MANAGEMENT'S DISCUSSION AND ANALYSIS

November 7, 2017

The following discussion and analysis is management's opinion of TransGlobe's historical financial and operating results and should be read in conjunction with the unaudited Condensed Consolidated Interim Financial Statements for the Company for the three and nine months ended September 30, 2017 and 2016 and the audited Consolidated Financial Statements and Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2016 included in the Company’s annual report. The Condensed Consolidated Interim Financial Statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board in the currency of the United States (except where otherwise noted). Additional information relating to the Company, including the Company’s Annual Information Form, is on SEDAR at www.sedar.com. The Company’s annual report on Form 40-F may be found on EDGAR at www.sec.gov.

READER ADVISORIES

Forward-Looking Statements

Certain statements or information contained herein may constitute forward-looking statements or information under applicable securities laws, including, but not limited to, management’s assessment of future plans and operations, anticipated changes to the Company's reserves and production, collection of accounts receivable from the Egyptian Government, timing of directly marketed crude oil sales, drilling plans and the timing thereof, commodity price risk management strategies, adapting to the current political situation in Egypt, reserve estimates, management’s expectation for results of operations for 2017, including expected 2017 average production, funds flow from operations, the 2017 capital program for exploration and development, the timing and method of financing thereof, the terms of drilling commitments under the Egyptian PSCs and the method of funding such drilling commitments, the Company's beliefs regarding the reserve and production growth of its assets and the ability to grow with a stable production base, and commodity prices and expected volatility thereof. Statements relating to "reserves" are deemed to be

forward‑looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

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

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

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

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

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

Q3-2017 1

MANAGEMENT STRATEGY AND OUTLOOK

The 2017 outlook provides information as to management’s expectation for results of operations for 2017. Readers are cautioned that the 2017 outlook may not be appropriate for other purposes. The Company’s expected results are sensitive to fluctuations in the business environment, including disruptions caused by the ongoing political changes and civil unrest occurring in jurisdictions that the Company operates in, and may vary accordingly. This outlook contains forward-looking statements that should be read in conjunction with the Company’s disclosure under “Forward-Looking Statements”, outlined on the first page of this MD&A.

2017 Outlook

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

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

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

NON-GAAP FINANCIAL MEASURES

Funds Flow from Operations

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

Reconciliation of Funds Flow from Operations

	Three months ended September 30				Nine months ended September 30
($000s)	2017		2016		2017	2016
Cash flow from operating activities	20,437		(14,857	)	15,187	(7,420	)
Changes in non-cash working capital	(1,220	)	17,204		23,387	8,963
Funds flow from operations1	19,217		2,347		38,574	1,543
1  Funds flow from operations does not include interest costs. Interest expense is included in financing costs on the Condensed Consolidated Interim         Statements of Earnings and Comprehensive Income. Cash interest paid is reported as a financing activity on the Condensed Consolidated Interim         Statements of Cash Flows.

Debt-to-Funds Flow ratio

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

Netback

Netback is a measure that represents sales net of royalties (all government interests, net of income taxes), operating expenses, current taxes and selling costs. Management believes that netback is a useful supplemental measure to analyze operating performance and provide an indication of the results generated by the Company’s principal business activities prior to the consideration of other income and expenses. Netback does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

