Exhibit

EX-1 2 a2016annualreport.htm EXHIBIT 1 Exhibit

CONTENTS



MESSAGE TO SHAREHOLDERS	Page 3
MANAGEMENT’S DISCUSSION AND ANALYSIS	Page 4
MANAGEMENT’S REPORT	Page 25
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM	Page 26
CONSOLIDATED FINANCIAL STATEMENTS	Page 28
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	Page 32
SUPPLEMENTARY INFORMATION
Financial / Reserves / Production and Sales Volumes	Page 55
Share Information	Page 56
Summary of International Production Sharing Concessions	Page 57
Reserves and Estimated Future Net Reserves	Page 58

TransGlobe Energy Corporation’s

Annual General Meeting of Shareholders

Thursday, May 11, 2017

3:00 PM

Mountain Time

Bow River Room located in the

Centennial Place West Conference Centre

3rd Floor, 250 5th Street S.W.

Calgary, Alberta, Canada

MESSAGE TO THE SHAREHOLDERS

The oil industry faced another challenging year in 2016, which saw Dated Brent oil prices fall below $30 per barrel in January and recover to over $56 per barrel to close the year. The gloom of January's price environment was replaced with cautious optimism in the industry at year-end. TransGlobe continued to make strides towards fully adapting to the lower price environment by becoming as cost efficient as possible, with the focus in 2016 placed mainly on improving capital cost efficiencies. The Company also executed on a significant strategic milestone by acquiring producing oil and gas properties in Canada just prior to year-end, which diversifies TransGlobe's country concentration risk going forward.

On December 20, 2016, TransGlobe closed the acquisition of producing and development assets in the Harmattan area of west central Alberta. The acquisition provides the Company with ~3,000 boepd of production (~60% liquids weighted) and total Proved plus Probable reserves of 20.7 million boe. Total consideration for the assets was C$80 million ($59.5 million), which was comprised of C$65 million ($48.3 million) cash and a vendor take-back note of C$15 million ($11.2 million). The purchase price represents a cost of C$25,806 ($19,203) per flowing boepd, or C$3.76 ($2.80) per boe of Proved plus Probable reserves. The acquisition met the Company's strategic objective to diversify and expand operations into lower political risk OECD countries with attractive netbacks to support growth in the current oil price environment. The assets provide TransGlobe with a stable production base in Canada, with significant future growth potential (45 net drilling locations assigned in Proved plus Probable reserves, and an additional 100+ net drilling locations identified by TransGlobe).

TransGlobe engaged in an active drilling program in 2016, drilling 17 wells in total. The exploration drilling program at NW Gharib, SE Gharib and SW Gharib, consisting of 14 wells in aggregate, yielded two oil discoveries (NWG 27 & NWG 38) and one well with oil shows that was abandoned due to drilling problems (NWG 26). Subsequent to year-end, the Company drilled NWG 26ST (side-track), resulting in a discovery. At the beginning of the year, due to the continuing weakness in oil prices and widening heavy oil differentials, the Company was aggressively conserving cash and working on cost cutting initiatives. By mid spring, in light of some stability returning to oil prices, the Company had developed a production recovery plan to recover production that had decreased due to the cash conservation strategy. In addition to the exploration program, the Company drilled two development wells at West Bakr and one development well at West Gharib as part of the production recovery plan. Capital costs associated with the drilling program trended 30% to 40% below historical norms due to better contract terms and optimized drilling programs, with Red Bed wells (D&A) costing ~$0.5 million per well versus pre-drill estimates of $0.8 million per well.

The Company's continued focus on cost reductions led to even further operating and G&A cost reductions in 2016. Operating costs were reduced from $61.8 million in 2015 to $43.6 million in 2016 (inclusive of operating costs capitalized as crude oil inventory). This translates into operating costs per produced barrel of $9.79, which represents a 16% decrease from 2015 operating costs per barrel of $11.67. These cost reductions were achieved through a number of factors, the chief of which was the efficiencies gained through merging the two eastern desert joint venture companies. This provided additional efficiencies through elimination of redundancies and shared contracting.

Gross G&A costs, excluding stock-based compensation, were $18.7 million in 2016 (2015 - $24.4 million), representing a 23% decrease from prior year. This brought gross G&A per produced barrel down to $4.22/bbl, versus $4.61/bbl in 2015. The decrease in G&A costs was mostly attributable to reduced payroll and staffing alignment expenditures.

Reserves at 2016 year-end were higher compared to 2015 year-end primarily due to the Canadian acquisition and positive revisions of the Arta Red Bed pool performance/technical revisions in addition to positive performance revisions in West Bakr. The Company drilled three development wells (two in K-South and one in the Arta Red Bed) all of which resulted in undeveloped reserve assignments as of the mid-year 2016 reserve update. One additional Arta Red Bed development well was drilled and rig released subsequent to December 31, 2016. The Company produced a total of 4.4 MMBbls of crude oil in Egypt in 2016, and production was replaced by the positive technical revisions in the West Gharib and West Bakr concessions. In addition, the Company filed for and received its first development lease in NW Gharib. Production from the NWG 3X well commenced prior to year-end 2016, representing a reserve conversion from proved undeveloped to proved producing.

The Company's 2017 capital budget of $56.4 million (firm plus contingent) is weighted 70% to development and 30% to exploration. The total firm plus contingent capital budget for Egypt is $40.2 million, which will be spent on drilling up to 18 wells, completing a large (600 km²) seismic acquisition program at NW Sitra, and completing various development/maintenance projects in the Eastern Desert. In Canada, the $16.2 million (firm plus contingent) capital program includes up to eight horizontal (multi-stage frac) development wells and additional maintenance/development capital for potential workovers/re-fracs.

Geoff Chase, a long-term director with TransGlobe, will be retiring in May 2017. Geoff has been a dedicated supporter of the Company since 2000. His leadership and passion for the industry will be missed. On behalf of the Board of Directors and staff we wish Geoff a long, happy and healthy retirement.

Signed by:

“Ross G. Clarkson”

Ross G. Clarkson

President and Chief Executive Officer

March 6, 2017



2016		3

MANAGEMENT'S DISCUSSION AND ANALYSIS

March 6, 2017

The following discussion and analysis is management’s opinion of TransGlobe’s historical financial and operating results and should be read in conjunction with the message to shareholders and the audited consolidated financial statements of the Company for the years ended December 31, 2016 and 2015, 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 2017, including expected 2017 average production, funds flow from operations, the 2017 capital program for exploration and development, the timing and method of financing thereof, the terms of drilling commitments under the Egyptian PSCs and the method of funding such drilling commitments, the Company's beliefs regarding the reserve and production growth of its assets and the ability to grow with a stable production base, and commodity prices and expected volatility thereof. Statements relating to "reserves" are deemed to be forward‑looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.

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

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

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

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

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



4		2016

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 gasreserves 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.

DIVIDENDS

The Company suspended its quarterly dividend effective March 8, 2016, and will evaluate its ability to reinstate a dividend program on a quarterly basis. During the year ended December 31, 2015, the Company paid quarterly dividends on its common shares of $0.05 per share for the first three quarters and $0.025 per share for the fourth quarter.

MANAGEMENT STRATEGY AND OUTLOOK

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

2017 Outlook

It is expected that 2017 production will average between 15,500 and 18,500 boepd, representing a 30% to 55% increase over 2016 production. The 2017 production outlook is provided as a range to reflect the firm and contingent budget that has been approved. The bottom end of the range is more reflective of the firm budget and the upper end of the range is more reflective of the contingent budget. Funds flow in any given period will be dependent upon the timing of crude oil tanker liftings in Egypt and the market price of the crude sold. Because these factors are difficult to accurately predict, the Company has not provided funds flow guidance for 2017. Funds flow and inventory levels in Egypt are expected to fluctuate significantly from quarter to quarter due to the timing of liftings.

2017 Capital Budget

The Company's 2017 capital program of $56.4 million (before capitalized G&A) includes $40.2 million for Egypt and $16.2 million (C$22.4 million) for Canada.

Egypt

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

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

Canada

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

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

The 2017 capital program is summarized in the following table:



2016		5



	TransGlobe 2017 Firm & Contingent Capital ($MM)							Gross Well Count
	Development			Exploration			Total	(Wells)
Concession	Wells	Maint	Projects	Wells	Bonus	Seismic	Total	Devel	Explor	Total
West Gharib	2.4	1.3	2.6	—	—	—	6.3	—	—	—
West Bakr	6.7	1.0	2.1	—	—	—	9.8	2	—	2
NW Gharib	7.6	—	—	6.9	0.1	—	14.6	6	8	14
SW Gharib	—	—	—	1.2	0.2	—	1.4	—	1	1
South Alamein	—	—	—	3.1	0.6	—	3.7	—	1	1
South Ghazalat	—	—	—	—	0.2	—	0.2	—	—	—
NW Sitra	—	—	—	—	0.2	4.0	4.2	—	—	—
Egypt	$16.7	$2.3	$4.7	$11.2	$1.3	$4.0	$40.2	8	10	18
Canada	$14.7	$1.5	—	—	—	—	$16.2	8	—	8
2016 Total	$31.4	$3.8	$4.7	$11.2	$1.3	$4.0	$56.4	16	10	26
Splits (%)	70%			30%			100%	62%	38%	100%

NON-GAAP FINANCIAL MEASURES

Funds flow from operations

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

Reconciliation of funds flow from operations



($000s)	2016		2015
Cash flow from operating activities	(1,065	)	77,526
Changes in non-cash working capital	(7,296	)	(86,428	)
Funds flow from operations¹	(8,361	)	(8,902	)
¹ Funds flow from operations does not include interest or financing costs. Interest expense is included in financing costs on the Consolidated Statements of Earnings and Comprehensive Income. Cash interest paid is reported as a financing activity on the Consolidated Statements of Cash Flows.

Debt-to-funds flow ratio

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

Netback

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

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 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 Bbl basis. Recycle ratio does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures used by other companies.

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 Bbl 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.



6		2016

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 liquid-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 $48.4 million cash from the balance sheet and a 10%, 24-month vendor take back loan of $11.2 million.

The acquisition provides the Company with ~3,000 boepd of production (60% liquids weighted) and total Proved plus Probable reserves of 20.7 million boe. The acquisition met the Company's strategic objective to diversify and expand operations into lower political risk OECD countries with attractive netbacks to support growth in the current oil price environment.



