Exhibit

EX-2 3 a2018q-3interimreport.htm EXHIBIT 2 Exhibit





2018 THIRD QUARTER INTERIM REPORT

Financial and Operating Results
For the three and nine months ended September 30, 2018
All dollar values are expressed in United States dollars unless otherwise stated



ø		Production for the nine months ended September 30, 2018 averaged 14,161 boepd (Egypt 11,876 bopd, Canada 2,285 boepd). Third quarter production averaged 14,331 boepd (Egypt 11,939 bopd, Canada 2,392 boepd). The Company expects to be within the full year production guidance range of 14,200 to 14,800 boepd by the end of 2018;

ø		Sales averaged 14,490 boepd with one cargo lifting of TransGlobe's entitlement crude oil occurring in July for net proceeds totaling $31.7 million (sale proceeds collected in August);

ø		Positive third quarter funds flow of $17.0 million ($0.24 per share). Third quarter net loss of $12.3 million, inclusive of a $14.1 million impairment loss and $3.3 million unrealized loss on derivative commodity contracts;

ø		Ended the third quarter with positive working capital of $52.4 million, including cash and cash equivalents of $62.7 million. The Company expects to fund its remaining 2018 capital program, continue debt repayments and explore business development opportunities with its working capital;

ø		Spent $12.8 million on exploration and development assets during the quarter;

ø		Drilled 4 wells in Egypt (2 exploration and 2 development), resulting in 2 dry holes (SGZ 1X and NWS 12X) and 2 oil wells (M-North and M-South);

ø		Subsequent to the quarter, the Company drilled and cased the South Ghazalat (SGZ 6X) exploration well as a potential Bahariya (Cretaceous) light oil discovery which encountered an internally estimated 22 feet of total net oil pay in the Upper and Lower Bahariya. The Company expects to complete testing this well in Q4-2018;

ø		Commenced the 2018 Cardium development drilling program with three gross (2.5 net) one-mile horizontal wells drilled and cased. The two-mile extended reach horizontal well was spud on September 30, 2018 and cased subsequent to the quarter. The remaining two gross (1.5 net) one-mile horizontal wells will be drilled and cased in Q4 2018. Plans for a one-mile horizontal outpost well to evaluate the newly acquired lands south of the Harmattan Cardium pool have been deferred;

ø		Paid a dividend of $0.035 per share on September 14, 2018 to shareholders of record on August 31, 2018.

A conference call to discuss TransGlobe's 2018 third quarter results as presented was held on Thursday, November 8, 2018 and can be accessed on the Company's website at http://www.trans-globe.com/investors/presentations-and-events/index.php

www.trans-globe.com

TSX & AIM: TGL NASDAQ: TGA

CONTENTS



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



2		Q3-2018

FINANCIAL AND OPERATING RESULTS

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



	Three Months Ended September 30					Nine Months Ended September 30
Financial	2018		2017		% Change	2018		2017		% Change
Petroleum and natural gas sales	74,345		68,372		9	226,516		179,637		26
Petroleum and natural gas sales, net of royalties	42,453		44,839		(5)	135,622		107,739		26
Realized derivative loss on commodity contracts	(2,430	)	(1,904	)	28	(8,329	)	(375	)	2,121
Unrealized derivative loss on commodity contracts	(3,295	)	(3,235	)	2	(20,157	)	(386	)	5,122
Production and operating expense	12,242		14,522		(16)	40,182		39,922		1
Selling costs	527		424		24	1,653		1,926		(14)
General and administrative expense	5,104		3,809		34	16,683		11,617		44
Depletion, depreciation and amortization expense	8,751		10,760		(19)	26,077		29,635		(12)
Income taxes expense	6,924		5,179		34	19,728		16,104		23
Cash flow generated by operating activities	47,639		20,437		133	59,370		15,187		291
Funds flow from operations¹	17,018		19,217		(11)	54,440		38,574		41
Basic per share	0.24		0.27			0.75		0.53
Diluted per share	0.23		0.27			0.75		0.53
Net loss	(12,283	)	(6,855	)	79	(15,042	)	(76,354	)	(80)
Basic per share	(0.17	)	(0.09	)		(0.21	)	(1.06	)
Diluted per share	(0.17	)	(0.09	)		(0.21	)	(1.06	)
Capital expenditures	12,783		10,133		26	23,273		29,081		(20)
Working capital	52,351		58,815		(11)	52,351		58,815		(11)
Long-term debt, including current portion	52,532		79,839		(34)	52,532		79,839		(34)
Common shares outstanding
Basic (weighted average)	72,206		72,206		—	72,206		72,206		—
Diluted (weighted average)	73,951		72,206		2	73,124		72,206		1
Total assets	314,203		338,802		(7)	314,203		338,802		(7)

Operating
Average production volumes (boepd)	14,331		14,912		(4)	14,161		16,029		(12)
Average sales volumes (boepd)	14,490		18,020		(20)	15,191		17,050		(11)
Inventory (mbbls)	496		988		(50)	496		988		(50)
Average sales price ($ per boe)	55.77		41.24		35	54.62		38.59		42
Operating expense ($ per boe)	9.18		8.76		5	9.69		8.58		13
¹ Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies.



Q3-2018		3

CORPORATE SUMMARY

TransGlobe Energy Corporation ("TransGlobe" or the "Company") produced an average of 14,331 barrels of oil equivalent per day ("boepd") during the third quarter of 2018. Egypt production was 11,939 barrels of oil per day ("bopd") and Canada production was 2,392 boepd. Production for the quarter was within the full-year 2018 guidance of 14,200 and 14,800 boepd and 4% higher than the previous quarter.

During the quarter, the Company completed one cargo lifting of 502 thousand barrels of entitlement crude oil for net proceeds of $31.7 million. TransGlobe did not sell any crude oil to EGPC during the quarter. As at September 30, 2018 the Company had approximately 496 thousand barrels of inventoried entitlement crude oil. All Canadian production was sold during the quarter.

TransGlobe's Egyptian crude oil is sold at a quality discount to Dated Brent. The Company received an average price of $61.87 per barrel during the quarter. In Canada, the Company received an average of $60.02 per barrel of oil and $1.01 per thousand cubic feet ("mcf") of natural gas in the third quarter of 2018.

During the third quarter of 2018, the Company had funds flow from operations of $17.0 million and ended the quarter with positive working capital of $52.4 million, including cash and cash equivalents of $62.7 million. The Company experienced a net loss in the quarter of $12.3 million, which included a $14.1 million non-cash impairment loss on the Company's exploration and evaluation assets in North West Sitra and a $3.3 million unrealized derivative loss on commodity contracts. The $3.3 million unrealized loss on derivative commodity contracts represents a fair value adjustment on the Company's hedging contracts as at September 30, 2018.

In the Eastern Desert, the Company drilled two development wells during the third quarter of 2018. At West Bakr, the Company completed a two well infill program (M-North and M-South) resulting in two oil wells. The M-North well was drilled to a total depth of 5,113 feet, encountered an internally estimated 132 feet of net oil pay, and is currently producing ~800 bopd. The M-South well was drilled to a total depth of 5,077 feet, encountered an internally estimated 142 feet of net oil pay, and is currently producing at ~800 bopd. Both of these wells have exceeded internal pre-drill estimates. At North West Gharib, the Company put the NWG 38A-Inj injector well onto production with an initial rate of ~110 bopd. The Company commenced drilling NWG 38A-7 (a potential water injector well) during the third quarter of 2018, targeting the 38A Red Bed pool in a structurally lower position 0.4 kilometers south of the NWG 38A-Inj injector well. The well is scheduled for completion in November.