TRANSGLOBE’S BUSINESS

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

2 Q3-2017

SELECTED QUARTERLY FINANCIAL INFORMATION

	2017						2016								2015
(000s, except per share,
price and volume amounts)	Q-3		Q-2		Q-1		Q-43		Q-3		Q-2		Q-1		Q-4
Operations
Average production volumes
Crude oil (bbls/d)	12,786		14,347		14,514		12,861		11,733		11,472		12,058		13,425
NGLs (bbls/d)	1,081		919		1,037		134		—		—		—		—
Natural gas (mcf/d)	6,268		7,191		7,075		916		—		—		—		—
Total (boe/d)	14,912		16,465		16,731		13,148		11,733		11,472		12,058		13,425
Average sales volumes
Crude oil (bbls/d)	15,894		17,141		11,610		7,018		11,485		11,783		14,126		7,205
NGLs (bbls/d)	1,081		919		1,037		134		—		—		—		—
Natural gas (mcf/d)	6,268		7,191		7,075		916		—		—		—		—
Total (boe/d)	18,020		19,259		13,826		7,305		11,485		11,783		14,126		7,205
Average realized sales prices
Crude oil ($/bbl)	44.82		39.46		41.66		37.38		34.43		30.27		22.58		32.38
NGLs ($/bbl)	18.90		21.08		19.08		12.33		—		—		—		—
Natural gas ($/Mcf)	1.65		2.14		1.96		1.80		—		—		—		—
Total oil equivalent ($/boe)	41.24		36.92		37.41		36.45		34.43		30.27		22.58		32.38
Inventory (Mbbl)	988		1,274		1,528		1,265		729		707		735		923
Petroleum and natural gas sales	68,372		64,711		46,553		24,501		36,376		32,461		29,022		21,460
Petroleum and natural gas sales, net of royalties	44,839		40,439		22,461		5,217		20,704		19,786		17,427		3,979
Cash flow from operating activities	20,437		(2,753	)	(2,497	)	6,355		(14,857	)	6,011		1,426		6,414
Funds flow from operations1	19,217		16,855		2,502		(9,904	)	2,347		2,026		(2,830	)	(11,108	)
Funds flow from operations per share
- Basic	0.27		0.23		0.03		(0.14	)	0.03		0.03		(0.04	)	(0.15	)
- Diluted	0.27		0.23		0.03		(0.14	)	0.03		0.03		(0.04	)	(0.15	)
Net earnings (loss)	(6,855	)	(56,622	)	(12,877	)	(33,997	)	(25,369	)	(12,050	)	(16,249	)	(35,255	)
Net earnings (loss) - diluted	(6,855	)	(56,622	)	(12,877	)	(38,641	)	(25,369	)	(12,050	)	(16,249	)	(35,255	)
Net earnings per share
- Basic	(0.09	)	(0.78	)	(0.18	)	(0.47	)	(0.35	)	(0.17	)	(0.23	)	(0.49	)
- Diluted	(0.09	)	(0.78	)	(0.18	)	(0.49	)	(0.35	)	(0.17	)	(0.23	)	(0.49	)
Capital expenditures	10,133		8,229		10,718		8,863		8,692		4,838		4,265		4,877
Dividends paid	—		—		—		—		—		—		—		1,805
Dividends paid per share	—		—		—		—		—		—		—		0.03
Total assets	338,802		337,596		403,686		406,142		414,363		433,013		441,624		455,500
Cash and cash equivalents	21,464		13,780		21,324		31,468		100,405		124,308		122,031		126,910
Convertible debentures	—		—		—		72,655		74,854		70,639		66,506		63,848
Note payable	—		—		11,259		11,162		—		—		—		—
Total long-term debt, including      current portion	79,839		83,725		73,549		—		—		—		—		—
Debt-to-funds flow ratio2	2.8		7.1		(28.0	)	(10.0	)	(7.8	)	(5.3	)	(7.9	)	(7.2	)
1 Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
2  Debt-to-funds flow ratio is a measure that represents total long-term debt (including the current portion) plus convertible debentures over funds flow from operations from the trailing 12 months and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
3  The Q4-2016 information includes the results of the operations of the Harmattan assets in Alberta, Canada from December 20, 2016 to December 31, 2016 (12 days). The Harmattan assets were acquired in a transaction that closed on December 20, 2016.