2016		7

SELECTED ANNUAL INFORMATION



($000s, except per share, price and volume amounts)	2016		% Change	2015		% Change	2014
($000s, except per share, price and volume amounts)	2016		% Change	2015		% Change	2014
Operations
Average production volumes
Crude oil (bbls/d)	12,033		(17)	14,511		(10)	16,103
NGLs and condensate (bbls/d)	34		100	—		—	—
Natural gas (mcf/d)	230		100	—		—	—
Total (boe/d)	12,105		(17)	14,511		(10)	16,103
Average sales volumes
Crude oil (bbls/d)	11,093		(7)	11,977		(26)	16,161
NGLs and condensate (bbls/d)	34		100	—		—	—
Natural gas (mcf/d)	230		100	—		—	—
Total (boe/d)	11,165		(7)	11,977		(26)	16,161
Average realized sales prices
Crude oil ($/Bbl)	30.05		(30)	42.93		(51)	86.99
NGLs and condensate ($/Bbl)	17.20		100	—		—	—
Natural gas ($/Mcf)	1.81		100	—		—	—
Total oil equivalent ($/boe)	29.94		(30)	42.93		(51)	86.99
Inventory (Bbl)	1,265,080		37	923,106		100	—
Petroleum and natural gas sales	122,360		(35)	187,665		(63)	513,153
Petroleum and natural gas sales, net of royalties	63,134		(32)	92,212		(66)	274,594
Cash flow from operating activities	(1,065	)	(101)	77,526		(47)	146,977
Funds flow from operations¹	(8,361	)	6	(8,902	)	(107)	120,489
- Basic per share	(0.12	)		(0.12	)		1.61
- Diluted per share²	(0.12	)		(0.12	)		1.46
Net earnings (loss)	(87,665	)	17	(105,600	)	(1,020)	11,482
Net earnings (loss) - diluted	(87,665	)	17	(105,600	)	(6,347)	(1,638	)
- Basic per share	(1.21	)		(1.44	)		0.15
- Diluted per share	(1.21	)		(1.44	)		(0.02	)
Dividends paid	—		(100)	12,865		(31)	18,752
Dividends paid per share	—		(100)	0.175		(30)	0.25
Total assets	406,142		(11)	455,500		(30)	654,058
Cash and cash equivalents	31,468		(75)	126,910		(10)	140,390
Convertible debentures	72,655		14	63,848		(8)	69,093
Note payable	11,162		100	—		—	—
Debt-to-funds flow ratio³	(10.0	)		(7.2	)		0.6
Reserves
Total Proved (MMBoe)⁴	29.9		71	17.5		(21)	22.1
Total Proved plus Probable (MMBoe)⁴	50.0		74	28.7		(14)	33.5
¹ Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
² Funds flow from operations per share (diluted) was not impacted by the convertible debentures for the years ended December 31, 2016 and December 31, 2015, as the convertible debentures were not dilutive in these years. Funds flow from operations per share (diluted) prior to the dilutive impact of the convertible debentures was $1.59 for the year ended December 31, 2014.
³ Debt-to-funds flow ratio is a measure that represents total long-term debt (including the current portion) plus convertible debentures over funds flow from operations for the trailing 12 months, and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
⁴ As determined by the Company's independent reserves evaluator, DeGolyer and MacNaughton Canada Limited ("DeGolyer") of Calgary, Alberta, in their reports dated January 18, 2017, January 15, 2016, and January 30, 2015 with effective dates of December 31, 2016, December 31, 2015, and December 31, 2014, respectively. The reports of DeGolyer have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time and National Instrument 51-101.
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).



8		2016

In 2016 compared with 2015, TransGlobe:

•

Experienced a decrease in petroleum and natural gas sales primarily as a result of a 30% decrease in realized oil prices along with a 7% reduction in sales volumes compared to 2015. The Company's sales price is market driven, and Egypt crude oil is a high sulfur heavy oil which is priced at a discount to Dated Brent. Dated Brent averaged $43.55 per bbl in 2016, which was a reduction of $8.81 per bbl from prior year;

•

Reported a 17% decrease in production volumes as compared to 2015. In early 2016, the Company intentionally reduced development/operations investment as a result of low oil prices. Accordingly, production was in decline for the first half of the year. During the second quarter, the Company finalized a production recovery plan ("PRP") as oil prices were strengthening. The Company executed on the PRP, and achieved a year-end exit rate of 13,800 bopd in Egypt;

•

Reported a net loss of $87.7 million, which includes a $33.4 million non-cash impairment loss on the Company's exploration and evaluation assets. Impairment losses related to the SE Gharib and SW Gharib concessions amounted to $15.2 million and $16.4 million, respectively. The exploration and evaluation assets in these concessions were written down to zero as no commercially viable quantities of oil have been discovered on these lands. The Company also recognized a $7.0 million unrealized non-cash loss on the fair value of the convertible debenture in 2016;


•	Recorded negative funds flow from operations of $8.4 million, which was relatively consistent with prior year. The effect of a $19.1 million decrease in revenues net of royalties and current income taxes was offset by decreased operating expenses ($12.4 million), selling costs ($3.7 million) and cash general and administrative costs ($3.4 million);


•	Acquired producing oil and gas assets in Canada for total consideration of $59.5 million in a transaction that closed on December 20, 2016; and


•	Spent $26.7 million on capital programs, which was funded through the use of working capital.

2016 TO 2015 NET EARNINGS VARIANCES



			$ Per Share
	$000s		Diluted		% Variance
2015 net earnings	(105,600	)	(1.44	)
Cash items
Volume variance	(8,532	)	(0.13	)	6
Price variance	(56,773	)	(0.79	)	54
Royalties	36,227		0.50		(34	)
Expenses:
Production and operating	12,373		0.17		(12	)
Transportation	(12	)	—		—
Selling costs	3,682		0.05		(3	)
Cash general and administrative	3,421		0.05		(3	)
Current income taxes	10,028		0.14		(9	)
Realized foreign exchange gain (loss)	405		0.01		—
Realized derivative gain (loss)	(268	)	—		—
Interest on long-term debt	112		—		—
Other income	(10	)	—		—
Total cash items variance	653		—		(1	)
Non-cash items
Unrealized foreign exchange gain (loss)	(15,625	)	(0.22	)	15
Depletion and depreciation	13,698		0.19		(13	)
Unrealized gain (loss) on financial instruments	(412	)	(0.01	)	—
Impairment loss	51,947		0.72		(49	)
Stock-based compensation	369		0.01		—
Deferred income taxes	(33,032	)	(0.46	)	31
Deferred lease inducement	(9	)	—		—
Loss on disposition	252		—		—
Amortization of deferred financing costs	94		—		—
Total non-cash items variance	17,282		0.23		(16	)
2016 net earnings	(87,665	)	(1.21	)	(17	)

The Company recorded a net loss of $87.7 million in 2016 compared to a net loss of $105.6 million in 2015. Realized sales prices in 2016 averaged $29.94 per boe, which was 30% lower than the 2015 average realized price of $42.93 per bbl. This translated into a negative cash earnings impact of $56.8 million in 2016 as compared to 2015, which was the single largest cash variance. Sales volumes declined 7% year over year, which was due to lower production levels and the timing and size of tanker liftings in Egypt. The sales volume decline resulted in a further negative earnings variance of $8.5 million. The negative volume and price variances were partially offset by corresponding reductions in royalties and current income



2016		9

taxes, which created a positive earnings variance of $46.3 million in aggregate. Production and operating expenses were reduced in 2016 by $12.4 million, which was the result of decreased oil treating fees, fuel costs and well servicing costs in Egypt. The disposal of the Yemen business unit in late 2015 also contributed significantly to the decrease in production and operating expenses, as the Company incurred $4.7 million of operating costs in Yemen in 2015. Furthermore, the Company added to its crude oil inventory during 2016, resulting in $3.2 million of production and operating costs being capitalized to inventory on a net basis during the year. Selling costs and cash general and administrative expenses decreased by $3.7 million and $3.4 million, respectively, from prior year. All 2016 tanker liftings were sold FOB shipping point, whereas one 2015 lifting was sold CIF (cost, insurance and freight) destination, resulting in significantly lower selling costs in 2016. The decrease in cash general and administrative costs is principally attributable to a reduction in payroll and staffing alignment expenditures, as the Company is now realizing cost savings associated with the structural staffing changes made in 2015.

The largest non-cash earnings variance item from 2016 to 2015 relates to the change from year to year in the impairment loss, which created a positive earnings variance. The Company recorded an impairment loss of $85.4 million on its petroleum properties and goodwill in 2015 as a direct result of the decline in oil prices, compared with a $33.4 million impairment loss in 2016. The 2016 impairment loss related mainly to exploration and evaluation costs at SE Gharib and SW Gharib, where no commercially viable quantities of oil have been discovered. The 2015 impairment loss caused a significant reduction in the accounting basis of the Company's petroleum properties, which resulted in a deferred tax recovery of $36.0 million in 2015, which created a $33.0 million negative earnings variance in the current year. The 2015 impairment loss also created a lower depletable cost base and therefore lower depletion expense in 2016. Furthermore, the Company's Q3-2016 positive reserve revisions created further reductions in depletion expense on the Company's petroleum properties, resulting in a substantial positive earnings variance for the year. The Company experienced a $15.6 million negative variance related to foreign exchange translation, which was mainly caused by the weakening of the Canadian dollar in 2015 versus a more stable Canadian dollar in 2016 comparatively.

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	2016	2015
Crude oil
Dated Brent average oil price (US$/Bbl)	43.55	52.36
Edmonton Sweet index (US$/bbl)	40.11	44.91
Natural gas
AECO (C$/mmbtu)	2.16	2.69
U.S./Canadian Dollar average exchange rate	1.3256	1.2790

The price of Dated Brent oil averaged 17% lower in 2016 compared with 2015. Egypt production is priced based on Dated Brent and shared with the Egyptian government through PSCs. When the price of oil increases, it takes fewer barrels to recover costs (cost recovery barrels) which are assigned 100% to the Company. The contracts provide for cost recovery per quarter up to a maximum percentage of total revenue. Timing differences often exist between the Company's recognition of costs and their recovery as the Company accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as "excess". In Egypt, depending on the PSC, the Contractor's share of excess ranges between 0% and 30%. If the eligible cost recovery exceeds the maximum allowed percentage, the unclaimed cost recovery is carried forward to the next quarter. Typically maximum cost recovery or cost oil ranges from 25% to 30% in Egypt. The balance of the production after maximum cost recovery is shared with the government (production sharing oil). In Egypt, depending on the contract, the government receives 70% to 86% of the production sharing oil or profit oil. Production sharing splits are set in each contract for the life of the contract. Typically the government’s share of production sharing oil increases when production exceeds pre-set production levels in the respective contracts. During times of increased oil prices, the Company receives less cost oil and may receive more production sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less profit oil. For reporting purposes, the Company records the government’s share of production as royalties and taxes (all taxes are paid out of the government’s share of production) which will increase during times of rising oil prices and will decrease in times of declining oil prices. If oil prices are sufficiently low and the Ras Gharib/Dated Brent differential is high, the cost oil portion may not be sufficient to cover operating costs and capital costs, or even operating costs alone. When this occurs, the non-recovered costs accumulate in the Company’s cost pools and are available to be offset against future cost oil during the term of the PSC and any eligible extension periods.

Egypt has been experiencing significant political changes over the past six years. While this has had an impact on the efficient operations of the government in general, business processes and the Company’s operations have generally proceeded as normal. While exploration and development

activities have generally been uninterrupted, the Company experienced delays in the collection of accounts receivable from the Egyptian government up to the end of 2013. Since the end of 2013, the Company has collected a total of $336.5 million from EGPC, reducing the balance due from EGPC to $13.5 million as at December 31, 2016. The Company's credit risk, as it relates to EGPC, has now been reduced due to the significant collections from EGPC combined with the 30-day collection cycle that the Company now enjoys as a result of direct marketing to third party international buyers who are generally required to post irrevocable letters of credit to support the sales prior to the cargo liftings.