In the Western Desert, the Company drilled two exploration wells during the third quarter of 2018. At South Ghazalat, the Company drilled the first of two planned exploration wells (SGZ 1X), in the south western portion of the concession, to a total depth of 3,068 feet with no hydrocarbon shows and abandoned for a total cost of ~$0.7 million. Subsequent to the quarter, the Company drilled the second of two planned exploration wells in South Ghazalat (SGZ 6X) to a depth of 5,195 feet. This well was cased as a potential oil discovery and encountered an internally estimated 22 feet of total net oil pay over three intervals in the targeted Bahariya formation. The Company has mobilized testing equipment and it is anticipated that testing results will be announced prior to month end. With the drilling of the second exploration well, the Company will have met all of the commitments for this concession.

At North West Sitra, the Company completed drilling the second of two planned exploration wells (NWS 12X) targeting a stacked Cretaceous/Jurassic prospect. The well was drilled to a total depth of 13,300 feet with no signs of hydrocarbons and was abandoned for a total cost of ~$4.0 million. With the completion of NWS 12X, the Company has now met the commitments for this concession. The Company does not plan to enter the second phase of the exploration concession.

At South Alamein, the Company received notification from the military that access would be granted for up to four locations submitted earlier in 2018, including the SA 24X-well. The Company submitted the required documentation and received written notice that only two of four locations were approved. The SA 24X location was rejected. In Q2-2018 the Company received a seven-month extension to the final exploration phase, which is set to expire January 26, 2019. The Company plans to engage EGPC to discuss potential solutions including concession extensions and/or suspending the exploration term until access issues are resolved.

In Canada, the Company commenced the 2018 Cardium development drilling program with three gross (2.5 net) one-mile horizontal wells drilled and cased in the third quarter. The Company began drilling the two-mile extended reach horizontal well on September 30, 2018. Subsequent to the quarter, the Company completed drilling the six well development program.

Due to the recent widening of the Canadian light oil differential to WTI, the Company has decided to defer its plans to drill a one-mile horizontal outpost well to evaluate the newly acquired Cardium lands until 2019.

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



4		Q3-2018

OPERATIONS UPDATE

ARAB REPUBLIC OF EGYPT

EASTERN DESERT

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

Operations and Exploration

No new wells were drilled during the quarter.

Production

Production from West Gharib averaged 4,793 bopd to TransGlobe during the third quarter of 2018, a 4% (223 bopd) decrease from the previous quarter, primarily due to natural declines.

Production averaged 4,271 bopd during October. October production was lower due to well servicing and natural declines.

Sales

The Company sold 205,913 barrels of inventoried entitlement crude to a third-party for $13.1 million in Q3-2018.



Quarterly West Gharib Production (bopd)	2018					2017
	Q-3		Q-2		Q-1	Q-4
Gross production rate	4,793		5,015		5,104	5,015
TransGlobe production (inventoried) sold	(206	)	(297	)	21	(774	)
Total sales	4,587		4,718		5,125	4,241

Government share (royalties and tax)	2,349		2,459		2,504	2,459
TransGlobe sales (after royalties and tax)¹	2,238		2,259		2,621	1,782
Total sales	4,587		4,718		5,125	4,241
¹ Under the terms of the W 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 third quarter of 2018, the Company drilled a two well infill program (M-North and M-South) resulting in two oil wells. The M-North well was drilled to a total depth of 5,113 feet, encountered an internally estimated 132 feet of net oil pay, and is currently producing ~800 bopd. The M-South well was drilled to a total depth of 5,077 feet, encountered an internally estimated 142 feet of net oil pay, and is currently producing at ~800 bopd. Both of these wells have exceeded internal pre-drill estimates.

During the quarter, the Company completed construction of the Phase 2 H-field facility expansion to double the fluid handling capacity from 10,000 bpd to 20,000 bpd of fluid. The Company initiated a well optimization campaign targeting wells with excess production capacity that had been constrained due to fluid handling at the K and H stations prior to the respective Phase 2 facility expansion projects. The accelerated fluid withdrawal rates will support incremental production volumes and additional reserves from the K and M fields in K station, and the H fields in H station.

Construction will commence in early 2019 on the K station Phase 3 expansion to add a third process train and triple the original fluid handling capacity to ~45,000 bpd. It is expected that the K station Phase 3 expansion will be commissioned mid 2019.

Production

Production from West Bakr averaged 6,126 bopd to TransGlobe during the third quarter, representing a 7% (379 bopd) increase from the previous quarter due to the well optimization program and successful M-North and M-South development wells.

Production averaged 6,972 bopd during October. The October production increase is primarily attributable to the new M field wells and continued well optimization.



Q3-2018		5

Sales

The Company sold 71,793 barrels of inventoried entitlement crude to a third party for $4.6M million in Q3-2018.



Quarterly West Bakr Production (bopd)	2018					2017
	Q-3		Q-2	Q-1		Q-4
Gross production rate	6,126		5,747	5,274		5,024
TransGlobe production (inventoried) sold	(1,700	)	6,235	(2,136	)	3,511
Total sales	4,426		11,982	3,138		8,535

Government share (royalties and tax)	3,646		3,419	3,138		2,990
TransGlobe sales (after royalties and tax)¹	780		8,563	—		5,545
Total sales	4,426		11,982	3,138		8,535
¹ Under the terms of the W Bakr Production Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing oil.

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

Operations and Exploration

During the third quarter of 2018, the NWG 38A-Inj injector well was put on production with an initial rate of ~110 bopd (following fracture stimulation) and is currently producing ~80 bopd. The Company commenced drilling the NWG 38A-7 well as a potential water injector targeting the 38A Red Bed pool in a structurally lower position 0.4 kilometers south of the NWG 38A-Inj injector well. The NWG 38A-7 well encountered the Red Bed formation which appears to contain both oil and water, however, the well was cased due to deteriorating wellbore conditions prior to acquiring definitive fluid samples. The NWG 38A-7 well will be completed during November and depending on the production results will be another oil producer or converted to a water injection well to support the NWG 38A oil pool. In the event NWG 38A-7 is an oil producer, the Company has planned an additional well (NWG 38A-8) further south as a contingency for reservoir pressure support.

Production

Production from NW Gharib averaged 1,020 bopd to TransGlobe during the third quarter, an 11% (131 bopd) decrease from the previous quarter, primarily due to natural declines.

Production averaged 1,074 bopd during October.

Sales

The Company sold 224,028 barrels of inventoried entitlement crude to a third party for $14.3 million in Q3-2018.



Quarterly North West Gharib Production (bopd)	2018					2017
	Q-3	Q-2		Q-1		Q-4
Gross production rate	1,020	1,151		1,399		1,212
TransGlobe production (inventoried) sold	2,065	(417	)	(507	)	(439	)
Total sales	3,085	734		892		773

Government share (royalties and tax)	650	734		892		773
TransGlobe sales (after royalties and tax)¹	2,435	—		—		—
Total sales	3,085	734		892		773
¹ Under the terms of the NW Gharib Production Sharing Concession, royalties and taxes are paid out of the Government's share of production sharing oil.

WESTERN DESERT

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

Operations and Exploration

No wells were drilled during the quarter.

In South Alamein the Company received notification from the military that access would be granted for up to four locations submitted earlier in 2018, including the SA 24X-well. The Company submitted the required documentation and subsequently received written notice that only two of four locations were approved. The SA 24X location was rejected. In Q2-2018 the Company received a seven-month extension to the final exploration phase, which is set to expire January 26, 2019. The Company plans to engage EGPC to discuss potential solutions including concession extensions and/or suspending the exploration term until access issues are resolved.

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



6		Q3-2018

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

Operations and Exploration

During the quarter, the Company drilled the second of two planned exploration wells in North West Sitra (“NWS”) at NWS 12X targeting a stacked Cretaceous/Jurassic prospect. The well was drilled to a total depth of 13,300 feet with no signs of hydrocarbons and was abandoned for a total cost of ~$4.0 million.

