MANAGEMENT'S DISCUSSION AND ANALYSIS

May 9, 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 of the Company for the three months ended March 31, 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 are 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.

Q1-2017 1

All oil and natural gas reserve 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.

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.

2 Q1-2017

MANAGEMENT STRATEGY AND OUTLOOK

The 2017 outlook provides information as to management’s expectation for results of operations for 2017. Readers are cautioned that the 2017 outlook may not be appropriate for other purposes. The Company’s expected results are sensitive to fluctuations in the business environment, including disruptions caused by the ongoing political changes and civil unrest occurring in 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 MD&A.

2017 Outlook

It is expected that 2017 production will average between 15,500 and 18,500 boepd, representing a 30% to 55% increase over 2016 production (production in Q1-2017 was 16,761 boepd).  The 2017 production outlook is provided as a range to reflect the firm and contingent budget. Funds flow in any given period will be dependent upon the timing of crude oil tanker liftings in Egypt 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.

2017 Capital Budget

The Company's 2017 capital program of $56.4 million (before capitalized G&A) consists of a $35.2 million firm budget and a $21.2 million contingent budget, and includes $40.2 million for Egypt and $16.2 million (C$22.4 million) for Canada.

Egypt

The $25.8 million Egypt firm program has $14.4 million (56%) allocated to exploration and $11.4 million (44%) to development. The $14.4 million exploration program includes drilling up to six wells in the Eastern Desert, two Boraq wells (one new drill and one re-entry) at South Alamein and a large (600 km²) 3-D seismic acquisition program at NW Sitra in the Western Desert. The $11.4 million 2017 development program includes one development well in the West Bakr K-South field, and development/maintenance projects at West Gharib, West Bakr and NW Gharib.

The $14.4 million Egypt contingent program has $2.0 million (14%) allocated to exploration and $12.2 million (86%) allocated to development. The program includes nine additional wells (two exploration and seven development) focused primarily in NW Gharib to appraise/develop the NW Gharib discoveries and to increase West Bakr production. The $14.4 million budget is contingent upon timing of cargo/inventory sales, oil prices and drilling results in the first half of the year.

Canada

The $9.4 million (C$12.5 million) Canada firm program consists of four horizontal (multi-stage frac) wells targeting the Cardium light oil resource at Harmattan and additional maintenance/development capital for potential workover/refracs. The initial Cardium well program is designed to provide a current benchmark for well costs and improved frac design/performance in the Harmattan area (no drilling has been conducted on the acquired lands since 2013). Based on historical offset wells and third party engineering estimates, it is expected that the horizontal wells will cost approximately $2.0 million (C$2.7 million) per well targeting a one mile lateral with approximately 600 tonnes of sand (30 stages) per well. It is expected that drilling will commence in the third quarter with all wells completed and on production prior to year-end to provide updated information for 2017 year-end reserves.

The $6.8 million (C$9.0 million) Canada contingent program consists of an additional four horizontal wells in the Harmattan area, to accelerate production growth in the Canadian operations. The $6.8 million budget is contingent on results of the initial drilling program and commodity prices.

The 2017 capital program is summarized in the following table:

	TransGlobe 2017 Firm & Contingent Capital ($MM)							Gross Well Count
	Development			Exploration			Total	(Wells)
Concession	Wells	Maint	Projects	Wells	Bonus	Seismic		Devel	Explor	Total
West Gharib	2.4	1.3	2.6	—	—	—	6.3	—	—	—
West Bakr	6.7	1.0	2.1	—	—	—	9.8	2	—	2
NW Gharib	7.6	—	—	6.9	0.1	—	14.6	6	8	14
SW Gharib	—	—	—	1.2	0.2	—	1.4	—	1	1
South Alamein	—	—	—	3.1	0.6	—	3.7	—	1	1
South Ghazalat	—	—	—	—	0.2	—	0.2	—	—	—
NW Sitra	—	—	—	—	0.2	4.0	4.2	—	—	—
Egypt	$16.7	$2.3	$4.7	$11.2	$1.3	$4.0	$40.2	8	10	18
Canada	$14.7	$1.5	—	—	—	—	$16.2	8	—	8
2017 Total	$31.4	$3.8	$4.7	$11.2	$1.3	$4.0	$56.4	16	10	26
Splits (%)	70%			30%			100%	62%	38%	100%

Q1-2017 3

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 March 31
($000s)	2017		2016
Cash flow from operating activities	(2,497	)	1,426
Changes in non-cash working capital	4,999		(4,256	)
Funds flow from operations1	2,502		(2,830	)
Note:
1  Funds flow from operations does not include interest costs. Interest expense is included in financing costs on the Condensed Consolidated Interim      Statements of Earnings 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, plus convertible debentures 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.