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



10		2016

SELECTED QUARTERLY FINANCIAL INFORMATION



	2016								2015
($000s, except per share,
price and volume amounts)	Q-4³		Q-3		Q-2		Q-1		Q-4		Q-3		Q-2		Q-1
Operations
Average production volumes
Crude oil (bbls/d)	12,861		11,733		11,472		12,058		13,425		14,683		15,064		14,886
NGLs (bbls/d)	134		—		—		—		—		—		—		—
Natural gas (mcf/d)	916		—		—		—		—		—		—		—
Total (boe/d)	13,148		11,733		11,472		12,058		13,425		14,683		15,064		14,886
Average sales volumes
Crude oil (bbls/d)	7,018		11,485		11,783		14,126		7,205		13,620		14,251		12,876
NGLs (bbls/d)	134		—		—		—		—		—		—		—
Natural gas (mcf/d)	916		—		—		—		—		—		—		—
Total (boe/d)	7,305		11,485		11,783		14,126		7,205		13,620		14,251		12,876
Average realized sales prices
Crude oil ($/Bbl)	37.38		34.43		30.27		22.58		32.38		39.35		48.31		46.82
NGLs ($/Bbl)	12.33		—		—		—		—		—		—		—
Natural gas ($/Mcf)	1.80		—		—		—		—		—		—		—
Total oil equivalent ($/boe)	36.45		34.43		30.27		22.58		32.38		39.35		48.31		46.82
Inventory (Bbl)	1,265,080		729,403		706,577		734,872		923,106		350,869		253,325		179,730
Petroleum and natural gas sales	24,501		36,376		32,461		29,022		21,460		49,307		62,647		54,251
Petroleum and natural gas sales, net of royalties	5,217		20,704		19,786		17,427		3,979		24,700		33,960		29,573
Cash flow from operating activities	6,355		(14,857	)	6,011		1,426		6,414		28,741		24,323		18,048
Funds flow from operations¹	(9,904	)	2,347		2,026		(2,830	)	(11,108	)	(1,497	)	6,991		(3,288	)
Funds flow from operations per share
- Basic	(0.14	)	0.03		0.03		(0.04	)	(0.15	)	(0.02	)	0.09		(0.04	)
- Diluted	(0.14	)	0.03		0.03		(0.04	)	(0.15	)	(0.02	)	0.09		(0.04	)
Net earnings (loss)	(33,997	)	(25,369	)	(12,050	)	(16,249	)	(35,255	)	(46,568	)	(12,580	)	(11,197	)
Net earnings (loss) - diluted	(38,641	)	(25,369	)	(12,050	)	(16,249	)	(35,255	)	(54,159	)	(12,580	)	(13,577	)
Net earnings per share
- Basic	(0.47	)	(0.35	)	(0.17	)	(0.23	)	(0.49	)	(0.64	)	(0.17	)	(0.15	)
- Diluted	(0.49	)	(0.35	)	(0.17	)	(0.23	)	(0.49	)	(0.68	)	(0.17	)	(0.17	)
Dividends paid	—		—		—		—		1,805		3,594		3,703		3,763
Dividends paid per share	—		—		—		—		0.025		0.05		0.05		0.05

Total assets	406,142		414,363		433,013		441,624		455,500		501,808		599,744		614,345
Cash and cash equivalents	31,468		100,405		124,308		122,031		126,910		126,874		122,961		126,101
Convertible debentures	72,655		74,854		70,639		66,506		63,848		65,682		74,421		65,511
Note payable	11,162		—		—		—		—		—		—		—
Debt-to-funds flow ratio²	(10.0	)	(7.8	)	(5.3	)	(7.9	)	(7.2	)	3.6		1.5		0.8
¹ Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
² Debt-to-funds flow ratio is a measure that represents total long-term debt (including the current portion) plus convertible debentures over funds flow from operations from the trailing 12 months and may not be comparable to measures used by other companies. See "Non-GAAP Financial Measures".
³ The Q4-2016 information includes the results of the operations of the Harmattan assets in Alberta, Canada from December 20, 2016 to December 31, 2016 (12 days). The Harmattan assets were acquired in a transaction that closed on December 20, 2016 (effective December 1, 2016).

During the fourth quarter of 2016, TransGlobe:


•	Reported an increase in production volumes of 12% as compared to Q3-2016, which was primarily a result of the Company's PRP. Production increases were achieved mainly in the West Bakr concession, where a 1,030 bopd increase was achieved quarter over quarter;


•	Did not receive a cargo lifting in Egypt, therefore did not sell any Egyptian entitlement crude oil. This resulted in significantly lower sales and sales volumes as compared to previous quarters, along with a build in crude oil inventory of 0.5 million barrels;


•	Reported a net loss of $34.0 million, which includes an $18.5 million non-cash impairment loss on the Company's exploration and evaluation assets; and


•	Recorded negative funds flow from operations of $9.9 million, mainly because the Company did not sell any Egypt entitlement oil during the quarter.



2016		11

OPERATING RESULTS AND NETBACK

Daily Volumes, Working Interest before Royalties (Boepd)

Production Volumes



	2016	2015
Egypt crude oil (bbls/d)	12,015	14,466
Yemen crude oil (bbls/d)	—	45
Canada crude oil (bbls/d)	18	—
Canada NGLs (bbls/d)	34	—
Canada natural gas (mcf/d)	230	—
Total Company (boe/d)	12,105	14,511

Sales Volumes (excludes volumes held as inventory)



	2016	2015
Egypt crude oil (bbls/d)	11,075	11,935
Yemen crude oil (bbls/d)	—	42
Canada crude oil (bbls/d)	18	—
Canada NGLs (bbls/d)	34	—
Canada natural gas (mcf/d)	230	—
Total Company (boe/d)	11,165	11,977

Netback



Consolidated netback
	2016		2015
(000s, except per Boe amounts)¹	$	$/Boe	$	$/Bbl
Petroleum and natural gas sales	122,360	29.94	187,665	42.93
Royalties and other	59,226	14.49	95,453	21.83
Current taxes	15,455	3.78	25,483	5.83
Operating expenses	40,323	9.87	52,696	12.05
Transportation	12	—	—	—
Selling costs	875	0.21	4,557	1.04
Netback	6,469	1.59	9,476	2.18
¹The Company achieved the netbacks above on sold barrels of oil equivalent for the year ended December 31, 2016 and December 31, 2015 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at December 31, 2016).



Canada
	2016		2015
(000s, except per Boe amounts)	$	$/Boe	$	$/Boe
Crude oil sales	266	40.38	—	—
Natural gas sales	152	10.83	—	—
NGL sales	214	17.20	—	—
Total sales	632	19.12
Royalties	132	3.99	—	—
Operating expenses	269	8.14	—	—
Transportation	12	0.36	—	—
Netback	219	6.63	—	—

The Canadian financial information presented in the table above represents 12 days of activity in Canada, following the closing of the Harmattan acquisition on December 20, 2016.



12		2016



Egypt
	2016		2015
(000s, except per Bbl amounts)¹	$	$/Bbl	$	$/Bbl
Oil sales	121,728	30.03	187,055	42.94
Royalties	59,094	14.58	95,330	21.88
Current taxes	15,455	3.81	25,284	5.80
Production and operating expenses	40,054	9.88	48,041	11.03
Selling costs	875	0.22	4,557	1.05
Netback	6,250	1.54	13,843	3.18
¹The Company achieved the netbacks above on sold barrels of oil for the year ended December 31, 2016 and December 31, 2015 (these figures do not include TransGlobe's Egypt entitlement barrels held as inventory at December 31, 2016).

The netback per Bbl in Egypt decreased 52% in 2016 compared with 2015. The decreased netbacks were principally the result of a 30% reduction in realized oil prices in 2016 compared to 2015, along with a build up of 0.3 million barrels of entitlement crude oil inventory in 2016.

Production and operating expenses decreased by $8.0 million in 2016 compared with 2015. This is principally the result of reduced activity levels combined with the Company's efforts to achieve cost efficiencies in a lower oil price environment. These cost savings have translated to a reduction of 10% on a per Bbl basis despite a 7% decrease in sales volumes in the current year. The most significant cost efficiencies were achieved in the areas of oil treating fees, fuel costs and well servicing. Selling costs were 79% lower on a per Bbl basis in 2016 as compared to 2015, creating a positive impact on current year netbacks. In 2015, one lifting was sold CIF (cost, insurance and freight) destination, resulting in significantly higher selling costs in the prior year. In 2016, all lifting were sold FOB shipping point, which results in significantly lower selling costs.

Royalties and taxes as a percentage of revenue were 61% in 2016 compared with 64% for 2015. Royalties and taxes are settled on a production basis, so the correlation of royalties and taxes to oil sales fluctuates depending on the timing of entitlement oil sales. In periods when the Company sells less than its entitlement production, royalties and taxes as a percentage of revenue will be higher than the terms of the PSCs dictate. In periods when the Company sells more than its entitlement production, royalties and taxes as a percentage of revenue will be lower than the terms of the PSCs dictate.

The average selling price for the year-ended December 31, 2016 was $30.03/Bbl, which was $13.52/Bbl lower than the average Dated Brent oil price of $43.55/Bbl for the year (December 31, 2015 - $52.36/Bbl). The difference is due to a gravity/quality adjustment and is also impacted by the timing of direct sales.

GENERAL AND ADMINISTRATIVE EXPENSES (“G&A”)



	2016				2015
(000s, except per Bbl amounts)	$		$/Boe		$		$/Bbl
G&A (gross)	18,716		4.58		24,466		5.60
Stock-based compensation	2,418		0.59		2,787		0.64
Capitalized G&A and overhead recoveries	(3,579	)	(0.88	)	(5,917	)	(1.35	)
G&A (net)	17,555		4.29		21,336		4.89

G&A expenses (net) decreased 18% in 2016 compared with 2015 (12% decrease on a per bbl basis). G&A (gross) has decreased $5.7 million in 2016 principally due to a reduction in payroll and staffing alignment expenditures, as the Company is now realizing cost savings associated with the structural staffing changes made in 2015.

Equity-settled stock-based compensation expense decreased $0.8 million in 2016 as compared to 2015, which is mainly the result of a decrease in the fair value of stock options granted in 2016 as compared to 2015. Cash-settled stock-based compensation increased $0.4 million in 2016 compared to 2015, which is principally due to an increase in the number of cash-settled stock-based compensation units granted during 2016 as compared to 2015, along with the relative weakness in the share price in 2015 as compared to 2016.

FINANCE COSTS

Finance costs for the year ended December 31, 2016 decreased to $6.1 million compared with $6.3 million in 2015. Interest expense on the convertible debentures decreased to $4.4 million in 2016, compared with $4.7 million in 2015. The interest on the convertible debenture is paid in Canadian dollars, and therefore fluctuates from period to period depending on the strength of the Canadian dollar relative to the US dollar.



(000s)	2016		2015
Interest expense	$	5,344	$	5,425
Amortization of deferred financing costs	724		849
Finance costs	$	6,068	$	6,274

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 Sumitomo Mitsui Banking Corporation ("SMBC"). The issued letters of credit under the bilateral letter of credit facility are secured by cash collateral which is on deposit with SMBC. The exploration commitments are expected to be fulfilled in 2017.



2016		13

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

Note Payable

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

Convertible Debentures

In February 2012, the Company sold, on a bought-deal basis, C$97.8 million ($97.9 million) aggregate principal amount of convertible unsecured subordinated debentures with a maturity date of March 31, 2017. The debentures are convertible at any time and from time to time into common shares of the Company at a price of C$13.63 per common share. The debentures were not redeemable by the Company on or before March 31, 2015 other than in limited circumstances described below or in connection with a change of control of TransGlobe. The conversion price of the convertible debentures is adjusted for any amounts paid out as dividends on the common shares of the Company. Interest of 6% is payable semi-annually in arrears on March 31 and September 30. At maturity or redemption, the Company has the option to settle all or any portion of principal obligations by delivering to the debenture holders sufficient common shares to satisfy these obligations. On October 17, 2016, a meeting of the Company's debenture holders was held to approve certain amendments to the outstanding debentures. The amendments were approved, and TransGlobe was granted the right to redeem all outstanding debentures at any point in time at a price equal to the principal amount outstanding, plus accrued and unpaid interest up to (but excluding) the redemption date, plus an interest penalty equal to interest otherwise due up to but excluding the maturity date.

Subsequent to year-end, the Company entered into a $75 million crude oil prepayment agreement, the proceeds of which are intended to be used to redeem the convertible debentures in full.

