Exhibit

EX-99.3 4 exhibit993.htm EXHIBIT 99.3 Exhibit

EXHIBIT 99.3

MANAGEMENT'S DISCUSSION AND ANALYSIS

March 5, 2018

The following discussion and analysis is management’s opinion of TransGlobe’s historical financial and operating results and should be read in conjunction with the message to shareholders and the audited consolidated financial statements of the Company for the years ended December 31, 2017 and 2016, 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 2018, including expected 2018 average production, funds flow from operations, the 2018 capital program for exploration and development, the timing and method of financing thereof, the terms of drilling commitments under the Egyptian Production Sharing Agreements and Production Sharing Concessions (collectively defined as "PSCs") and the method of funding such drilling commitments, the Company's beliefs regarding the 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.



2017		1

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

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

MANAGEMENT STRATEGY AND OUTLOOK

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

2018 Outlook

The 2018 production outlook for the Company is provided as a range to reflect timing and performance contingencies.

Total corporate production is expected to range between 14,200 and 15,600 boepd for 2018 (mid-point of 14,900 boepd) with a 94% weighting to oil and liquids. Egypt oil production is expected to range between 12,000 and 13,000 bopd in 2018. Canadian production is expected to range between 2,200 and 2,600 boepd in 2018, adjusting for a one month shut-in for plant and facility turnarounds scheduled for May in the Harmattan area. The May shut-in is expected to reduce corporate production by approximately 200 boepd on an annualized basis.

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

2018 Capital Budget

The Company’s 2018 budgeted capital program of $41.3 million (before capitalized G&A) includes $29.1 million for Egypt and $12.2 million (C$15.3 million) for Canada. The 2018 capital program is balanced to anticipated funds flow from operations using a $55/bbl Brent oil price forecast. The capital program may be increased if the recent run-up in Brent prices is sustained.

Egypt

The $29.1 million capital program for Egypt has $11.7 million (40%) allocated to exploration and $17.4 million (60%) to development. The $11.7 million 2018 exploration program is focused entirely on the Western Desert with 5 exploration wells planned (2 wells in South Ghazalat, 2 wells in NW Sitra and 1 well in South Alamein). The $17.4 million 2018 development program, focused entirely on the Eastern Desert includes: 8 development wells (5 in West Bakr, 2 in NW Gharib and 1 in West Gharib) and development/maintenance projects in West Bakr, NW Gharib and West Gharib.

The primary focus of the 2018 Egypt capital plan is to sustain/grow Eastern Desert production and to evaluate the Company’s 1 million + acres of exploration lands. The exploration program is designed to test an independent structure at South Alamein to prove up additional oil reserves on the concession and to test four independent structures on South Ghazalat and N.W. Sitra. The South Ghazalat and N.W. Sitra exploration wells are basin opening prospects which could also de-risk 13 of the 21 additional prospects mapped on 3-D seismic. No production is budgeted from the Western Desert exploration assets in 2018.

Canada

The $12.2 million (C$15.3 million) budgeted program for Canada consists of 6 (5.5 net) horizontal (multi-stage frac) wells targeting the Cardium light oil resource at Harmattan and additional maintenance/development capital. The Cardium drilling program in 2018 provides growth in oil and liquids production. The development program is expected to increase the Canadian oil and liquids production weighting to approximately 67% from 60% in 2017.

The well design for the 2018 development program will be similar to the 2017 which targeted one mile horizontal laterals with multi-stage facture stimulations placing ~600 tonnes of proppant per well. The final 2018 completion design will incorporate lessons learned and results from the 2017 program. Based on 2017 results, the Company is budgeting ~$2.0 million (C$2.5 million) per well to drill, complete, equip and tie-in for the 2018 program. In addition the Company is evaluating a potential two mile horizontal Cardium well as part of the 2018 program.



2		2017

The 2018 capital program is summarized in the following table:



	TransGlobe 2018 Capital ($MM)					Gross Well Count
	Development		Exploration		Total	Drilling
Concession	Wells*	Other	Wells*	Other	Total	Devel	Explor	Total
West Gharib	2.6	1.1	—	—	3.7	1	—	1
West Bakr	7.3	3.1	—	—	10.4	5	—	5
NW Gharib	2.4	0.9	—	—	3.3	2	—	2
NW Sitra	—	—	5.2	0.2	5.4	—	2	2
South Ghazalat	—	—	3.3	0.2	3.5	—	2	2
South Alamein	—	—	2.8	—	2.8	—	1	1
Egypt	$12.3	$5.1	$11.3	$0.4	$29.1	8	5	13
Canada	$11.2	$1.0	—	—	$12.2	6	—	6
2018 Total	$23.5	$6.1	$11.3	$0.4	$41.3	14	5	19
Splits (%)	72%		28%		100%	74%	26%	100%
*Wells includes new wells, completions, workovers, recompletions and equipping.

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. Funds flow from operations include sales and associated costs of production from inventoried crude sold during the period. 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)	2017		2016
Cash flow from operating activities	59,450		(1,065	)
Changes in non-cash working capital	(3,858	)	(7,296	)
Funds flow from operations¹	55,592		(8,361	)
¹ Funds flow from operations does not include interest or financing costs. Interest expense is included in financing costs on the Consolidated Statements of Loss and Comprehensive Loss. Cash interest paid is reported as a financing activity on the Consolidated Statements of Cash Flows.

Net debt-to-funds flow from operations ratio

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

Netback

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

Finding and development costs/finding, development and net acquisition costs

Finding and development ("F&D") costs and finding, development and net acquisition ("FD&A") costs are measures that are used to evaluate the Company's capital costs associated with adding proved and proved plus probable reserves. F&D costs are calculated as the aggregate of exploration costs, development costs and the change in estimated future development costs divided by the applicable reserve additions. FD&A costs incorporate acquisitions, net of any dispositions in the year. Neither F&D costs nor FD&A costs 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 recycle netback from production. The ratio is calculated by dividing the recycle netback by the proved and proved plus probable finding and development cost on a per boe basis. Recycle ratio does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.



2017		3

Recycle netback

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 boe of production. Recycle netback does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

TRANSGLOBE’S BUSINESS

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

ASSET ACQUISITION

On December 20, 2016, TransGlobe closed the acquisition of production and working interests in certain facilities in the Cardium light oil and Mannville liquids-rich gas assets in the Harmattan area of west central Alberta for total consideration of $59.5 million after adjustments. The acquisition was effective December 1, 2016, and was funded by $48.3 million cash from the balance sheet and a 10%, 24-month vendor take back loan of $11.2 million.

The acquisition provided the Company with liquids-weighted production and total Proved plus Probable reserves of 20.7 million boe at the time of the acquisition. The acquisition met the Company's strategic objective to diversify and expand into operations with attractive netbacks to support growth in a challenging oil price environment.