4 Q1-2017

SELECTED QUARTERLY FINANCIAL INFORMATION

	2017		2016								2015
($000s, except per share,
price and volume amounts)	Q-1		Q-43		Q-3		Q-2		Q-1		Q-4		Q-3		Q-2
Operations
Average production volumes
Crude oil (bbls/d)	14,514		12,861		11,733		11,472		12,058		13,425		14,683		15,064
NGLs (bbls/d)	1,037		134		—		—		—		—		—		—
Natural gas (mcf/d)	7,075		916		—		—		—		—		—		—
Total (boe/d)	16,731		13,148		11,733		11,472		12,058		13,425		14,683		15,064
Average sales volumes
Crude oil (bbls/d)	11,610		7,018		11,485		11,783		14,126		7,205		13,620		14,251
NGLs (bbls/d)	1,037		134		—		—		—		—		—		—
Natural gas (mcf/d)	7,075		916		—		—		—		—		—		—
Total (boe/d)	13,826		7,305		11,485		11,783		14,126		7,205		13,620		14,251
Average realized sales prices
Crude oil ($/Bbl)	41.66		37.38		34.43		30.27		22.58		32.38		39.35		48.31
NGLs ($/Bbl)	19.08		12.33		—		—		—		—		—		—
Natural gas ($/Mcf)	1.96		1.80		—		—		—		—		—		—
Total oil equivalent ($/boe)	37.41		36.45		34.43		30.27		22.58		32.38		39.35		48.31
Inventory (Bbl)	1,528,295		1,265,080		729,403		706,577		734,872		923,106		350,869		253,325
Petroleum and natural gas sales	46,553		24,501		36,376		32,461		29,022		21,460		49,307		62,647
Petroleum and natural gas sales, net of royalties	22,461		5,217		20,704		19,786		17,427		3,979		24,700		33,960
Cash flow from operating activities	(2,497	)	6,355		(14,857	)	6,011		1,426		6,414		28,741		24,323
Funds flow from operations1	2,502		(9,904	)	2,347		2,026		(2,830	)	(11,108	)	(1,497	)	6,991
Funds flow from operations per share
- Basic	0.03		(0.14	)	0.03		0.03		(0.04	)	(0.15	)	(0.02	)	0.09
- Diluted	0.03		(0.14	)	0.03		0.03		(0.04	)	(0.15	)	(0.02	)	0.09
Net earnings (loss)	(12,877	)	(33,997	)	(25,369	)	(12,050	)	(16,249	)	(35,255	)	(46,568	)	(12,580	)
Net earnings (loss) - diluted	(12,877	)	(38,641	)	(25,369	)	(12,050	)	(16,249	)	(35,255	)	(54,159	)	(12,580	)
Net earnings per share
- Basic	(0.18	)	(0.47	)	(0.35	)	(0.17	)	(0.23	)	(0.49	)	(0.64	)	(0.17	)
- Diluted	(0.18	)	(0.49	)	(0.35	)	(0.17	)	(0.23	)	(0.49	)	(0.68	)	(0.17	)
Capital expenditures	10,718		8,863		8,692		4,838		4,265		4,877		3,587		22,337
Dividends paid	—		—		—		—		—		1,805		3,594		3,703
Dividends paid per share	—		—		—		—		—		0.025		0.05		0.05
Total assets	403,686		406,142		414,363		433,013		441,624		455,500		501,808		599,744
Cash and cash equivalents	21,324		31,468		100,405		124,308		122,031		126,910		126,874		122,961
Convertible debentures	—		72,655		74,854		70,639		66,506		63,848		65,682		74,421
Note payable	11,259		11,162		—		—		—		—		—		—
Total long-term debt, including      current portion	73,549		—		—		—		—		—		—		—
Debt-to-funds flow ratio2	(28.0	)	(10.0	)	(7.8	)	(5.3	)	(7.9	)	(7.2	)	3.6		1.5
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.