With the completion of NWS 12X, the Company has now met all of the work commitments for the first exploration phase of the concession.

Prior to January 7, 2019 (the expiration date of the first exploration phase) the Company can elect to enter the second and final exploration phase (3.0 years after the extension of phase one). Based on a review of the well results, the Company elected to book an impairment during the third quarter for all North West Sitra exploration and evaluation assets and does not plan to enter the second phase of the exploration concession.

No production was budgeted from the North West Sitra exploration assets in 2018.

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

Operations and Exploration

During the quarter, the Company drilled the first of two planned exploration wells in the south western portion of the South Ghazalat concession (“SGZ”). SGZ 1X was drilled to a total depth of 3,068 feet with no hydrocarbon shows and abandoned for a total cost of ~$0.7 million. Based on the SGZ 1X results, the planned SGZ 2X well was cancelled in favour of an alternate exploration prospect (SGZ 6X) located on the eastern portion of the concession offsetting the Raml oil field in the Abu Gharadig basin.

Subsequent to the quarter, the Company drilled the SGZ 6X exploration well to a total depth of 5,195 feet. This well was cased as a potential Bahariya light oil discovery. Based on open hole logs and oil recovered on MDT wireline sampling, the well encountered an internally estimated 22 feet of total net oil pay over three intervals in the targeted Bahariya formation. The Company has mobilized testing equipment and it is anticipated that testing results will be announced prior to month end. Concurrently the Company requested and received a 6 month extension to May 6, 2019 for the current exploration phase.

With the completion of the second exploration well, the Company will have met the commitments for the concession.

No production is currently budgeted from the South Ghazalat exploration assets in 2018.

CANADA

Operations and Exploration

During the quarter, the Company drilled and cased the first three gross (2.5 net) one-mile horizontal wells of the six wells planned from a common pad.

Subsequent to the quarter, the Company completed drilling and cased the remaining three wells in the program including a two-mile extended reach horizontal well and two gross (1.5 net) one-mile horizontal. The Company is targeting to complete the wells during the fourth quarter, with first production from the multi-well pad by year-end/early January. In addition, the Company has elected to defer a one-mile horizontal outpost well planned to evaluate the newly acquired lands, 16 net sections (10,240 acres).

Production

Production from Canada averaged 2,392 boepd to TransGlobe during the third quarter, a 28% (525 boepd) increase from the previous quarter which was primarily due to lower production in the second quarter associated with a planned shut-in during May.

Production has averaged 2,387 boepd during October.



Quarterly Canada Production (boepd)	2018			2017
	Q-3	Q-2	Q-1	Q-4
Canada crude oil (bbls/d)	567	497	675	775
Canada NGLs (bbls/d)	876	521	894	915
Canada natural gas (mcf/d)	5,695	5,094	6,176	6,058
Total production (boe/d)	2,392	1,867	2,598	2,700



Q3-2018		7

MANAGEMENT'S DISCUSSION AND ANALYSIS

November 6, 2018

The following discussion and analysis is management’s opinion of TransGlobe’s historical financial and operating results and should be read in conjunction with the unaudited Condensed Consolidated Interim Financial Statements of the Company for the three and nine months ended September 30, 2018 and 2017, and the audited Consolidated Financial Statements and Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2017 included in the Company's annual report. The Condensed Consolidated Interim Financial Statements were prepared in accordance with International Accounting Standard 34, Interim Financial Reporting using accounting policies consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board in the currency of the United States, except where otherwise noted. Additional information relating to the Company, including the Company’s Annual Information Form, is on SEDAR at www.sedar.com. The Company’s annual report on Form 40-F may be found on EDGAR at www.sec.gov.

READER ADVISORIES

Forward-Looking Statements

Certain statements or information contained herein may constitute forward-looking statements or information under applicable securities laws, including, but not limited to, management’s assessment of future plans and operations, anticipated changes to TransGlobe Energy Corporation's ("TransGlobe" or the "Company") reserves and production, timing of directly marketed crude oil sales, drilling plans and the timing thereof, commodity price risk management strategies, adapting to the current political situation in Egypt, reserves estimates, management’s expectation for results of operations for 2018, including expected 2018 average production, funds flow from operations, the 2018 capital program for exploration and development, the timing and method of financing thereof, collection of accounts receivable from the Egyptian Government, the terms of drilling commitments under the Egyptian Production Sharing Agreements and Production Sharing Concessions (collectively defined as "PSCs") and the method of funding such drilling commitments, the Company's beliefs regarding the reserves and production growth of its assets and the ability to grow with a stable production base, and commodity prices and expected volatility thereof. Statements relating to "reserves" are deemed to be forward‑looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

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

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

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

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

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



8		Q3-2018

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

Mr. Brett Norris, M.Sc., P Geo, - Vice President Exploration for TransGlobe Energy Corporation, and a qualified person as defined in the Guidance Note for Mining, Oil and Gas Companies, June 2009, of the London Stock Exchange, has reviewed and approved the technical information contained in this report. Mr. Norris obtained a Master’s of Science Degree in Geology from the University of Western Ontario. He is a Registered Professional Geoscientist in the province of Alberta and has over 30 years’ experience in oil and gas.

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

MANAGEMENT STRATEGY AND OUTLOOK

The 2018 outlook provides information as to management’s expectation for results of operations for 2018. Readers are cautioned that the 2018 outlook may not be appropriate for other purposes. The Company’s expected results are sensitive to fluctuations in the business environment, including disruptions caused by the ongoing political changes and civil unrest occurring in the jurisdictions that the Company operates in, and may vary accordingly. This outlook contains forward-looking statements that should be read in conjunction with the Company’s disclosure under “Forward-Looking Statements”, outlined on the first page of this Management's Discussion & Analysis ("MD&A").

2018 Outlook

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

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

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

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

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



Netback sensitivity
Benchmark crude oil price (US$/bbl)	40		50	60	70	80
Benchmark natural gas price (C$/mcf)	0.95		1.15	1.35	1.55	1.75

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

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

NON-GAAP FINANCIAL MEASURES

Funds flow from operations

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



Q3-2018		9

Reconciliation of funds flow from operations



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

Net debt-to-funds flow from operations ratio

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

Netback

Netback is a measure of operating results and is computed as sales net of royalties (all government interests, net of income taxes), operating expenses, current taxes and selling costs. The Company's netbacks include sales and associated costs of production from inventoried crude oil sold during the period. Royalties and taxes associated with inventoried crude are recognized at production. Netbacks fluctuate depending on the timing of entitlement oil sales. Management believes that netback is a useful supplemental measure to analyze operating performance and provide an indication of the results generated by the Company’s principal business activities prior to the consideration of other income and expenses. Netback does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