DEPLETION AND DEPRECIATION (“DD&A”)



	2016		2015
(000s, except per Bbl amounts)	$	$/Boe	$	$/Bbl
Egypt	28,386	7.00	42,366	9.73
Canada	303	9.16	—	—
Corporate	488	—	509	—
	29,177	7.14	42,875	9.81

In Egypt, DD&A decreased 28% on a per Bbl basis in 2016 as compared to 2015. The decrease is primarily related to a lower depletable cost base, which is the result of impairment losses booked in 2015, along with a 57% reduction in future development costs. In addition, the Company's third quarter 2016 positive reserve revisions created further reductions in depletion expense on a per bbl basis.

In Canada, the Company booked depletion for 12 days of production following the closing of the Canadian asset acquisition on December 20, 2016.

IMPAIRMENT OF PETROLEUM PROPERTIES

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


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


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


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


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

As a result of this assessment, the Company recorded an impairment loss of $33.4 million on its exploration and evaluation assets in 2016. The impairment loss was principally related 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. The Company relinquished its interest in South East Gharib in November 2016, and intends to relinquish its interest in South West Gharib in the first half of 2017 as no commercially viable quantities of oil have been discovered on either concession. At South West Gharib, the Company drilled two wells subsequent to year-end, both of which were dry and abandoned. An impairment loss will be recorded in the first quarter of 2017 in an amount equal to the capital costs associated with these wells.

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



14		2016

CAPITAL EXPENDITURES



($000s)	2016	2015
Egypt	26,658	44,747
Property acquisitions	59,475	—
Corporate	—	155
Total	86,133	44,902

In Egypt, total capital expenditures in 2016 were $26.7 million (2015 - $44.7 million). The Company drilled 17 wells in Egypt in 2016 (ten at NW Gharib, two at SE Gharib, two at SW Gharib, two at West Bakr and one at West Gharib). The West Bakr and West Gharib wells were development oil wells that formed part of the Company's PRP. The remaining wells were exploration wells, which yielded two new oil discoveries. Workovers contributed $2.2 million to the Company's capital spending, and the Company capitalized $3.6 million of G&A costs related to capital projects.

On December 20, 2016, TransGlobe closed the acquisition of production and working interests in certain facilities in the Cardium light oil and Mannville liquid-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.

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.



Proved
($000s, except volumes and $/Boe amounts)	2016	2015		2014
Total capital expenditures	26,658	42,902		107,539
Acquisitions¹	59,475	2,000		—
Dispositions	—	(1,500	)	—
Net change from previous year’s future capital	60,084	(9,024	)	(16,447	)
	146,217	34,378		91,092
Reserve additions and revisions (MBoe)
Exploration and development	5,138	990		(3,619	)
Acquisitions, net of dispositions	11,667	(300	)	—
Total reserve additions (MBoe)	16,805	690		(3,619	)
Average cost per Boe
F&D²	4.02	34.22		—
FD&A²	8.70	49.83		—
Three-year weighted average cost per Boe
F&D²	58.03	83.93		19.93
FD&A²	19.58	110.07		25.34
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 2014, F&D and FD&A costs were negative. The negative F&D and FD&A costs are driven primarily by negative reserve revisions, most of which relate to the Company's West Gharib concession (specifically, the Lower Nukhul reserves in the Arta/East Arta fields) and the reclassification of Yemen reserves to contingent resources. The Company did not make sufficient new discoveries to offset the negative technical revisions, resulting in negative F&D and FD&A costs which are meaningless on a per Bbl basis.
Note: The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.



2016		15



Proved Plus Probable
($000s, except volumes and $/Boe amounts)	2016	2015		2014
Total capital expenditure	26,658	42,902		107,539
Acquisitions¹	59,475	2,000		—
Dispositions	—	(1,500	)	—
Net change from previous year’s future capital	110,102	(30,741	)	(21,948	)
	196,235	12,661		85,591
Reserve additions and revisions (MBoe)
Exploration and development	4,906	1,498		(5,919	)
Acquisitions, net of dispositions	20,744	(936	)	—
Total reserve additions (MBbl)	25,650	562		(5,919	)
Average cost per Boe
F&D²	3.66	8.03		—
FD&A²	7.65	22.53		—
Three-year weighted average cost per Boe
F&D³	231.05	—		30.06
FD&A³	14.51	—		39.10
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 2014, F&D and FD&A costs were negative. The negative F&D and FD&A costs are driven primarily by negative reserve revisions, most of which relate to the Company's West Gharib concession (specifically, the Lower Nukhul reserves in the Arta/East Arta fields) and the reclassification of Yemen reserves to contingent resources. The Company did not make sufficient new discoveries to offset the negative technical revisions, resulting in negative F&D and FD&A costs which are meaningless on a per Bbl basis.
³ In 2015, the three-year weighted average F&D and FD&A costs on a 2P basis were negative. The negative F&D and FD&A costs are driven primarily by negative reserve revisions in 2014. The Company did not make sufficient new discoveries to offset the negative technical revisions in 2014, resulting in negative F&D and FD&A costs which are meaningless on a per Bbl basis.
Note: The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

RECYCLE RATIO

Recycle Ratio



	Three-Year
Proved	Weighted
	Average²	2016		2015		2014
Netback ($/Boe)¹	5.47	(3.12	)	(3.12	)	17.83
Proved F&D costs ($/Boe)³	58.03	4.02		34.22		—
Proved FD&A costs ($/Boe)³	19.58	8.70		49.83		—
F&D Recycle ratio⁴	0.09	—		—		—
FD&A Recycle ratio⁴	0.28	—		—		—
¹ Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), realized foreign exchange (gain) loss, cash finance costs and current income tax expense per Bbl of production.
² The negative reserves revisions and costs used in the 2014 calculation were included in the three-year weighted average recycle ratios.
³ In 2014, F&D and FD&A costs were negative, which was driven primarily by negative reserve revisions. Negative F&D and FD&A costs are meaningless on a per Bbl basis; therefore, the Company has presented these values as nil.
⁴ In 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	2016		2015		2014
Netback ($/Boe)¹	5.47	(3.12	)	(3.12	)	17.83
Proved plus Probable F&D costs ($/Boe)³	231.05	3.66		8.03		—
Proved plus Probable FD&A costs ($/Boe)³	14.51	7.65		22.53		—
F&D Recycle ratio⁴	0.02	—		—		—
FD&A Recycle ratio⁴	0.38	—		—		—
¹ Netback, for the purposes of calculating the recycle ratio, is defined as net sales less operating, exploration, selling, G&A (excluding non-cash items), realized foreign exchange (gain) loss, cash finance costs and current income tax expense per Bbl of production.
² The negative reserves revisions and costs used in the 2014 calculation were included in the three-year weighted average recycle ratios.
³ In 2014, F&D and FD&A costs were negative, which was driven primarily by negative reserve revisions. Negative F&D and FD&A costs are meaningless on a per Bbl basis; therefore, the Company has presented these values as nil.
⁴ In 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.



16		2016

The 2016 recycle ratio is negative as a result of negative recycle ratio netbacks in the year. The negative netbacks were primarily the result of low oil prices, combined with the fact that the Company did not sell all of its entitlement oil in 2016. Since negative recycle ratios are meaningless, they have been presented as nil in the tables above. However, the 2015 and 2016 negative netbacks were used to calculate the three-year weighted average recycle ratios.

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



Recycle Netback Calculation
($000s, except volumes and per Boe amounts)	2016		2015		2014
Net earnings	(87,665	)	(105,600	)	11,482
Adjustments for non-cash items:
Depletion, depreciation and amortization	29,177		42,875		51,589
Stock-based compensation	2,418		2,787		5,914
Deferred income taxes	(3,009	)	(36,041	)	(9,813	)
Amortization of deferred financing costs	724		849		1,106
Amortization of deferred lease inducement	(95	)	(104	)	442
Realized (gain) loss on commodity contracts	956		688		—
Unrealized foreign exchange (gain) loss	4,292		(11,333	)	(6,476	)
Unrealized (gain) loss on financial instruments	7,027		6,615		(11,589	)
Impairment loss	33,426		85,373		71,373
Loss on corporate disposal	—		252		—
Other adjustments:
Other revenue	—		—		(9,250	)
Recycle netback¹	(12,749	)	(13,639	)	104,778
Sales volumes (MBoe)	4,086		4,372		5,878
Recycle netback per Boe¹	(3.12	)	(3.12	)	17.83
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, interest and current income tax expense per Boe of production.

OUTSTANDING SHARE DATA

As at December 31, 2016, the Company had 72,205,369 common shares issued and outstanding and 6,045,953 stock options issued and outstanding, which are exercisable in accordance with their terms into an equal number of common shares of the Company.

As at March 6, 2017, the Company had 72,205,369 common shares issued and outstanding and 5,995,953 stock options issued and outstanding, which are exercisable in accordance with their terms into an equal number of common shares of the Company.

NORMAL COURSE ISSUER BID

On March 25, 2015, the Toronto Stock Exchange ("TSX") accepted the Company's notice of intention to make a Normal Course Issuer Bid ("NCIB") for its common shares. The NCIB, which commenced on March 31, 2015 and terminated on March 30, 2016, provided the Company with the right to acquire up to 6,207,585 common shares, which was equal to 10% of the public float. During 2015, the Company repurchased and cancelled 3,103,792 common shares under the NCIB. No common shares were repurchased under the NCIB during the year ended December 31, 2016. The Company has not renewed the NCIB.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity describes a company’s ability to access cash. Companies operating in the upstream oil and gas industry require sufficient cash in order to fund capital programs necessary to maintain and increase production and reserves, to acquire strategic oil and gas assets and to repay debt. TransGlobe’s capital programs are funded by its existing working capital and cash provided from operating activities. As a direct result of a lower oil price environment, TransGlobe’s debt-to-funds flow from operations ratio continued to deteriorate throughout the year and was negative 10.0 at December 31, 2016 (December 31, 2015 - negative 7.2) as a result of negative funds flow for the year. The Company's debt-to-funds flow from operations ratio will continue to experience downward pressure until oil prices improve. Despite the deterioration of this particular ratio, the Company remains in a relatively strong financial position due to prudent capital resource management. TransGlobe's management will continue to steward capital programs and focus on cost reductions in order to maintain balance sheet strength through the current low oil price environment.



2016		17

The following table illustrates TransGlobe’s sources and uses of cash during the years ended December 31, 2016 and 2015:



Sources and Uses of Cash
($000s)	2016		2015
Cash sourced
Funds flow from operations¹	(8,361	)	(8,902	)
Transfer from restricted cash	—		688
Proceeds from corporate dispositions	—		1,500
Increase in note payable	11,162		—
Exercise of options	—		208
	2,801		(6,506	)
Cash used
Capital expenditures	26,658		44,902
Dividends paid	—		12,865
Transfer to restricted cash	17,462		—
Property acquisitions	59,475		—
Purchase of common shares	—		12,221
Finance costs	5,288		5,779
Other	2,212		1,635
	111,095		77,402
	(108,294	)	(83,908	)
Changes in non-cash working capital	12,852		70,428
Increase (decrease) in cash and cash equivalents	(95,442	)	(13,480	)
Cash and cash equivalents – beginning of year	126,910		140,390
Cash and cash equivalents – end of year	31,468		126,910
¹ Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital, and may not be comparable to measures used by other companies.

Funding for the Company’s capital expenditures was provided by cash on hand. The Company expects to fund its 2017 exploration and development program 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.

Working capital is the amount by which current assets exceed current liabilities. At December 31, 2016, the Company had a working capital deficiency of $16.8 million (December 31, 2015 - surplus of $153.8 million). The decrease to working capital in 2016 is principally due to the reclassification of the convertible debt to current liabilities. Since the maturation of the convertible debentures is within one year of the balance sheet date, they must now be presented as current liabilities, which has a significant impact on the Company's working capital balance. Subsequent to year-end, the Company entered into a $75 million crude oil prepayment agreement, the proceeds of which are intended to be used to redeem the convertible debentures in full. Working capital was also significantly impacted by the acquisition of the Harmattan assets, as the Company invested $48.4 million of its cash balance in the transaction.