During the first quarter of 2017, TransGlobe:

• Reported positive working capital of $42.8 million (including $21.3 million in cash and cash equivalents) at March 31, 2017;

• Reported a net loss of $12.9 million , which includes a $1.2 million non-cash impairment loss on the Company's exploration and evaluation assets at SW Gharib and a $3.7 million unrealized derivative loss on commodity contracts (mark-to-market loss on the Company's hedging contracts). The Company's SW Gharib exploration and evaluation assets were written down to nil as no commercially viable quantities of oil have been discovered on these lands;

• Experienced a 60% increase in petroleum and natural gas sales compared to Q1-2016, which was principally due to a 66% increase in realized prices and the addition of sales from the recently acquired Canadian assets of $5.5 million. Realized pricing for the Company's petroleum and natural gas products are market driven;

Q1-2017 5

• Recorded positive funds flow from operations of $2.5 million compared with negative funds flow of $2.8 million in Q1-2016. The increase is primarily the result of a 66% increase in realized oil prices combined with a 23% reduction in operating costs. These positive variances were partially offset by an increase to royalties and current income taxes of $14.7 million;

• Reported a 39% increase in production volumes as compared to Q1-2016, which translates into an additional 4,673 boepd. The recently acquired Canadian assets contributed 2,782 boepd of additional production, and increased Egypt production accounted for the remaining variance. The increased Egypt production was the result of the production recovery plan undertaken in the second half of 2016, along with the first full quarter of production from NW Gharib, which contributed 982 bopd.

• Repaid $73.4 million (C$97.8 million) convertible debentures on March 31, 2017 with the proceeds from the prepayment agreement;

• Sold 303,817 barrels of inventoried entitlement crude oil to EGPC, resulting in a build in crude oil inventory of 0.3 million barrels; and

• Spent $10.7 million on capital programs, which was funded entirely with funds flow and cash on hand.

6 Q1-2017

2017 TO 2016 NET EARNINGS VARIANCES

			$ Per Share
	$000s		Diluted		% Variance
Q1-2016 net earnings (loss)	(16,249	)	(0.23	)
Cash items
Volume variance	(1,536	)	(0.02	)	9
Price variance	19,065		0.26		(117	)
Royalties	(12,496	)	(0.17	)	77
Expenses:
Production and operating	2,998		0.04		(18	)
Transportation	(198	)	—		1
Selling costs	828		0.01		(5	)
Cash general and administrative	(1,111	)	(0.02	)	7
Current income taxes	(2,245	)	(0.03	)	14
Realized foreign exchange gain (loss)	(20	)	—		—
Realized derivative gain (loss)	258		—		(2	)
Interest on long-term debt	(227	)	—		1
Other income	(212	)	—		1
Total cash items variance	5,104		0.07		(32	)
Non-cash items
Unrealized derivative loss	(3,729	)	(0.05	)	23
Unrealized foreign exchange gain (loss)	5,426		0.08		(33	)
Depletion and depreciation	1,504		0.02		(9	)
Asset retirement obligation accretion	(60	)	—		—
Unrealized gain (loss) on financial instruments	(1,782	)	(0.02	)	11
Impairment loss	(1,191	)	(0.02	)	7
Stock-based compensation	193		—		(1	)
Deferred income taxes	(2,197	)	(0.03	)	14
Deferred lease inducement	(5	)	—		—
Amortization of deferred financing costs	109		—		(1	)
Total non-cash items variance	(1,732	)	(0.02	)	11
Q1-2017 net earnings (loss)	(12,877	)	(0.18	)	(21	)

