Collar	250,000	—	54.00	65.45	45.00
23-May-2017	Jul 2020	3-Way Collar	50,000	—	54.00	63.45	45.00
23-May-2017	Aug 2020	3-Way Collar	50,000	—	54.00	63.45	45.00
23-May-2017	Sep 2020	3-Way Collar	50,000	—	54.00	63.45	45.00
23-May-2017	Oct 2020	3-Way Collar	50,000	—	54.00	63.45	45.00
23-May-2017	Nov 2020	3-Way Collar	50,000	—	54.00	63.45	45.00
23-May-2017	Dec 2020	3-Way Collar	50,000	—	54.00	63.45	45.00

The Company has agreed with Mercuria the counterparty to the prepayment agreement to enter into further hedges for 800,000 bbls in 2019 and 600,000 bbls in 2020.

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 June 30, 2017 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

Q2-2017 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						Six months ended
		June 30						June 30
	Notes	2017			2016			2017			2016
REVENUE
Petroleum and natural gas sales, net of royalties	4	$	40,439		$	19,786		$	62,900		$	37,213
Finance revenue		19			137			44			374
		40,458			19,923			62,944			37,587
EXPENSES
Production and operating		14,923			10,640			25,046			23,761
Transportation costs		156			—			354			—
Selling costs	6	1,502			47			1,502			875
General and administrative		3,362			4,125			7,808			7,648
Foreign exchange (gain) loss		82			(45		)	67			5,346
Finance costs	5	1,717			1,456			3,265			2,885
Depletion, depreciation and amortization	11	10,363			8,083			18,875			18,099
Accretion	12	57			—			117			—
Realized derivative (gain) loss on commodity contracts		(1,529		)	698			(1,529		)	956
Unrealized derivative (gain) loss on commodity contracts	3	(6,578		)	—			(2,849		)	—
Unrealized (gain) loss on financial instruments	14	—			4,286			151			2,655
Impairment of exploration and evaluation assets	10	67,520			—			68,711			—
		91,575			29,290			121,518			62,225
Earnings (loss) before income taxes		(51,117		)	(9,367		)	(58,574		)	(24,638		)
Income tax expense (recovery) - current		5,505			3,495			10,925			6,670
- deferred		—			(812		)	—			(3,009		)
		5,505			2,683			10,925			3,661
NET EARNINGS (LOSS) FOR THE PERIOD		$	(56,622	)	$	(12,050	)	$	(69,499	)	$	(28,299	)
OTHER COMPREHENSIVE (LOSS) INCOME
Currency translation adjustments		(32		)	—			(615		)	—
COMPREHENSIVE INCOME (LOSS) FOR THE PERIOD		$	(56,654	)	$	(12,050	)	$	(70,114	)	$	(28,299	)
Earnings (loss) per share
Basic		$	(0.78	)	$	(0.17	)	$	(0.96	)	$	(0.39	)
Diluted		$	(0.78	)	$	(0.17	)	$	(0.96	)	$	(0.39	)

See accompanying notes to the Condensed Consolidated Interim Financial Statements.

24 Q2-2017

Condensed Consolidated Interim Balance Sheets

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

		As at			As at
	Notes	June 30, 2017			December 31, 2016
ASSETS
Current
Cash and cash equivalents	7	$	13,780		$	31,468
Restricted cash	8	7,858			18,323
Accounts receivable	3	41,910			14,836
Derivative commodity contracts	3	2,849			—
Prepaids and other		1,924			1,772
Product inventory	9	17,114			19,602
		85,435			86,001
Non-Current
Intangible exploration and evaluation assets	10	49,002			105,869
Property and equipment
Petroleum and natural gas assets	11	199,261			210,027
Other assets	11	3,898			4,245
		$	337,596		$	406,142
LIABILITIES
Current
Accounts payable and accrued liabilities		$	25,116		$	24,529
Convertible debentures	14	—			72,655
Current portion of note payable	13	—			5,581
		25,116			102,765
Non-Current
Note payable	13	—			5,581
Long-term debt	13	83,725			—
Asset retirement obligation	12	12,829			12,099
Other long-term liabilities		338			381
		122,008			120,826
SHAREHOLDERS’ EQUITY
Share capital	16	152,084			152,084
Accumulated other comprehensive income		(615		)	—
Contributed surplus		23,081			22,695
Retained earnings		41,038			110,537
		215,588			285,316
		$	337,596		$	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