The Company now has a very manageable receivable balance of $13.5 million due from EGPC, and enjoys a 30-day cash collection cycle on directly marketed crude oil sales to third party international buyers who are generally 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 completed three cargo liftings during 2016, and management has arranged for three liftings in 2017.

As at December 31, 2016, the Company held 1,265,080 barrels of entitlement oil as inventory, which represents approximately seven months of entitlement oil production. All oil produced is delivered to EGPC facilities, and the Company works with EGPC on a continuous basis to schedule tanker liftings. 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 2015 there was a steady increase in crude oil inventory levels, as production outpaced sales. In Q1-2016 and Q2-2016, crude oil inventory levels dropped as a result of crude oil sales being greater than our production. During the second half of 2016, crude oil inventory levels once again grew as production was greater than sales. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows. The Company expects to complete both external sales (tanker liftings) and internal sales (offsets) in 2017, and anticipates that 2017 year-end crude oil inventory will be approximately 700,000 barrels.

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

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. Subsequent to year-end, the Company entered into a prepayment agreement, which allows for advances up to $75 million.

COMMITMENTS AND CONTINGENCIES

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



18		2016



($000s)		Payment Due by Period^{1 2}
	Recognized
	in Financial	Contractual	Less than			More than
	Statements	Cash Flows	1 year	1-3 years	4-5 years	5 years
Accounts payable and accrued liabilities	Yes - Liability	24,529	24,529	—	—	—
Convertible debentures	Yes - Liability	72,655	72,655	—	—	—
Note payable	Yes - Liability	11,162	5,581	5,581	—	—
Office and equipment leases³	No	3,732	1,200	1,556	976	—
Minimum work commitments⁴	No	17,986	8,335	9,651	—	—
Total		130,064	112,300	16,788	976	—
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, 2016 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 has a minimum financial commitment of $35.0 million ($5.0 million remaining) and a work commitment for 30 wells and 200 km² of 3-D seismic during the initial-three year exploration period, which commenced on November 7, 2013. As at December 31, 2016, the Company had expended $30.0 million towards meeting that commitment. The Company received a six month extension to the initial exploration period, which now extends to May 7, 2017.

Pursuant to the PSC for South East Gharib in Egypt, the Company had a minimum financial commitment of $7.5 million and a work commitment for two wells, 200 km² of 3-D seismic and 300 kilometers of 2-D seismic during the initial three-year exploration period, which commenced on November 7, 2013. The Company met its financial commitment at South East Gharib in 2016, and relinquished its interest in the concession during the fourth quarter as no commercially viable quantities of oil have been discovered.

Pursuant to the PSC for South West Gharib in Egypt, the Company has a minimum financial commitment of $10.0 million ($3.4 million remaining) and a work commitment for four wells and 200 km² 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 now extends to May 7, 2017. Since no commercially viable quantities of oil have been discovered at South West Gharib, the Company intends to relinquish its interest in the concession during the first half of 2017. As at December 31, 2016, the Company had expended $6.6 million towards meeting its financial commitment.

Pursuant to the PSC for South Ghazalat in Egypt, the Company had a minimum financial commitment of $8.0 million and a work commitment for two wells and 400 km² of 3-D seismic during the initial three-year exploration period, which commenced on November 7, 2013 and reached its primary term on November 7, 2016. Prior to expiry, the Company elected to enter the first two-year extension period (expiry November 7, 2018). The Company had met its financial commitment for the first phase ($8.0 million) and the first extension ($4.0 million), however the Company had not completed the first phase work program. Prior to entering the first extension the Company posted a $4.0 million performance bond with EGPC to carry forward two exploration commitment wells into the first extension period. The $4.0 million performance bond is supported by a production guarantee from the Company's producing concessions which will be released when the commitment wells have been drilled. In accordance with the concession agreement the Company relinquished 25% of the original exploration acreage prior to entering the first extension period. In addition, the first extension period has an additional financial commitment of $4.0 million, which has been met, and two additional exploration wells.

Pursuant to the PSC for North West Sitra in Egypt, the Company has a minimum financial commitment of $10.0 million ($9.7 million remaining) and a work commitment for two wells and 300 km² of 3-D seismic during the initial three and a half year exploration period, which commenced on January 8, 2015. As at December 31, 2016, the Company had expended $0.3 million towards meeting that commitment.

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

The Company is not aware of any material provisions or other contingent liabilities as at December 31, 2016.

ASSET RETIREMENT OBLIGATION

At December 31, 2016, TransGlobe recorded an asset retirement obligation ("ARO") of $12.1 million (2015 - nil) for the future abandonment and reclamation costs associated with the Harmattan assets. The estimated ARO includes assumptions in respect of actual costs to abandon wells and/or reclaim the properties, the time frame in which such costs will be incurred, as well as annual inflation factors in order to calculate the undiscounted total future liability. TransGlobe calculated the present value of the obligations using discount rates between 0.74% and 2.31% to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates.

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, 2016.



2016		19

RISKS

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


•	Financial risks;


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


•	Credit risks;


•	Liquidity risks;


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


•	Safety, environmental, social and regulatory risks; and


•	Political risks.

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

Financial Risk

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

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

The frequent political changes that have created instability in Egypt since 2011 could present challenges to the Company if the issues persist over an extended period of time. Continued instability could reduce the Company’s ability to access debt, capital and banking markets. To mitigate potential financial risk factors, the Company maintains a strong liquidity position and management regularly evaluates operational and financial risk strategies and continues to monitor the 2017 capital budget and the Company’s long-term plans. In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. Going forward, 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, convertible debentures, accounts payable and accrued liabilities denominated in Canadian dollars. When assessing the potential impact of foreign currency exchange risk, the Company believes 10% volatility is a reasonable measure. The Company estimates that a 10% increase in the value of the Canadian dollar against the U.S. dollar would result in an increase in the net loss for the year ended December 31, 2016 of approximately $8.1 million and conversely a 10% decrease in the value of the Canadian dollar against the U.S. dollar would decrease the net loss by $6.6 million for the same period. The Company has not utilized derivative instruments to manage this risk.

The Company is also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while the Company is generally able to spend the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. Using month-end cash balances converted at month-end foreign exchange rates, the average Egyptian pound cash balance for 2016 was $3.9 million (2015 - $20.8 million) in equivalent U.S. dollars. The Company estimates that a 10% increase in the value of the Egyptian pound against the U.S. dollar would result in a decrease in the net loss for the year ended December 31, 2016 of approximately $0.4 million and conversely a 10% decrease in the value of the Egyptian pound against the U.S. dollar would increase the net loss by $0.4 million for the same period. The Company does not currently utilize derivative instruments to manage this risk.



20		2016

Interest rate risk

Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable-interest, U.S.-dollar-denominated debt. No derivative contracts were entered into during 2016 to mitigate this risk. When assessing interest rate risk applicable to the Company’s variable-interest, U.S.-dollar-denominated debt the Company believes 1% volatility is a reasonable measure. Since the Company did not have any amounts drawn on its variable-interest, U.S.-dollar-denominated debt at any time in 2016, the effect of interest rates increasing or decreasing by 1% would have no impact on the Company's net earnings for the year ended December 31, 2016.

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 a significant account receivable outstanding from the Government of Egypt. In the past, the timing of payments on these receivables from the Government of Egypt were historically longer than normal industry standard. Despite these factors, the Company expects to collect this account receivable in full, although there can be no assurance that this will occur. In the event the Government of Egypt fails to meet its obligations, or other third-party creditors fail to meet their obligations to the Company, such failures could individually or in the aggregate have a material adverse effect on the Company, its cash flow from operating activities and its ability to conduct its ongoing capital expenditure program. The Company has not experienced any material credit loss in the collection of accounts receivable to date.

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 are required to post irrevocable letters of credit to support the sales prior to the cargo liftings. Going forward, the Company anticipates that direct sales will continue to reduce 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 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 2015 there was a steady increase in crude oil inventory levels, as production outpaced sales. In Q1-2016 and Q2-2016, crude oil inventory levels dropped as a result of crude oil sales being greater than our production. During the second half of 2016, crude oil inventory levels once again grew as production was greater than sales. These fluctuations in crude oil inventory levels impact the Company’s financial condition, financial performance and cash flows.

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.



2016		21

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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

Oil and Gas Reserves

TransGlobe's Proved and Probable oil and gas reserves are 100% evaluated and reported on by independent reserve evaluators to the Reserves, 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 Earnings and Comprehensive Income.

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

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

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

Subsequent costs

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.



22		2016

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

Financial assets and liabilities at fair value through profit or loss

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

Other

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

Derivative financial instruments

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

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

CHANGES IN ACCOUNTING POLICIES

Future changes to accounting policies

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

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



2016		23

impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. The Company does not currently apply hedge accounting. IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. The Company 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"

In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers, replacing IAS 11 Construction Contracts, IAS 18 Revenue, and several revenue-related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive when control is transferred to the purchaser. Disclosure requirements have also been expanded. The new standard is required to be adopted either retrospectively or using a modified transition approach for fiscal years beginning on or after January 1, 2018, with earlier adoption permitted. The Company does not expect the adoption of IFRS 9 amendments to have a material effect on its Consolidated Financial Statements.

IFRS 16 "Leases"

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

DISCLOSURE CONTROLS AND PROCEDURES

As of December 31, 2016, 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 IFRS, focusing in particular on controls over information contained in the annual and interim financial statements. Due to its inherent limitations, internal controls over financial reporting may not prevent or detect misstatements on a timely basis. A system of internal controls over financial reporting, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the internal controls over financial reporting are met. Also, projections of any evaluation of the effectiveness of internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Management has assessed the effectiveness of the Company's internal control over financial reporting based on the Committee of Sponsoring Organizations of the Treadway Commission framework on Internal Control - Integrated Framework (2013). Based on this assessment, management concluded that the Company's internal control over financial reporting was effective as at December 31, 2016. No changes were made to the Company's internal control over financial reporting during the year ended December 31, 2016 that have materially affected, or are reasonably likely to materially affect, the internal controls over financial reporting.



24		2016

MANAGEMENT'S REPORT

Management’s Responsibility on Financial Statements

The consolidated financial statements of TransGlobe Energy Corporation were prepared by management within acceptable limits of materiality and are in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. Management is responsible for ensuring that the financial and operating information presented in this annual report is consistent with that shown in the consolidated financial statements.

The consolidated financial statements have been prepared by management in accordance with the accounting policies as described in the notes to the consolidated financial statements. Timely release of financial information sometimes necessitates the use of estimates when transactions affecting the current accounting period cannot be finalized until future periods. When necessary, such estimates are based on informed judgments made by management.

To ensure the integrity of the consolidated financial statements, we carefully select and train qualified personnel. We also ensure our organizational structure provides appropriate delegation of authority and division of responsibilities. Our policies and procedures are communicated throughout the organization and include a written Code of Conduct that applies to all employees, including the Chief Executive Officer and Chief Financial Officer.

Deloitte LLP, an independent registered public accounting firm appointed by the shareholders, has conducted an examination of the corporate and accounting records in order to express their opinion on the consolidated financial statements. The Audit Committee, consisting of three independent directors, has met with representatives of Deloitte LLP and management in order to determine if management has fulfilled its responsibilities in the preparation of the consolidated financial statements. The Board of Directors has approved the consolidated financial statements.

