EXHIBIT 99.3

MANAGEMENT'S DISCUSSION AND ANALYSIS

March 8, 2016

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 message to shareholders and the audited consolidated financial statements of the Company for the years ended December 31, 2015 and 2014, together with the notes related thereto (the "Consolidated Financial Statements"). The Consolidated 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. 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 to the United States Securities and Exchange Commission 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 2016, including expected 2016 average production, funds flow from operations, the 2016 capital program for exploration and development, the timing and method of financing thereof, the terms of drilling commitments under the 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.

2015 1

DIVIDENDS

During the year ended December 31, 2015, the Company paid the following dividends on its common shares:

Ex-dividend date	Record date	Payment date	Per share amount
March 12, 2015	March 16, 2015	March 31, 2015		$0.05
June 11, 2015	June 15, 2015	June 30, 2015		$0.05
September 11, 2015	September 15, 2015	September 30, 2015		$0.05
December 11, 2015	December 15, 2015	December 31, 2015		$0.025

The actual amount of future dividends will be proposed by management and subject to the approval and discretion of the Board. The Board reviews proposed dividend payments in conjunction with their review of quarterly financial and operating results. Future dividend levels will be dependent upon economic factors including commodity prices, capital expenditure programs and operating cash flows, and will be evaluated regularly to ensure that dividend payments do not compromise the strong financial position or the growth of the Company.

MANAGEMENT STRATEGY AND OUTLOOK

The Q1-2016 outlook provides information as to management’s expectation for results of operations for Q1-2016. Readers are cautioned that the Q1-2016 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.

Q1-2016 Outlook

It is expected that Q1-2016 production will average approximately 12,000 Bopd.  Funds flow in any given period will be dependent upon the timing of crude oil tanker liftings 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 2016. Funds flow and inventory levels are expected to fluctuate significantly from quarter to quarter due to the timing of liftings. The Company has sold one tanker of 544,042 barrels of entitlement crude oil in February 2016 at February Dated Brent less a quality differential of $14.05/bbl.

2016 Capital Budget

The Company's 2016 capital program of $41.0 million has $22.3 million (54%) allocated to exploration and $18.7 million (46%) to development. The $22.3 million exploration program includes $20.9 million for drilling up to 22 wells in the Eastern Desert with an additional $0.4 million for seismic acquisition in the Western Desert and $1.0 million for annual land costs. The $18.7 million 2016 development program includes: $4.5 million for three development wells in West Bakr K south field, $2.5 million for three development projects at NWG (NWG 1, 3 & 5) plus $4.6 million for development/optimization projects and $7.1 million for maintenance projects at West Gharib and West Bakr. It is anticipated that the Company will fund its 2016 capital budget from funds flow from operations and working capital.

The 2016 capital program is summarized in the following table:

	TransGlobe 2016 Capital ($MM)							Gross Well Count
	Development			Exploration			Total	(Wells)
Concession	Wells	Maint	Projects	Wells	Bonus	Seismic		Devel	Explor	Total
West Gharib	—	3.5	2.5	—	—	—	6.0	—	—	—
West Bakr	4.5	3.6	2.1	—	—	—	10.2	3	—	3
NW Gharib	—	—	2.5	11.6	0.2	—	14.3	—	13	13
SW Gharib	—	—	—	6.8	0.2	—	7.0	—	6	6
SE Gharib	—	—	—	2.5	0.2	—	2.7	—	3	3
South Ghazalat	—	—	—	—	0.2	—	0.2	—	—	—
NW Sitra	—	—	—	—	0.2	0.4	0.6	—	—	—
2016 Total	$4.5	$7.1	$7.1	$20.9	$1.0	$0.4	$41.0	3	22	25
Splits (%)	46%			54%			100%	12%	88%	100%

As a result of continuing low oil prices, management continues to seek opportunities to reduce the 2016 budget through outright cost reductions, delays and deferrals. Should low oil prices persist throughout 2016, management currently expects the actual spending in 2016 to be reduced by approximately $10 million as a result of lower spending on drilling development wells, delays on maintenance and projects and the deferral of some exploration spending into 2017. In order to achieve the deferral of exploration spending into 2017 the Company will need to obtain the cooperation and approval of EGPC.

The Company also continues to actively pursue opportunities to grow through strategic acquisitions. The oil price downturn that began in 2014 has created opportunities in the market. TransGlobe is committing significant internal resources to examining these opportunities in 2016.

2 2015

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 prescribed by IFRS and therefore may not be comparable to similar measures used by other companies.

Reconciliation of Funds Flow from Operations

($000s)	2015		2014
Cash flow from operating activities	77,526		146,977
Changes in non-cash working capital	(86,428	)	(26,488	)
Funds flow from operations1	(8,902	)	120,489
1  Funds flow from operations does not include interest or financing costs. Interest expense is included in financing costs on the Consolidated Statements of Earnings and     Comprehensive Income. Cash interest paid is reported as a financing activity on the Consolidated 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.

Recycle ratio

Recycle ratio is a measure that is used to evaluate the efficiency of the Company's capital program by comparing the cost of finding and developing both proved reserves and proved plus probable reserves with the netback from production. The ratio is calculated by dividing the netback by the proved and proved plus probable finding and development cost on a per Bbl basis. Recycle ratio 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 exploration and production company whose activities are concentrated in the Arab Republic of Egypt (“Egypt”).

2015 3

SELECTED ANNUAL INFORMATION

($000s, except per share, price and volume amounts)	2015		% Change	2014		% Change	2013
Operations
Average production volumes (Bopd)	14,511		(10)	16,103		(12)	18,284
Inventory (Bbl)	923,106		100	—		(100)	37,326
Average sales volumes (Bopd)	11,977		(26)	16,161		(11)	18,193
Average sales price ($/Bbl)	42.93		(51)	86.99		(9)	95.70
Oil sales	187,665		(63)	513,153		(19)	635,496
Oil sales, net of royalties	92,212		(66)	274,594		(13)	315,316
Cash flow from operating activities	77,526		(47)	146,977		(26)	199,508
Funds flow from operations1	(8,902	)	(107)	120,489		(13)	139,118
- Basic per share	(0.12	)		1.61			1.88
- Diluted per share2	(0.12	)		1.46			1.70
Net earnings	(105,600	)	(1,020)	11,482		(80)	58,512
Net earnings (loss) - diluted	(105,600	)	6,347	(1,638	)	(103)	53,036
- Basic per share	(1.44	)		0.15			0.79
- Diluted per share	(1.44	)		(0.02	)		0.65
Dividends paid	12,865		(31)	18,752		100	—
Dividends paid per share	0.175		(30)	0.25		100	—
Total assets	455,500		(30)	654,058		(3)	675,800
Cash and cash equivalents	126,910		(10)	140,390		15	122,092
Convertible debentures	63,848		(8)	69,093		(21)	87,539
Debt-to-funds flow ratio3	(7.2	)		0.6			0.6
Reserves
Total Proved (MMBbl)4	17.5		(21)	22.1		(30)	31.6
Total Proved plus Probable (MMBbl)4	28.7		(14)	33.5		(26)	45.3
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  Funds flow from operations per share (diluted) was not impacted by the convertible debentures for the year ended December 31, 2015, as the convertible debentures were not dilutive for the year. Funds flow from operations per share (diluted) prior to the dilutive impact of the convertible debentures was $1.59 for the year ended December 31, 2014 and $1.84 for the year ended December 31, 2013.
3   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 for the trailing        12 months, and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
4  As determined by the Company's independent reserves evaluator, DeGolyer and MacNaughton Canada Limited ("DeGolyer") of Calgary, Alberta, in their reports dated January 15, 2016, January 30, 2015 and January 15, 2014 with effective dates of December 31, 2015, December 31, 2014 and December 31, 2013, respectively. The reports of DeGolyer have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time and National Instrument 51-101.