Q2-2017 25

Condensed Consolidated Interim Statements of Changes in Shareholders’ Equity

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

		Three Months Ended						Six months ended
		June 30						June 30
	Notes	2017			2016			2017			2016
Share Capital
Balance, beginning of period	16	$	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		$	(583	)	$	—		$	—		$	—
Currency translation adjustment		(32		)	—			(615		)	—
Balance, end of period		$	(615	)	$	—		$	(615	)	$	—
Contributed Surplus
Balance, beginning of period		$	22,914		$	21,824		$	22,695		$	21,398
Stock-based compensation expense	17	167			343			386			769
Balance, end of period		$	23,081		$	22,167		$	23,081		$	22,167
Retained Earnings
Balance, beginning of period		$	97,660		$	181,953		$	110,537		$	198,202
Net earnings (loss) and total comprehensive income (loss)		(56,622		)	(12,050		)	(69,499		)	(28,299		)
Balance, end of period		$	41,038		$	169,903		$	41,038		$	169,903

See accompanying notes to the Condensed Consolidated Interim Financial Statements.

26 Q2-2017

Condensed Consolidated Interim Statements of Cash Flows

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

		Three Months Ended						Six months ended
		June 30						June 30
	Notes	2017			2016			2017			2016
CASH FLOWS RELATED TO THE FOLLOWINGACTIVITIES:
OPERATING
Net earnings (loss) for the period		$	(56,622	)	$	(12,050	)	$	(69,499	)	$	(28,299	)
Adjustments for:
Depletion, depreciation and amortization	11	10,363			8,083			18,875			18,099
Accretion	12	57			—			117			—
Deferred lease inducement		(21		)	(24		)	(43		)	(51		)
Impairment of exploration and evaluation assets	10	67,520			—			68,711			—
Stock-based compensation	17	421			1,124			650			1,546
Finance costs	5	1,717			1,456			3,265			2,885
Income tax expense		5,505			2,683			10,925			3,661
Unrealized (gain) loss on commodity contracts	3	(6,578		)	—			(2,849		)	—
Unrealized (gain) loss on financial instruments	14	—			4,286			151			2,655
Unrealized (gain) loss on foreign currency translation		(2		)	(37		)	(21		)	5,370
Income taxes paid		(5,505		)	(3,495		)	(10,925		)	(6,670		)
Changes in non-cash working capital		(19,608		)	3,985			(24,607		)	8,241
Net cash generated by (used in) operating activities		(2,753		)	6,011			(5,250		)	7,437
INVESTING
Additions to intangible exploration and evaluation assets	10	(3,667		)	(2,633		)	(14,115		)	(4,262		)
Additions to petroleum and natural gas assets	11	(4,279		)	(2,071		)	(4,473		)	(4,384		)
Additions to other assets	11	(284		)	(133		)	(360		)	(456		)
Changes in restricted cash	8	8,515			290			10,465			289
Changes in non-cash working capital		(2,436		)	1,117			516			2,331
Net cash generated by (used in) investing activities		(2,151		)	(3,430		)	(7,967		)	(6,482		)
FINANCING
Repayment of note payable	13	(11,041		)	—			(11,041		)	—
Financing costs	5	(55		)	—			(1,555		)	—
Interest paid		(1,836		)	(183		)	(4,027		)	(2,530		)
Increase in long-term debt		10,140			—			85,140			—
Repayment of convertible debentures	14	—			—			(73,375		)	—
Net cash generated by (used in) financing activities		(2,792		)	(183		)	(4,858		)	(2,530		)
Currency translation differences relating to cash and cash equivalents		152			(121		)	387			(1,027		)
NET INCREASE (DECREASE) IN CASH AND CASHEQUIVALENTS		(7,544		)	2,277			(17,688		)	(2,602		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		21,324			122,031			31,468			126,910
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	13,780		$	124,308		$	13,780		$	124,308

See accompanying notes to the Condensed Consolidated Interim Financial Statements.