4		2017

SELECTED ANNUAL INFORMATION



($000s, except per share, price and volume amounts)	2017		% Change	2016		% Change	2015
($000s, except per share, price and volume amounts)	2017		% Change	2016		% Change	2015
Operations
Average production volumes
Crude oil (bbls/d)	13,411		11	12,033		(17)	14,511
NGLs and condensate (bbls/d)	988		2806⁵	34		100	—
Natural gas (mcf/d)	6,644		2789⁵	230		100	—
Total (boe/d)	15,506		28	12,105		(17)	14,511
Average sales volumes
Crude oil (bbls/d)	14,754		33	11,093		(7)	11,977
NGLs and condensate (bbls/d)	988		2806⁵	34		100	—
Natural gas (mcf/d)	6,644		2789⁵	230		100	—
Total (boe/d)	16,849		51	11,165		(7)	11,977
Average realized sales prices
Crude oil ($/bbl)	44.71		49	30.05		(30)	42.93
NGLs and condensate ($/bbl)	21.31		24	17.20		100	—
Natural gas ($/mcf)	1.70		(6)	1.81		100	—
Total oil equivalent ($/boe)	41.07		37	29.94		(30)	42.93
Inventory (Mbbl)	777		(39)	1,265		37	923
Petroleum and natural gas sales	252,591		106	122,360		(35)	187,665
Petroleum and natural gas sales, net of royalties	148,464		135	63,134		(32)	92,212
Cash flow from operating activities	59,450		5,682	(1,065	)	(101)	77,526
Funds flow from operations¹	55,592		765	(8,361	)	6	(8,902	)
- Basic per share	0.77			(0.12	)		(0.12	)
- Diluted per share²	0.77			(0.12	)		(0.12	)
Net loss	(78,736	)	10	(87,665	)	17	(105,600	)
Net loss - diluted	(78,736	)	10	(87,665	)	17	(105,600	)
Net loss per share
- Basic	(1.09	)		(1.21	)		(1.44	)
- Diluted²	(1.09	)		(1.21	)		(1.44	)
Capital expenditures	38,159		43	26,658		(41)	44,902
Property expenditures	—		(100)	59,475		—	—
Dividends paid	—			—		(100)	12,865
Dividends paid per share	—			—		(100)	0.18
Total assets	327,702		(19)	406,142		(11)	455,500
Cash and cash equivalents	47,449		51	31,468		(75)	126,910
Working capital	50,639		402	(16,764	)	(111)	153,835
Convertible debentures	—		(100)	72,655		14	63,848
Note payable	—		(100)	11,162		100	—
Total long-term debt, including current portion	69,999		—	—		—	—
Net debt-to-funds flow from operations ratio³	0.3			(12.0	)		10.1
Reserves
Total Proved (MMboe)⁴	27.5		(8)	29.9		71	17.5
Total Proved plus Probable (MMboe)⁴	45.9		(8)	50.0		74	28.7
¹ Funds flow from operations (before finance costs) is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
² Funds flow from operations per share (diluted) and net loss per share (diluted) was not impacted by the convertible debentures for the years ended December 31, 2017, December 31, 2016 and December 31, 2015, as the convertible debentures were not dilutive in these years.
³ Net debt-to-funds flow from operations ratio is a measure that represents total long-term debt (including the current portion), plus convertible debentures and working capital, over funds flow from operations for the trailing 12 months, and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
⁴As determined by the Company's 2017 independent reserves evaluator, GLJ Petroleum Consultants Ltd. (“GLJ”), in their report dated January 9, 2018, with an effective date of December 31, 2017. As determined by the Company's, 2016 and 2015 independent reserves evaluator, DeGolyer and MacNaughton Canada Limited ("DeGolyer") of Calgary, Alberta, in their reports dated January 18, 2017, and January 15, 2016 with effective dates of December 31, 2016, and December 31, 2015. The reports of GLJ and 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.
⁵ The 2016 information includes the results of the operations of the Harmattan assets in Alberta, Canada from December 20, 2016 to December 31, 2016 (12 days). The Harmattan assets were acquired in a transaction that closed on December 20, 2016 (effective December 1, 2016).



2017		5

In 2017 compared with 2016, TransGlobe:

•

Reported a net loss of $78.7 million, versus $87.7 million in 2016. The 2017 net loss includes a $79.0 million non-cash impairment loss on the Company's exploration and evaluation assets and a $8.0 million unrealized derivative loss on commodity contracts (mark-to-market loss on the Company's hedging contracts). Excluding the impairment charge and the unrealized loss on derivative commodity contracts, the Company would have achieved net earnings for 2017 of $8.3 million;


•	Reported a 28% increase in production volumes as compared to 2016, which translates into an additional 3,401 boepd. The recently acquired Canadian assets contributed 2,684 boepd of additional production, and increased Egypt production accounted for the remaining variance. The increased Egypt production was primarily from NW Gharib, which contributed 1,112 bopd;


•	Experienced a 106% increase in petroleum and natural gas sales compared to 2016, which was principally due to a 37% increase in realized prices along with a 51% increase in sales volumes.


•	Achieved positive funds flow from operations of $55.6 million, compared with negative funds flow from operations of $8.4 million in 2016;


•	Repaid the $73.4 million (C$97.8 million) convertible debentures on March 31, 2017 with the proceeds from the prepayment agreement entered into with Mercuria Energy Trading S.A. ("Mercuria") in Q1 of 2017;


•	Repaid the $11.0 million (C$15.0 million) vendor take-back note with the revolving reserves-based lending facility ("RBL"), obtained from Alberta Treasury Branches ("ATB") in Q2 of 2017 and cash;


•	Repaid $15.0 million of the amount outstanding under the prepayment agreement with cash on hand;


•	Sold three tanker liftings of entitlement crude oil totaling 1,468,726 barrels and sold an additional 1,121,391 barrels of inventoried entitlement crude oil to EGPC, resulting in a net decrease in crude oil inventory of 0.5 million barrels from 2016;


•	Spent $38.2 million on capital programs, which was funded from funds flow from operations and cash on hand; and


•	Ended the year with positive working capital of $50.6 million (including cash and cash equivalents of $47.4 million) at December 31, 2017.



6		2017

2017 TO 2016 NET LOSS VARIANCES



			$ Per Share
	$000s		Diluted		% Variance
2016 net loss	(87,665	)	(1.21	)
Cash items
Volume variance	84,747		1.16		(95	)
Price variance	45,484		0.63		(52	)
Royalties	(44,901	)	(0.62	)	51
Expenses:
Production and operating	(9,889	)	(0.14	)	11
Transportation	(781	)	(0.01	)	1
Selling costs	(1,620	)	(0.02	)	2
Cash general and administrative	1,366		0.02		(2	)
Current income taxes	(6,364	)	(0.09	)	7
Realized foreign exchange loss	(914	)	(0.01	)	1
Realized derivative loss	(1,915	)	(0.03	)	2
Interest on long-term debt	(560	)	(0.01	)	1
Other income	(565	)	(0.01	)	1
Total cash items variance	64,088		0.87		(72	)
Non-cash items
Unrealized derivative loss	(7,970	)	(0.11	)	9
Unrealized foreign exchange gain	4,327		0.06		(5	)
Depletion, depreciation and amortization	(10,859	)	(0.15	)	12
Accretion	(256	)	—		—
Unrealized gain on convertible debentures	6,876		0.10		(8	)
Impairment loss	(45,599	)	(0.63	)	52
Stock-based compensation	940		0.01		(1	)
Deferred income taxes	(3,009	)	(0.04	)	3
Deferred lease inducement	(4	)	—		—
Amortization of deferred financing costs	395		0.01		—
Total non-cash items variance	(55,159	)	(0.75	)	62
2017 net loss	(78,736	)	(1.09	)	(10	)

The Company recorded a net loss of $78.7 million in 2017 compared to a net loss of $87.7 million in 2016. The largest positive earnings variance was a result of a 37% increase in the average realized sales price and a 51% increase in sales volumes totaling $130.2 million in aggregate compared to 2016, which was partially offset by increased royalties and current income taxes of $51.3 million. The Company incurred an increase of $1.6 million in selling costs during the period. Operating expenditures increased in 2017 compared to 2016, due principally to recognizing capitalized operating costs associated with the previously inventoried entitlement crude oil barrels sold during the year.