TRANSGLOBE’S BUSINESS

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



10		Q3-2018

SELECTED QUARTERLY FINANCIAL INFORMATION



	2018					2017								2016
($000s, except per share,
price and volume amounts)	Q-3		Q-2	Q-1		Q-4		Q-3		Q-2		Q-1		Q-4³
Operations
Average production volumes
Crude oil (bbls/d)	12,506		12,409	12,452		12,027		12,786		14,347		14,514		12,861
NGLs (bbls/d)	876		521	894		915		1,081		919		1,037		134
Natural gas (mcf/d)	5,695		5,094	6,176		6,059		6,268		7,191		7,075		916
Total (boe/d)	14,331		13,779	14,375		13,952		14,912		16,465		16,731		13,148
Average sales volumes
Crude oil (bbls/d)	12,665		17,931	9,830		14,324		15,894		17,141		11,610		7,018
NGLs (bbls/d)	876		521	894		915		1,081		919		1,037		134
Natural gas (mcf/d)	5,695		5,094	6,176		6,059		6,286		7,191		7,075		916
Total (boe/d)	14,490		19,301	11,753		16,249		18,020		19,259		13,826		7,305
Average realized sales prices
Crude oil ($/bbl)	61.79		59.39	56.26		53.25		44.82		39.46		41.66		37.38
NGLs ($/bbl)	22.64		38.39	27.72		26.86		18.90		21.08		19.08		12.33
Natural gas ($/mcf)	1.01		1.08	1.70		0.94		1.65		2.14		1.96		1.80
Total oil equivalent ($/boe)	55.77		56.49	50.06		48.80		41.24		36.92		37.41		36.45
Inventory (mbbls)	496		510	1,013		777		988		1,274		1,528		1,265
Petroleum and natural gas sales	74,345		99,220	52,951		72,954		68,372		64,712		46,553		24,501
Petroleum and natural gas sales, net of royalties	42,453		68,454	24,715		40,725		44,839		40,439		22,461		5,217
Cash flow from operating activities	47,639		18,886	(7,155	)	44,263		20,437		(2,753	)	(2,497	)	6,355
Funds flow from operations¹	17,018		33,499	3,923		17,018		19,217		16,855		2,502		(9,904	)
Funds flow from operations per share:
- Basic	0.24		0.46	0.05		0.24		0.27		0.23		0.03		(0.14	)
- Diluted	0.23		0.46	0.05		0.24		0.27		0.23		0.03		(0.14	)
Net earnings (loss)	(12,283	)	7,361	(10,120	)	(2,382	)	(6,855	)	(56,622	)	(12,877	)	(33,997	)
Net earnings (loss) per share:
- Basic	(0.17	)	0.10	(0.14	)	(0.03	)	(0.09	)	(0.78	)	(0.18	)	(0.47	)
- Diluted	(0.17	)	0.10	(0.14	)	(0.03	)	(0.09	)	(0.78	)	(0.18	)	(0.49	)
Capital expenditures	12,783		5,855	4,635		9,078		10,133		8,230		10,718		8,863
Property expenditures	—		—	—		—		—		—		—		59,475

Total assets	314,203		329,542	312,691		327,702		338,802		337,596		403,686		406,142
Cash and cash equivalents	62,663		38,088	31,084		47,449		21,464		13,780		21,324		31,468
Working capital	52,351		60,464	45,252		50,639		58,815		60,319		42,759		(16,764	)
Convertible debentures	—		—	—		—		—		—		—		72,655
Note payable	—		—	—		—		—		—		11,259		11,162
Total long-term debt, including current portion	52,532		62,173	67,167		69,999		79,839		83,725		73,549		—
Net debt-to-funds flow from operations ratio²	1.20		0.02	0.36		0.30		0.70		2.00		(13.90	)	(12.00	)
¹ Funds flow from operations (before finance costs) is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
² Net debt-to-funds flow from operations ratio is a measure that represents total long-term debt (including the current portion) plus convertible debentures and working capital over funds flow from operations from the trailing 12 months and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
³ The Q4-2016 information includes the results of the operations of the Harmattan assets in Alberta, Canada from December 20, 2016 to December 31, 2016 (12 days). The Harmattan assets were acquired in a transaction that closed on December 20, 2016 (effective December 1, 2016).

During the third quarter of 2018, TransGlobe:


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


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


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


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


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



Q3-2018		11


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


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


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

2018 TO 2017 NET EARNINGS VARIANCES



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

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

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



12		Q3-2018

BUSINESS ENVIRONMENT

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



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

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

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

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

OPERATING RESULTS AND NETBACK

Daily volumes, working interest before royalties (boepd)



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



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



Q3-2018		13

Netback



Consolidated Netback
	Nine Months Ended September 30
	2018		2017
(000s, except per boe amounts)¹	$	$/boe	$	$/boe
Petroleum and natural gas sales	226,516	54.62	179,637	38.59
Royalties and other²	90,894	21.92	71,898	15.45
Current taxes²	19,728	4.76	16,104	3.46
Production and operating expenses	40,182	9.69	39,922	8.58
Selling costs	1,653	0.40	1,926	0.41
Netback	74,059	17.85	49,787	10.69
¹ The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended September 30, 2018 and September 30, 2017 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at September 30, 2018).
² Royalties and taxes are settled at the time of production. Fluctuations in royalty and tax costs per bbl are due to timing differences between the production and sale of the Company's entitlement crude.



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



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



Egypt
	Three Months Ended September 30
	2018		2017
(000s, except per bbl amounts)¹	$	$/bbl	$	$/bbl
Oil sales	68,861	61.87	63,403	44.82
Royalties²	31,278	28.10	22,506	15.91
Current taxes²	6,924	6.22	5,179	3.66
Production and operating expenses	10,677	9.59	13,242	9.36
Selling costs	527	0.47	425	0.30
Netback	19,455	17.49	22,051	15.59
¹ The Company achieved the netbacks above on sold barrels of oil equivalent for the periods ended September 30, 2018 and September 30, 2017 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at September 30, 2018).
² Royalties and taxes are settled at the time of production. Fluctuations in royalty and tax costs per bbl are due to timing differences between the production and sale of the Company's entitlement crude.

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



14		Q3-2018

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

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

Royalties and taxes as a percentage of revenue were 55% and 52%, in the three and nine month periods ended September 30, 2018, respectively, compared to 44% and 52% for the same periods in 2017. Royalties and taxes are settled on a production basis, therefore, the correlation of royalties and taxes to oil sales fluctuates depending on the timing of entitlement oil sales. If sales volumes had been equal to production volumes during the three and nine month periods ended September 30, 2018, royalties and taxes as a percentage of revenue would have been 56% and 56%, respectively (2017 - 58% and 54%). In periods when the Company sells less than its entitlement production, royalties and taxes as a percentage of revenue will be higher than the terms of the PSCs dictate. In periods when the Company sells more than its entitlement production, royalties and taxes as a percentage of revenue will be lower than the terms of the PSCs dictate.

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



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



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

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

TransGlobe pays royalties to the Alberta provincial government and landowners in accordance with the established royalty regime. In Alberta, Crown royalty rates are based on reference commodity prices, production levels and well depths, and are offset by certain incentive programs, which usually have a finite period of time and are in place to promote drilling activity by reducing overall royalty expense.



Q3-2018		15

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)



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



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

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

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

FINANCE COSTS



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

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

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

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

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

DEPLETION AND DEPRECIATION (“DD&A”)



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



16		Q3-2018



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

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

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

IMPAIRMENT LOSS

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

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

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

CAPITAL EXPENDITURES



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

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

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

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

OUTSTANDING SHARE DATA

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

LIQUIDITY AND CAPITAL RESOURCES

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

Funding for the Company’s capital expenditures was provided by funds flow from operations and cash on hand. The Company expects to fund its remaining 2018 exploration and development program through the use of working capital and funds flow from operations. The Company also expects to pay down debt and explore business development opportunities with its working capital. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks may impact capital resources and capital expenditures.



Q3-2018		17

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

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

Over the past 10 years, the Company experienced delays in the collection of accounts receivable from EGPC. The length of delay peaked in 2013, returned to historical (pre-2011) delays of up to four to six months in 2017, and has now decreased to a historical low. As at September 30, 2018, amounts owing from EGPC were $6.7 million. The Company considers there to be minimal credit risk associated with EGPC's delays.