Q2-2017 27

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

As at June 30, 2017 and December 31, 2016 and for the periods ended June 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 June 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 August 11, 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 Q2-2017

3. 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 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:

	June 30, 2017				December 31, 2016
	Carrying		Fair		Carrying		Fair
Classification (000s)	Value		Value		Value		Value
Financial assets at fair value through profit or loss	$	16,629	$	16,629	$	31,468	$	31,468
Loans and receivables	49,768		49,768		33,159		33,159
Financial liabilities at fair value through profit or loss	—		—		72,655		72,655
Other liabilities	108,841		110,256		35,691		35,691

Assets and liabilities at June 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.

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 13), 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.

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

The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at June 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
27-Mar-2017	Sep 2017	Swap	425,000	51.00	—	—	—
28-Mar-2017	Dec 2017	Collar	300,000	—	45.00	56.00	—
7-Apr-2017	Mar 2018	3-Way Collar	250,000	—	53.00	61.15	44.00
12-Apr-2017	Jun 2018	3-Way Collar	250,000	—	54.00	63.10	45.00
12-Apr-2017	Sep 2018	3-Way Collar	250,000	—	54.00	64.15	45.00
12-Apr-2017	Dec 2018	3-Way Collar	250,000	—	54.00	65.45	45.00
23-May-2017	Jul 2020	3-Way Collar	50,000	—	54.00	63.45	45.00
23-May-2017	Aug 2020	3-Way Collar	50,000	—	54.00	63.45	45.00
23-May-2017	Sep 2020	3-Way Collar	50,000	—	54.00	63.45	45.00
23-May-2017	Oct 2020	3-Way Collar	50,000	—	54.00	63.45	45.00
23-May-2017	Nov 2020	3-Way Collar	50,000	—	54.00	63.45	45.00
23-May-2017	Dec 2020	3-Way Collar	50,000	—	54.00	63.45	45.00

Q2-2017 29

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.

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 one shipment in the second quarter 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 six months of 2017, the Company sold 606,465 barrels of inventoried entitlement crude oil to EGPC for $25.2 million to cover in-country expenditures for Q1/Q2. The Company collected $19.9 million of accounts receivable from EGPC during the first six months of 2017.

(000s)
Trade receivables at June 30, 2017
Neither impaired nor past due	$	30,561
Impaired (net of valuation allowance)
Not impaired and past due in the following period:
Within 30 days	4,133
31-60 days	3,900
61-90 days	2,380
Over 90 days	936
	$	41,910

4. PETROLEUM AND NATURAL GAS SALES

	Three months ended June 30				Six months ended June 30
(000s)	2017		2016		2017		2016
Petroleum and natural gas sales	$	64,712	$	32,461	$	111,265	$	61,483
Less: Royalties	24,273		12,675		48,365		24,270
Petroleum and natural gas sales, net of royalties	$	40,439	$	19,786	$	62,900	$	37,213

5. FINANCE REVENUE AND 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 June 30				Six months ended June 30
(000s)	2017		2016		2017		2016
Interest on convertible debenture	$	—	$	1,125	$	1,089	$	2,178
Interest on long-term debt	1,327		—		1,455		—
Interest on note payable	250		—		532		—
Interest on borrowing base facility	49		188		49		406
Amortization of deferred financing costs	91		143		140		301
Finance costs	$	1,717	$	1,456	$	3,265	$	2,885

30 Q2-2017

6. SELLING COSTS

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

7. CASH AND CASH EQUIVALENTS

(000s)	June 30, 2017		December 31, 2016
Cash	$	13,741	$	31,392
Cash equivalents	39		76
	$	13,780	$	31,468

As at June 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.

8. RESTRICTED CASH

As at June 30, 2017, the Company had restricted cash of $7.9 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.

9. 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 crude oil that is held in storage as determined on a concession by concession basis.

As at June 30, 2017, the Company had 1,274,057 barrels of entitlement oil in inventory valued at $13.43 per barrel (December 31, 2016 - 1,265,080 barrels valued at $15.49 per barrel).