The largest non-cash positive earnings variance item in 2017 compared to 2016 related to the mark-to-market adjustment on the convertible debentures of $6.9 million. The convertible debentures were repaid during the first quarter of 2017. The largest non-cash negative earnings variance in 2016 was created by the impairment loss recorded on the Company's South East Gharib ($16.4 million), South West Gharib ($15.2 million) and North West Gharib ($1.8 million) exploration and evaluation assets for a total of $33.4 million versus an aggregate corresponding $79.0 million impairment loss recorded in 2017 related to the Company's South West Gharib ($1.2 million), North West Gharib ($67.5 million) and South Alamein ($10.3 million) exploration and evaluation assets. The increase of $10.9 million in depletion, depreciation and amortization in 2017 compared to 2016 is principally a result of the depletion, depreciation and amortization on the recently acquired Canadian assets and recognizing capitalized depletion costs associated with the previously inventoried entitlement crude oil barrels sold during the year. The Company recorded an $8.0 million non-cash unrealized derivative loss on its outstanding hedging commodity contracts held at the end of 2017, which was a result of recording the contracts at their respective market values. In 2016, there were no hedging contracts outstanding.

BUSINESS ENVIRONMENT

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



Average reference prices	2017	2016
Crude oil
Dated Brent average oil price (US$/Bbl)	54.25	43.55
Edmonton Sweet index (US$/bbl)	48.50	40.11
Natural gas
AECO (C$/mmbtu)	2.16	2.16
U.S./Canadian Dollar average exchange rate	1.2978	1.3256



2017		7

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

Egypt has been experiencing significant financial challenges over the past seven years. While exploration and development activities have generally been uninterrupted, the Company experienced delays in the collection of accounts receivable from the Egyptian government up to the end of 2013. Since the end of 2013, the Company has collected a total of $384.2 million from EGPC, reducing the balance due from EGPC to $14.2 million as at December 31, 2017. The Company's credit risk, as it relates to accounts receivable from EGPC, has now been reduced due to the significant collections from EGPC. EGPC owns the storage and export facilities where the Company's production is delivered, and the Company requires EGPC cooperation and approval to schedule liftings. Once liftings are scheduled, the Company enjoys a 30-day collection cycle on liftings as a result of direct marketing to third party international buyers. Depending on the Company's assessment of the credit of crude cargo buyers, buyers may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings.

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

The price of Edmonton Sweet index oil expressed in USD averaged 21% higher in 2017 compared with 2016. The price of the AECO average remained the same in 2017 compared with 2016.



8		2017

SELECTED QUARTERLY FINANCIAL INFORMATION



	2017								2016
($000s, except per share,
price and volume amounts)	Q-4		Q-3		Q-2		Q-1		Q-4³		Q-3		Q-2		Q-1
Operations
Average production volumes
Crude oil (bbls/d)	12,027		12,786		14,347		14,514		12,861		11,733		11,472		12,058
NGLs (bbls/d)	915		1,081		919		1,037		134		—		—		—
Natural gas (mcf/d)	6,059		6,268		7,191		7,075		916		—		—		—
Total (boe/d)	13,952		14,912		16,465		16,731		13,148		11,733		11,472		12,058
Average sales volumes
Crude oil (bbls/d)	14,324		15,894		17,141		11,610		7,018		11,485		11,783		14,126
NGLs (bbls/d)	915		1,081		919		1,037		134		—		—		—
Natural gas (mcf/d)	6,059		6,268		7,191		7,075		916		—		—		—
Total (boe/d)	16,249		18,020		19,259		13,826		7,305		11,485		11,783		14,126
Average realized sales prices
Crude oil ($/Bbl)	53.25		44.82		39.46		41.66		37.38		34.43		30.27		22.58
NGLs ($/Bbl)	26.86		18.90		21.08		19.08		12.33		—		—		—
Natural gas ($/Mcf)	0.94		1.65		2.14		1.96		1.80		—		—		—
Total oil equivalent ($/boe)	48.80		41.24		36.92		37.41		36.45		34.43		30.27		22.58
Inventory (MBbl)	777		988		1,274		1,528		1,265		729		707		735
Petroleum and natural gas sales	72,954		68,372		64,711		46,553		24,501		36,376		32,461		29,022
Petroleum and natural gas sales, net of royalties	40,725		44,839		40,439		22,461		5,217		20,704		19,786		17,427
Cash flow from operating activities	44,263		20,437		(2,753	)	(2,497	)	6,355		(14,857	)	6,011		1,426
Funds flow from operations¹	17,018		19,217		16,855		2,502		(9,904	)	2,347		2,026		(2,830	)
Funds flow from operations per share
- Basic	0.24		0.27		0.23		0.03		(0.14	)	0.03		0.03		(0.04	)
- Diluted	0.24		0.27		0.23		0.03		(0.14	)	0.03		0.03		(0.04	)
Net loss	(2,382	)	(6,855	)	(56,622	)	(12,877	)	(33,997	)	(25,369	)	(12,050	)	(16,249	)
Net loss - diluted	(2,382	)	(6,855	)	(56,622	)	(12,877	)	(38,641	)	(25,369	)	(12,050	)	(16,249	)
Net loss per share
- Basic	(0.03	)	(0.09	)	(0.78	)	(0.18	)	(0.47	)	(0.35	)	(0.17	)	(0.23	)
- Diluted	(0.03	)	(0.09	)	(0.78	)	(0.18	)	(0.49	)	(0.35	)	(0.17	)	(0.23	)
Capital expenditures	9,078		10,133		8,229		10,718		8,863		8,692		4,838		4,265
Property acquisition	—		—		—		—		59,475		—		—		—
Total assets	327,702		338,802		337,596		403,686		406,142		414,363		433,013		441,624
Cash and cash equivalents	47,449		21,464		13,780		21,324		31,468		100,405		124,308		122,031
Working capital	50,639		58,815		60,319		42,759		(16,764	)	53,029		65,413		75,158
Convertible debentures	—		—		—		—		72,655		74,854		70,639		66,506
Note payable	—		—		—		11,259		11,162		—		—		—
Total long-term debt, including current portion	69,999		79,839		83,725		73,549		—		—		—		—
Net debt-to-funds flow from operations ratio²	0.3		0.7		2.0		(13.9	)	(12.0	)	(2.3	)	(0.4	)	1.0
¹ Funds flow from operations (before finance costs) is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
² Net debt-to-funds flow from operations ratio is a measure that represents total long-term debt (including the current portion), plus convertible debentures and working capital over funds flow from operations from the trailing 12 months and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
³ The Q4-2016 information includes the results of the operations of the Harmattan assets in Alberta, Canada from December 20, 2016 to December 31, 2016 (12 days). The Harmattan assets were acquired in a transaction that closed on December 20, 2016 (effective December 1, 2016).