In 2015 compared with 2014, TransGlobe:

• Maintained a strong financial position, reporting positive working capital of $153.8 million (including cash and cash equivalents of $126.9 million) at December 31, 2015;

• Experienced a decrease in oil sales primarily as a result of a 51% decrease in realized oil prices along with a 26% reduction in sales volumes compared to 2014. Sales volumes were significantly lower than production volumes in 2015 as the Company accumulated crude oil inventory of 923,106 barrels of entitlement oil;

• Reported a net loss of $105.6 million, which includes an $85.4 million non-cash impairment loss on the Company's petroleum properties and goodwill, offset by an associated deferred tax recovery of $36.0 million. The majority of the impairment loss was split between the West Gharib concession ($50.9 million), the West Bakr concession ($23.1 million) and the East Ghazalat concession ($3.2 million). In addition, an impairment loss of $8.2 million was recognized on the Company's goodwill balance. The Company also experienced a foreign exchange gain of $11.6 million and a $6.6 million unrealized non-cash loss on the fair value of the convertible debenture;

• Recorded negative funds flow from operations of $8.9 million, compared with positive funds flow of $120.5 million in 2014. The decrease in funds flow from operations in 2015 is principally due to a significant reduction in realized oil prices and sales volumes. The Company now directly sells all of its entitlement oil production in Egypt, and the timing of cargo liftings has a direct impact to funds flow in any given period. As at the end of 2015, TransGlobe held 519,317 barrels of West Gharib and 403,789 barrels of West Bakr entitlement oil as inventory. Had all entitlement oil produced during the year been sold, at the average price received, during the same period it was produced, funds flow for the year would have been approximately $15.0 million ($0.20/share);

• Spent $44.9 million on capital programs, which was funded through the use of working capital and cash generated by operating activities;

• Paid a total of $12.9 million ($0.175/share) in dividends; and

• Collected a total of $95.0 million from EGPC (2014 - $233.5 million), bringing the 2015 year-end accounts receivable balance to $22.9 million.

4 2015

2015 TO 2014 NET EARNINGS VARIANCES

			$ Per Share
	$000s		Diluted		% Variance
2014 net earnings1	11,482		0.15
Cash items
Volume variance	(65,590	)	(0.89	)	(570	)
Price variance	(259,898	)	(3.54	)	(2,264	)
Royalties	143,106		1.95		1,246
Expenses:
Production and operating	23,772		0.32		207
Selling costs	(4,557	)	(0.06	)	(40	)
Cash general and administrative	4,884		0.07		43
Exploration	642		0.01		6
Current income taxes	37,556		0.51		327
Realized foreign exchange gain (loss)	270		—		2
Realized derivative gain (loss)	(688	)	(0.01	)	(6	)
Interest on long-term debt	1,037		0.01		9
Other income	(8,888	)	(0.12	)	(77	)
Total cash items variance	(128,354	)	(1.75	)	(1,117	)
Non-cash items
Unrealized foreign exchange gain (loss)	4,857		0.07		42
Depletion and depreciation	8,714		0.12		76
Unrealized gain (loss) on financial instruments	(18,204	)	(0.25	)	(159	)
Impairment loss	(14,000	)	(0.19	)	(122	)
Stock-based compensation	3,127		0.04		27
Deferred income taxes	26,228		0.36		228
Deferred lease inducement	546		0.01		5
Loss on disposition	(252	)	—		(2	)
Amortization of deferred financing costs	256		—		2
Total non-cash items variance	11,272		0.16		97
2015 net earnings	(105,600	)	(1.44	)	(1,020	)
1 Diluted earnings per share for 2014 is presented prior to the dilutive effect of the convertible debentures in the year.

The Company recorded a net loss of $105.6 million in 2015 compared to earnings of $11.5 million in 2014. The negative cash earnings impact of significantly lower oil prices and reduced sales volumes totaled $325.5 million in aggregate compared to year-end 2014, which was partially offset by decreased royalties and current income taxes of $180.7 million. Production and operating expenses were reduced in 2015 by $23.8 million, resulting in a significant positive earnings impact year over year. The decrease was related primarily to decreases in activity levels, along with the capitalization of $9.1 million of production and operating costs into the Company's year-end product inventory balance. Cash general and administrative expenses decreased $4.9 million in 2015 as compared to 2014, principally due to a reduction in payroll and insurance costs, along with the weakening of the Canadian dollar and Egyptian pound. The Company began lifting and directly marketing its entitlement oil from the eastern desert to international buyers in 2015. The Company completed three direct sales of crude oil to third party buyers during 2015, which resulted in selling costs (mainly transportation and marketing fees). A further negative cash variance was caused by the reverse termination fee received from Caracal in Q2-2014, which was included in other income.

The largest non-cash negative earnings variance item from 2015 to 2014 relates to the mark-to-market adjustment on the convertible debentures, which created a negative earnings swing of $18.2 million. The Company recorded an impairment loss of $85.4 million on its petroleum properties and goodwill in 2015, compared with a $71.4 million impairment loss in 2014. The 2015 impairment loss caused a significant reduction in the accounting basis of the Company's petroleum properties, which resulted in a deferred tax recovery of $36.0 million in 2015, which represents a $26.2 million positive earnings variance as compared to 2014.

BUSINESS ENVIRONMENT

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

	2015	2014
Dated Brent average oil price ($/Bbl)	52.36	99.03
U.S./Canadian Dollar average exchange rate	1.2790	1.1048

2015 5

The price of Dated Brent oil averaged 47%lower in 2015 compared with 2014. All of the Company’s 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). In Egypt, depending on the contract, the 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 five years. While this has had an impact on the efficient operations of the government in general, business processes and the Company’s 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. The Company collected a substantial amount on overdue receivables in 2014 ($233.5 million) and 2015 ($95.0 million), which reduced the total accounts receivable balance to $117.6 million ($115.6 million due from EGPC) as at December 31, 2014 and $22.9 million ($21.9 million due from EGPC) at the end of 2015. The Company's credit risk, as it relates to EGPC, has now been effectively eliminated due to the significant collections from EGPC combined with the 30-day collection cycle that the Company now enjoys as a result of direct marketing to third party international buyers who are required to post irrevocable letters of credit to support the sales prior to the cargo liftings.

6 2015

SELECTED QUARTERLY FINANCIAL INFORMATION

	2015								2014
($000s, except per share,
price and volume amounts)	Q-4		Q-3		Q-2		Q-1		Q-4		Q-3		Q-2	Q-1
Average production volumes (Bopd)	13,425		14,683		15,064		14,886		15,172		15,109		16,112	18,067
Inventory (Bbl)	923,106		350,869		253,325		179,730		—		13,025		4,500	49,103
Average sales volumes (Bopd)	7,205		13,620		14,251		12,876		15,139		15,132		16,485	17,932
Average sales price ($/Bbl)	32.38		39.35		48.31		46.82		66.41		88.59		96.14	94.89
Oil sales	21,460		49,307		62,647		54,251		92,488		123,317		144,208	153,140
Oil sales, net of royalties	3,979		24,700		33,960		29,573		52,340		67,848		76,040	78,366
Cash flow from operating activities	6,414		28,741		24,323		18,048		113,422		(3,123	)	33,467	3,211
Funds flow from operations1	(11,108	)	(1,497	)	6,991		(3,288	)	15,932		28,885		43,185	32,487
Funds flow from operations per share
- Basic	(0.15	)	(0.02	)	0.09		(0.04	)	0.21		0.38		0.58	0.44
- Diluted	(0.15	)	(0.02	)	0.09		(0.04	)	0.19		0.35		0.57	0.43
Net earnings (loss)	(35,255	)	(46,568	)	(12,580	)	(11,197	)	(50,571	)	19,162		26,199	16,692
Net earnings (loss) - diluted	(35,255	)	(54,159	)	(12,580	)	(13,577	)	(63,384	)	14,934		26,199	16,692
Net earnings per share
- Basic	(0.49	)	(0.64	)	(0.17	)	(0.15	)	(0.67	)	0.26		0.35	0.22
- Diluted	(0.49	)	(0.68	)	(0.17	)	(0.17	)	(0.77	)	0.18		0.35	0.22
Dividends paid	1,805		3,594		3,703		3,763		3,762		3,761		11,229	—
Dividends paid per share	0.025		0.05		0.05		0.05		0.05		0.05		0.15	—
Total assets	455,500		501,808		599,744		614,345		654,058		720,306		705,859	692,341
Cash and cash equivalents	126,910		126,874		122,961		126,101		140,390		77,939		110,057	107,607
Convertible debentures	63,848		65,682		74,421		65,511		69,093		83,229		88,814	87,765
Debt-to-funds flow ratio2	(7.2	)	3.6		1.5		0.8		0.6		0.6		0.6	0.6
1 Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
2  Debt-to-funds flow ratio is a measure that represents total long-term debt (including the current portion) plus convertible debentures over funds flow from operations from the trailing 12 months and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".