TransGlobe recorded a net loss of $12.9 million in Q1-2017 compared to a net loss of $16.2 million in Q1-2016. The average realized sales price in Q1-2017 was $37.41 per boe, versus $22.58 per bbl in the same period of the prior year. This 66% increase resulted in a positive cash variance of $19.1 million, which was the single largest earnings variance item. The positive sales price variance was partially offset by increased royalties and current income taxes, which created a negative earnings variance of $14.7 million in aggregate. The Company achieved cost reductions of $3.0 million on operating expenses in Q1-2017, which was primarily as a result of a decrease in oil treating fees, fuel costs and well services in Egypt, along with the impact of the devaluation of the Egyptian pound. Cash general and administrative expenses increased in Q1-2017 compared to Q1-2016, resulting in a negative earnings variance of $1.1 million. This increase was principally due to staffing alignment expenditures, along with staff additions associated with the Canadian acquisition in December 2016. The Company did not have a cargo lifting to sell TransGlobe's entitlement crude oil in Egypt in Q1-2017, resulting in no selling costs during the period. In Q1-2016, the Company completed one cargo lifting in Egypt, resulting in selling costs of $0.8 million.

The largest non-cash earnings variance item in Q1-2017 compared to Q1-2016 relates to the unrealized foreign exchange gain/loss. The fluctuation is mainly the result of a significant foreign exchange loss on the convertible debentures in Q1-2016 ($4.3 million). The convertible debentures were repaid during the first quarter of 2017. A reduction in future development costs of 38% created a lower depletable cost base and therefore lower depletion expense, resulting in a $1.5 million positive earnings variance for Q1-2017. The largest non-cash negative earnings variance in Q1-2017 compared to Q1-2016 related to the unrealized derivative loss on commodity contracts recorded in Q1-2017. The Company recorded a $3.7 million non-cash loss on its outstanding hedging contracts as at March 31, 2017, which was a result of marking the contracts to their respective market values. In Q1-2016, there were no such contracts outstanding. The mark-to-market adjustment on the convertible debentures created a negative earnings swing of $1.7 million, while a further $1.2 million negative variance was caused by a impairment loss recorded on the Company's exploration and evaluation assets at South West Gharib.

Q1-2017 7

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	2017	2016
	Q-1	Q-4	Q-3	Q-2	Q-1
Crude oil
Dated Brent average oil price (US$/Bbl)	53.68	49.19	45.79	45.52	33.70
Edmonton Sweet index (US$/bbl)	48.37	46.18	41.99	42.51	29.76
Natural gas
AECO (C$/mmbtu)	2.69	3.09	2.32	1.40	1.83
U.S./Canadian Dollar average exchange rate	1.323	1.334	1.305	1.289	1.375

The price of Dated Brent oil averaged 9% higher in Q1-2017 compared with Q4-2016. Egypt production is priced based on Dated Brent and shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost recovery barrels) which are assigned 100% to the Company. The contracts provide for cost recovery per quarter up to a maximum percentage of total revenue. Timing differences often exist between the Company's recognition of costs and their recovery as the Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSC, the Contractor's share of excess ranges between 0% and 30%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum cost recovery or cost oil ranges from 25% to 30% in Egypt. The balance of the production after maximum cost recovery is shared with the government (production sharing oil). Depending on the contract, the Egyptian government receives 70% to 86% of the production sharing oil or profit oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of production sharing oil increases when production exceeds pre-set production levels in the respective contracts. During times of increased oil prices, the Company receives less cost oil and may receive more production sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil. For reporting purposes, the Company records the government’s share of production as royalties and taxes (all taxes are paid out of the government’s share of production) which will increase during times of rising oil prices and will decrease in times of declining oil prices. If oil prices are sufficiently low and the Ras Gharib/Dated Brent differential is high, the cost oil portion may not be sufficient to cover operating costs and capital costs, or even operating costs alone. When this occurs, the non-recovered costs accumulate in the Company’s cost pools and are available to be offset against future cost oil during the term of the PSC and any eligible extension periods.

Egypt has been experiencing significant political changes over the past six years. While this has had an impact on the efficient operations of the government in general, business processes and the Company’s drilling and field operations have generally proceeded as normal. 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 $344.1 million from EGPC, reducing the balance due from EGPC to $18.6 million as at March 31, 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 approval to schedule liftings. Once liftings are approved and scheduled, the Company now enjoys a 30-day collection cycle as a result of direct marketing to third party international buyers who are generally required to post irrevocable letters of credit to support the sales prior to the cargo liftings.

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

The price of Edmonton Sweet index oil averaged 5% higher in Q1-2017 compared with Q4-2016. The price of AECO averaged 13% lower in Q1-2017 compared with Q4-2016.