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

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

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

PRODUCT INVENTORY

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



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

COMMITMENTS AND CONTINGENCIES

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



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



18		Q3-2018

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

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

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

ASSET RETIREMENT OBLIGATION

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

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

DERIVATIVE COMMODITY CONTRACTS

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

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

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



Q3-2018		19

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



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

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

CHANGE IN ACCOUNTING POLICIES

New accounting standards

IFRS 9 "Financial Instruments: Classification and Measurement"

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

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


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


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

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

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

IFRS 15 "Revenue from Contracts with Customers"

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

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

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

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



20		Q3-2018

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

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

Standards issued but not yet effective

IFRS 16 "Leases"

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

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

INTERNAL CONTROLS OVER 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 the IASB, focusing in particular on controls over information contained in the annual and interim financial statements. Due to its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements on a timely basis. A system of internal controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

No changes were made to the Company's internal control over financial reporting during the three months ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.



Q3-2018		21

Condensed Consolidated Interim Statements of Loss and Comprehensive Loss

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



		Three Months Ended						Nine Months Ended
		September 30						September 30
	Notes	2018			2017			2018			2017
REVENUE
Petroleum and natural gas sales, net of royalties	17	$	42,453		$	44,839		$	135,622		$	107,739
Finance revenue		180			15			399			59
		42,633			44,854			136,021			107,798

EXPENSES
Production and operating		12,242			14,522			40,182			39,922
Selling costs		527			424			1,653			1,926
General and administrative		5,104			3,809			16,683			11,617
Foreign exchange loss		216			3			195			70
Finance costs	5	1,222			1,485			3,923			4,750
Depletion, depreciation and amortization	9	8,751			10,760			26,077			29,635
Asset retirement obligation accretion	10	72			74			205			191
Loss on financial instruments	4	5,725			5,139			28,486			912
Impairment loss	8	14,138			10,314			14,138			79,025
Gain on disposition of assets		(5		)	—			(207		)	—
		47,992			46,530			131,335			168,048

Net earnings (loss) before income taxes		(5,359		)	(1,676		)	4,686			(60,250		)

Income tax expense – current		6,924			5,179			19,728			16,104
NET LOSS FOR THE PERIOD		$	(12,283	)	$	(6,855	)	$	(15,042	)	$	(76,354	)

OTHER COMPREHENSIVE INCOME (LOSS)
Currency translation adjustments		1,000			4,070			(679		)	3,455
COMPREHENSIVE LOSS FOR THE PERIOD		$	(11,283	)	$	(2,785	)	$	(15,721	)	$	(72,899	)

Net loss per share
Basic	15	$	(0.17	)	$	(0.09	)	$	(0.21	)	$	(1.06	)
Diluted	15	$	(0.17	)	$	(0.09	)	$	(0.21	)	$	(1.06	)

See accompanying notes to the Condensed Consolidated Interim Financial Statements



22		Q3-2018

Condensed Consolidated Interim Balance Sheets

(Unaudited - Expressed in thousands of US Dollars)



		As at		As at
	Notes	September 30, 2018		December 31, 2017
ASSETS
Current
Cash and cash equivalents	6	$	62,663	$	47,449
Accounts receivable	4	10,932		18,090
Prepaids and other		3,862		4,745
Product inventory	7	7,799		11,474
		85,256		81,758
Non-Current
Intangible exploration and evaluation assets	8	34,376		41,478
Property and equipment
Petroleum and natural gas assets	9	191,444		200,981
Other assets	9	3,127		3,485
		$	314,203	$	327,702

LIABILITIES
Current
Accounts payable and accrued liabilities		$	28,488	$	27,104
Derivative commodity contracts	4	4,417		4,015
		32,905		31,119
Non-Current
Derivative commodity contracts	4	23,707		3,955
Long-term debt	11	52,532		69,999
Asset retirement obligation	10	11,322		12,332
Other long-term liabilities		1,315		290
		121,781		117,695

SHAREHOLDERS’ EQUITY
Share capital	13	152,084		152,084
Accumulated other comprehensive income		2,114		2,793
Contributed surplus		23,992		23,329
Retained earnings		14,232		31,801
		192,422		210,007
		$	314,203	$	327,702

Commitments and Contingencies (Note 12)

See accompanying notes to the Condensed Consolidated Interim Financial Statements

Approved on behalf of the Board:

Signed by:



“Ross G. Clarkson”	“Steven Sinclair”

Ross G. Clarkson	Steven Sinclair
CEO	Director
Director



Q3-2018		23

Condensed Consolidated Interim Statements of Changes in Shareholders’ Equity

(Unaudited - Expressed in thousands of US Dollars)



		Three Months Ended						Nine Months Ended
		September 30						September 30
	Notes	2018			2017			2018			2017

Share Capital
Balance, beginning of period	13	$	152,084		$	152,084		$	152,084		$	152,084
Balance, end of period		$	152,084		$	152,084		$	152,084		$	152,084

Accumulated Other Comprehensive Income (Loss)
Balance, beginning of period		$	1,114		$	(615	)	$	2,793		$	—
Currency translation adjustment		1,000			4,070			(679		)	3,455
Balance, end of period		$	2,114		$	3,455		$	2,114		$	3,455

Contributed Surplus
Balance, beginning of period		23,828			23,081			23,329			22,695
Share-based compensation expense	14	164			164			663			550
Balance, end of period		$	23,992		$	23,245		$	23,992		$	23,245

Retained Earnings
Balance, beginning of period		$	29,042		$	41,038		$	31,801		$	110,537
Net loss		(12,283		)	(6,855		)	(15,042		)	(76,354		)
Dividends	16	(2,527		)	—			(2,527		)	—
Balance, end of period		$	14,232		$	34,183		$	14,232		$	34,183

See accompanying notes to the Condensed Consolidated Interim Financial Statements



24		Q3-2018

Condensed Consolidated Interim Statements of Cash Flows

(Unaudited - Expressed in thousands of US Dollars)



		Three Months Ended						Nine Months Ended
		September 30						September 30
	Notes	2018			2017			2018			2017
CASH FLOWS RELATED TO THE FOLLOWING ACTIVITIES:

OPERATING
Net loss		$	(12,283	)	$	(6,855	)	$	(15,042	)	$	(76,354	)
Adjustments for:
Depletion, depreciation and amortization	9	8,751			10,760			26,077			29,635
Asset retirement obligation accretion	10	72			74			205			191
Deferred lease inducement		(23		)	(22		)	(68		)	(65		)
Impairment loss		14,138			10,314			14,138			79,025
Share-based compensation	14	1,624			236			5,309			886
Finance costs	5	1,222			1,485			3,923			4,750
Unrealized loss on financial instruments	4	3,295			3,235			20,157			537
Unrealized loss on foreign currency translation		227			(10		)	205			(31		)
Gain on asset dispositions		(5		)	—			(207		)	—
Asset retirement obligations settled	10	—			—			(257		)	—
Changes in non-cash working capital	18	30,621			1,220			4,930			(23,387		)
Net cash generated by operating activities		47,639			20,437			59,370			15,187

INVESTING
Additions to intangible exploration and evaluation assets	8	(5,455		)	(2,257		)	(7,036		)	(16,372		)
Additions to petroleum and natural gas assets	9	(7,185		)	(7,678		)	(15,859		)	(12,151		)
Additions to other assets	9	(143		)	(198		)	(378		)	(558		)
Proceeds from asset dispositions		5			—			207			—
Changes in restricted cash		—			3,046			—			13,511
Changes in non-cash working capital	18	3,229			557			2,594			1,073
Net cash used in investing activities		(9,549		)	(6,530		)	(20,472		)	(14,497		)

FINANCING
Interest paid	5	(1,233		)	(1,426		)	(3,714		)	(7,008		)
Increase in long-term debt	11	146			125			395			85,265
Repayment of convertible debentures		—			—			—			(73,375		)
Repayments of long-term debt	11	(10,000		)	(5,000		)	(17,797		)	(16,041		)
Dividends paid	16	(2,527		)	—			(2,527		)	—
Changes in non-cash working capital	18	(3		)	—			(3		)	—
Net cash used in financing activities		(13,617		)	(6,301		)	(23,646		)	(11,159		)
Currency translation differences relating to cash and cash equivalents		102			78			(38		)	465
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		24,575			7,684			15,214			(10,004		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		38,088			13,780			47,449			31,468
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	62,663		$	21,464		$	62,663		$	21,464

See accompanying notes to the Condensed Consolidated Interim Financial Statements



Q3-2018		25

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

As at September 30, 2018 and December 31, 2017 and for the three and nine month periods ended September 30, 2018 and 2017

(Unaudited - Expressed in US Dollars)

1. CORPORATE INFORMATION

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

2. BASIS OF PREPARATION

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

These Condensed Consolidated Interim Financial Statements were authorized for issue by the Board of Directors on November 6, 2018.