Management’s Report On Internal Control Over Financial Reporting

Management has designed and maintains an appropriate system of internal controls to provide reasonable assurance that all assets are safeguarded and financial records are properly maintained to facilitate the preparation of consolidated financial statements for reporting purposes. Management’s evaluation concluded that the internal control over financial reporting was effective as of December 31, 2016.



Signed by:

“Ross G. Clarkson”	“Randy C. Neely”

Ross G. Clarkson	Randy C. Neely
President & Chief Executive Officer	Vice President, Finance & Chief Financial Officer

March 6, 2017



2016		25

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of TransGlobe Energy Corporation

We have audited the accompanying consolidated financial statements of TransGlobe Energy Corporation and subsidiaries (the “Company”), which comprise the consolidated balance sheets as at December 31, 2016 and December 31, 2015, and the consolidated statements of earnings and comprehensive income, consolidated statements of changes in shareholders’ equity, and consolidated statements of cash flows for the years then ended, and a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries as at December 31, 2016 and December 31, 2015, and their financial performance and their cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Other Matter

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 6, 2017 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ Deloitte LLP

Chartered Professional Accountants

March 6, 2017

Calgary, Canada



26		2016

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of TransGlobe Energy Corporation

We have audited the internal control over financial reporting of TransGlobe Energy Corporation and subsidiaries (the “Company”) as of December 31, 2016, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's 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 International Financial Reporting Standards as issued by the International Accounting Standards Board. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the 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 the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2016 of the Company and our report dated March 6, 2017 expressed an unmodified/unqualified opinion on those financial statements.

/s/ Deloitte LLP

Chartered Professional Accountants

March 6, 2017

Calgary, Canada



2016		27

Consolidated Statements of Earnings (Loss) and Comprehensive Income (Loss)

(Expressed in thousands of U.S. Dollars, except per share amounts)



	Notes	2016			2015
REVENUE
Petroleum and natural gas sales, net of royalties	8	$	63,134		$	92,212
Finance revenue	9	673			683
		63,807			92,895

EXPENSES
Production and operating		40,323			52,696
Transportation costs		12			—
Selling costs	10	875			4,557
General and administrative		17,555			21,336
Foreign exchange (gain) loss		3,607			(11,613		)
Finance costs	9	6,068			6,274
Depletion, depreciation and amortization	17	29,177			42,875
Realized derivative loss on commodity contracts		956			688
Unrealized (gain) loss on financial instruments	22	7,027			6,615
Impairment loss	16, 17	33,426			85,373
Loss on corporate dispositions	24	—			252
		139,026			209,053

Earnings (loss) before income taxes		(75,219		)	(116,158		)

Income tax expense (recovery) – current	15	15,455			25,483
– deferred	15	(3,009		)	(36,041		)
		12,446			(10,558		)
NET EARNINGS (LOSS) AND COMPREHENSIVE INCOME (LOSS) FOR THE YEAR		$	(87,665	)	$	(105,600	)

Earnings (loss) per share	27
Basic		$	(1.21	)	$	(1.44	)
Diluted		$	(1.21	)	$	(1.44	)

See accompanying notes to the Consolidated Financial Statements.



28		2016

Consolidated Balance Sheets

(Expressed in thousands of U.S. Dollars)



		As at		As at
	Notes	December 31, 2016		December 31, 2015
ASSETS
Current
Cash and cash equivalents	11	$	31,468	$	126,910
Restricted cash	13	18,323		—
Accounts receivable	7	14,836		22,929
Prepaids and other		1,772		3,206
Product inventory	14	19,602		17,287
		86,001		170,332
Non-Current
Restricted cash	13	—		860
Deferred financing costs	21	—		724
Intangible exploration and evaluation assets	16	105,869		122,020
Property and equipment
Petroleum and natural gas assets	17	210,027		156,597
Other assets	17	4,245		4,967
		$	406,142	$	455,500

LIABILITIES
Current
Accounts payable and accrued liabilities	20	$	24,529	$	16,497
Convertible debentures	22	72,655		—
Current portion of note payable	21	5,581		—
		102,765		16,497
Non-Current
Note payable	21	5,581		—
Convertible debentures	22	—		63,848
Asset retirement obligation	18	12,099		—
Deferred taxes	15	—		3,009
Other long-term liabilities		381		462
		120,826		83,816

SHAREHOLDERS’ EQUITY
Share capital	25	152,084		152,084
Contributed surplus		22,695		21,398
Retained earnings		110,537		198,202
		285,316		371,684
		$	406,142	$	455,500

See accompanying notes to the Consolidated Financial Statements.

Approved on behalf of the Board:

Signed by:



“Ross G. Clarkson”	“Fred J. Dyment”

Ross G. Clarkson	Fred J. Dyment
President and CEO,	Director
Director



2016		29

Consolidated Statement of Changes in Shareholders’ Equity

(Expressed in thousands of U.S. Dollars)



	Notes	2016			2015

Share Capital
Balance, beginning of year	25	$	152,084		$	164,006
Purchase of common shares	25	—			(12,221		)
Stock options exercised	25	—			208
Transfer from contributed surplus on exercise of options	25	—			91
Balance, end of year		$	152,084		$	152,084

Contributed Surplus
Balance, beginning of year		$	21,398		$	19,427
Share-based compensation expense	26	1,297			2,062
Transfer to share capital on exercise of options		—			(91		)
Balance, end of year		$	22,695		$	21,398

Retained Earnings
Balance, beginning of year		$	198,202		$	316,667
Net earnings (loss) and total comprehensive income (loss)		(87,665		)	(105,600		)
Dividends	28	—			(12,865		)
Balance, end of year		$	110,537		$	198,202

See accompanying notes to the Consolidated Financial Statements.



30		2016

Consolidated Statements of Cash Flows

(Expressed in thousands of U.S. Dollars)



		Year Ended			Year Ended
	Notes	December 31, 2016			December 31, 2015
CASH FLOWS RELATED TO THE FOLLOWING ACTIVITIES:

OPERATING
Net earnings (loss) for the year		$	(87,665	)	$	(105,600	)
Adjustments for:
Depletion, depreciation and amortization	17	29,177			42,875
Deferred lease inducement		(95		)	(104		)
Impairment loss	16, 17	33,426			85,373
Share-based compensation	26	2,418			2,787
Finance costs	9	6,068			6,274
Income tax expense (recovery)	15	12,446			(10,558		)
Unrealized (gain) loss on financial instruments	22	7,027			6,615
Unrealized (gain) loss on foreign currency translation		4,292			(11,333		)
Loss on corporate dispositions	24	—			252
Income taxes paid		(15,455		)	(25,483		)
Changes in non-cash working capital, net of effect of corporate disposals	32	7,296			86,428
Net cash generated by (used in) operating activities		(1,065		)	77,526

INVESTING
Additions to intangible exploration and evaluation assets	16	(19,425		)	(21,426		)
Additions to petroleum properties	17	(6,618		)	(22,723		)
Additions to other assets	17	(615		)	(753		)
Property acquisition	6, 17	(48,313		)	—
Proceeds from corporate dispositions	24	—			1,500
Changes in restricted cash	13	(17,462		)	688
Changes in non-cash working capital, net of effect of corporate disposals	32	5,556			(16,000		)
Net cash generated by (used in) investing activities		(86,877		)	(58,714		)

FINANCING
Issue of common shares for cash	25	—			208
Repurchase of common shares for cash	25	—			(12,221		)
Interest paid		(5,288		)	(5,779		)
Dividends paid	28	—			(12,865		)
Net cash generated by (used in) financing activities		(5,288		)	(30,657		)
Currency translation differences relating to cash and cash equivalents		(2,212		)	(1,635		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(95,442		)	(13,480		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR		126,910			140,390
CASH AND CASH EQUIVALENTS, END OF YEAR		$	31,468		$	126,910

See accompanying notes to the Consolidated Financial Statements.



2016		31

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As at December 31, 2016 and December 31, 2015 and for the years then ended

(Expressed in U.S. Dollars)

1. CORPORATE INFORMATION

TransGlobe Energy Corporation (the "Company or TransGlobe") is a publicly listed company incorporated in Alberta, Canada and its shares are listed on the Toronto Stock Exchange (“TSX”) and the Global Select Market of the NASDAQ Stock Market (“NASDAQ”). The address of its registered office is 2300, 250 – 5th Street SW, Calgary, Alberta, Canada, T2P 0R4. TransGlobe together with its subsidiaries ("TransGlobe" or the "Company") is engaged primarily in oil and gas exploration, development and production and the acquisition of properties.

2. BASIS OF PREPARATION

Statement of compliance

These Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board effective as of December 31, 2016.

These Consolidated Financial Statements were authorized for issue by the Board of Directors on March 6, 2017.

Basis of measurement

The accounting policies used in the preparation of these Consolidated Financial Statements are described in Note 3, Significant Accounting Policies.

The Company prepared these Consolidated Financial Statements on a going concern basis, which contemplates the realization of assets and liabilities in the normal course of business as they become due. Accordingly, these Consolidated Financial Statements have been prepared on a historical cost basis, except for cash and cash equivalents and convertible debentures that have been measured at fair value. The method used to measure fair value is discussed further in Notes 3 and 7.

Functional and presentation currency

In these Consolidated Financial Statements, unless otherwise indicated, all dollar amounts are presented and expressed in United States (U.S.) dollars, which is the Company’s functional currency. All references to $ are to United States dollars and references to C$ are to Canadian dollars. All values are rounded to the nearest thousand except when otherwise indicated.

3. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently to all periods presented in these Consolidated Financial Statements.

Basis of consolidation

Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies of an entity, it is exposed to or has rights to variable returns associated with its involvement in the entity, and it has the ability to use that power to influence the amount of returns it is exposed to or has rights to. In assessing control, potential voting rights need to be considered. The Consolidated Financial Statements include the financial statements of the Company and its controlled subsidiaries.

The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies.

All intra-company transactions, balances, income and expenses, unrealized gains and losses are eliminated on consolidation.

Joint operations

The Company conducts many of its oil and gas production activities through joint operations and the Consolidated Financial Statements reflect only the Company's share in such activities.

Foreign currency translation

The Consolidated Financial Statements are presented in U.S. dollars. The Company's reporting and functional currency is the U.S. dollar as this is the principal currency of the primary economic environment the entity operates in and is normally the one in which it primarily generates and expends cash. Transactions in foreign currencies are translated to the functional currency of the Company at exchange rates at the dates of the transactions.

Monetary assets and liabilities denominated in foreign currencies at the reporting date are re-translated to the functional currency at the exchange rate at that date. The foreign currency gain or loss on monetary items is the difference between its functional currency equivalent at the beginning of the period, or when the transaction was entered into if it occurred during the period, and the functional currency equivalent translated at the exchange rate at the end of the period.

Non-monetary assets and liabilities denominated in foreign currencies that are measured at fair value are translated to the functional currency at the exchange rate at the date that the fair value was determined. The foreign currency gain or loss on non-monetary items is the difference in fair value measured in the functional currency between measurement dates.



32		2016

Cash and cash equivalents

Cash and cash equivalents includes cash and short-term, highly liquid investments that mature within three months of the date of their purchase.

Restricted cash

Restricted cash represents a cash collateralized letter of credit facility that is used to guarantee the Company's commitments on its Egyptian exploration concessions.

Financial instruments

Non-derivative financial instruments

Financial assets and liabilities at fair value through profit or loss

Other

Other non-derivative financial instruments, such as accounts receivable, accounts payable and accrued liabilities, 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

Share capital

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as a deduction from equity. When the Company acquires and cancels its own common shares, share capital is reduced by the cost of shares repurchased, including transaction costs.