8 Q1-2017

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest before Royalties (Boepd)

Production Volumes

	Three months ended March 31
	2017	2016
Egypt crude oil (bbls/d)	13,948	12,058
Canada crude oil (bbls/d)	566	—
Canada natural gas (mcf/d)	7,075	—
Canada NGLs (bbls/d)	1,037	—
Total Company (boe/d)	16,731	12,058

Sales Volumes (excludes volumes held as inventory)

	Three months ended March 31
	2017	2016
Egypt crude oil (bbls/d)	11,044	14,126
Canada crude oil (bbls/d)	566	—
Canada natural gas (mcf/d)	7,075	—
Canada NGLs (bbls/d)	1,037	—
Total Company (boe/d)	13,826	14,126

Netback

Consolidated netback
	Three months ended March 31
	2017		2016
(000s, except per Boe amounts)1	$	$/Boe	$	$/Bbl
Petroleum and natural gas sales	46,553	37.41	29,022	22.58
Royalties and other	24,092	19.36	11,595	9.02
Current taxes	5,420	4.36	3,175	2.47
Production and operating expenses	10,123	8.14	13,121	10.21
Transportation	198	0.16	—	—
Selling costs	—	—	828	0.64
Netback	6,720	5.39	303	0.24
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended March 31, 2017 and March 31, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at March 31, 2017).

Canada
	Three months ended March 31
	2017		2016
(000s, except per Boe amounts)	$	$/Boe	$	$/Boe
Crude oil sales	2,487	48.82	—	—
Natural gas sales	1,245	11.73	—	—
NGL sales	1,781	19.08	—	—
Total sales	5,513	22.02
Royalties	1,177	4.70	—	—
Production and operating expenses	1,577	6.30	—	—
Transportation	198	0.79	—	—
Netback	2,561	10.23	—	—

The Canadian financial information presented in the table above represents the first full quarter activity in for the Company's newly acquired Canadian assets.

Netbacks in Canada were $10.23 per Boe for the first quarter of 2017, which represents an increase of $3.60 per Boe as compared to the 12-day period that TransGlobe owned the Canadian assets in 2016. This increase is mainly due to an increase in realized sales prices of $2.90 per Boe combined with a 17% decrease in production and operating expenses on a per Boe basis.

TransGlobe pays royalties to the Alberta provincial governments 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.

Q1-2017 9

For the three months ended March 31, 2017, the Company incurred $1.2 million in royalty costs. Royalties amounted to 22% of petroleum and natural gas sales revenue in the three months ended March 31, 2017.

Egypt
	Three months ended March 31
	2017		2016
(000s, except per Bbl amounts)1	$	$/Bbl	$	$/Bbl
Oil sales	41,040	41.29	29,022	22.58
Royalties	22,915	23.05	11,595	9.02
Current taxes	5,420	5.45	3,175	2.47
Production and operating expenses	8,546	8.60	13,121	10.21
Selling costs	—	—	828	0.64
Netback	4,159	4.19	303	0.24
1 The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended March 31, 2017 and March 31, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at March 31, 2017).

Netbacks in Egypt increased by $3.95 per Bbl in Q1-2017 compared with Q1-2016. The increased netback was principally the result of an 83% increase in realized oil prices in Q1-2017 compared to Q1-2016.

Production and operating expenses decreased by $4.6 million in Q1-2017 compared with Q1-2016. This is principally the result of lower sales volumes in Q1-2017, causing more operating costs to be capitalized as crude oil inventory in the period. On a per Bbl basis, production and operating costs have decreased by 16% in Q1-2017 compared with Q1-2016. The most significant cost efficiencies were achieved in the areas of labour costs and equipment rentals. The devaluation of the Egyptian pound also had a significant positive impact on operating expenses in the quarter. The Company did not incur selling costs in Q1-2017 as all entitlement oil sold was purchased by EGPC.