Q3-2017 3

During the third quarter of 2017, TransGlobe:

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

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

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

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

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

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

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

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

4 Q3-2017

2017 TO 2016 NET EARNINGS VARIANCES

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

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

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

BUSINESS ENVIRONMENT

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

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

Q3-2017 5

The price of Dated Brent oil averaged 5% higher in Q3-2017 compared with Q2-2017. Egypt production is priced based on Dated Brent, less a quality differential and shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost recovery barrels) which are assigned 100% to the Company. The contracts provide for cost recovery per quarter up to a maximum percentage of total revenue. Timing differences often exist between the Company's recognition of costs and their recovery as the Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSC, the Contractor's share of excess ranges between 0% and 30%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum cost recovery or cost oil ranges from 25% to 30% in Egypt. The balance of the production after maximum cost recovery is shared with the government (production sharing oil). Depending on the contract, the Egyptian government receives 70% to 86% of the production sharing oil or profit oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of production sharing oil increases when production exceeds pre-set production levels in the respective contracts. During times of increased oil prices, the Company receives less cost oil and may receive more production sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil. For reporting purposes, the Company records the government’s share of production as royalties and taxes (all taxes are paid out of the government’s share of production) which will increase during times of rising oil prices and will decrease in times of declining oil prices. If oil prices are sufficiently low and the Ras Gharib/Dated Brent differential is high, the cost oil portion may not be sufficient to cover operating costs and capital costs, or even operating costs alone. When this occurs, the non-recovered costs accumulate in the Company’s cost pools and are available to be offset against future cost oil during the term of the PSC and any eligible extension periods.

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

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

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

6 Q3-2017

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest before Royalties (Boepd)

Production Volumes

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

Sales Volumes (excludes volumes held as inventory)

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

Netback

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

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

Q3-2017 7

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

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

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

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

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

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

8 Q3-2017

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

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

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

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

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

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

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)

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

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

Q3-2017 9

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

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

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

FINANCE COSTS

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

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

Convertible Debentures

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

Prepayment Agreement

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

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

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

Revolving Reserve-Based Lending Facility

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

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

10 Q3-2017

Note Payable

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

DEPLETION AND DEPRECIATION (“DD&A”)

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

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

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

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

IMPAIRMENT LOSS

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

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

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

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

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

Q3-2017 11

CAPITAL EXPENDITURES

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

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

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

OUTSTANDING SHARE DATA

As at September 30, 2017, the Company had 72,205,369 common shares issued and outstanding and 5,344,520 stock options issued and outstanding, which are exercisable in accordance with their terms into an equal number of common shares of the Company.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity describes a company’s ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs necessary to maintain and increase production and reserves, to acquire strategic oil and gas assets and to repay current liabilities and debt. TransGlobe’s capital programs are funded by its existing working capital and cash provided from operating activities. TransGlobe’s debt-to-funds flow from operations ratio deteriorated significantly from late 2014 as a direct result of a continued lower oil price environment. As of September 30, 2017, debt-to-funds flow improved to 2.8 (December 31, 2016 - negative 10.0) as a result of positive funds flow for the trailing 12 months. The Company's funds flow from operations can vary significantly from quarter to quarter depending on the timing of tanker liftings, and these fluctuations in funds flow impact the Company's debt-to-funds flow from operations ratio. TransGlobe's management will continue to steward capital programs and focus on cost reductions in order to maintain balance sheet strength through the current low oil price environment.

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

Sources and Uses of Cash
	Nine months ended September 30
($000s)	2017		2016
Cash sourced
Funds flow from operations1	38,574		1,543
Transfer from restricted cash	13,511		289
Increase in long-term debt	85,265		—
Other	465		—
	137,815		1,832
Cash used
Capital expenditures	29,081		17,794
Deferred financing costs	1,555		—
Repayment of long-term debt	5,000		—
Repayment of convertible debentures	73,375		—
Repayment of note payable	11,041		—
Finance costs	5,453		5,007
Other	—		1,128
	125,505		23,929
	12,310		(22,097	)
Changes in non-cash working capital	(22,314	)	(4,408	)
Increase (decrease) in cash and cash equivalents	(10,004	)	(26,505	)
Cash and cash equivalents – beginning of period	31,468		126,910
Cash and cash equivalents – end of period	21,464		100,405
1  Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital, and may not      be comparable to measures used by other companies.