During the fourth quarter of 2017, TransGlobe:


•	Reported a net loss of $2.4 million, which includes a $7.6 million unrealized derivative loss on commodity contracts (mark-to-market loss on the Company's hedging contracts). Excluding the unrealized loss on derivative commodity contracts, the Company would have achieved net earnings for the quarter of $5.2 million;

•

Experienced a 198% increase in petroleum and natural gas sales compared to Q4-2016, which was principally due to a 34% increase in realized prices along with a 122% increase in sales volumes. Realized pricing for the Company's petroleum and natural gas products are market driven. The tanker lifting sale of entitlement crude oil during the quarter and the acquired Canadian assets also contributed to the petroleum and natural gas sales increase;


•	Achieved positive funds flow from operations of $17.0 million, representing the third consecutive quarter of positive funds flow from operations;



2017		9


•	Reported a 6% increase in production volumes as compared to Q4-2016. The increase principally relates to the acquired Canadian assets in December 2016 which contributed 2,700 boepd of additional production;


•	Repaid $10.0 million of the amount outstanding under the prepayment agreement with cash on hand during Q4-2017;


•	Sold a tanker of entitlement crude of 510,148 barrels and sold an additional 163,924 barrels of inventoried entitlement crude oil to EGPC, resulting in a decrease in crude oil inventory of 0.2 million barrels from Q3-2017; and


•	Spent $9.1 million on capital programs.

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest before Royalties (Boepd)

Production Volumes



	2017	2016
Egypt crude oil (bbls/d)	12,822	12,015
Canada crude oil (bbls/d)	589	18
Canada NGLs (bbls/d)	988	34
Canada natural gas (mcf/d)	6,644	230
Total Company (boe/d)	15,506	12,105

Sales Volumes (excludes volumes held as inventory)



	2017	2016
Egypt crude oil (bbls/d)	14,165	11,075
Canada crude oil (bbls/d)	589	18
Canada NGLs (bbls/d)	988	34
Canada natural gas (mcf/d)	6,644	230
Total Company (boe/d)	16,849	11,165

Netback



Consolidated netback
	2017		2016
(000s, except per boe amounts)¹	$	$/boe	$	$/boe
Petroleum and natural gas sales	252,591	41.07	122,360	29.94
Royalties	104,127	16.93	59,226	14.49
Current taxes	21,819	3.55	15,455	3.78
Operating expenses	50,212	8.16	40,323	9.87
Transportation	793	0.13	12	—
Selling costs	2,495	0.41	875	0.21
Netback	73,145	11.89	6,469	1.59
¹The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended December 31, 2017 and December 31, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at December 31, 2017 and December 31, 2016).
² Royalties and taxes are settled on a production basis, royalties and taxes attributable to oil sales fluctuates dependent upon the sale of inventoried entitlement oil.



Egypt
	2017		2016
(000s, except per bbl amounts)¹	$	$/bbl	$	$/bbl
Oil sales	230,323	44.55	121,728	30.03
Royalties	99,336	19.21	59,094	14.58
Current taxes	21,819	4.22	15,455	3.81
Production and operating expenses	44,705	8.65	40,054	9.88
Selling costs	2,495	0.48	875	0.22
Netback	61,968	11.99	6,250	1.54
¹The Company achieved the netbacks above on sold barrels of oil for the year ended December 31, 2017 and December 31, 2016 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at December 31, 2017 and December 31, 2016).
² Royalties and taxes are settled on a production basis, royalties and taxes attributable to oil sales fluctuates dependent upon the sale of inventoried entitlement oil.

The netback per bbl in Egypt increased 679% in 2017 compared with 2016. The increased netbacks were principally the result of realized oil prices increasing by 48%, an increase in previously inventoried entitlement barrels sold (488,326 barrels) and a decrease in operating costs per barrel of 12% during 2017 compared with 2016.



10		2017

Production and operating expenses increased by $4.7 million during 2017 compared to 2016. This is principally the result of an increase in sales volumes in 2017, resulting in recognizing the capitalized operating costs associated with the crude oil inventory in the period. On a per bbl basis, production and operating costs have decreased by 12% compared to 2016. The most significant cost efficiencies were achieved in the areas of labour costs and well servicing. The devaluation of the Egyptian pound, which occurred in Q4 of 2016, also had a positive impact on operating expenses in the year as compared to 2016. The gains realized from increased prices and lower operating costs were offset somewhat by higher transportation and marketing fees incurred on the direct sales of the Company's crude oil. TransGlobe completed three direct sales of crude oil during 2017.

Royalties and taxes as a percentage of revenue were 53% in 2017 compared with 61% for 2016. Royalties and taxes are settled on a production basis, so the correlation of royalties and taxes to oil sales fluctuates depending on the timing of inventoried oil sales. As such, in periods when the Company sells less than its entitlement production, royalties and taxes as a percentage of revenue will be higher and in periods when the Company sells more than its entitlement production, royalties and taxes as a percentage of revenue will be lower.

The average selling price for the year-ended December 31, 2017 was $44.55/bbl, which was $9.70/bbl lower than the average Dated Brent oil price of $54.25/bbl for 2017 (2016 - $43.55/bbl). Generally the difference in the average Dated Brent price and the Company's realized selling price is due to a gravity/quality differential and is impacted by the timing of direct sales.



Canada
	2017		2016
(000s, except per boe amounts)	$	$/boe	$	$/boe
Crude oil sales	10,464	48.67	266	40.38
Natural gas sales	4,120	10.19	152	10.83
NGL sales	7,684	21.31	214	17.20
Total sales	22,268	22.73	632	19.12
Royalties	4,791	4.89	132	3.99
Operating expenses	5,507	5.62	269	8.14
Transportation	793	0.81	12	0.36
Netback	11,177	11.41	219	6.63

The Canadian financial information presented in the table above represent 2017 full year activity and 12 days of activity for 2016, following the closing of the Harmattan acquisition on December 20, 2016.

Netbacks in Canada for 2017 were $11.41 per boe, which represents an increase of $4.78 per boe as compared to 2016. The increased netback was primarily attributable to increased average commodity prices and as a result of cost containment efforts in 2017 which focused on increased operational efficiencies, field optimization work, and competitive tendering of service contracts. The Company executed a strong optimization program during 2017, resulting in minimal downtime and reduced operating expenses.

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

For the year-ended December 31, 2017, the Company incurred $4.8 million in royalty costs. Royalties amounted to 22% of petroleum and natural gas sales revenue in 2017.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)



	2017				2016
(000s, except per boe amounts)	$		$/boe		$		$/boe
G&A (gross)	16,033		2.61		18,716		4.58
Stock-based compensation	1,478		0.24		2,418		0.59
Capitalized G&A and overhead recoveries	(2,258	)	(0.37	)	(3,579	)	(0.88	)
G&A (net)	15,253		2.48		17,555		4.29

G&A expenses (net) for 2017 decreased 13% as compared with 2016 (42% decrease on a per boe basis). G&A (gross) for 2017 decreased 14% as compared with 2016 (43% decrease on a per boe basis). This was primarily due to reduced staffing and office costs. G&A on a per boe basis decreased due to a 51% sales volume increase in 2017 compared with 2016.

Capitalized G&A for 2017 decreased 37%, as compared with 2016 (58% on a per boe basis). In 2016, the Company's capital spending commitments in Egypt were secured by letters of credit drawn on the Company's borrowing base facility. Banking fees associated with these letters of credit in the amount of $1.0 million were capitalized for the year-ended December 31, 2016. In December 2016 the Company terminated its Egypt borrowing base facility, and the spending commitments were secured by a cash collateralized letter of credit facility.



2017		11

FINANCE COSTS

Finance costs for the year ended December 31, 2017 increased to $6.2 million compared with $6.1 million in 2016.