Royalties and taxes as a percentage of revenue increased from 51% in Q1-2016 to 69% in Q1-2017. 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. If sales volumes had been equal to production volumes in Q1-2017, the Q1-2017 royalties and taxes as a percentage of revenue would have been 55%. 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 in Q1-2017 was $41.29/Bbl, which was $12.39/Bbl lower than the average Dated Brent oil price of $53.68/Bbl for the period (March 31, 2016 - $33.70/Bbl). The difference is due to a gravity/quality adjustment and is also impacted by the timing of direct sales.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)

	Three months ended March 31
	2017				2016
(000s, except Boe amounts)	$		$/Boe		$		$/Boe
G&A (gross)	4,749		3.82		4,132		3.21
Stock-based compensation	229		0.18		422		0.33
Capitalized G&A and overhead recoveries	(532	)	(0.43	)	(1,031	)	(0.80	)
G&A (net)	4,446		3.57		3,523		2.74

G&A expenses (net) increased 26% in Q1-2017 compared with Q1-2016 (30% on a per boe basis). G&A (gross) was elevated in Q1-2017 primarily due to staffing alignment expenditures incurred in the first quarter, along with staff additions associated with the Canadian acquisition in December 2016.

Capitalized G&A decreased 48% in Q1-2017 compared with Q1-2016 (46% 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 $0.4 million were capitalized in Q1-2016. In December 2016 the Company terminated its borrowing base facility, and the spending commitments are now secured by a cash collateralized letter of credit facility.

FINANCE COSTS

Finance costs for the three-month period ended March 31, 2017 increased to $1.5 million compared with $1.4 million in the same period in 2016.

	Three months ended March 31
(000s)	2017		2016
Convertible debentures	$	1,089	$	1,053
Long-term debt	128		—
Note payable	282		—
Borrowing base facility	—		218
Amortization of deferred financing costs	49		158
Finance costs	$	1,548	$	1,429

10 Q1-2017

Convertible Debentures

Interest expense on the convertible debentures for the three-month period ended March 31, 2017 was $1.1 million (Q1-2016 - $1.1 million). Interest on the convertible debentures is paid in Canadian dollars, and and therefore fluctuates 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 million crude oil prepayment agreement between its wholly owned subsidiary, TransGlobe Petroleum International Inc. ("TPI") and Mercuria Energy Trading SA ("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 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.

The prepayment agreement is subject to certain covenants, the details of which are outlined in Note 12 to the Company's Condensed Consolidated Interim Financial Statements.

Note Payable

On December 20, 2016, the Company closed the acquisition of the Harmattan petroleum properties in west central Alberta, Canada. The acquisition was partially funded by a vendor take-back note of C$15.0 million ($11.2 million). The note payable has a 24-month term and bears interest at a rate of 10% per annum. Principal repayments must be made on a quarterly basis, and must be equal to or greater than 50% of the net operating income of the acquired assets. The first principal payment was made on May 1, 2017.

DEPLETION AND DEPRECIATION (“DD&A”)

	Three months ended March 31
	2017		2016
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Egypt	6,114	6.15	9,894	7.70
Canada	2,302	9.19	—	—
Corporate	96	—	122	—
	8,512	6.84	10,016	7.79

In Egypt, DD&A decreased 20% on a per Bbl basis in the three months ended March 31, 2017 compared to the same period in 2016. The decrease is primarily related to a lower depletable cost base, which is the result of a 38% reduction in future development costs.

In Canada, DD&A was $9.19 per Bbl in the three months ended March 31, 2017, which was consistent with the DD&A rate for the 12 day period ended December 31, 2016 after the closing of the Canadian asset acquisition.

IMPAIRMENT LOSS

The Company recorded an non-cash impairment loss of $1.2 million on its exploration and evaluation assets during the first quarter of 2017. The impairment related to the South West Gharib concession in Egypt and represents the entire intangible exploration and evaluation asset balance at South West Gharib as at March 31, 2017. It was determined that an impairment loss was necessary as no commercially viable quantities of oil were discovered at South West Gharib, and no further drilling activities are planned.

CAPITAL EXPENDITURES

	Three months ended March 31
($000s)	2017	2016
Egypt	10,670	4,265
Canada	48	—
Total	10,718	4,265

In Egypt, total capital expenditures in Q1-2017 were $10.7 million (2016 - $4.3 million). During the first quarter, the Company drilled six exploration wells and one development well. Four wells were drilled at NW Gharib resulting in two oil discoveries (NWG 26 and NWG 27) and two dry holes (NWG 39 and NWG 42). At SW Gharib the Company drilled two exploration wells, both of which were dry and abandoned. At West Gharib, the second of two infill development oil wells in the Arta Red Bed pool was drilled. Total capitalized drilling costs in the quarter amounted to $6.1 million.