During the fourth quarter of 2015, TransGlobe:

• Maintained a strong financial position, reporting positive working capital of $153.8 million (including cash and cash equivalents of $126.9 million) at December 31, 2015;

• Reported a net loss of $35.3 million, which includes a $22.3 million non-cash impairment loss on the Company's petroleum properties, along with an associated deferred tax recovery of $3.2 million;

• Paid a quarterly dividend of $1.8 million ($0.025/share) during the fourth quarter of 2015;

• Recorded negative funds flow from operations of $11.1 million, mainly because the Company did not sell any Eastern Desert entitlement oil during the quarter. The Company now directly sells all of its entitlement oil production in Egypt, and the timing of cargo liftings has a direct impact to funds flow in any given period. As at the end of the fourth quarter, TransGlobe held 519,317 barrels of West Gharib and 403,789 barrels of West Bakr entitlement oil as inventory. Had all entitlement oil produced during the quarter been sold at Q4-2015 realized pricing, funds flow for the quarter would have been approximately $1.0 million; and

• Experienced a decrease in oil sales compared to Q3-2015, mainly because the Company did not sell any of its West Gharib or West Bakr entitlement oil during the quarter.

2015 7

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest before Royalties (Bopd)

Production Volumes

	2015	2014
Egypt	14,466	15,767
Yemen	45	336
Total Company	14,511	16,103

Sales Volumes (excludes volumes held as inventory)

	2015	2014
Egypt	11,935	15,767
Yemen	42	394
Total Company	11,977	16,161

Netback

Accounting netback
	2015				2014
(000s, except per Bbl amounts)1	$		$/Bbl		$		$/Bbl
Egypt	13,843		3.18		136,453		23.71
Yemen	(4,367	)	(284.86	)	(1,366	)	(9.50	)
Consolidated	9,476		2.18		135,087		22.90
1 The Company achieved the netbacks above on sold barrels of oil for the year ended December 31, 2015 and December 31, 2014 (these figures do not include TransGlobe entitlement barrels held as inventory at December 31, 2015).

Notional netback
	2015				2014
(000s, except per Bbl amounts)1	$		$/Bbl		$		$/Bbl
Egypt	37,738		7.15		136,453		23.71
Yemen	(4,367	)	(284.86	)	(1,366	)	(9.50	)
Consolidated	33,371		6.31		135,087		22.90
1  It is estimated that the Company would have achieved the netbacks noted above if the Company’s sales volumes had been equivalent to production volumes, and if all sales had taken place at the average realized selling price for the period.

Egypt - accounting netback
	2015		2014
(000s, except per Bbl amounts)1	$	$/Bbl	$	$/Bbl
Oil sales	187,055	42.94	498,556	86.63
Royalties	95,330	21.88	235,154	40.86
Current taxes	25,284	5.80	61,972	10.77
Production and operating expenses	48,041	11.03	64,977	11.29
Selling costs	4,557	1.05	—	—
Netback	13,843	3.18	136,453	23.71

Egypt - notional netback
	2015		2014
(000s, except per Bbl amounts)1	$	$/Bbl	$	$/Bbl
Oil sales	221,394	41.93	498,556	86.63
Royalties	95,330	18.05	235,154	40.86
Current taxes	25,284	4.79	61,972	10.77
Production and operating expenses	57,162	10.83	64,977	11.29
Selling costs	5,880	1.11	—	—
Netback	37,738	7.15	136,453	23.71
1 It is estimated that the Company would have achieved the netbacks noted above if the Company’s sales volumes had been equivalent to production volumes, and if all sales had taken place at the average realized selling price for the period.

8 2015

The netback per Bbl in Egypt decreased 87% in 2015 compared with 2014. The decreased netbacks were principally the result of a 50% reduction in realized oil prices in 2015 compared to 2014, along with the build up of entitlement crude oil inventory in 2015.

Production and operating expenses decreased by $16.9 million in 2015 compared with 2014. This is principally the result of reduced activity levels combined with the Company's efforts to achieve cost efficiencies in a lower oil price environment. These cost savings have translated to a reduction of 2% on a per Bbl basis despite a 24% decrease in sales volumes in the current year. Also contributing to the reduction in netback per Bbl were selling costs (mainly transportation and marketing fees) incurred on the direct sale of the Company's crude oil. TransGlobe completed three direct sales of crude oil to third party buyers during the year-ended December 31, 2015. The Q1-2015 lifting was sold CIF (cost, insurance and freight) destination, resulting in significantly higher selling costs in the first quarter, whereas the Q2-2015 and Q3-2015 liftings were sold FOB shipping point.

As at December 31, 2015, the Company held 923,106 barrels of crude oil as product inventory. If TransGlobe had sold all entitlement crude produced at average realized pricing for the period in which it was produced, the total netback for Egypt would have been approximately $37.7 million ($7.15 per Bbl) as at December 31, 2015.

Royalties and taxes as a percentage of revenue were 64% in 2015 compared with 60% for 2014. If all crude oil had been sold in the period in which it was produced in 2015, royalties and taxes as a percentage of revenue would have been 54% for the year-ended December 31, 2015. When oil prices fall it takes more barrels to recover costs, thereby reducing (or eliminating) excess cost oil barrels, the majority of which are allocated to the government. Unrecovered costs during the period are carried forward to future quarters for recovery, should prices/revenue increase.

The average selling price for the year-ended December 31, 2015 was $42.94/Bbl, which was $9.42/Bbl lower than the average Dated Brent oil price of $52.36/Bbl for the year (December 31, 2014 - $99.03/Bbl). The difference is due to a gravity/quality adjustment and is also impacted by the timing of direct sales.

Yemen

In January 2015, the Company provided notice of its relinquishment of its interests in Block 32 and Block 72 in Yemen due to project economics and security issues. The relinquishment of Blocks 32 and 72 were effective March 31, 2015 and February 28, 2015, respectively.

Although TransGlobe’s Yemen properties contributed minimal sales volumes during the twelve months of the year, the Company continued to incur the majority of the operating costs associated with the blocks. These factors resulted in a negative netback per Bbl of $284.86 in Yemen for the year ended December 31, 2015. There were no sales in Yemen for the three months ended December 31, 2015.

On October 29, 2015 the Company disposed of its last remaining interests (25% interest in Blocks S-1 and 75) in Yemen.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)

	2015				2014
(000s, except per Bbl amounts)	$		$/Bbl		$		$/Bbl
G&A (gross)	24,439		5.59		31,351		5.31
Stock-based compensation	2,787		0.64		5,914		1.00
Capitalized G&A and overhead recoveries	(5,917	)	(1.35	)	(7,399	)	(1.25	)
G&A (net)	21,309		4.88		29,866		5.06

G&A expenses (net) decreased 29% in 2015 compared with 2014 (4% decrease on a per bbl basis). G&A (gross) has decreased in 2015 principally due to a reduction in payroll and insurance costs, along with foreign exchange rate fluctuations. The majority of the increase in G&A (gross) per bbl is due to reduced sales volumes in 2015 as compared to 2014. While production volumes were down year over year, the majority of the decrease in sales volumes is due to the fact that the Company did not sell all of its entitlement oil in 2015. As at December 31, 2015, the Company held crude oil entitlement inventory of 923,106 barrels (2014 - nil). If all crude oil produced in 2015 was sold during the year, G&A (gross) per bbl would have been $4.61, representing a 13% decrease as compared to 2014.

Equity-settled stock-based compensation expense decreased $2.6 million and cash-settled stock-based compensation decreased $0.6 million in 2015 compared to 2014. The decrease in equity-settled stock-based compensation is mainly the result of a significant decrease in the fair value of stock options granted in 2015 as compared to 2014. The decrease in cash-settled stock-based compensation is mostly due to the decrease in the Company's share price in 2015.

FINANCE COSTS

Finance costs for the year ended December 31, 2015decreased to $6.3 million compared with $7.6 million in 2014. Interest expense on the convertible debentures decreased to $4.7 million in 2015, compared with $5.3 million in 2014. The decrease in this portion of the interest expense is due to the weakening of the Canadian dollar, as the interest on the convertible debentures is paid in Canadian dollars. The remaining decrease in interest expense is due to lower utilization of the Company's Borrowing Base Facility in 2015 as compared to 2014.

(000s)	2015		2014
Interest expense	$	5,425	$	6,462
Amortization of deferred financing costs	849		1,105
Finance costs	$	6,274	$	7,567

2015 9

The Company had no long-term debt outstanding under the Borrowing Base Facility as at December 31, 2015 (December 31, 2014 - $nil). As at December 31, 2015 the borrowing base available to the Company was $39.3 million (December 31, 2014 - $85.5 million). The Borrowing Base Facility bears interest at LIBOR plus an applicable margin that varies from 5.0% to 5.5% depending on the amount drawn under the facility, and the term of the facility extends to December 31, 2017.