Property and equipment and intangible exploration and evaluation assets

Exploration and evaluation assets

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

Intangible exploration and evaluation assets are not depleted. They are carried forward until technical feasibility and commercial viability of extracting a mineral resource is determined. The technical feasibility and commercial viability is considered to be determined when proved and/or probable reserves are determined to exist or they can be empirically supported with actual production data or conclusive formation tests. A review of each CGU is carried out at least annually. Intangible exploration and evaluation 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 and natural gas assets

Petroleum and natural gas ("PNG") assets and other assets are recognized 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 exploration and evaluation assets, and for



2016		33

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, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property and equipment and are recognized in net earnings (loss) 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 profit or loss 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 well, field or geotechnical area basis, together with the discounted value of estimated future costs of asset retirement obligations. When components of PNG assets are replaced, disposed of, or no longer in use, the carrying amount is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

Depletion, depreciation and amortization

The depletion, depreciation and amortization of PNG assets and other assets are recognized in earnings (loss).

The net carrying value of the PNG 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 and determined in accordance with National Instrument 51-101 Standards of Disclosure of Oil and Gas Activities. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.

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

Goodwill

Goodwill arises on the acquisition of businesses.

Recognition and measurement

Goodwill represents the excess of the cost of an acquisition over the Company’s interest in the net fair value of the identifiable assets, liabilities and contingent liabilities of the acquiree. When the excess is negative, it is recognized immediately in earnings.

Subsequent measurement

Goodwill is measured at cost less accumulated impairment losses.

Goodwill is not amortized but instead tested for impairment annually, or at any time there are indications of impairment.

Product inventory

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

Impairment

Financial assets carried at amortized cost

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of the asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics.

All impairment losses are recognized in profit or loss. An impairment loss may be reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. Any such reversal is recognized in profit or loss.



34		2016

Non-financial assets

The carrying amounts of the Company’s non-financial assets are reviewed at each reporting date to determine whether there is any indication of impairment, except for E&E assets and goodwill, which are reviewed when circumstances indicate impairment may exist and at least annually, as discussed in more detail below. If any such indication exists, then the asset’s recoverable amount is estimated.

For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the cash-generating unit or “CGU”). The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell. The Company’s CGUs are not larger than a segment. In assessing both fair value less costs to sell and value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.

For D&P assets, fair value less costs to sell and value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves.

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. Impairment indicators are evaluated at a CGU level. Indications of impairment include:


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


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


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


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

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the CGUs and then to reduce the carrying amounts of the other assets in the CGUs on a pro-rata basis.

Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss may be reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

For goodwill, the recoverable amount is estimated each year on December 31. An impairment loss in respect of goodwill is calculated by reference to the recoverable amount determined at that time. The goodwill acquired in a business combination, for the purpose of impairment testing, is allocated to CGU’s that are expected to benefit from the synergies of the combination. An impairment loss in respect of goodwill is never reversed.

Share-based payment transactions

Equity-settled transactions

The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which equity instruments are granted and is recognized as an expense over the vesting period, which ends on the date on which the relevant employees become fully entitled to the award. Fair value is determined by using the lattice-based trinomial option pricing model. An estimated forfeiture rate is taken into consideration when assigning a fair value to options granted such that no expense is recognized for awards that do not ultimately vest.

At each financial reporting date before vesting, the cumulative expense is calculated, which represents the extent to which the vesting period has expired and management’s best estimate of the number of equity instruments that will ultimately vest. The movement in cumulative expense since the previous financial reporting date is recognized in earnings, with a corresponding entry in equity.

When the terms of an equity-settled award are modified or a new award is designated as replacing a cancelled or settled award, the cost based on the original award terms continues to be recognized over the remainder of the new vesting period for the incremental fair value of any modification, based on the difference between the fair value of the original award and the fair value of the modified award, both as measured on the date of the modification. No reduction is recognized if this difference is negative.

Cash-settled transactions

The cost of cash-settled transactions is measured at fair value using the lattice-based trinomial pricing model and recognized as an expense over the vesting period, with a corresponding liability recognized on the balance sheet.

The grant date fair value of cash-settled units granted to employees is recognized as compensation expense, within general and administrative expenses, with a corresponding increase in accounts payable and accrued liabilities, over the period that the employees become unconditionally entitled to the units. The amount recognized as an expense is adjusted to reflect the actual number of units for which the related service and non-market vesting conditions are met. The liability is re-measured at each reporting date with changes to fair value recognized through profit or loss until it is ultimately settled.

Provisions and asset retirement obligations

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

The Company provides for asset retirement obligations on all of its Canadian property, plant and equipment based on current legislation and industry operating practices. The estimated present value of the asset retirement obligation is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. This increase is depleted with the related depletion unit and is allocated to a CGU for impairment



2016		35

testing. The liability recorded is increased each reporting period due to the passage of time and this change is charged to net earnings (loss) in the period as accretion expense. The asset retirement obligation can also increase or decrease due to changes in the estimated timing of cash flows, changes in the discount rate and/or changes in the original estimated undiscounted costs. Increases or decreases in the obligation will result in a corresponding change in the carrying amount of the related asset. Actual costs incurred upon settlement of the asset retirement obligation are charged against the asset retirement obligation to the extent of the liability recorded. The Company discounts the costs related to asset retirement obligations using the discount rate that reflects the current market assessment of the time value of money and risks specific to the liabilities that have not been reflected in the cash flow estimates. The Company applies discount rates applicable to each of the jurisdictions in which it has future asset retirement obligations. Asset retirement obligations are remeasured at each reporting period in order to reflect the discount rates in effect at that time.

Future abandonment and reclamation costs have been assessed a zero value in Egypt. In accordance with all of the Company's PSCs, the Company does not at any time hold title to the lands on which it operates, and title to fixed and movable assets is transferred to the respective government when its total cost has been recovered through cost recovery, or at the time of termination of the PSC. Since the Company will not hold title to the land or the assets at the termination of the PSC, the Company does not have a legal obligation, nor the legal ability to decommission the Egypt assets. Furthermore, there is no explicit contractual obligation under the Company's PSCs for abandonment of assets or reclamation of lands upon termination of the PSCs.

Revenue recognition

Canada

Revenues from the sale of petroleum and natural gas are recorded when title to the products transfers to the purchasers based on volumes delivered and contracted delivery points and prices. Revenue is measured at the fair value of the consideration received or receivable. Revenue from the sale of crude oil, natural gas, condensate and natural gas liquids ("NGLs") (prior to deduction of transportation costs) is recognized when all of the following conditions have been satisfied:


•	The Company has transferred the significant risks and rewards of ownership of the goods to the buyer;


•	The Company retains no continuing managerial involvement to the degree usually associated with ownership or effective control over the goods sold;


•	The amount of revenue can be measured reliably;


•	It is probable that the economic benefits associated with the transaction will flow to the Company; and


•	The costs incurred or to be incurred in respect of the transaction can be measured reliably.

Capital processing charges to other entities for use of facilities owned by TransGlobe are recognized as revenue as they accrue in accordance with the terms of the service agreements and are presented as other income.

Egypt

Revenues associated with the sales of the Company's crude oil are recognized by reference to actual volumes produced and quoted market prices in active markets for identical assets, adjusted according to specific terms and conditions as applicable, when the significant risks and rewards of ownership have been transferred, which is when title passes from the Company to its customer. Crude oil produced and sold by the Company below or above its working interest share in the related resource properties results in production under-liftings or over-liftings. Under-liftings are recorded as inventory and over-liftings are recorded as deferred revenue or used to offset receivables.

Pursuant to the PSCs associated with the Company's operations, the Company and other non-governmental partners (if applicable) pay all operating and capital costs for exploration and development. 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 fiscal year. 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 Egypt, 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 the respective government. 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.

Transportation

Costs paid by TransGlobe for the transportation of crude oil, natural gas, condensate and NGLs to the point of title transfer are recognized when the transportation is provided.

Finance revenue and costs

Finance revenue comprises interest income on funds invested. Interest income is recognized as it accrues in earnings, using the effective interest method.

Finance costs comprises interest expense on borrowings.

Borrowing costs incurred for qualifying assets are capitalized during the period of time that is required to complete and prepare the assets for their intended use or sale. Qualifying assets are those that necessarily take a substantial period of time to get ready for their intended use or sale. All other borrowing costs are recognized in earnings using the effective interest method.



36		2016

Royalties

Canada

Royalties are recorded at the time the product is produced and sold. Royalties are calculated in accordance with the applicable regulations and/or the terms of individual royalty agreements. Crown royalties for natural gas, condensate and other associated liquids are based on Alberta Government posted reference prices as all of the Company's producing assets are in Alberta.

Egypt

For the Company’s international operations, all government interests, except for income taxes, are considered royalty payments. Government interests are determined in accordance with the respective PSCs.

Income tax

Income tax expense is comprised of current and deferred tax. TransGlobe is subject to income taxes based on the tax legislation of each respective country in which TransGlobe conducts business.

Current tax

Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted by the date of the statement of financial position.

The Company's contractual arrangements in Egypt stipulate that income taxes are paid by the respective government out of its entitlement share of production sharing oil. Such amounts are included in current income tax expense at the statutory rate in effect at the time of production.

Deferred tax

The Company determines the amount of deferred income tax assets and liabilities based on the difference between the carrying amounts of the assets and liabilities reported for financial accounting purposes from those reported for tax. Deferred income tax assets and liabilities are measured using the substantively enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. Deferred income tax assets associated with unused tax losses are recognized to the extent it is probable the Company will have sufficient future taxable earnings available against which the unused tax losses can be utilized.

Joint arrangements

A joint arrangement involves joint control and offers joint ownership by the Company and other joint interest partners of the financial and operating policies, and of the assets associated with the arrangement. Joint arrangements are classified into one of two categories: joint operations or joint ventures.

A joint operation is a joint arrangement whereby the Company and the other parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities relating to the arrangement. Parties involved in joint operations must recognize in relation to their interests in the joint operation their proportionate share of the revenues, expenses, assets and liabilities. A joint venture is a joint arrangement whereby the Company and the other parties that have joint control of the arrangement have rights to the net assets of the arrangement. Parties involved in joint ventures must recognize their interests in joint ventures as investments and must account for that investment using the equity method.

In Canada, the Company conducts many of its oil and gas production activities through jointly controlled operations and the financial statements reflect only the Company's proportionate interest in such activities. Joint control exists for contractual agreements governing TransGlobe's assets whereby TransGlobe has less than 100% working interest, all of the partners have control of the arrangement collectively, and spending on the project requires unanimous consent of all parties that collectively control the arrangement and share the associated risks. TransGlobe does not have any joint arrangements that are individually material to the Company or that are structured through joint venture arrangements.

In Egypt, joint arrangements in which the Company is involved are conducted pursuant to Production Sharing Agreements and Production Sharing Concessions (collectively defined as "PSCs"). Given the nature and contractual terms associated with the PSCs, the Company has determined that it has rights to the assets and obligations for the liabilities in all of its joint arrangements, and that there are no currently existing joint arrangements where the Company has rights to net assets. Accordingly, all joint arrangements have been classified as joint operations, and the Company has recognized in the Consolidated Financial Statements its share of all revenues, expenses, assets and liabilities in accordance with the PSCs.

Business combinations

Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities and contingent liabilities assumed are measured at their fair values at the acquisition date. The cost of an acquisition is measured as the aggregate consideration transferred, measured at the acquisition date fair value. If the cost of the acquisition is less than the fair value of the net assets acquired, the difference is recognized immediately in net earnings. If the cost of the acquisition is more than the fair value of the net assets acquired, the difference is recognized on the balance sheet as goodwill. Acquisition costs incurred are expensed.