The Company also spent $4.1 million on seismic acquisition at NW Sitra during the quarter, and capitalized $0.5 million of G&A costs related to capital projects.

Q1-2017 11

OUTSTANDING SHARE DATA

As at March 31, 2017, the Company had 72,205,369 common shares issued and outstanding and 5,278,153 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. As a direct result of a continued lower oil price environment, TransGlobe’s debt-to-funds flow from operations ratio has significantly deteriorated and was negative 28.0 at March 31, 2017 (December 31, 2016 - negative 10.0) as a result of negative funds flow for the trailing 12 months. The Company's funds flow from operations varies significantly from quarter to quarter depending on the timing of tanker liftings, and these fluctuations in funds flow impact the Company's debt-to-funds flow from operations ratio. TransGlobe's management will continue to steward capital programs and focus on cost reductions in order to maintain balance sheet strength through the current low oil price environment.

The following table illustrates TransGlobe’s sources and uses of cash during the periods ended March 31, 2017 and 2016:

Sources and Uses of Cash
	Three months ended March 31
($000s)	2017		2016
Cash sourced
Funds flow from operations1	2,502		(2,830	)
Transfer from restricted cash	1,950		—
Increase in long-term debt	75,000		—
Other	235		—
	79,687		(2,830	)
Cash used
Capital expenditures	10,718		4,265
Deferred financing costs	1,500		—
Transfer to restricted cash	—		1
Repayment of convertible debentures	73,375		—
Finance costs	2,191		2,347
Other	—		906
	87,784		7,519
	(8,097	)	(10,349	)
Changes in non-cash working capital	(2,047	)	5,470
Increase (decrease) in cash and cash equivalents	(10,144	)	(4,879	)
Cash and cash equivalents – beginning of period	31,468		126,910
Cash and cash equivalents – end of period	21,324		122,031
Note:
1  Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital, and may not      be comparable to measures used by other companies.

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 $56.4 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 March 31, 2017, the Company had a working capital surplus of $42.8 million (December 31, 2016 - deficiency of $16.8 million). The increase to working capital in Q1-2017 is principally due to the repayment of the convertible debt, which was a current liability at year-end 2016, using the proceeds from the prepayment agreement as at March 31, 2017. The Company's working capital continues to be negatively impacted by low oil prices.

The Company now has a receivable balance of $18.6 million due from EGPC. During the first quarter of 2017, the Company sold 303,817 barrels of inventoried entitlement crude oil to EGPC for $12.7 million to cover in-country expenditures for Q1/Q2. As at March 31, 2017 the Company had collected $6.7 million of the $12.7 million in sales to EGPC. Accounts receivable offsets with local operational expenditures totaled $4.7 million and cash collections accounted for $2.9 million. Subsequent to the quarter the Company collected an additional $3.0 million in the form of accounts receivable offsets and $0.5 million in cash from EGPC.

The Company repaid its convertible debentures in full on March 31, 2017, which was the maturity date of the debentures. The convertible debentures were denominated in Canadian dollars, and the aggregate face value of all outstanding convertible debentures was C$97.8 million ($73.4 million). The repayment was made using the funds received by drawing on the $75 million prepayment agreement with Mercuria.

As at March 31, 2017, the Company had restricted cash of $16.4 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.

The Company has advanced discussions with a Canadian based lender to establish a Canadian borrowing base for capital and operations in Alberta. Upon completion, the facility would initially be used to repay the existing C$15 million vendor-take-back loan outstanding.

12 Q1-2017

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 March 31, 2017, the Company had 1,528,295 barrels of entitlement oil as inventory, which represents approximately eight months of entitlement oil production. Since the Company began directly marketing its oil on January 1, 2015, both increases and decreases in crude oil inventory levels have been experienced from quarter to quarter. Throughout 2015 there was a steady increase in crude oil inventory levels, as production outpaced sales. In Q1-2016 and Q2-2016, crude oil inventory levels dropped as a result of crude oil sales being greater than our production. During the second half of 2016 and Q1-2017, crude oil inventory levels once again grew as production was greater than sales. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows. The Company expects to complete both external sales (tanker liftings) and internal sales to EGPC in 2017, and anticipates that 2017 year-end crude oil inventory will be less than 1 million barrels, subject to the current tanker lifting schedule. Three tanker liftings are currently scheduled in 2017, with expected total shipment volumes of 1.5 to 1.6 MMBbl.