In February 2012, the Company sold, on a bought-deal basis, C$97.8 million ($97.9 million) aggregate principal amount of convertible unsecured subordinated debentures with a maturity date of March 31, 2017. The debentures are convertible at any time and from time to time into common shares of the Company at a price of C$13.63 per common share. The debentures were not redeemable by the Company on or before March 31, 2015 other than in limited circumstances in connection with a change of control of TransGlobe. After March 31, 2015 and prior to March 31, 2017, the debentures may be redeemed by the Company at a redemption price equal to the principal amount plus accrued and unpaid interest, provided that the weighted-average trading price of the common shares for the 20 consecutive trading days ending five trading days prior to the date on which notice of redemption is provided is not less than 125 percent of the conversion price (or C$17.04 per common share). The conversion price of the convertible debentures will adjust for any amounts paid out as dividends on the common shares of the Company, provided that the dividend payment causes the conversion price to change by 1% or more. Interest of 6% is payable semi-annually in arrears on March 31 and September 30. At maturity or redemption, the Company has the option to settle all or any portion of principal obligations by delivering to the debenture holders sufficient common shares to satisfy these obligations.

DEPLETION AND DEPRECIATION (“DD&A”)

	2015		2014
(000s, except per Bbl amounts)	$	$/Bbl	$	$/Bbl
Egypt	42,366	9.73	49,387	8.58
Yemen	—	—	1,741	12.11
Corporate	509	—	461	—
	42,875	9.81	51,589	8.75

In Egypt, DD&A increased 13% on a per Bbl basis in 2015 as compared to 2014. This increase is mostly due to a lower reserve base over which to deplete costs in Egypt, which was partially offset by reduced future development costs and a decrease in the capital base being depleted.

In Yemen, no DD&A expense was recorded in 2015 due to the fact that the Company wrote its Yemen assets down to nil on the 2014 year-end Consolidated Balance Sheet. The Company currently has no remaining interests in Yemen.

IMPAIRMENT OF PETROLEUM PROPERTIES AND GOODWILL

The Company recorded an impairment loss of $85.4 million in aggregate on its producing properties and goodwill in 2015. The impairment loss recorded on the Company's petroleum properties amounted to $77.2 million, which was split between the West Gharib concession ($50.9 million), the West Bakr concession ($23.1 million) and the East Ghazalat concession ($3.2 million). At West Gharib and West Bakr, the impairment losses were recorded to reduce the carrying value of the assets to their recoverable amounts, which were estimated as the net present value of proved plus probable reserves, discounted at 15%. The recoverable amounts of the assets declined from prior year due to the continued decline in oil prices throughout 2015. The East Ghazalat concession was sold in October 2015, and an impairment loss was booked in Q3-2015 to reduce the carrying amount of the assets to the value being paid for the assets in the disposal transaction. An impairment loss of $8.2 million was recognized on the Company's goodwill balance in 2015. The entire goodwill balance was related to the West Gharib acquisition. This impairment loss reduces the carrying value of goodwill to zero. The after-tax cash flows used to determine the recoverable amount of the cash-generating unit to which goodwill was assigned were discounted using an estimated weighted average cost of capital of 15%.

The Company completed an impairment evaluation on all exploration and evaluation ("E&E") assets as at December 31, 2015. E&E assets are tested for impairment when they are reclassified to petroleum properties and also if facts and circumstances suggest that the carrying amount of E&E assets may exceed their recoverable amount. Indications of impairment include:

1. Expiry or impending expiry of lease with no expectation of renewal;

2. Lack of budget or plans for substantive expenditures on further E&E;

3. Discontinuance of E&E activities due to a lack of commercially viable discoveries; and

4. Carrying amount of E&E asset is unlikely to be recovered in full from a successful development project.

The Company considered the applicability of these impairment indicators to its exploration concessions (NW Gharib, SW Gharib, SE Gharib, South Ghazalat, NW Sitra and South Alamein) and determined that it was premature to conclude that impairment indicators were present as at December 31, 2015. The success, or lack thereof, of the Company's 2016/2017 exploration drilling program will provide additional insight into whether the Company's E&E assets should be subject to future impairment write-downs.

In 2014, the Company recorded an impairment loss of $71.4 million in aggregate on its exploration and producing properties. The majority of the impairment loss ($51.5 million) related to the Company's Yemen properties, which were written down to a net book value of zero on the December 31, 2014 Consolidated Balance Sheet. In January 2015, the Company provided notice of relinquishment of its interests in Block 32 and Block 72 in Yemen due to ongoing political and tribal turmoil in the vicinity of these blocks. These assets had an aggregate carrying value of $13.8 million, and were written off in full as at December 31, 2014. The Company's reserves at Block S-1 were classified as contingent resources as at December 31, 2014 due primarily to the lack of production from the block for an extended period of time and management's assessment of the unlikelihood of production resuming in the near future. Because there were no proved plus probable reserves assigned to Block S-1, the net present value of the oil reserves on the block were assigned a nil valuation, and the net book value of the block was written off in full ($31.5 million). Furthermore, the Company wrote off its exploration assets at Block 75 ($6.1 million) since there were no plans for further spending on the exploration block as at December 31, 2014.

10 2015

In Egypt, the Company recorded an impairment loss of $3.3 million on its West Bakr concession and $16.6 million on its East Ghazalat concession in 2014. On the East Ghazalat concession, $6.4 million of the impairment loss related to the North Dabaa discovery, which was not expected to attribute any future value to TransGlobe based on current pricing and cost structure. The remaining $10.2 million impairment at East Ghazalat and the $3.3 million impairment at West Bakr were recorded to reduce the carrying value of the assets to their recoverable amounts, which were estimated as the net present value of proved plus probable reserves, discounted at 15%. The recoverable amounts of the assets declined from prior year due to reduced quantities of reserves and lower oil prices in late 2014.

CAPITAL EXPENDITURES

($000s)	2015	2014
Egypt	44,747	105,169
Yemen	—	1,537
Corporate	155	833
Total	44,902	107,539

In Egypt, total capital expenditures in 2015 were $44.7 million (2014 - $105.2 million). The Company drilled five wells in Egypt in 2015 (three at NW Gharib, one at West Bakr and one at West Gharib). All drilling activity took place in the first quarter of the year. The Company spent $13.9 million on seismic acquisition, processing and interpretation in 2015, all of which has been capitalized as exploration and evaluation assets. The largest contributor to seismic costs during the year has been the South Ghazalat 3-D acquisition, which was under budget at $11.9 million. The Company has expended $4.4 million on facilities construction and improvements, and has capitalized $5.9 million of G&A costs related to capital projects.

The Company paid a signing bonus in the amount of $2.0 million upon ratification of the NW Sitra concession agreement, which has been capitalized as an intangible exploration and evaluation asset.

FINDING AND DEVELOPMENT COSTS/FINDING, DEVELOPMENT AND NET ACQUISITION COSTS

National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), specifies how finding and development (“F&D”) costs should be calculated. NI 51-101 requires that exploration and development costs incurred in the year along with the change in estimated future development costs be aggregated and then divided by the applicable reserve additions. The calculation specifically excludes the effects of acquisitions and dispositions on both reserves and costs. TransGlobe believes that the provisions of NI 51-101 do not fully reflect TransGlobe’s on-going reserve replacement costs. Since acquisitions can have a significant impact on TransGlobe’s annual reserves replacement cost, to not include these amounts could result in an inaccurate portrayal of TransGlobe’s cost structure. Accordingly, TransGlobe has also reported finding, development and acquisition (“FD&A”) costs that incorporate acquisitions, net of any dispositions during the year.