(000s)	2017		2016
Convertible debentures	$	1,089	$	4,418
Long-term debt	3,994		—
Note payable	532		140
Reserves based lending facility	289		—
Borrowing base facility	—		786
Amortization of deferred financing costs	329		724
Finance costs	$	6,233	$	6,068

Convertible Debentures

Interest expense on the convertible debentures decreased to $1.1 million in 2017, compared with $4.4 million in 2016. Interest on the convertible debentures was paid in Canadian dollars, and therefore fluctuated from period to period depending on the strength of the Canadian dollar relative to the US dollar. The convertible debentures outstanding at December 31, 2016 were repaid in full on March 31, 2017 using the proceeds of the prepayment agreement.

Prepayment Agreement

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

TPI's obligations under the prepayment agreement are guaranteed by the Company and the subsidiaries of TPI (the "Guarantors"). The obligations of TPI and the Guarantors will be supported by, among other things, a pledge of equity held by the Company in TPI and a pledge of equity held by TPI in its subsidiaries. The funding arrangement has a term of four years, maturing March 31, 2021 and advances bear interest at a rate of LIBOR plus 6.0%. The funding arrangement is revolving with each advance to be satisfied through the delivery of crude oil to Mercuria. Further advances become available upon delivery of crude oil to Mercuria up to a maximum of $75.0 million and subject to compliance with the other terms and conditions of the prepayment agreement. The prepayment agreement was initially recognized at fair value, net of financing costs, and has subsequently been measured at amortized cost. The prepayment agreement is classified as long-term debt in the Company's financial statements. Financing costs of $1.5 million will be amortized over the term of the prepayment agreement using the effective interest rate method. Interest expense on the prepayment agreement in 2017 was $4.0 million.

The prepayment agreement is subject to certain covenants, the details of which are outlined in Note 20 to the Company's Consolidated Financial Statements.

Reserves Based Lending Facility

As at December 31, 2017, the Company had in place a revolving Canadian reserves-based lending facility with Alberta Treasury Branches ("ATB") totaling C$30.0 million ($24.0 million), of which C$14.0 million ($11.2 million) was drawn.

The facility borrowing base is re-calculated no less frequently than on a semi-annual basis of May 31 and November 30 of each year, or as requested by the lender. Lender shall notify the Company of each change in the amount of the borrowing base. In the event that lender re-calculates the borrowing base to be an amount that is less than the borrowings outstanding under the facility, the Company shall repay the difference between such borrowings outstanding and the new borrowing base within 45 days of receiving notice of the new borrowing base.

The Company may request an extension of the term date by no later than 90 days prior to the then current term date, and lender may in its sole discretion agree to extend the term date for a further period of 364 days. Unless extended, before May 11, 2018, any unutilized amount of the facility will be cancelled, and the amount of the facility will be reduced to the aggregate borrowings outstanding on that date. The balance of all amounts owing under the facility are due and payable in full on the date falling one year after the term date. If no extension is granted by the lender, the amounts owing pursuant to the facility are due at the maturity date. The facility bears interest at a rate of either ATB Prime or CDOR (Canadian Dollar Offered Rate) plus applicable margins that vary from 1.25% to 3.25% depending on the Company's net debt to trailing cash flow ratio. The revolving reserve-based lending facility was initially recognized at fair value, net of financing costs, and has subsequently been measured at amortized cost. Financing costs of $0.1 million will be amortized over the term of the agreement using the effective interest rate method. Interest expense on the revolving reserves-based lending facility at December 31, 2017 was $0.3 million.

Note Payable

On December 20, 2016, the Company closed the acquisition of certain petroleum properties in west central Alberta, Canada. The acquisition was partially funded by a vendor take-back note of C$15.0 million ($11.2 million). The note payable had a 24-month term and bore interest at a rate of 10% per annum. The Company repaid the outstanding vendor take-back note balance of C$13.6 million ($10.0 million) on May 16, 2017. Repayment was made using the revolving reserves-based lending facility. Interest expense on the note payable at December 31, 2017 was $0.5 million.

Borrowing Base Facility

In December 2016 the Company terminated its Borrowing Base Facility. There were no amounts outstanding under the Borrowing Base Facility at the time of termination; however, the Company was utilizing approximately $16.0 million in the form of letters of credit to support its exploration commitments in Egypt. The letters of credit outstanding under the borrowing base facility were transferred to a bilateral letter of credit facility with



12		2017

Sumitomo Mitsui Banking Corporation ("SMBC"). The issued letters of credit under the bilateral letter of credit facility were secured by cash collateral which was on deposit with SMBC. The exploration commitments associated with the cash collateralized letter of credit facility were fulfilled in 2017.

All remaining deferred financing costs related to the Borrowing Base Facility were expensed at the time of termination of the facility.

DEPLETION AND DEPRECIATION (“DD&A”)



	2017		2016
(000s, except per boe amounts)	$	$/boe	$	$/boe
Egypt	30,653	5.93	28,386	7.00
Canada	8,985	9.17	303	9.16
Corporate	398	—	488	—
	40,036	6.51	29,177	7.14

In Egypt, DD&A decreased 15% on a per Bbl basis in 2017 as compared to 2016. The decrease is primarily related to a lower depletable cost base, which is the result of a 7% reduction in future development costs.

In Canada, DD&A was $9.17 per boe, which was consistent with the DD&A per barrel recognized in 2016.

IMPAIRMENT OF EXPLORATION AND EVALUATION PROPERTIES

The Company completed an impairment evaluation on all exploration and evaluation ("E&E") assets as at December 31, 2017. 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.	Cessation of E&E activities due to a lack of commercially viable discoveries; and


4.	Carrying amounts of E&E assets are unlikely to be recovered in full from a successful development project.

For the year ended December 31, 2017 the Company recorded an impairment loss of $79.0 million on its exploration and evaluation assets. The impairment loss was split between the South West Gharib concession ($1.2 million), the North West Gharib concession ($67.5 million) and the South Alamein concession ($10.3 million).

At South West Gharib, it was determined during Q1-2017 that an impairment loss was necessary as no commercial quantities of oil were discovered, and no further drilling activities were planned. The South West Gharib exploration lands have been fully evaluated and all commitments had been met at the end of the first exploration phase. The Company elected to not enter the second exploration period and relinquished the concession in 2017.

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

At South Alamein, it was determined during Q3-2017 that an impairment loss was necessary, due to the results of the Boraq 5 well and the uncertainty of an economic development of Boraq in the future. The Company completed testing two zones in the Boraq 5 appraisal well. The Boraq 5 well failed to produce any hydrocarbons from the two zones and was plugged and abandoned.

In 2016, the Company recorded an impairment loss of $33.4 million on its exploration and evaluation assets. The impairment loss was related principally to the South East Gharib and South West Gharib concessions in Egypt. The impairment loss recognized on these two concessions represented the entire intangible exploration and evaluation asset balances on the concessions, as the recoverable amounts of the concessions were determined to be nil. The Company relinquished its interest in South East Gharib in November 2016, and relinquished its interest in South West Gharib in the first half of 2017 as no commercially viable quantities of oil had been discovered on either concession. At South West Gharib, the Company drilled two wells during Q1-2017, both of which were dry and abandoned. An impairment loss was recorded in the first quarter of 2017 in an amount equal to the capital costs associated with these wells.

CAPITAL EXPENDITURES



($000s)	2017	2016
Egypt	31,151	26,658
Canada	6,967	—
Property acquisitions	—	59,475
Corporate	41	—
Total	38,159	86,133



2017		13

In Egypt, total capital expenditures in 2017 were $31.2 million (2016 - $26.7 million). The Company spent $13.4 million in drilling, $4.9 million on seismic acquisition, $2.9 million on completions, $1.1 million on workovers and $3.9 million on facilities construction/maintenance and $1.0 million related to the approval for three development leases.