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

3. CHANGES IN ACCOUNTING POLICIES

New accounting standards

IFRS 9 "Financial Instruments: Classification and Measurement"

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


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


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

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

IFRS 15 "Revenue from Contracts with Customers"



26		Q3-2018

measured at the fair value of the consideration received or receivable. For reporting purposes, the Company records the government’s share of production as royalties and taxes as all royalties and taxes are paid out of the government’s share of production.

Revenue segregated by product type and geographical market is disclosed in Note 17.

Standards issued but not yet effective

IFRS 16 "Leases"

4. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair values of financial instruments

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

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



	September 30, 2018		December 31, 2017
	Carrying	Fair	Carrying	Fair
Classification ($000s)	Value	Value	Value	Value
Financial assets at fair value through profit or loss	62,663	62,663	47,449	47,449
Financial assets at amortized cost	10,932	10,932	18,090	18,090
Financial liabilities at fair value through profit or loss	28,124	28,124	7,970	7,970
Financial liabilities at amortized cost	82,335	83,288	97,103	98,329

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

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

Derivative commodity contracts

The nature of TransGlobe’s operations exposes it to fluctuations in commodity prices, interest rates and foreign currency exchange rates. TransGlobe monitors and, when appropriate, uses derivative financial instruments to manage its exposure to these fluctuations. All transactions of this nature entered into by TransGlobe are related to an underlying financial position or to future crude oil and natural gas production. TransGlobe does not use derivative financial instruments for speculative purposes. TransGlobe has elected not to designate any of its derivative financial instruments as accounting hedges and thus accounts for changes in fair value in earnings at each reporting period. TransGlobe has not obtained collateral or other



Q3-2018		27

security to support its financial derivatives as management reviews the creditworthiness of its counterparties prior to entering into derivative contracts. The derivative financial instruments are initiated within the guidelines of the Company's corporate hedging policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions.

In conjunction with the prepayment agreement (see Note 11), TransGlobe has also entered into a marketing contract with Mercuria Energy Trading S.A. ("Mercuria") to market nine million barrels of TransGlobe's entitlement production. The pricing of the crude oil sales will be based on market prices at the time of sale.

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



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

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



	Three Months Ended September 30				Nine Months Ended September 30
(000s)	2018		2017		2018		2017
Realized derivative loss on commodity contracts settled during the period	$	2,430	$	1,904	$	8,329	$	375
Unrealized derivative loss on commodity contracts outstanding at period end	3,295		3,235		20,157		386
Unrealized loss on financial instruments	—		—		—		151
	$	5,725	$	5,139	$	28,486	$	912

Credit risk

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

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

Trade and other receivables are analyzed in the table below.



(000s)
Trade receivables	September 30, 2018		December 31, 2017
Neither impaired nor past due	$	2,443	$	10,534

Not impaired and past due in the following period:
Within 30 days	80		3,804
31-60 days	195		2,575
61-90 days	4,881		—
Over 90 days	3,333		1,177
	$	10,932	$	18,090

The Company sold one cargo of crude oil during the three months ended September 30, 2018. Depending on the Company's assessment of the credit of crude cargo buyers, they may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. During the first nine months of 2018, the Company sold 318,291 barrels of inventoried entitlement crude oil to EGPC for $17.9 million. The Company collected $24.6 million of accounts receivable from EGPC during the first nine months of 2018. As at September 30, 2018, $6.7 million (December 31, 2017 - $14.2 million) of the total accounts receivable balance of $10.9 million (January 1, 2018 - $18.1 million) is due from EGPC.



28		Q3-2018

5. FINANCE COSTS

Finance costs recognized in earnings were as follows:



	Three Months Ended September 30						Nine Months Ended September 30
(000s)	2018			2017			2018			2017
Interest on convertible debenture	$	—		$	—		$	—		$	1,089
Interest on long-term debt	1,018			1,276			3,320			2,731
Interest on note payable	—			—			—			532
Interest on borrowing base facility	118			115			331			164
Amortization of deferred financing costs	86			94			272			234
Finance costs	$	1,222		$	1,485		$	3,923		$	4,750
Interest paid	$	(1,233	)	$	(1,426	)	$	(3,714	)	$	(7,008	)

6. CASH AND CASH EQUIVALENTS



(000s)	September 30, 2018		December 31, 2017
Cash	$	17,213	$	46,051
Cash equivalents	45,450		1,398
	$	62,663	$	47,449

7. PRODUCT INVENTORY

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

As at September 30, 2018, the Company had 496 thousand barrels of entitlement oil in inventory valued at approximately $15.74 per barrel (December 31, 2017 - 777 thousand barrels valued at approximately $14.77 per barrel).

8. INTANGIBLE EXPLORATION AND EVALUATION ASSETS



(000s)
Balance at December 31, 2017	$	41,478
Additions	7,036
Impairment loss	(14,138		)
Balance at September 30, 2018	$	34,376

During the nine months ended September 30, 2018, the Company recorded an impairment loss of $14.1 million on its exploration and evaluation assets which is fully related to the North West Sitra concession. It was determined that an impairment loss was necessary as no commercially viable quantities of oil were discovered in this concession and no further drilling activities are planned. The recoverable amount of the North West Sitra cash-generating unit is $nil.

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

During the nine months ended September 30, 2018, the Company spent $5.3 million and $1.1 million on exploration and evaluation activities at North West Sitra and South Ghazalat, respectively. The ending balance of intangible exploration and evaluation assets as at September 30, 2018 includes $12.8 million in South Alamein (December 31, 2017 - $13.3 million), $21.1 million in South Ghazalat (December 31, 2017 - $20.0 million), $nil in North West Sitra (December 31, 2017 - $8.2 million), and $0.5 million in Canada.



Q3-2018		29

9. PROPERTY AND EQUIPMENT



	Petroleum & Natural Gas Assets			Other Assets
(000s)	Petroleum & Natural Gas Assets			Other Assets		Total
Balance at December 31, 2017	$	652,831		$	15,525	$	668,356
Additions	15,859			378		16,237
Changes in estimate for asset retirement obligations	(468		)	—		(468		)
Effect of movement in foreign exchange rates	(1,890		)	—		(1,890		)
Balance at September 30, 2018	$	666,332		$	15,903	$	682,235

Accumulated depletion, depreciation, amortization and impairment losses at December 31, 2017	$	451,850		$	12,040	$	463,890
Depletion, depreciation and amortization for the period¹	23,038			736		23,774
Balance at September 30, 2018	$	474,888		$	12,776	$	487,664
¹ Depletion, depreciation and amortization for the period includes amounts capitalized to product inventory for barrels produced but not sold in the period.