Proved
($000s, except volumes and $/Bbl amounts)	2015		2014		2013
Total capital expenditure	42,902		107,539		86,570
Acquisitions1	2,000		—		42,600
Dispositions	(1,500	)	—		—
Net change from previous year’s future capital	(9,024	)	(16,447	)	33,027
	34,378		91,092		162,197
Reserve additions and revisions (MBbl)
Exploration and development	990		(3,619	)	5,542
Acquisitions, net of dispositions	(300	)	—		—
Total reserve additions (MBbl)	690		(3,619	)	5,542
Average cost per Bbl
F&D2	34.22		—		21.58
FD&A2	49.83		—		29.27
Three-year weighted average cost per Bbl
F&D2	83.93		19.93		10.81
FD&A2	110.07		25.34		11.86
1   The 2015 Acquisitions figure relates to acquisition costs on the NW Sitra concession agreement that was awarded to the Company in the 2014 EGPC bid round and ratified into law in 2015. The 2013 Acquisitions figure consists entirely of acquisition costs on the four new concession agreements that were awarded to the Company in the 2011/2012 EGPC bid round and ratified into law in 2013. For the purpose of the FD&A cost per Bbl calculation, the costs have been treated as land acquisition costs.
2    In 2014, F&D and FD&A costs were negative. The negative F&D and FD&A costs are driven primarily by negative reserve revisions, most of which relate to the Company's West Gharib concession (specifically, the Lower Nukhul reserves in the Arta/East Arta fields) and the reclassification of Yemen reserves to contingent resources. The Company did not make sufficient new discoveries to offset the negative technical revisions, resulting in negative F&D and FD&A costs which are meaningless on a per Bbl basis.
Note: The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

2015 11

Proved Plus Probable
($000s, except volumes and $/Bbl amounts)	2015		2014		2013
Total capital expenditure	42,902		107,539		86,570
Acquisitions1	2,000		—		42,600
Dispositions	(1,500	)	—		—
Net change from previous year’s future capital	(30,741	)	(21,948	)	25,876
	12,661		85,591		155,046
Reserve additions and revisions (MBbl)
Exploration and development	1,498		(5,919	)	3,233
Acquisitions, net of dispositions	(936	)	—		—
Total reserve additions (MBbl)	562		(5,919	)	3,233
Average cost per Bbl
F&D2	8.03		—		34.78
FD&A2	22.53		—		47.96
Three-year weighted average cost per Bbl
F&D3	—		30.06		10.02
FD&A3	—		39.10		10.23
1   The 2015 Acquisitions figure relates to acquisition costs on the NW Sitra concession agreement that was awarded to the Company in the 2014 EGPC bid round and ratified into law in 2015. The 2013 Acquisitions figure consists entirely of acquisition costs on the four new concession agreements that were awarded to the Company in the 2011/2012 EGPC bid round and ratified into law in 2013. For the purpose of the FD&A cost per Bbl calculation, the costs have been treated as land acquisition costs.
2    In 2014, F&D and FD&A costs were negative. The negative F&D and FD&A costs are driven primarily by negative reserve revisions, most of which relate to the Company's West Gharib concession (specifically, the Lower Nukhul reserves in the Arta/East Arta fields) and the reclassification of Yemen reserves to contingent resources. The Company did not make sufficient new discoveries to offset the negative technical revisions, resulting in negative F&D and FD&A costs which are meaningless on a per Bbl basis.
3     In 2015, the three-year weighted average F&D and FD&A costs on a 2P basis were negative. The negative F&D and FD&A costs are driven primarily by negative reserve revisions                in 2014. The Company did not make sufficient new discoveries to offset the negative technical revisions in 2014, resulting in negative F&D and FD&A costs which are meaningless                on a per Bbl basis.
Note: The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

RECYCLE RATIO

Recycle Ratio - Accounting

	Three-Year
Proved	Weighted
	Average2	2015		2014	2013
Netback ($/Bbl)1	13.13	(3.12	)	17.83	19.64
Proved F&D costs ($/Bbl)3	83.93	34.22		—	21.58
Proved FD&A costs ($/Bbl)3	110.07	49.83		—	29.27
F&D Recycle ratio4	0.16	—		—	0.91
FD&A Recycle ratio4	0.12	—		—	0.67
1   Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), realized foreign exchange     (gain) loss, cash finance costs and current income tax expense per Bbl of production.
2   The negative reserves revisions and costs used in the 2014 calculation were included in the three-year weighted average recycle ratios.
3    In 2014, F&D and FD&A costs were negative, which was driven primarily by negative reserve revisions. Negative F&D and FD&A costs are meaningless on a per Bbl basis; therefore, the Company has presented these values as nil.
4    In 2015, recycle ratios were negative as a result of negative netbacks. Negative recycle ratios are meaningless and have therefore been presented as nil. The negative netbacks for 2015 were included in the three-year weighted average recycle ratios.

	Three-Year
Proved Plus Probable	Weighted
	Average2	2015		2014	2013
Netback ($/Bbl)1	13.13	(3.12	)	17.83	19.64
Proved plus Probable F&D costs ($/Bbl)3	—	8.03		—	34.78
Proved plus Probable FD&A costs ($/Bbl)3	—	22.53		—	47.96
F&D Recycle ratio4	—	—		—	0.56
FD&A Recycle ratio4	—	—		—	0.41
1  Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), realized foreign exchange    (gain) loss, cash finance costs and current income tax expense per Bbl of production.
2   The negative reserves revisions and costs used in the 2014 calculation were included in the three-year weighted average recycle ratios.
3    In 2014, F&D and FD&A costs were negative, which was driven primarily by negative reserve revisions. Negative F&D and FD&A costs are meaningless on a per Bbl basis; therefore, the Company has presented these values as nil.
4    In 2015, recycle ratios were negative as a result of negative netbacks. Negative recycle ratios are meaningless and have therefore been presented as nil. The negative netbacks for 2015 were included in the three-year weighted average ratios.

12 2015

The 2015 recycle ratio is negative as a result of negative recycle ratio netbacks in the year. The negative netbacks were primarily the result of low oil prices, combined with the fact that the Company did not sell all of its entitlement oil in 2015. Since negative recycle ratios are meaningless, they have been presented as nil in the tables above. However, the 2015 negative netbacks were used to calculate the three-year weighted average recycle ratios.

The recycle ratio is calculated by dividing the netback by the proved and proved plus probable finding and development costs on a per Bbl basis.

Recycle Netback Calculation - Accounting
($000s, except volumes and per Bbl amounts)	2015		2014		2013
Net earnings	(105,600	)	11,482		58,512
Adjustments for non-cash items:
Depletion, depreciation and amortization	42,875		51,589		49,414
Stock-based compensation	2,787		5,914		5,264
Deferred income taxes	(36,041	)	(9,813	)	(3,500	)
Amortization of deferred financing costs	849		1,106		1,109
Amortization of deferred lease inducement	(104	)	442		449
Realized (gain) loss on commodity contracts	688		—		—
Unrealized foreign exchange (gain) loss	(11,333	)	(6,476	)	(4,968	)
Unrealized (gain) loss on financial instruments	6,615		(11,589	)	(5,254	)
Impairment loss	85,373		71,373		30,071
Loss on corporate disposal	252		—		—
Other adjustments:
Other revenue	—		(9,250	)	—
Recycle netback1	(13,639	)	104,778		131,097
Sales volumes (MBbl)	4,372		5,878		6,674
Recycle netback per Bbl1	(3.12	)	17.83		19.64
1 Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Bbl of production.

Recycle Ratio - Notional

	Three-Year
Proved	Weighted
	Average2	2015	2014	2013
Netback ($/Bbl)1	13.79	1.94	17.83	19.64
Proved F&D costs ($/Bbl)3	83.93	34.22	—	21.58
Proved FD&A costs ($/Bbl)3	110.07	49.83	—	29.27
F&D Recycle ratio	0.16	0.06	—	0.91
FD&A Recycle ratio	0.13	0.04	—	0.67
1   Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), realized foreign exchange     (gain) loss, cash finance costs and current income tax expense per Bbl of production. For the purpose of calculating the notional recycle ratio, netback is adjusted to reflect the results that would have been achieved if all entitlement oil produced in the year had been sold in the period it was produced at average realized prices in the respective periods.
2   The negative reserves revisions and costs used in the 2014 calculation were included in the three-year weighted average recycle ratios.
3   In 2014, F&D and FD&A costs were negative, which was driven primarily by negative reserve revisions. Negative F&D and FD&A costs are meaningless on a per Bbl basis; therefore, the Company has presented these values as nil.

	Three-Year
Proved Plus Probable	Weighted
	Average2	2015	2014	2013
Netback ($/Bbl)1	13.79	1.94	17.83	19.64
Proved plus Probable F&D costs ($/Bbl)3	—	8.03	—	34.78
Proved plus Probable FD&A costs ($/Bbl)3	—	22.53	—	47.96
F&D Recycle ratio	—	0.24	—	0.56
FD&A Recycle ratio	—	0.09	—	0.41
1   Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), realized foreign exchange (gain) loss, cash finance costs and current income tax expense per Bbl of production. For the purpose of calculating the notional recycle ratio, netback is adjusted to reflect the results that would have been achieved if all entitlement oil produced in the year had been sold in the period it was produced at average realized prices in the respective periods.
2   The negative reserves revisions and costs used in the 2014 calculation were included in the three-year weighted average recycle ratios.
3   In 2014, F&D and FD&A costs were negative, which was driven primarily by negative reserve revisions. Negative F&D and FD&A costs are meaningless on a per Bbl basis; therefore,the Company has presented these values as nil.