In Egypt, during the year 2017, the Company drilled ten exploration wells, four development wells and one appraisal well. Seven exploration wells were drilled at NW Gharib resulting in two oil discoveries (NWG 26, NWG 27) and five dry holes (NWG 3A side track, NWG 28, NWG 39, NWG 40 and NWG 42). At SW Gharib, the Company drilled two exploration wells, both of which were dry and abandoned. At South Alamein the Company drilled one exploration well, Boraq 5, resulting in a dry hole. At West Gharib, the second of two infill development oil wells in Arta Red Bed pool was drilled and at West Bakr the K-47 development well was drilled and cased as an Asl A oil well in the South-K field. At NW Gharib, the Company drilled two development oil wells, NWG 38A1 and NWG 38A2, in the NW Gharib 38 Red Bed pool. In addition, the Company drilled one appraisal well at NWG 3A that was dry and abandoned.

In Canada, the Company equipped and tied in three horizontal Cardium oil wells in Harmattan during the year. The three wells were drilled, completed and equipped for approximately $2.1 million (C$2.6 million) each.

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

Finding and development (“F&D”) costs are calculated as the aggregate of exploration costs, development costs and the change in estimated future development costs divided by the applicable reserve additions. Finding, development and acquisition (“FD&A”) costs incorporate acquisitions, net of any dispositions during the year. The Company expects to fund the development costs of the reserves through a combination of sources including funds flow from operations, debt capacity, proceeds from property dispositions and if necessary, the issuance of Common Shares.

Changes in forecast future development capital occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect the independent evaluator’s best estimate of what it will cost to bring the proved plus probable undeveloped reserves on production at that time. Undiscounted future development costs ("FDC") for proved plus probable undeveloped reserves decreased $12.0 million compared to year-end 2016, to total $127.5 million at year end 2017. The change in FDC is attributable to reduced estimates after actual costs incurred in the Company’s most recent capital program were lower than previously budgeted.

Estimates of reserves and future net revenues have been made assuming the development of each property, in respect of which the estimate is made, will occur, without regard to the likely availability to us of funding required for the development. There can be no guarantee that funds will be available or that we will allocate funding to develop all of the reserves attributed in the reserves evaluator's report. Failure to develop those reserves would have a negative impact on future funds flow from operations.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates and would reduce reserves and future net revenues to some degree depending upon the funding sources utilized. TransGlobe does not anticipate that interest or other funding costs would make development of any property uneconomic.



Proved
($000s, except volumes and $/boe amounts)	2017		2016	2015
Total capital expenditures	38,159		26,658	42,902
Acquisitions¹	—		59,475	2,000
Dispositions	—		—	(1,500	)
Net change from previous year’s future capital	(13,311	)	60,084	(9,024	)
	24,848		146,217	34,378
Reserve additions and revisions (Mboe)
Exploration and development	3,262		5,138	990
Acquisitions, net of dispositions	—		11,667	(300	)
Total reserve additions (Mboe)	3,262		16,805	690
Average cost per boe
F&D	7.62		4.02	34.22
FD&A	7.62		8.70	49.83
Three-year weighted average cost per boe
F&D	8.45		58.03	83.93
FD&A	9.88		19.58	110.07
¹ The 2016 Acquisitions figure consists entirely of acquisition costs on the Canadian assets. 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.
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.



14		2017



Proved Plus Probable
($000s, except volumes and $/boe amounts)	2017		2016	2015
Total capital expenditure	38,159		26,658	42,902
Acquisitions¹	—		59,475	2,000
Dispositions	—		—	(1,500	)
Net change from previous year’s future capital	(12,009	)	110,102	(30,741	)
	26,150		196,235	12,661
Reserve additions and revisions (Mboe)
Exploration and development	1,538		4,906	1,498
Acquisitions, net of dispositions	—		20,744	(936	)
Total reserve additions (Mboe)	1,538		25,650	562
Average cost per boe
F&D	17.00		3.66	8.03
FD&A	17.00		7.65	22.53
Three-year weighted average cost per boe
F&D²	7.07		231.05	—
FD&A²	8.47		14.51	—
¹ The 2016 Acquisitions figure consists entirely of acquisition costs on the Canadian assets. 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.
² 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



	Three-Year
Proved	Weighted
	Average²	2017	2016		2015
Netback ($/boe)¹	1.59	8.08	(3.12	)	(3.12	)
Proved F&D costs ($/boe)	8.45	7.62	4.02		34.22
Proved FD&A costs ($/boe)	9.88	7.62	8.80		49.83
F&D Recycle ratio²	0.19	1.06	—		—
FD&A Recycle ratio²	0.16	1.06	—		—
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 In 2016 and 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 2016 and 2015 were included in the three-year weighted average recycle ratios.



	Three-Year
Proved Plus Probable	Weighted
	Average²	2017	2016		2015
Netback ($/boe)¹	1.59	8.08	(3.12	)	(3.12	)
Proved plus Probable F&D costs ($/boe)	7.07	17.00	3.66		8.03
Proved plus Probable FD&A costs ($/boe)	8.46	17.00	7.65		22.53
F&D Recycle ratio²	0.22	0.48	—		—
FD&A Recycle ratio²	0.19	0.48	—		—
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 In 2016 and 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 2016 and 2015 were included in the three-year weighted average ratios.

The 2017 recycle ratio is positive as a result of positive recycle ratio netbacks in the year. The positive netbacks were primarily the result of higher oil prices, combined with the Company selling three cargo's of entitlement crude oil totaling 1,468,726 barrels and selling an additional 1,121,391 barrels of inventoried entitlement crude oil to EGPC, resulting in an overall decrease in inventoried crude oil by 488,326 barrels from 2016.

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



2017		15

Recycle Netback Calculation

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, interest and current income tax expense per boe of production.



($000s, except volumes and per boe amounts)	2017		2016		2015
Net loss	(78,736	)	(87,665	)	(105,600	)
Adjustments for non-cash items:
Depletion, depreciation and amortization	40,036		29,177		42,875
Accretion	256		—		—
Stock-based compensation	1,478		2,418		2,787
Deferred income taxes	—		(3,009	)	(36,041	)
Amortization of deferred financing costs	329		724		849
Amortization of deferred lease inducement	(91	)	(95	)	(104	)
Realized loss on commodity contracts	7,970		956		688
Unrealized foreign exchange (gain) loss	(35	)	4,292		(11,333	)
Unrealized loss on financial instruments	151		7,027		6,615
Impairment loss	79,025		33,426		85,373
Asset retirement obligations settled	(695	)	—		—
Recycle netback	49,688		(12,749	)	(13,639	)
Sales volumes (Mboe)	6,150		4,086		4,372
Recycle netback per boe	8.08		(3.12	)	(3.12	)

OUTSTANDING SHARE DATA

As at December 31, 2017, the Company had 72,205,369 common shares issued and outstanding and 4,958,553 stock options issued and outstanding, which are exercisable in accordance with their terms into an equal number of common shares of the Company.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity describes a company’s ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs necessary to maintain and increase production and reserves, to acquire strategic oil and gas assets and to repay current liabilities and debt. TransGlobe’s capital programs are funded by its existing working capital and cash provided from operating activities. TransGlobe’s net debt to funds flow from operations ratio has improved significantly from 2016 as a result of a better oil price environment and increased sales of inventoried entitlement oil. As at December 31, 2017, net debt-to-funds flow from operations improved to 0.3 (December 31, 2016 - negative 12.0) as a result of positive funds flow from operations for the trailing 12 months. The Company's funds flow from operations can vary significantly from year to year depending on the timing of tanker liftings, and these fluctuations in funds flow impact the Company's net debt-to-funds flow from operations ratio. TransGlobe's management will continue to steward its capital and focus on cost control in order to maintain balance sheet strength through the current oil price environment.