12 Q3-2017

Funding for the Company’s capital expenditures was provided by funds flow from operations and cash on hand. The Company expects to fund its 2017 exploration and development program of $40.7 million, including contractual commitments, through the use of working capital and funds flow from operations. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks may impact capital resources and capital expenditures.

Working capital is the amount by which current assets exceed current liabilities. At September 30, 2017, the Company had a working capital surplus of $58.8 million (December 31, 2016 - deficiency of $16.8 million). The increase to working capital in Q3-2017 is principally due to the repayment of the convertible debt, which was a current liability at year-end 2016, (using the proceeds from the prepayment agreement) and increased sales of inventoried entitlement oil, as well as marginally better crude pricing and lower Gharib blend differentials, offset by lower natural gas prices in Canada. During Q3-2017 the Company repaid $5.0 million of the amount outstanding under the prepayment agreement with cash on hand.

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

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

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

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

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

PRODUCT INVENTORY

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

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

Q3-2017 13

COMMITMENTS AND CONTINGENCIES

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

($000s)		Payment Due by Period 1,2
	Recognized
	in Financial	Contractual	Less than
	Statements	Cash Flows	1 year	1-3 years	4-5 years
Accounts payable and accrued liabilities	Yes - Liability	32,532	32,532
Long-term debt	Yes - Liability	79,839	—	11,128	68,711
Financial derivative instruments	Yes - Liability	465	465	—	—
Office and equipment leases3	No	3,922	1,819	2,103	—
Minimum work commitments4	No	5,129	5,129	—	—
Total		121,887	39,945	13,231	68,711
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at September 30, 2017 exchange rates.
3 Office and equipment leases includes all drilling rig contracts.
4 Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

The Company is subject to certain office and equipment leases.

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

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

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

Pursuant to the PSC for North West Sitra in Egypt, the Company has a minimum financial commitment of $10.0 million ($5.1 million remaining) and a work commitment for two wells and 300 square kilometers of 3-D seismic during the initial three and a half year exploration period, which commencedon January 8, 2015. As at September 30, 2017, the Company had expended $4.9 million towards meeting the financial and operating commitment, with the acquisition of 600 km² of 3-D seismic in 2017.

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

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

14 Q3-2017

ASSET RETIREMENT OBLIGATION

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

Under the terms of the Production Sharing Contracts TransGlobe is not responsible for ARO in Egypt.

DERIVATIVE COMMODITY CONTRACTS

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

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

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

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

Financial Brent Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume bbl	Sold Swap US$/bbl	Bought Put US$/bbl	Sold Call US$/bbl	Sold Put US$/bbl
28-Mar-17	Dec-17	Collar	300,000	—	45.00	56.00	—
7-Apr-17	Mar-18	3-Way Collar	250,000	—	53.00	61.15	44.00
12-Apr-17	Jun-18	3-Way Collar	250,000	—	54.00	63.10	45.00
12-Apr-17	Sep-18	3-Way Collar	250,000	—	54.00	64.15	45.00
12-Apr-17	Dec-18	3-Way Collar	250,000	—	54.00	65.45	45.00
23-May-17	Jul 2020 - Dec 20201	3-Way Collar	300,000	—	54.00	63.45	45.00
31-Aug-17	Jan 2020 - Jun 20202	3-Way Collar	300,000	—	54.00	61.25	46.50
1 50,000 bbl per calendar month through Jul 2020 - Dec 2020
2 50,000 bbl per calendar month through Jan 2020 - Jun 2020

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

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

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

Q3-2017 15

INTERNAL CONTROLS OVER FINANCIAL REPORTING

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

No changes were made to the Company’s internal control over financial reporting during the period ended September 30, 2017 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

16 Q3-2017