10. INTANGIBLE EXPLORATION AND EVALUATION ASSETS

(000s)
Balance at December 31, 2016	$	105,869
Additions	14,115
Transfers to petroleum properties	(2,271		)
Impairment loss	(68,711		)
Balance at June 30, 2017	$	49,002

The Company recorded an impairment loss of $68.7 million on its exploration and evaluation assets as at June 30, 2017. The impairment primarily related to the North West Gharib concession in Egypt. The recoverable amount of the North West Gharib cash-generating unit is $4.4 million. The remaining North West Gharib exploration and evaluation assets were written down to nil as at June 30, 2017. 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 and has filed development lease applications on its discoveries. The Company has relinquished the remaining exploration lands that are not covered by development lease applications.

During the six months ended June 30, 2017 the Company spent $6.6 million at North West Gharib, $4.9 million at North West Sitra, $1.3 million at South Alamein, $1.2 million at South West Gharib and $0.1 million at South Ghazalat.

Q2-2017 31

11. PROPERTY AND EQUIPMENT

(000s)	PNG Assets		Other Assets		Total
Balance at December 31, 2016	$	625,893	$	14,572	$	640,465
Additions	4,473		360		4,833
Changes in estimate for asset retirement obligations	206		—		206
Transfer from exploration and evaluation assets	2,271		—		2,271
Balance at June 30, 2017	$	632,843	$	14,932	$	647,775
Accumulated depletion, depreciation, amortization and impairment losses at December 31, 2016	$	415,866	$	10,327	$	426,193
Depletion, depreciation and amortization for the period	17,716		707		18,423
Balance at June 30, 2017	$	433,582	$	11,034	$	444,616
Net Book Value
At December 31, 2016	$	210,027	$	4,245	$	214,272
At June 30, 2017	$	199,261	$	3,898	$	203,159

12. ASSET RETIREMENT OBLIGATION

(000s)
Balance at December 31, 2016	$	12,099
Changes in estimates for asset retirement obligations	(64		)
Asset retirement obligation accretion	117
Changes in discount rates	268
Effect of movements in foreign exchange rates	409
Balance at June 30, 2017	$	12,829

TransGlobe has estimated the net present value of its asset retirement obligation to be $12.8 million as at June 30, 2017 (December 31, 2016 - $12.1 million) based on a total undiscounted future liability, after inflation adjustment, of $19.2 million (December 31, 2016 - $19.0 million). These payments are expected to be made between 2017 and 2066. TransGlobe calculated the present value of the obligations using discount rates between 1.09% and 2.13% 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 June 30, 2017 and December 31, 2016.

13. LONG-TERM DEBT

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

Prepayment Agreement

(000s)	June 30, 2017			December 31, 2016
Prepayment agreement	$	75,000		$	—
Deferred financing costs	(1,369		)	—
	73,631			—
Current portion of long-term debt
	$	73,631		$	—

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 Energy Trading SA ("Mercuria") of Geneva, Switzerland.

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 14).

32 Q2-2017

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 June 30, 2017 is 1.86:1.00, 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 June 30, 2017 is 4.65:1.00, 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 June 30, 2017 is 3.06:3.00, the Company is in compliance with the ratio.

As at June 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 divided by 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.

The cover ratio as at June 30, 2017 is 1.27:1.00, 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 June 30, 2017 are as follows:

(000s)
2017	$	—
2018	—
2019	—
2020	8,196
2021	66,804
	$	75,000

Revolving Reserve-Based Lending Facility

As at June 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.

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 June 30, 2017 is 1.78:1.00, the Company is in compliance with the ratio; and

Q2-2017 33

• 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 June 30, 2017 is 0.43:1.00, 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)	June 30, 2017		December 31, 2016
Note payable	$	—	$	11,162
Current portion of note payable	—		(5,581		)
	$	—	$	5,581

14. CONVERTIBLE DEBENTURES

(000s)
Balance at December 31, 2016	$	72,655
Repayment	(73,375		)
Fair value adjustment	151
Foreign exchange adjustment	569
Balance at June 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 13).

15. 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 lease applications.

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. Since 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 June 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 June 30, 2017.