2015 13

Recycle Netback Calculation - Notional
($000s, except volumes and per Bbl amounts)	2015		2014		2013
Net earnings	(89,871	)	11,482		58,512
Adjustments for non-cash items:
Depletion, depreciation and amortization	51,041		51,589		49,414
Stock-based compensation	2,787		5,914		5,264
Deferred income taxes	(36,041	)	(9,813	)	(3,500	)
Amortization of deferred financing costs	849		1,106		1,109
Amortization of deferred lease inducement	(104	)	442		449
Realized (gain) loss on commodity contracts	688		—		—
Unrealized foreign exchange (gain) loss	(11,333	)	(6,476	)	(4,968	)
Unrealized (gain) loss on financial instruments	6,615		(11,589	)	(5,254	)
Impairment loss	85,373		71,373		30,071
Loss on corporate disposal	252		—		—
Other adjustments:
Other revenue	—		(9,250	)	—
Recycle netback1	10,256		104,778		131,097
Production volumes (MBbl)	5,296		5,878		6,674
Recycle netback per Bbl1	1.94		17.83		19.64
1 Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), foreign exchange (gain) loss, interest and current income tax expense per Bbl of production. For the purpose of calculating the notional recycle ratio, netback is adjusted to reflect the results that would have been achieved if all entitlement oil produced in the year had been sold in the period it was produced at average realized prices in the respective periods.

OUTSTANDING SHARE DATA

As at December 31, 2015, the Company had 72,205,369 common shares issued and outstanding and 5,348,100 stock options issued and outstanding, which are exercisable in accordance with their terms into a maximum of 5,348,100 common shares of the Company.

As at March 8, 2016, the Company had 72,205,369 common shares issued and outstanding and 5,294,500 stock options issued and outstanding, which are exercisable in accordance with their terms into a maximum of 5,294,500 common shares of the Company.

NORMAL COURSE ISSUER BID

On March 25, 2015, the Toronto Stock Exchange ("TSX") accepted the Company's notice of intention to make a Normal Course Issuer Bid ("NCIB") for its common shares. Under the NCIB, the Company may acquire up to 6,207,585 common shares, which is equal to 10% of the public float. The NCIB commenced on March 31, 2015, and will terminate on March 30, 2016 or such earlier date on which TransGlobe completes its purchases of common shares under the NCIB or terminates the NCIB at its option. The maximum number of common shares that may be acquired by the Company during the same trading day is 89,289, which is equal to 25% of the Company's average daily trading volume of 357,159 for the previous six completed calendar months, subject to the Company's ability to make one block purchase of common shares per calendar week that exceeds such limit. All shares acquired will be cancelled.

During the year ended December 31, 2015, the Company repurchased a total of 3,103,792 common shares. All common shares acquired were cancelled and the cost of shares repurchased (including transaction costs) was applied directly against share capital.

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 debt. TransGlobe’s capital programs are funded by its existing working capital and cash provided from operating activities. As a direct result of a lower oil price environment, TransGlobe’s debt-to-funds flow from operations ratio deteriorated significantly throughout the year and was negative at December 31, 2015 (December 31, 2014 - 0.6) as a result of negative funds flow for the year. The Company's debt-to-funds flow from operations ratio will continue to experience downward pressure until oil prices improve. Despite the deterioration of this particular ratio, the Company remains in a relatively strong financial position due to prudent capital resource management. TransGlobe's management will continue to steward capital programs and focus on cost reductions in order to maintain as much balance sheet strength as possible through the current low oil price environment.

14 2015

The following table illustrates TransGlobe’s sources and uses of cash during the years ended December 31, 2015 and 2014:

Sources and Uses of Cash
($000s)	2015		2014
Cash sourced
Funds flow from operations1	(8,902	)	120,489
Transfer from restricted cash	688		—
Proceeds from corporate dispositions	1,500		—
Exercise of options	208		2,562
	(6,506	)	123,051
Cash used
Capital expenditures	44,902		107,539
Dividends paid	12,865		18,752
Transfer to restricted cash	—		2
Purchase of common shares	12,221		—
Finance costs	5,779		7,289
Other	1,635		1,135
	77,402		134,717
	(83,908	)	(11,666	)
Changes in non-cash working capital	70,428		29,964
Increase (decrease) in cash and cash equivalents	(13,480	)	18,298
Cash and cash equivalents – beginning of year	140,390		122,092
Cash and cash equivalents – end of year	126,910		140,390
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.

The Company funded its 2015 exploration and development program of $44.9 million and contractual commitments through the use of working capital and cash generated by operating activities. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks including timely collections of accounts receivable from the Egyptian Government may impact capital resources.

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2015, the Company had working capital of $153.8 million (December 31, 2014 - $229.7 million). The decrease to working capital in 2015 is principally due to reduced oil prices. The Company collected $95.0 million from EGPC in 2015, reducing the EGPC accounts receivable balance to $21.9 million as at December 31, 2015. TransGlobe expects that EGPC will continue to make regular payments on its outstanding debt, and that the EGPC receivable balance will be reduced to a very modest level by the end of 2016. In 2015, the Company sold a portion of its Eastern Desert entitlement oil directly to third party international buyers. The Company completed three cargo liftings during the year. The balance of the 2015 entitlement oil (923,106 barrels) remained in inventory at December 31, 2015. The reduction of the EGPC receivable balance, combined with the 30-day cash collection cycle on directly marketed crude oil sales that TransGlobe has experienced in 2015, has improved TransGlobe's credit risk profile.

To date, the Company has experienced no difficulties with transferring funds abroad (see "Risks").

At December 31, 2015, TransGlobe had $39.3 million available under a Borrowing Base Facility of which no amounts were drawn, however, the Company was utilizing $30.7 million in the form of letters of credit to support its work commitments under the Egyptian PSCs signed in 2013. Subsequent to year-end, the Company's borrowing capacity under the Borrowing Base Facility was reduced to $37.2 million.

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 Period1 2
	Recognized
	in Financial	Contractual	Less than			More than
	Statements	Cash Flows	1 year	1-3 years	4-5 years	5 years
Accounts payable and accrued liabilities	Yes - Liability	16,497	16,497	—	—	—
Convertible debentures	Yes - Liability	63,848	—	63,848	—	—
Office and equipment leases3	No	5,082	1,325	1,483	1,516	758
Minimum work commitments4	No	25,188	—	25,188	—	—
Total		110,615	17,822	90,519	1,516	758
1 Payments exclude ongoing operating costs, finance costs and payments made to settle derivatives.
2 Payments denominated in foreign currencies have been translated at December 31, 2015 exchange rates.
3 Office and equipment leases include all drilling rig contracts.
4 Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations.

2015 15

Pursuant to the PSC for North West Gharib in Egypt, the Company had a minimum financial commitment of $35.0 million ($8.4 million remaining) 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 December 31, 2015, the Company had expended $26.6 million towards meeting that commitment.

Pursuant to the PSC for South East Gharib in Egypt, the Company had a minimum financial commitment of $7.5 million ($2.1 million remaining)and a work commitment for two wells, 200 square kilometers of 3-D seismic and 300 kilometers of 2-D seismic during the initial three-year exploration period, which commenced on November 7, 2013. As at December 31, 2015, the Company had expended $5.4 million towards meeting that commitment.

Pursuant to the PSC for South West Gharib in Egypt, the Company had a minimum financial commitment of $10.0 million ($4.9 million remaining)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. As at December 31, 2015, the Company had expended $5.1 million towards meeting that commitment.

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. As at December 31, 2015, the Company had met its financial commitment.

Pursuant to the PSC for North West Sitra in Egypt, the Company had a minimum financial commitment of $10.0 million ($9.8 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 December 31, 2015, the Company had expended $0.2 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 December 31, 2015.

OFF BALANCE SHEET ARRANGEMENTS

The Company has certain lease arrangements, all of which are reflected in the Commitments and Contingencies table, which were entered into in the normal course of operations. All leases have been treated as operating leases whereby the lease payments are included in operating expenses or G&A expenses depending on the nature of the lease. No asset or liability value has been assigned to these leases in the Consolidated Balance Sheet as of December 31, 2015.