	Three months ended		Year ended
(bbls)	March 31, 2017		December 31, 2016
Product inventory, beginning of period	1,265,080		923,106
TransGlobe entitlement production	567,032		2,036,483
Tanker liftings	—		(1,694,509	)
EGPC sales	(303,817	)	—
Product inventory, end of period	1,528,295		1,265,080

COMMITMENTS AND CONTINGENCIES

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

($000s)		Payment Due by Period 1,2
	Recognized
	in Financial	Contractual	Less than
	Statements	Cash Flows	1 year	1-3 years	4-5 years
Accounts payable and accrued   liabilities	Yes - Liability	30,407	30,407	—	—
Long-term debt	Yes - Liability	75,000	—	24,966	50,034
Note payable	Yes - Liability	11,259	7,037	4,222	—
Financial derivative instruments	Yes - Liability	3,729	3,729	—	—
Office and equipment leases3	No	5,627	3,265	1,575	787
Minimum work commitments4	No	6,138	613	5,525	—
Total		132,160	45,051	36,288	50,821
Notes:
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at March 31, 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 ($0.6 million remaining as at March 31, 2017) 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. As at March 31, 2017, the Company had expended $34.4 million towards meeting that commitment. The Company received a six month extension to the initial exploration period, extending the initial exploration period to May 7, 2017. Subsequent to the end of the first quarter, the Company completed the initial exploration period work program and met all financial commitments.

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

Q1-2017 13

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 ($5.5 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 March 31, 2017, the Company had expended $4.5 million towards meeting that commitment.

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 March 31, 2017.

ASSET RETIREMENT OBLIGATION

At March 31, 2017, TransGlobe recorded an asset retirement obligation ("ARO") of $12.3 million (December 31, 2016 - $12.1 million) for the future abandonment and reclamation costs associated with the Harmattan assets. 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 0.75% and 2.31% 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.

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 addition, 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 three outstanding derivative commodity contracts as at March 31, 2017 (December 31, 2016 - nil), the fair values of which have been presented as liabilities on the Condensed Consolidated Interim Balance Sheet.

The following table summarizes TransGlobe’s outstanding derivative commodity contract positions as at March 31, 2017:

Financial BRENT Crude Oil Contracts
Term		Contract	Volume bbl	Sold Swap US$/bbl	Bought Put US$/bbl	Sold Call US$/bbl
28-Mar-2017	31-Dec-2017	Collar	300,000	—	45.00	56.00
24-Mar-2017	30-Jun-2017	Swap	500,000	50.65	—	—
27-Mar-2017	30-Sep-2017	Swap	425,000	51.00	—	—

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

Financial BRENT Crude Oil Contracts
Term		Contract	Volume bbl	Bought Put US$/bbl	Sold Call US$/bbl	Sold Put US$/bbl
7-Apr-2017	31-Mar-2018	3-Way Collar	250,000	53.00	61.15	44.00
13-Apr-2017	30-Jun-2018	3-Way Collar	250,000	54.00	63.10	45.00
13-Apr-2017	30-Sep-2018	3-Way Collar	250,000	54.00	64.15	45.00
13-Apr-2017	31-Dec-2018	3-Way Collar	250,000	54.00	65.45	45.00

The Company is required to enter into further hedges for 800,000 bbls in 2019 and 600,000 bbls in 2020 in accordance with the commitment to Mercuria.

14 Q1-2017

INTERNAL CONTROLS OVER FINANCIALREPORTING

TransGlobe's management designed and implemented internal controls over financial reporting, as defined under National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings, of the Canadian Securities Administrators and as defined in Rule 13a-15 under the US Securities Exchange Act of 1934. Internal controls over financial reporting is a process designed under the supervision of the Chief Executive Officer and the Chief Financial Officer and effected by the Board of Directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with 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 March 31, 2017 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

Q1-2017 15