34 Q2-2017

16. SHARE CAPITAL

Authorized

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

Issued

	Six months ended			Year Ended
	June 30, 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

17. 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:

	Six months ended			Year Ended
	June 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	(759	)	7.69	(54	)	11.84
Expired	(692	)	11.66	(718	)	12.95
Options outstanding, end of period	5,638		5.29	6,046		6.87
Options exercisable, end of period	3,413		7.07	3,527		9.14

Compensation expense of $0.4 million was recorded as general and administrative expenses in the Condensed Consolidated Interim Statements of Earnings (loss) and Comprehensive Income (loss) and Changes in Shareholders’ Equity during the six month period ended June 30, 2017 (2016 - $0.8 million) 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 six month period ended June 30, 2017, no stock options were exercised (2016 – nil). As at June 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 June 30, 2017 are as follows:

Q2-2017 35

	Restricted		Performance		Deferred
	Share		Share		Share
(000s, except per share amounts)	Units		Units		Units
Units outstanding, beginning of period	546		1,366		437
Granted	649		542		181
Vested	(220	)	(249	)	(56	)
Forfeited	(107	)	(226	)	—
Expired	—		N/A		—
Units outstanding, end of period	868		1,433		562

Compensation expense of$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 six month period endedJune 30, 2017(2016 -0.8 million) 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.

18. PER SHARE AMOUNTS

The weighted-average number of common shares outstanding (basic and diluted) for the three and six month periods ended June 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 six month periods ended June 30, 2017, the Company excluded 5,638,053 stock options (2016 – 4,676,100 and 6,145,953, respectively) as their exercise price was greater than the average common share market price in the respective periods.

19. SEGMENTED INFORMATION

The Company has two reportable operating segments for the period ended June 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. There are no inter-segment sales.

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

36 Q2-2017

	Egypt						Canada					Total
	Six months ended						Six months ended					Six months ended
	June 30						June 30					June 30
(000s)	2017			2016			2017			2016		2017			2016
Revenue
Petroleum and natural gas sales, net of royalties	54,544			37,213			8,356			—		62,900			37,213
Finance revenue	2			101			—			—		2			101
Total segmented revenue	54,546			37,314			8,356			—		62,902			37,314
Segmented expenses
Production and operating	22,102			23,761			2,944			—		25,046			23,761
Transportation costs	—			—			354			—		354			—
Selling costs	1,502			875			—			—		1,502			875
General and administrative	2,494			3,264			566			—		3,060			3,264
Finance costs	1,583			707			593			—		2,176			707
Depletion, depreciation and amortization	14,208			17,855			4,510			—		18,718			17,855
Asset retirement obligation accretion	—			—			117			—		117			—
Realized derivative (gain) loss on commodity contracts	(1,529		)	956			—			—		(1,529		)	956
Unrealized derivative (gain) loss on commodity contracts	(2,849		)	—			—			—		(2,849		)	—
Income taxes - current	10,925			6,670			—			—		10,925			6,670
Income taxes - deferred	—			(3,009		)	—			—		—			(3,009		)
Impairment of exploration and evaluation assets	68,711			—			—			—		68,711			—
Total segmented expenses	117,147			51,079			9,084			—		126,231			51,079
Segmented earnings (loss)	$	(62,601	)	$	(13,765	)	$	(728	)	$	—	$	(63,329	)	(13,765		)
Non-segmented expenses (income)
General and administrative												4,748			4,384
Foreign exchange (gain) loss												67			5,346
Depreciation and amortization												157			244
Unrealized (gain) loss on financial instruments												151			2,655
Finance revenue												(42		)	(273		)
Finance costs												1,089			2,178
Total non-segmented expenses												6,170			14,534
Net earnings (loss) for the year												$	(69,499	)	$	(28,299	)
Capital expenditures
Exploration and development	18,597			9,102			324			—		18,921			9,102
Corporate	—			—			—			—		27			—
Total capital expenditures												$	18,948		$	9,102