16		2017

The table illustrates TransGlobe’s sources and uses of cash during the years ended December 31, 2017 and 2016:



Sources and Uses of Cash
($000s)	2017	2016
Cash sourced
Funds flow from operations¹	55,592	(8,361	)
Transfer from restricted cash	18,323	—
Increase in long-term debt	85,328	—
Other	548	—
	159,791	(8,361	)
Cash used
Capital expenditures	38,159	26,658
Deferred financing costs	1,554	—
Transfer to restricted cash	—	17,462
Property acquisitions	—	48,313
Repayment of long-term debt	15,000	—
Repayment of convertible debentures	73,375	—
Repayment of note payable	11,041	—
Finance costs	6,952	5,288
Other	—	2,212
	146,081	99,933
	13,710	(108,294	)
Changes in non-cash working capital	2,271	12,852
Increase (decrease) in cash and cash equivalents	15,981	(95,442	)
Cash and cash equivalents – beginning of year	31,468	126,910
Cash and cash equivalents – end of year	47,449	31,468
¹ Funds flow from operations (before finance costs) is a measure that represents cash generated from operating activities before changes in non-cash working capital, and may not be comparable to measures used by other companies.

Funding for the Company’s capital expenditures was provided by funds flow from operations and cash on hand. The Company expects to fund its 2018 exploration and development program of $41.3 million, including contractual commitments, through the use of working capital and funds flow from operations. Fluctuations in commodity prices, product demand, foreign exchange rates, interest rates and various other risks may impact capital resources and capital expenditures.

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2017, the Company had a working capital surplus of $50.6 million (December 31, 2016 - deficiency of $16.8 million). The increase to working capital in 2017 is principally due to the repayment of the convertible debt, which was a current liability at year-end 2016, (using the proceeds from the prepayment agreement) and increased sales of inventoried entitlement oil, as well as better crude pricing and lower Gharib blend differentials, offset by lower natural gas prices in Canada. During 2017, the Company repaid $15.0 million of the amount outstanding under the prepayment agreement with cash on hand.

As at December 31, 2017, the Company held 776,754 barrels of entitlement oil as inventory, which represents approximately five months of entitlement oil production. Crude oil inventory levels fluctuate from year to year depending on the timing and size of tanker liftings in Egypt. Since the Company began directly marketing its oil on January 1, 2015, both increases and decreases in crude oil inventory levels have been experienced from year to year. Throughout 2016 and Q1-2017 there was a steady increase in crude oil inventory levels, as production outpaced sales. In Q2-2017, Q3-2017 and Q4-2017, crude oil inventory levels dropped as a result of crude oil sales being greater than our production. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows.

The Company's third cargo lifting of 2017 was completed in November and proceeds from the lifting were received in December. The Company now enjoys a 30-day collection cycle as a result of direct marketing to third party international buyers. Depending on the Company's assessment of the credit of crude cargo buyers, buyers may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings, which has significantly reduced the Company's credit risk profile. The Company expects to complete both external sales (tanker liftings) and internal sales in 2018. The Company works with EGPC on a continuous basis to schedule tanker liftings and management has arranged for four liftings in 2018.

The Company now has a receivables balance of $14.2 million due from EGPC. During 2017, the Company sold 1,121,391 barrels of inventoried entitlement crude oil to EGPC for $48.5 million to cover in-country expenditures. The Company collected $47.8 million of accounts receivable from EGPC during 2017.

At December 31, 2017, the Company had in place a revolving Canadian reserves-based lending facility with ATB totaling C$30.0 million ($24.0 million), of which C$13.6 million ($10.0 million) was drawn on May 16, 2017 to repay the remaining outstanding vendor take-back note balance in full for $C13.6 million ($10.0 million). As at December 31, 2017, C$14.0 million ($11.2 million) was drawn. Subsequent to year-end, the Company repaid C$2.0 million ($1.6 million) towards the reserves-based lending facility.

As at December 31, 2017, the Company had no restricted cash (December 31, 2016 - $18.3 million). Restricted cash represented a cash collateralized letter of credit facility that was used to guarantee the Company's commitments on its Egyptian exploration concessions.

The Company terminated its Borrowing Base Facility in December 2016. There were no amounts drawn on the Borrowing Base Facility at any time in 2016.

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



2017		17

PRODUCT INVENTORY

Product inventory consists of the Company's Egypt entitlement crude oil barrels, which are valued at the lower of cost or net realizable value. Cost includes operating expenses and depletion associated with the unsold entitlement crude oil as determined on a concession by concession basis. All oil produced is delivered to EGPC facilities, and EGPC also owns the storage and export facilities where the Company's product inventory is sold from. The Company requires EGPC approval to schedule liftings and works with EGPC on a continuous basis to schedule tanker liftings. Crude oil inventory levels fluctuate from year to year depending on EGPC approvals granted and the timing and size of tanker liftings in Egypt. As at December 31, 2017, the Company had 776,754 barrels of entitlement oil as inventory, which represents approximately five months of entitlement oil production. Since the Company began directly marketing its oil on January 1, 2015, both increases and decreases in crude oil inventory levels have been experienced from year to year. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows. The Company expects to complete both external sales (tanker liftings) and internal sales to EGPC in 2018, and anticipates that 2018 year-end crude oil inventory will remain at less than 1 million barrels, subject to the current tanker lifting schedule. Four tanker liftings are currently scheduled for in 2018, with expected total shipment volumes of approximately 1.8 to 2.1 MMbbl. Inventoried entitlement crude oil has been reduced by 488,326 barrels in 2017 compared to 2016.



	Year ended		Year ended
(bbls)	December 31, 2017		December 31, 2016
Product inventory, beginning of period	1,265,080		923,106
TransGlobe entitlement production	2,101,792		2,036,483
Tanker liftings	(1,468,727	)	(1,694,509	)
EGPC sales	(1,121,391	)	—
Product inventory, end of period	776,754		1,265,080

COMMITMENTS AND CONTINGENCIES

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



($000s)		Payment Due by Period^{1 2}
	Recognized
	in Financial	Contractual	Less than
	Statements	Cash Flows	1 year	1-3 years	4-5 years
Accounts payable and accrued liabilities	Yes - Liability	27,104	27,104	—	—
Long-term debt	Yes - Liability	69,999	—	11,207	58,792
Financial derivative instruments	Yes - Liability	7,970	4,015	3,955	—
Convertible debentures	Yes - Liability	—	—	—	—
Note payable	Yes - Liability	—	—	—	—
Office and equipment leases³	No	3,587	1,707	1,880	—
Minimum work commitments⁴	No	5,129	5,129	—	—
Total		113,789	37,955	17,042	58,792
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, 2017 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.

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

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

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



2017		18

Pursuant to the PSC for North West Sitra in Egypt, the Company has a minimum financial commitment of $10.0 million ($5.1 million remaining) and a work commitment for two wells and 300 square kilometers of 3-D seismic during the initial three and a half year exploration period, which commenced on January 8, 2015. As at December 31, 2017, the Company had expended $4.9 million towards meeting the financial and operating commitment, with the acquisition of 600 square kilometers of 3-D seismic in 2017.

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

The Company is not aware of any material provisions or other contingent liabilities as at December 31, 2017.