Net Book Value
At December 31, 2017	$	200,981	$	3,485	$	204,466
At September 30, 2018	$	191,444	$	3,127	$	194,571

10. ASSET RETIREMENT OBLIGATION



(000s)
Balance at December 31, 2017	$	12,332
Additional obligations recognized	212
Changes in estimates for asset retirement obligation	(278		)
Obligations settled	(257		)
Asset retirement obligation accretion	205
Changes in discount rates	(402		)
Effect of movements in foreign exchange rates	(490		)
Balance at September 30, 2018	$	11,322

TransGlobe has estimated the net present value of its asset retirement obligation to be $11.3 million as at September 30, 2018 (December 31, 2017 - $12.3 million) based on a total undiscounted future liability, after inflation adjustment, of $19.0 million (December 31, 2017 - $19.6 million). These payments are expected to be made between 2018 and 2066. TransGlobe calculated the present value of the obligations using discount rates between 2.21% and 2.42% to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates. The inflation rate used in determining the cash flow estimate was 2% per annum.

11. LONG-TERM DEBT

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



(000s)	September 30, 2018		December 31, 2017
Prepayment agreement	$	44,046	$	58,792
Reserves-based lending facility¹	8,486		11,207
Balance at September 30, 2018	$	52,532	$	69,999
¹ As at September 30, 2018 and December 31, 2017, the Company had in place a revolving Canadian reserves-based lending facility totaling C$30.0 million ($24.0 million), of which C $11.0 million was drawn (December 31, 2017 - C$14.0 million).

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



(000s)
Balance at December 31, 2017	$	69,999
Draws on facility	395
Repayment of long-term debt	(17,797		)
Amortization of deferred financing costs	272
Effect of movements in foreign exchange rates	(337		)
Balance at September 30, 2018	$	52,532

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



30		Q3-2018

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



(000s)
2020	8,486
2021	44,046
	$	52,532

12. COMMITMENTS AND CONTINGENCIES



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

Pursuant to the PSC for North West Sitra in Egypt, the Company had a minimum financial commitment of $10.0 million and a work commitment for two wells and 300 square kilometers of 3-D seismic during the initial three-and-a-half year exploration period, which commenced on January 8, 2015. The Company requested and received a six month extension of the initial exploration period to January 7, 2019. As at September 30, 2018, the Company has met its financial and operating commitments, with the acquisition of 600 square kilometers of 3-D seismic in 2017 and the drilling of two wells in the first nine months of 2018. The Company has now completed the initial exploration period work program and based on well results in not planning to enter the second exploration phase.

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

13. SHARE CAPITAL

Authorized

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

Issued

Nine Months Ended

Year Ended

September 30, 2018

December 31, 2017

(000s)

Amount

Balance, beginning and end of period

72,206

152,084

72,206

152,084



Q3-2018		31

14. SHARE-BASED PAYMENTS

Stock options

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



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

Compensation expense of $0.7 million was recorded in general and administrative expenses in the Condensed Consolidated Interim Statements of Loss and Comprehensive Loss and Contributed Surplus during the nine month period ended September 30, 2018 (September 30, 2017 - $0.5 million) for equity-settled share-based payment transactions. The fair value of all common stock options granted is estimated on the date of grant using the lattice-based trinomial option pricing model.

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

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

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



	Restricted		Performance		Deferred
	Share		Share		Share
(000s)	Units		Units		Units
Units outstanding, beginning of period	970		1,376		595
Granted	387		672		225
Exercised	(356	)	(316	)	—
Forfeited	(157	)	(55	)	—
Reinvested	8		16		8
Units outstanding, end of period	852		1,693		828

During the nine month period ended September 30, 2018, compensation expense of $4.6 million (September 30, 2017 - $0.3 million) was recorded in general and administrative expenses in the Condensed Consolidated Interim Statements of Loss and Comprehensive Loss for share units granted under the three plans described above. The expense related to the share units granted under these plans is measured at fair value using the lattice-based trinomial pricing model and is recognized over the vesting period, with a corresponding liability recognized on the Condensed Consolidated Interim Balance Sheets. Until the liability is ultimately settled, it is re-measured at each reporting date with changes to fair value recognized in earnings.

15. PER SHARE AMOUNTS

The basic weighted-average number of common shares outstanding for the nine months ended September 30, 2018 and 2017 was 72,205,369. The diluted weighted-average number of common shares outstanding for the nine months ended September 30, 2018 was 73,124,103 (September 30, 2017 - 72,205,369). These outstanding share amounts were used to calculate net loss per share in the respective periods.

In determining diluted net 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 period ended September 30, 2018, the Company excluded 1,640,000 stock options (September 30, 2017 – 5,344,520) as their exercise price was greater than the average common share market price in the period.

16. DIVIDENDS

During the quarter the Company paid out a dividend of $0.035 per share on September 14, 2018 to shareholders of record on August 31, 2018.

17. SEGMENTED INFORMATION

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



32		Q3-2018

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



	Egypt						Canada						Corporate						Total
	Nine Months Ended						Nine Months Ended						Nine Months Ended						Nine Months Ended
	September 30						September 30						September 30						September 30
(000s)	2018			2017			2018			2017			2018			2017			2018			2017
Revenue
Oil sales	$	209,310		$	163,984		$	9,356		$	6,635		$	—		$	—		$	218,666		$	170,619
Natural gas sales	—			—			1,975			3,594			—			—			1,975			3,594
Natural gas liquids sales	—			—			5,875			5,424			—			—			5,875			5,424
Less: Royalties	(88,624		)	(68,543		)	(2,270		)	(3,355		)	—			—			(90,894		)	(71,898		)
Petroleum and natural gas sales, net of royalties	120,686			95,441			14,936			12,298			—			—			135,622			107,739
Finance revenue	77			3			—			2			322			54			399			59
Total segmented revenue	120,763			95,444			14,936			12,300			322			54			136,021			107,798

Segmented expenses
Production and operating	34,344			35,344			5,838			4,578			—			—			40,182			39,922
Selling costs	1,653			1,926			—			—			—			—			1,653			1,926
General and administrative	3,659			4,577			871			884			12,153			6,156			16,683			11,617
Share-based compensation	—			—			—			—			(5,309		)	(886		)	(5,309		)	(886		)
Lease inducement	—			—			—			—			68			65			68			65
Settlement of asset retirement obligations	—			—			257			—			—			—			257			—
Realized foreign exchange loss	—			—			—			—			(10		)	101			(10		)	101
Realized derivative loss on commodity contracts	7,879			375			450			—			—			—			8,329			375
Income tax expense	19,728			16,104			—			—			—			—			19,728			16,104
Segmented funds flow from operations	$	53,500		$	37,118		$	7,520		$	6,838		$	(6,580	)	$	(5,382	)	$	54,440		$	38,574

																			Total
																			Nine Months Ended
																			September 30
																			2018			2017
Reconciliation of funds flow from operations to net loss:

Funds flow from operations																			$	54,440		$	38,574
Depletion, depreciation and amortization																			(26,077		)	(29,635		)
Accretion																			(205		)	(191		)
Deferred lease inducement																			68			65
Impairment of exploration and evaluation assets																			(14,138		)	(79,025		)
Stock-based compensation																			(5,309		)	(886		)
Finance costs																			(3,923		)	(4,750		)
Unrealized loss on financial instruments																			(20,157		)	(537		)
Unrealized gain (loss) on foreign currency translation																			(205		)	31
Asset retirement obligations settled																			257			—
Proceeds from asset dispositions																			207			—
Net loss																			$	(15,042	)	$	(76,354	)


Capital expenditures
Exploration and development	$	20,063		$	24,667		$	3,142		$	4,384		$	—		$	—		$	23,205		$	29,051
Corporate	—			—			—			—			68			30			68			30
Total capital expenditures	$	20,063		$	24,667		$	3,142		$	4,384		$	68		$	30		$	23,273		$	29,081