Q2-2017 37

	Egypt						Canada					Total
	Three months ended						Three months ended					Three months ended
	June 30						June 30					June 30
(000s)	2017			2016			2017			2016		2017			2016
Revenue
Petroleum and natural gas sales, net of royalties	36,419			19,786			4,020			—		40,439			19,786
Total segmented revenue	36,419			19,786			4,020			—		40,439			19,786
Segmented expenses
Production and operating	13,556			10,640			1,367			—		14,923			10,640
Transportation costs	—			—			156			—		156			—
Selling costs	1,502			47			—			—		1,502			47
General and administrative	1,082			1,531			315			—		1,397			1,531
Finance costs	1,406			331			311			—		1,717			331
Depletion, depreciation and amortization	8,094			7,961			2,208			—		10,302			7,961
Asset retirement obligation accretion	—			—			57			—		57			—
Realized derivative (gain) loss on commodity contracts	(1,529		)	698			—			—		(1,529		)	698
Unrealized derivative (gain) loss on commodity contracts	(6,578		)	—			—			—		(6,578		)	—
Income taxes - current	5,505			3,495			—			—		5,505			3,495
Income taxes - deferred	—			(812		)	—			—		—			(812		)
Impairment of exploration and evaluation assets	67,520			—			—			—		67,520			—
Total segmented expenses	90,558			23,891			4,414			—		94,972			23,891
Segmented earnings (loss)	$	(54,139	)	$	(4,105	)	$	(394	)	$	—	$	(54,533	)	(4,105		)
Non-segmented expenses (income)
Exploration												—			—
General and administrative												1,965			2,594
Foreign exchange (gain) loss												82			(45		)
Depreciation and amortization												61			122
Unrealized (gain) loss on financial instruments												—			4,286
Finance revenue												(19		)	(137		)
Finance costs												—			1,125
Total non-segmented expenses												2,089			7,945
Net earnings (loss) for the year												$	(56,622	)	$	(12,050	)
Capital expenditures
Exploration and development	7,927			4,837			276			—		8,203			4,837
Corporate												27			—
Total capital expenditures												$	8,230		$	4,837

38 Q2-2017

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

June 30, 2017
(000s)	Egypt		Canada		Total
Assets
Accounts receivable	$	39,281	$	2,195	$	41,476
Derivative commodity contracts	2,849				2,849
Intangible exploration and evaluation assets	49,002		—		49,002
Property and equipment
Petroleum and natural gas assets	131,971		67,290		199,261
Other assets	2,568		—		2,568
Other	18,178		4,121		22,299
Segmented assets	243,849		73,606		317,455
Non-segmented assets					20,141
Total assets					$	337,596
Liabilities
Accounts payable and accrued liabilities	$	16,097	$	2,248	$	18,345
Long-term debt	73,631		10,094		83,725
Asset retirement obligation	—		12,829		12,829
Segmented liabilities	89,728		25,171		114,899
Non-segmented liabilities					7,109
Total liabilities					$	122,008

December 31, 2016
(000s)	Egypt		Canada		Total
Assets
Accounts receivable	$	13,654	$	620	$	14,274
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	22,101		—		22,101
Segmented assets	283,166		71,890		355,056
Non-segmented assets					51,086
Total assets					$	406,142
Liabilities
Accounts payable and accrued liabilities	$	14,005	$	432	$	14,437
Current and long-term note payable	—		11,162		11,162
Asset retirement obligation	—		12,099		12,099
Segmented liabilities	14,005		23,693		37,698
Non-segmented liabilities					83,128
Total liabilities					$	120,826

Q2-2017 39

20. SUPPLEMENTAL CASH FLOW INFORMATION

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

	Three Months Ended June 30						Six months ended June 30
(000s)	2017			2016			2017			2016
Operating activities
(Increase) decrease in current assets
Accounts receivable	$	(20,068	)	$	6,776		$	(27,074	)	$	7,303
Prepaids and other	(146		)	518			(278		)	1,059
Product inventory1	3,506			(79		)	2,036			1,744
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	(2,900		)	(3,230		)	709			(1,865		)
	$	(19,608	)	$	3,985		$	(24,607	)	$	8,241
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	(2,436		)	1,117		516		2,331
	$	(2,436	)	$	1,117	$	516	$	2,331

40 Q2-2017

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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