RISKS

TransGlobe’s results are affected by a variety of business risks and uncertainties in the international petroleum industry including but not limited to:

• Financial risks;

• Market risks (such as commodity price, foreign exchange and interest rates);

• Credit risks;

• Liquidity risks;

• Operational risks including capital, operating and reserves replacement risks;

• Safety, environmental, social and regulatory risks; and

• Political risks.

Many of these risks are not within the control of management, but the Company has adopted several strategies to reduce and minimize the effects of these risks:

Financial Risk

Financial risk is the risk of loss or lost opportunity resulting from financial management and market conditions that could have a positive or negative impact on TransGlobe.

The Company actively manages its cash position and maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future funds flow from operations, working capital and availability under existing banking arrangements will be adequate to support these financial liabilities, as well as its capital programs.

The frequent political changes that have created instability in Egypt since 2011 could present challenges to the Company if the issues persist over an extended period of time. Continued instability could reduce the Company’s ability to access debt, capital and banking markets. To mitigate potential financial risk factors, the Company maintains a very strong liquidity position and management regularly evaluates operational and financial risk strategies and continues to monitor the 2016 capital budget and the Company’s long-term plans. Furthermore, the Company entered into a joint marketing arrangement with EGPC in late December 2014 to gain more control over the Company's cash inflows. In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. The Company completed three separate direct crude sale shipments to third party buyers in 2015. Going forward, the Company anticipates that direct sales will continue to reduce financial risk in future periods.

16 2015

Market Risk

Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The market price movements that the Company is exposed to include oil prices (commodity price risk), foreign currency exchange rates and interest rates, all of which could adversely affect the value of the Company’s financial assets, liabilities and financial results.

Commodity price risk

The Company’s operational results and financial condition are dependent on the commodity prices received for its oil production.

Any movement in commodity prices would have an effect on the Company’s financial condition which could result in the delay or cancellation of drilling, development or construction programs, all of which could have a material adverse impact on the Company. Therefore, the Company uses financial derivative contracts from time to time as deemed necessary to manage fluctuations in commodity prices in the normal course of operations. The use of derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors.

Foreign currency exchange risk

As the Company’s business is conducted primarily in U.S. dollars and its financial instruments are primarily denominated in U.S. dollars, the Company’s exposure to foreign currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, convertible debentures, accounts payable and accrued liabilities denominated in Canadian dollars. When assessing the potential impact of foreign currency exchange risk, the Company believes 10% volatility is a reasonable measure. The Company estimates that a 10% increase in the value of the Canadian dollar against the U.S. dollar would result in an increase in the net loss for the year ended December 31, 2015 of approximately $7.1 million and conversely a 10% decrease in the value of the Canadian dollar against the U.S. dollar would decrease the net loss by $5.8 million for the same period. The Company has not utilized derivative instruments to manage this risk.

The Company is also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while the Company is generally able to spend the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates, the average Egyptian pound cash balance for 2015 was $20.8 million (2014 - $4.2 million) in equivalent U.S. dollars. The Company estimates that a 10% increase in the value of the Egyptian pound against the U.S. dollar would result in a decrease in the net loss for the year ended December 31, 2015 of approximately $2.3 million and conversely a 10% decrease in the value of the Egyptian pound against the U.S. dollar would increase the net loss by $1.9 million for the same period. The Company does not currently utilize derivative instruments to manage this risk.

Interest rate risk

Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable-interest, U.S.-dollar-denominated debt. No derivative contracts were entered into during 2015 to mitigate this risk. When assessing interest rate risk applicable to the Company’s variable-interest, U.S.-dollar-denominated debt the Company believes 1% volatility is a reasonable measure. Since the Company did not have any amounts drawn on its variable-interest, U.S.-dollar-denominated debt at any time in 2015, the effect of interest rates increasing or decreasing by 1% would have no impact on the Company's net earnings for the year ended December 31, 2015.

Credit Risk

Credit risk is the risk of loss if counter-parties do not fulfill their contractual obligations. The Company’s exposure to credit risk primarily relates to accounts receivable, the majority of which are in respect of oil operations. The Company is and may in the future be exposed to third-party credit risk through its contractual arrangements with its current or future joint interest partners, marketers of its petroleum production and other parties, including the government of Egypt. Significant changes in the oil industry, including fluctuations in commodity prices and economic conditions, environmental regulations, government policy, royalty rates and other geopolitical factors, could adversely affect the Company’s ability to realize the full value of its accounts receivable. The Company historically has had a significant account receivable outstanding from the Government of Egypt. In the past, the timing of payments on these receivables from the Government of Egypt were historically longer than normal industry standard. Despite these factors, the Company expects to collect this account receivable in full, although there can be no assurance that this will occur. In the event the Government of Egypt fails to meet its obligations, or other third-party creditors fail to meet their obligations to the Company, such failures could individually or in the aggregate have a material adverse effect on the Company, its cash flow from operating activities and its ability to conduct its ongoing capital expenditure program. The Company has not experienced any material credit loss in the collection of accounts receivable to date.

During 2015, EGPC made regular payments to TransGlobe against the outstanding receivable, resulting in a significant reduction in the receivable balance. The reduction in the receivable balance due from EGPC has decreased TransGlobe's credit risk. The Company expects that EGPC will continue to make regular payments on its outstanding debt, and that the EGPC receivable balance will be reduced to a very modest level by the end of 2016.

TransGlobe entered into a joint marketing arrangement with EGPC in December 2014. In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. The Company completed three separate direct crude sale shipments to third party buyers in 2015. Buyers are required to post irrevocable letters of credit to support the sales prior to the cargo liftings. Going forward, the Company anticipates that direct sales will continue to reduce outstanding accounts receivable and credit risk in future periods.

In Egypt, the Company sold all of its 2015 Eastern Desert entitlement oil directly to third party international buyers, compared to 2014 production which was sold to EGPC.

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. 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 proved reserves, to acquire strategic oil and gas assets and to repay debt.

2015 17

The Company actively maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. Management believes that future funds flows from operations, working capital and availability under existing banking arrangements will be adequate to support these financial liabilities, as well as its capital programs. All of the payments received from the sale of the Company's entitlement crude oil are deposited directly to its accounts held in London, England.

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

Operational Risk

The Company’s future success largely depends on its ability to exploit its current reserve base and to find, develop or acquire additional oil reserves that are economically recoverable. Failure to acquire, discover or develop these additional reserves will have an impact on cash flows of the Company.

To mitigate these operational risks, as part of its capital approval process, the Company applies rigorous geological, geophysical and engineering analysis to each prospect. The Company utilizes its in-house expertise for all international ventures or employs and contracts professionals to handle each aspect of the Company’s business. The Company retains independent reserve evaluators to determine year-end Company reserves and estimated future net revenues.

The Company also mitigates operational risks by maintaining a comprehensive insurance program according to customary industry practice, but cannot fully insure against all risks.

Safety, Environmental, Social and Regulatory Risk

To mitigate safety, environmental and social risks, TransGlobe conducts its operations in accordance with the Company's Health, Safety, Environmental, and Social Responsibility Policy to ensure compliance with government regulations and guidelines. Monitoring and reporting programs for environmental health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental and regulatory standards are met. Security risks are managed through security procedures designed to protect TransGlobe's personnel and assets. The Company has a Whistleblower Protection Policy which protects employees if they raise any concerns regarding TransGlobe's operations, accounting or internal control matters.

Regulatory and legal risks are identified and monitored by TransGlobe's corporate team and external legal professionals to ensure that the Company continues to comply with laws and regulations.

Political Risk

TransGlobe operates in a country with political, economic and social systems which subject the Company to a number of risks that are not within the control of the Company. These risks may include, among others, currency restrictions and exchange rate fluctuations, loss of revenue and property and equipment as a result of expropriation, nationalization, war, insurrection and geopolitical and other political risks, increases in taxes and governmental royalties, changes in laws and policies governing operations of foreign-based companies, economic and legal sanctions and other uncertainties arising from foreign governments.

Egypt has been experiencing significant political changes over the past five years and while this has had an impact on the efficient operations of the government in general, business processes and the Company’s operations have generally proceeded as normal. The current government has added stability in the Egyptian political landscape, however, the possibility of future political changes exists. Future political changes could have a negative impact on the Company's operations.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with IFRS requires that management make appropriate decisions with respect to the selection of accounting policies and in formulating estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses.