ASSET RETIREMENT OBLIGATION

At December 31, 2017, TransGlobe recorded an asset retirement obligation ("ARO") of $12.3 million (2016 - $12.1 million) for the future abandonment and reclamation costs associated with the Harmattan assets. The estimated ARO includes assumptions in respect of actual costs to abandon wells and/or reclaim the properties, the time frame in which such costs will be incurred, as well as annual inflation factors in order to calculate the undiscounted total future liability. TransGlobe calculated the present value of the obligations using discount rates between 1.68% and 2.26% to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates.

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

DERIVATIVE COMMODITY CONTRACTS

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

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

There were eleven outstanding derivative commodity contracts as at December 31, 2017 (December 31, 2016 - nil), the fair values of which have been presented as liabilities on the Consolidated Balance Sheet.

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



Financial Brent Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume bbl	Bought Put USD$/bbl	Sold Call USD$/bbl	Sold Put USD$/bbl
7-Apr-17	Mar-18	3-Way Collar	250,000	53.00	61.15	44.00
12-Apr-17	Jun-18	3-Way Collar	250,000	54.00	63.10	45.00
12-Apr-17	Sep-18	3-Way Collar	250,000	54.00	64.15	45.00
12-Apr-17	Dec-18	3-Way Collar	250,000	54.00	65.45	45.00
23-May-17	Jul 2020 - Dec 2020¹	3-Way Collar	300,000	54.00	63.45	45.00
31-Aug-17	Jan 2020 - Jun 2020²	3-Way Collar	300,000	54.00	61.25	46.50
12-Oct-17	Jan 2019 - Dec 2019³	3-Way Collar	396,000	53.00	62.10	46.00
26-Oct-17	Jan 2019 - Dec 2019⁴	3-Way Collar	399,996	54.00	61.35	46.00
^1.50,000 bbls per calendar month through Jul 2020 - Dec 2020
^2.50,000 bbls per calendar month through Jan 2020 - Jun 2020
^3. 33,000 bbls per calendar month through Jan 2019 - Dec 2019
^4. 33,333 bbls per calendar month through Jan 2019 - Dec 2019



Financial WTI Crude Oil Contracts
Transaction Date	Period Hedged	Contract	Volume bbl	Sold Swap USD$/bbl	Bought Put CAD$/bbl	Sold Call CAD$/bbl
15-Dec-17	Jan 2018 - Dec 2018¹	Swap	60,225	56.35	—	—
15-Dec-17	Jan 2018 - Dec 2018¹	Put Option	60,225	—	64.00	—
15-Dec-17	Jan 2018 - Dec 2018¹	Call Option	60,255	—	—	78.85
^1.165 bbls per day



2017		19

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, 2017.

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 financial 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 strong liquidity position and management regularly evaluates operational and financial risk strategies and continues to monitor the 2018 capital budget and the Company’s long-term plans. In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. The Company anticipates that direct sales will continue to reduce financial risk in future periods.

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 commodity prices, 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 and gas 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, long-term debt, former convertible debentures, accounts payable and accrued liabilities denominated in Canadian dollars. When assessing the potential impact of foreign currency exchange risk, the Company believes that 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 increase the net loss for the year ended December 31, 2017 by approximately $0.5 million and conversely a 10% decrease in the value of the Canadian dollar against the U.S. dollar would decrease the net loss by $0.4 million for the same period. The Company does not utilize 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 2017 was $0.8 million (2016 - $3.9 million) in equivalent U.S. dollars. The Company estimates that a 10% increase in the value of the Egyptian pound



20		2017

against the U.S. dollar would increase the net loss for the year ended December 31, 2017 by approximately $0.1 million and conversely a 10% decrease in the value of the Egyptian pound against the U.S. dollar would decrease the net loss by $0.1 million for the same period. The Company does not currently utilize derivative instruments to manage foreign currency exchange risk.

Interest rate risk

Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable interest debt. No derivative contracts were entered into during 2017 to mitigate interest rate 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. The effect of interest rates increasing by 1% would decrease the Company’s net earnings, for the year ended December 31, 2017, by $0.5 million and conversely the effect of interest rates decreasing by 1% would increase the Company’s net earnings, for the year ended December 31, 2017, by $0.5 million.

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 and gas 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 and gas 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 significant receivables outstanding from the Government of Egypt. In the past, the timing of payments on these receivables from the Government of Egypt were longer than normal industry standard. Despite these factors, the Company expects to collect these receivables in full, though 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.

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. Buyers may be required to post irrevocable letters of credit to support the sales prior to the cargo liftings. The Company anticipates that direct sales will continue to reduce credit risk in future periods.

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.

The Company actively maintains its 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 lifting and sale of the Company's entitlement crude oil are deposited directly to its accounts held in London, England.

Crude oil inventory levels fluctuate from quarter to quarter depending on the timing and size of tanker liftings in Egypt. Since the Company began directly marketing its oil on January 1, 2015, both increases and decreases in crude oil inventory levels have been experienced from quarter to quarter. Throughout 2016 and Q1-2017 there was a steady increase in crude oil inventory levels, as production outpaced sales. In Q2-2017, Q3-2017 and Q4-2017, crude oil inventory levels dropped as a result of crude oil sales being greater than our production. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows.

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 and domestic 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.



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Political risk

TransGlobe operates in countries 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 companies, economic and legal sanctions and other uncertainties arising from foreign and domestic governments.

Egypt has been experiencing significant political changes over the past seven 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 amounts 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 evaluated and reported on by independent reserve evaluators to the Reserves, Health, Safety, Environment and Social Responsibility 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 Loss and Comprehensive Loss.

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 cash-generating unit ("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.



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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, long-term debt, the former note payable and previous 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.

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, derivative commodity contracts and the former 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, long-term debt, the prior note payable 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; when the terms of the embedded derivatives are the same as those of a freestanding derivative; and when 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.

NEW STANDARDS AND INTERPRETATIONS NOT YET ADOPTED

Future changes to accounting policies

As at the date of authorization of the Consolidated Financial Statements the following pronouncements from the International Accounting Standards Board ("IASB") are applicable to TransGlobe and will become effective for future reporting periods, but have not yet been adopted:

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



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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. This amendment will be adopted by the Company on January 1, 2018 and the Company does not expect the adoption of IFRS 9 amendments to have a material effect on its Consolidated Financial Statements.

IFRS 15 "Revenue from Contracts with Customers"

IFRS 15 was issued in May 2014 and replaces IAS 18 Revenue, IAS 11 Construction Contracts and related interpretations. The standard is required to be adopted either retrospectively or using a modified transaction approach. IFRS 15 will be adopted by the Company on January 1, 2018. The Company is finalizing the review of its sales contracts with customers and does not expect IFRS 15 will have a material impact on the consolidated financial statements. Upon adoption, the Company will expand its disclosures in the notes to the consolidated financial statements including disaggregated revenue streams by product type and any impairment losses recognized on receivables arising from contracts with customers.

IFRS 16 "Leases"

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

DISCLOSURE CONTROLS AND PROCEDURES

As of December 31, 2017, 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 as defined in Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in Canada by National Instrument 52-109, Certification of Disclosure in Issuers' Annual and Interim Filings. 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.

Disclosure controls and procedures are defined as controls and other procedures of an issuer that are designed to provide reasonable assurance that information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by an issuer in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the issuer’s management, including its certifying officers, as appropriate to allow timely decisions regarding required disclosure.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

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

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 of December 31, 2017. No changes were made to the Company's internal control over financial reporting during the year ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.



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