Q3-2018		33



	Egypt						Canada						Corporate						Total
	Three Months Ended						Three Months Ended						Three Months Ended						Three Months Ended
	September 30						September 30						September 30						September 30
(000s)	2018			2017			2018			2017			2018			2017			2018			2017
Revenue
Oil sales	$	68,861		$	63,403		$	3,131		$	2,141		$	—		$	—		$	71,992		$	65,544
Natural gas sales	—			—			528			949			—			—			528			949
Natural gas liquids sales	—			—			1,825			1,879			—			—			1,825			1,879
Less: Royalties	(31,278		)	(22,506		)	(614		)	(1,027		)	—			—			(31,892		)	(23,533		)
Petroleum and natural gas sales, net of royalties	37,583			40,897			4,870			3,942			—			—			42,453			44,839
Finance revenue	27			1			—			2			153			12			180			15
Total segmented revenue	37,610			40,898			4,870			3,944			153			12			42,633			44,854

Segmented expenses
Production and operating	10,677			13,242			1,565			1,280			—			—			12,242			14,522
Selling costs	527			424			—			—			—			—			527			424
General and administrative	1,133			2,083			345			318			3,626			1,408			5,104			3,809
Share-based compensation	—			—			—			—			(1,624		)	(236		)	(1,624		)	(236		)
Lease inducement	—			—			—			—			23			22			23			22
Realized foreign exchange loss (gain)	—			—			—			—			(11		)	13			(11		)	13
Realized derivative loss on commodity contracts	2,430			1,904			—			—			—			—			2,430			1,904
Income tax expense	6,924			5,179			—			—			—			—			6,924			5,179
Segmented funds flow from operations	$	15,919		$	18,066		$	2,960		$	2,346		$	(1,861	)	$	(1,195	)	$	17,018		$	19,217

																			Total
																			Three Months Ended
																			September 30
																			2018			2017
Reconciliation of funds flow from operations to net loss:

Funds flow from operations																			$	17,018		$	19,217
Depletion, depreciation and amortization																			(8,751		)	(10,760		)
Accretion																			(72		)	(74		)
Deferred lease inducement																			23			22
Impairment of exploration and evaluation assets																			(14,138		)	(10,314		)
Stock-based compensation																			(1,624		)	(236		)
Finance costs																			(1,222		)	(1,485		)
Unrealized loss on financial instruments																			(3,295		)	(3,235		)
Unrealized gain (loss) on foreign currency translation																			(227		)	10
Proceeds from asset dispositions																			5			—
Net loss																			$	(12,283	)	$	(6,855	)


Capital expenditures
Exploration and development	$	10,113		$	6,070		$	2,636		$	4,060		$	—		$	—		$	12,749		$	10,130
Corporate	—			—			—			—			34			3			34			3
Total capital expenditures	$	10,113		$	6,070		$	2,636		$	4,060		$	34		$	3		$	12,783		$	10,133



34		Q3-2018

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



	At September 30, 2018						At December 31, 2017
(000s)	Egypt		Canada		Total		Egypt		Canada		Total
Assets
Accounts receivable	$	8,047	$	2,439	$	10,486	$	14,956	$	2,684	$	17,640
Intangible exploration and evaluation assets	34,376		—		34,376		41,478		—		41,478
Property and equipment
Petroleum and natural gas assets	123,367		68,077		191,444		127,363		73,618		200,981
Other assets	2,195		24		2,219		2,381		27		2,408
Other	64,102		4,312		68,414		49,769		3,467		53,236
Segmented assets	232,087		74,852		306,939		235,947		79,796		315,743
Non-segmented assets					7,264						11,959
Total assets					$	314,203					$	327,702

Liabilities
Accounts payable and accrued liabilities	$	16,277	$	4,043	$	20,320	$	17,035	$	4,004	$	21,039
Derivative commodity contracts	28,124		—		28,124		7,813		157		7,970
Long-term debt	44,047		8,485		52,532		58,792		11,207		69,999
Asset retirement obligation	—		11,322		11,322		—		12,332		12,332
Segmented liabilities	88,448		23,850		112,298		83,640		27,700		111,340
Non-segmented liabilities					9,483						6,355
Total liabilities					$	121,781					$	117,695

18. SUPPLEMENTAL CASH FLOW INFORMATION

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



	Three Months Ended September 30						Nine Months Ended September 30
(000s)	2018			2017			2018			2017
Operating Activities
(Increase) decrease in current assets:
Accounts receivable	$	30,558		$	(7,797	)	$	7,158		$	(34,871	)
Prepaids and other	427			(625		)	1,101			(903		)
Product inventory	(666		)	2,820			1,371			4,856
(Decrease) increase in current liabilities:
Accounts payable and accrued liabilities	(791		)	6,822			(5,793		)	7,531
Other long-term liabilities	$	1,093		$	—		$	1,093		$	—
	$	30,621		$	1,220		$	4,930		$	(23,387	)



Investing Activities
Increase in current assets:
Prepaids and other	$	3	$	—	$	—	$	—
Increase in current liabilities:
Accounts payable and accrued liabilities	3,226		557		2,594		1,073
	$	3,229	$	557	$	2,594	$	1,073



Financing Activities
Decrease in current liabilities:
Accounts payable and accrued liabilities	(3		)	—		(3		)	—
	$	(3	)	$	—	$	(3	)	$	—



Q3-2018		35



CORPORATE & SHAREHOLDER INFORMATION

DIRECTORS		INVESTOR RELATIONS
		Telephone: 403-264-9888
Robert G. Jennings - Chairman		investor.relations@trans-globe.com
Ross G. Clarkson⁽⁴⁾ - Chief Executive Officer
Randy C. Neely ⁽⁴⁾ - President
Matthew Brister ⁽²⁾⁽³⁾		NOMINATED ADVISER & JOINT BROKER
David B. Cook ⁽²⁾		Canaccord Genuity Limited
Fred J. Dyment ⁽¹⁾		8 Wood Street, London, EC2V 7QR
G. R. (Bob) MacDougall ⁽¹⁾⁽³⁾
Susan M. MacKenzie ⁽²⁾⁽³⁾
Steven W. Sinclair ⁽¹⁾⁽²⁾		CO-BROKER
		GMP FirstEnergy Capital LLP
(1) Audit Committee		88 London Wall
(2) Compensation Human Resources & Governance Committee		London EC2M 7AD
(3) Reserves Health Safety & Social Responsibility Committee
(4) Disclosure and AIM Compliance Committee
		LEGAL COUNSEL
OFFICERS		Burnet, Duckworth & Palmer LLP
Ross G. Clarkson ⁽⁴⁾- Chief Executive Officer		Calgary, Alberta
Randy C. Neely ⁽⁴⁾ - President
Lloyd W. Herrick ⁽⁴⁾ - Vice President & Chief Operating Officer
Edward D. Ok ⁽⁴⁾ - Vice President, Finance & Chief Financial Officer		AUDITORS
Brett Norris ⁽⁴⁾ - Vice President, Exploration		Deloitte LLP
Marilyn A. Vrooman-Robertson - Corporate Secretary		Calgary, Alberta


HEAD OFFICE		EVALUATION ENGINEERS
2300, 250 – 5th Street S.W.		GLJ Petroleum Consultants Ltd.
Calgary, Alberta, Canada T2P 0R4		Calgary, Alberta
Telephone: (403) 264-9888
Facsimile: (403) 770-8855
		BANKS
		Sumitomo Mitsui Banking Corporation Europe Limited
EGYPT OFFICE		London, Great Britain
6 Badr Towers, 10^th Floor
Ring Road		Alberta Treasury Branches
New Maadi, Cairo, Egypt		Calgary, Alberta, Canada


UK OFFICE		PUBLIC RELATIONS
105 Victoria Street		FTI Consulting Inc.
London, UK SWIE 6Q7		Telephone: +44 (0) 203 727 1000
		Email: energy@fticonsulting.com

WEBSITE
www.trans-globe.com

www.trans-globe.com

TSX & AIM: TGL NASDAQ: TGA