The following is included in the MD&A to aid the reader in assessing the critical accounting policies and practices of the Company. The information will also aid in assessing the likelihood of materially different results being reported depending on management's assumptions and changes in prevailing conditions which affect the application of these policies and practices. Significant accounting policies are disclosed in Note 3 of the Consolidated Financial Statements.

Oil and Gas Reserves

TransGlobe's Proved and Probable oil and gas reserves are 100% evaluated and reported on by independent reserve evaluators to the Reserves Committee comprised of independent directors. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to reflect updated information. Reserve estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts.

Property and equipment and intangible exploration and evaluation assets

Recognition and measurement

E&E costs related to each license/prospect are initially capitalized within "intangible exploration and evaluation assets." Such E&E costs may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, directly attributable expenses, including remuneration of production personnel and supervisory management, and the projected costs of retiring the assets (if any), but do not include pre-licensing costs incurred prior to having obtained the legal rights to explore an area, which are expensed directly to earnings as they are incurred and presented as exploration expenses on the Consolidated Statements of Earnings and Comprehensive Income.

18 2015

Tangible assets acquired for use in E&E activities are classified as other assets; however, to the extent that such a tangible asset is consumed in developing an intangible exploration asset, the amount reflecting that consumption is recorded as part of the cost of the intangible exploration and evaluation asset.

Intangible E&E assets are not depleted. They are carried forward until technical feasibility and commercial viability of extracting a mineral resource is determined. The technical feasibility and commercial viability is considered to be determined when proved and/or probable reserves are determined to exist or they can be empirically supported with actual production data or conclusive formation tests. A review of each CGU is carried out at least annually. Intangible E&E assets are transferred to petroleum properties as development and production ("D&P") assets upon determination of technical feasibility and commercial viability. The intangible E&E assets being transferred to D&P assets are subject to impairment testing upon transfer.

Petroleum properties and other assets are measured at cost less accumulated depletion, depreciation, and amortization, and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, including qualifying E&E costs on reclassification from intangible E&E assets, and for qualifying assets, where applicable, borrowing costs. When significant parts of an item of property and equipment have different useful lives, they are accounted for as separate items.

Gains and losses on disposal of items of property and equipment are determined by comparing the proceeds from disposal with the carrying amount of property and equipment and are recognized in earnings immediately.

Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property and equipment are recognized as petroleum properties or other assets only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in earnings as incurred. Such capitalized property and equipment generally represent costs incurred in developing Proved and/or Probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis.

The carrying amount of any replaced or sold component is derecognized.

Depletion, depreciation and amortization

The depletion, depreciation and amortization of petroleum properties and other assets are recognized in earnings.

The net carrying value of D&P assets included in petroleum properties is depleted using the unit of production method by reference to the ratio of production in the year to the related proved and probable reserves using estimated future prices and costs. Costs subject to depletion include estimated future development costs necessary to bring those reserves into production. These estimates are reviewed by independent reserve engineers at least annually.

Proved and probable reserves are estimated using independent reserve evaluator reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially viable. The specified degree of certainty must be a minimum 90% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and a minimum 50% statistical probability for proved and probable reserves to be considered commercially viable.

Furniture and fixtures are depreciated at declining balance rates of 20% to 30%, whereas vehicles and leasehold improvements are depreciated on a straight-line basis over their estimated useful lives.

Depreciation methods, useful lives and residual values are reviewed at each reporting date.

Production Sharing Concessions

International operations conducted pursuant to PSCs are reflected in the Consolidated Financial Statements based on the Company's working interest in such operations. Under the PSCs, the Company and other non-governmental partners pay all operating and capital costs for exploring and developing the concessions. Each PSC establishes specific terms for the Company to recover these costs ("Cost Recovery Oil") and to share in the production sharing oil. Cost Recovery Oil is determined in accordance with a formula that is generally limited to a specified percentage of production during each quarter. Production sharing oil is that portion of production remaining after Cost Recovery Oil and is shared between the joint interest partners and the government of each country, varying with the level of production. Production sharing oil that is attributable to the government includes an amount in respect of all income taxes payable by the Company under the laws of the respective country. Revenue represents the Company's share and is recorded net of royalty payments to government and other mineral interest owners. For the Company's international operations, all government interests, except for income taxes, are considered royalty payments. The Company's revenue also includes the recovery of costs paid on behalf of foreign governments in international locations.

Financial instruments

Non-derivative financial instruments

Non-derivative financial instruments comprise cash and cash equivalents, accounts receivable, restricted cash, accounts payable and accrued liabilities and convertible debentures. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs. Subsequent to initial recognition non-derivative financial instruments are measured as described below.

2015 19

Financial assets and liabilities at fair value through profit or loss

An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition, such as cash and cash equivalents and convertible debentures. Financial instruments are designated at fair value through profit or loss if the Company makes purchase and sale decisions based on their fair value in accordance with the Company's documented risk management strategy. Upon initial recognition, any transaction costs attributable to the financial instruments are recognized through earnings when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in earnings.

Other

Other non-derivative financial instruments, such as accounts receivable, accounts payable and accrued liabilities and restricted cash are measured initially at fair value, then at amortized cost using the effective interest method, less any impairment losses.

Derivative financial instruments

The Company enters into certain financial derivative contracts from time to time in order to reduce its exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company does not designate financial derivative contracts as effective accounting hedges, and thus does not apply hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, the Company's policy is to classify all financial derivative contracts at fair value through profit or loss and to record them on the Consolidated Balance Sheet at fair value. Attributable transaction costs are recognized in earnings when incurred. The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts.

Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract when their economic characteristics and risks are not closely related to those of the host contract, the terms of the embedded derivatives are the same as those of a freestanding derivative and the combined contract is not measured at fair value through profit or loss. Changes in the fair value of separable embedded derivatives are recognized immediately in profit or loss.

CHANGES IN ACCOUNTING POLICIES

Future changes to accounting policies

As at the date of authorization of the Consolidated Financial Statements the following Standards, which have not yet been applied in the Consolidated Financial Statements, have been issued but are not yet effective:

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

In July 2014, the IASB issued the final version of IFRS 9 Financial Instruments to replace IAS 39 Financial Instruments: Recognition and Measurement . IFRS 9 introduces a single approach to determine whether a financial asset is measured at amortized cost or fair value and replaces the multiple rules in IAS 39. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of the financial assets. For financial liabilities, IFRS 9 retains most of the IAS 39 requirements; however, where the fair value option is applied to financial liabilities, the change in fair value resulting from an entity’s own credit risk is recorded in other comprehensive income rather than net earnings, unless this creates an accounting mismatch. In addition, a new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. The Company does not currently apply hedge accounting. IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. The Company is currently evaluating the impact these amendments may have on its Consolidated Financial Statements.

IFRS 15 "Revenue from Contracts with Customers"

In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers, replacing IAS 11 Construction Contracts, IAS 18 Revenue, and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive when control is transferred to the purchaser. Disclosure requirements have also been expanded. The new standard is effective for annual periods beginning on or after January 1, 2018, with earlier adoption permitted. The standard may be applied retrospectively or using a modified retrospective approach. The Company is currently evaluating the impact these amendments may have on its Consolidated Financial Statements.

IFRS 16 "Leases"

In January 2016, the IASB issued IFRS 16 Leases, replacing IAS 17 Leases. IFRS 16 establishes a set of principles that both parties to a contract apply to provide relevant information about leases in a manner that faithfully represents those transactions. The current standard (IAS 17) requires lessees and lessors to classify their leases as either finance leases or operating leases, with separate accounting treatment depending on the classification of the lease. Under the new standard, the accounting treatment associated with an operating lease will no longer exist, and lessees will be required to recognize assets and liabilities associated with all leased items. The new standard is effective for annual periods beginning on or after January 1, 2019. The Company is currently evaluating the impact these amendments may have on its Consolidated Financial Statements.

20 2015

DISCLOSURE CONTROLS AND PROCEDURES

As of December 31, 2015, an evaluation was carried out under the supervision, and with the participation of the Company's management, including the Chief Executive Officer and Chief Financial Officer, on the effectiveness of the Company's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as of the end of the fiscal year, the design and operation of these disclosure controls and procedures were effective to ensure that all information required to be disclosed by the Company in its annual filings is recorded, processed, summarized and reported within the specified time periods.

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.

Management has assessed the effectiveness of the Company's internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission framework on Internal Control - Integrated Framework (2013). Based on this assessment, management concluded that the Company's internal control over financial reporting was effective as at December 31, 2015. No changes were made to the Company's internal control over financial reporting during the year ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.

2015 21