4. CRITICAL JUDGMENTS AND ACCOUNTING ESTIMATES

Timely preparation of the financial statements in conformity with IFRS as issued by the International Accounting Standards Board requires that management make estimates and assumptions and use judgments that affect the application of accounting policies and the reported amounts of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. The effect of these estimates,



2016		37

assumptions and the use of judgments are explained throughout the notes to the Consolidated Financial Statements. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected.

The key sources of estimation uncertainty that have a significant risk of causing material adjustment to the carrying amounts of assets and liabilities are discussed below.

Recoverability of asset carrying values

The recoverability of development and production asset carrying values are assessed at the CGU level. Determination of what constitutes a CGU is subject to management judgment of the lowest level at which there are identifiable cash inflows that are largely independent of the cash inflows of other groups of assets or properties. The factors used by TransGlobe to determine CGUs may vary by country due to unique operating and geographic circumstances in each country. However, in general, TransGlobe assesses the following factors in determining whether a group of assets generate largely independent cash inflows:


•	geographic proximity of the assets within a group to one another;


•	geographic proximity of the group of assets to other groups of assets; and


•	homogeneity of the production from the group of assets and the sharing of infrastructure used to process and/or transport production.

In Egypt, each production sharing concession ("PSC") is considered a separate CGU. In Canada, CGUs are determined by regional geography. The asset composition of a CGU can directly impact the recoverability of the assets included therein. In assessing the recoverability of the Company's petroleum properties, each CGU's carrying value is compared to its recoverable amount, defined as the greater of its fair value less costs to sell and value-in-use. As at December 31, 2016 and December 31, 2015, the recoverable amounts of the Company's CGU's were estimated as their fair value less costs to sell based on the net present value of the after-tax cash flows from the oil and natural gas reserves of each CGU based on reserves estimated by the Company's independent reserve evaluator.

Key input estimates used in the determination of cash flows from oil and natural gas reserves include the following:

•

Reserves - There are numerous uncertainties inherent in estimating oil and gas reserves. An external reserve engineering report which incorporates a full evaluation of reserves is prepared on an annual basis with internal reserve updates completed at each quarterly period. Estimating reserves is highly complex, requiring many judgments including forward price estimates, production costs, and recovery rates based on available geological, geophysical, engineering and economic data. Changes in these judgments may have a material impact on the estimated reserves. These estimates may change, resulting in either negative or positive impacts to net earnings as further information becomes available and as the economic environment changes.


•	Commodity prices - Forward price estimates of crude oil and natural gas prices are incorporated into the determination of expected future net cash flows. Commodity prices have fluctuated significantly in recent years due to global and regional factors including supply and demand fundamentals, inventory levels, foreign exchange rates, economic, and geopolitical factors.


•	Discount rate - The discount rate used to determine the net present value of future cash flows is based on the Company's estimated weighted average cost of capital. Changes in the economic environment could change the Company's weighted average cost of capital.

Impairment tests were carried out at December 31, 2016 and were based on fair value less costs to sell calculations, using a discount rate of 10% for Canada and 15% for Egypt on future after-tax cash flows and the following forward commodity price estimates:



	Egypt²		Canada²
	Oil		Oil		Gas		Condensate		Butane		Propane		Ethane
Year	$US/Bbl		$US/Bbl		$US/Mcf		$US/Bbl		$US/Bbl		$US/Bbl		$US/Bbl
2017	44.86		49.28		2.52		51.66		29.82		15.81		7.64
2018	48.99		51.88		2.27		54.44		33.22		16.74		8.03
2019	53.26		53.69		2.35		55.48		33.47		17.00		8.31
2020	58.79		56.77		2.49		58.61		35.46		18.01		8.77
2021	62.37		57.97		2.57		60.78		37.41		18.86		8.95
Thereafter (%)¹	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%
¹ Percentage change represents the increase in each year after 2021 to the end of the reserve life.
² DeGolyer and MacNaughton Canada Limited (“DeGolyer”) price forecasts, effective December 31, 2016.

Depletion of petroleum properties

Reserves and resources are used in the units of production calculation for depletion, depreciation and amortization. Depletion of petroleum properties is calculated based on total Proved plus Probable reserves as well as estimated future development costs associated with these reserves as determined by the Company's independent reserve evaluator. See above for discussion of estimates and judgments involved in reserve estimation.

Income taxes

Related assets and liabilities are recognized for the estimated tax consequences between amounts included in the financial statements and their tax base using substantively enacted future income tax rates. Timing of future revenue streams and future capital spending changes can affect the timing of any temporary differences, and accordingly affect the amount of the deferred tax asset or liability calculated at a point in time. Tax interpretations, regulations, and legislation in the various jurisdictions in which TransGlobe and its subsidiaries operate are subject to change and interpretation. Such changes can affect the timing of the reversal of temporary tax differences, the tax rates in effect when such differences reverse and TransGlobe's ability to use tax losses and other tax pools in the future. The Company’s income tax filings are subject to audit by taxation



2016		38

authorities in different jurisdictions and the results of such audits may increase or decrease the tax liability. The determination of current and deferred tax amounts recognized in the consolidated financial statements are based on management’s assessment of the tax positions, which includes consideration of their technical merits, communications with tax authorities and management’s view of the most likely outcome. These differences could materially impact earnings.

Business combinations

Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of property, plant, and equipment, and exploration and evaluation assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices, and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities in the purchase price allocation, and any resulting gain or goodwill. Future net earnings can be affected as a result of changes in future depletion, depreciation and accretion, and asset impairments.

Financial instruments

The fair values of financial instruments are estimated based upon market and third party inputs. These estimates are subject to change with fluctuations in commodity prices, interest rates, foreign currency exchange rates and estimates of non-performance risk.

Share-based payments

The fair value estimates of equity-settled and cash-settled share-based payment awards depend on certain assumptions including share price volatility, risk free interest rate, the term of the awards, and the forfeiture rate which, by their nature, are subject to measurement uncertainty.

Asset retirement obligations

The provision for site restoration and abandonment in Canada is based on current legal and constructive requirements, technology, price levels and expected plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, market conditions, discovery and analysis of site conditions and changes in technology.

Recoverability of accounts receivable

The recoverability of accounts receivable due from the Egyptian General Petroleum Company ("EGPC") is assessed to determine the carrying value of accounts receivable on the Company's Consolidated Balance Sheets. Management judgment is required in performing the recoverability assessment. No material credit losses have been experienced to date, and the Company expects to collect the accounts receivable balance in full.

5. NEW STANDARDS AND INTERPRETATIONS NOT YET ADOPTED

As at the date of authorization of the Consolidated Financial Statements the following pronouncements from the International Accounting Standards Board ("ISAB") 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 income rather than net earnings, unless this creates an accounting mismatch. In addition, a new expected credit loss model for calculating impairment on financial assets replaces the incurred loss impairment model used in IAS 39. The new model will result in more timely recognition of expected credit losses. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. The Company does not currently apply hedge accounting. IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. The Company 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"



2016		39

IFRS 16 "Leases"

6. BUSINESS COMBINATION

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

In accordance with IFRS, a property acquisition is accounted for as a business combination when certain criteria are met, such as the acquisition of inputs and processes to convert those inputs into beneficial outputs. TransGlobe assessed the property acquisition and determined that it constitutes a business combination under IFRS. In a business combination, acquired assets and liabilities are recognized by the acquirer at their fair market value at the time of purchase. Any variance between the determined fair value of the assets and liabilities and the purchase price is recognized as either goodwill or a gain in the statement of comprehensive income in the period of acquisition.

The estimated fair value of the property, plant and equipment acquired through the transaction was determined based on the present value of the expected future cash flows associated with the acquired property using both internal estimates and an independent reserve evaluation. The decommissioning liabilities assumed were determined using the timing and estimated costs associated with the abandonment, restoration and reclamation of the wells and facilities acquired. The total net fair value of the acquired property was equal to the consideration paid by the Company. As a result, no bargain purchase gain or goodwill was recognized for the year ended December 31, 2016 relating to the acquisition.

The consideration paid and fair values of the identifiable assets acquired and liabilities assumed by the Company are as follows:



(000s)
Consideration paid
Cash paid to vendor	$	48,313
Vendor take back loan	11,162
	$	59,475

Net assets acquired
Petroleum and natural gas assets	$	71,564
Asset retirement obligations assumed	(12,089		)
	$	59,475

If the acquisition had been effective January 1, 2016, the Company would have realized an estimated additional $17.2 million (unaudited) of production revenue and an estimated additional $7.9 million (unaudited) of net operating income before tax. Between the acquisition date of December 20, 2016 and December 31, 2016, approximately $0.6 million of production revenue and $0.2 million of net operating income before tax was recognized relating to the acquired properties.

7. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Fair Values of Financial Instruments

The Company has classified its cash and cash equivalents as assets at fair value through profit or loss and its convertible debentures as financial liabilities at fair value through profit or loss, which are both measured at fair value with changes being recognized through earnings. Accounts receivable and restricted cash are classified as loans and receivables; accounts payable and accrued liabilities, long-term debt and note payable are classified as other liabilities, all of which are measured initially at fair value, then at amortized cost after initial recognition.

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



	December 31, 2016				December 31, 2015
	Carrying		Fair		Carrying		Fair
Classification (000s)	Value		Value		Value		Value
Financial assets at fair value through profit or loss	$	31,468	$	31,468	$	126,910	$	126,910
Loans and receivables	33,159		33,159		23,789		23,789
Financial liabilities at fair value through profit or loss	72,655		72,655		63,848		63,848
Other liabilities	35,691		35,691		16,497		16,497



2016		40

Assets and liabilities at December 31, 2016 that are measured at fair value are classified into levels reflecting the method used to make the measurements. Fair values of assets and liabilities included in Level 1 are determined by reference to quoted prices in active markets for identical assets and liabilities. Assets and liabilities in Level 2 include valuations using inputs other than quoted prices for which all significant inputs are observable, either directly or indirectly. Level 3 valuations are based on inputs that are unobservable and significant to the overall fair value measurement.

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

Overview of Risk Management

The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production and financing activities:

• Credit risk

• Market risk

• Liquidity risk

This note presents information about the Company’s exposure to each of the above risks, the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital. Further quantitative disclosures are included throughout these Consolidated Financial Statements.

The Board of Directors and Audit Committee oversee management’s establishment and execution of the Company’s risk management framework. Management has implemented and monitors compliance with risk management policies. The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.

Credit risk

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

TransGlobe's accounts receivable related to the Canadian operations are with customers and joint interest partners in the petroleum and natural gas industry and are subject to normal industry credit risks. Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. The Company currently sells its production to several purchasers under standard industry sale and payment terms. Purchasers of TransGlobe's natural gas, crude oil and natural gas liquids are subject to a periodic internal credit review to minimize the risk of non-payment. The Company has continued to closely monitor and reassess the creditworthiness of its counterparties, including financial institutions.

Trade and other receivables are analyzed in the table below. The majority of the overdue receivables are due from the EGPC. The political transition and resultant economic malaise in the country that began in 2011 resulted in irregular collection of accounts receivable from EGPC and generally a larger receivable balance, which increased TransGlobe's credit risk. Despite these factors, the Company expects to collect in full all receivables outstanding from EGPC.

In January 2015, TransGlobe began direct sales of Eastern Desert entitlement production to international buyers. The Company completed three separate direct crude sale shipments to third party buyers in 2016. Buyers are required to post irrevocable letters of credit to support the sales prior to the cargo liftings. Going forward, the Company anticipates that direct sales will continue to reduce outstanding accounts receivable and credit risk in future periods.



(000s)
Trade receivables at December 31, 2016
Neither impaired nor past due	$	620
Not impaired and past due in the following period
Within 30 days	—
31-60 days	—
61-90 days	—
Over 90 days	14,216

The Company manages its credit risk on cash equivalents by investing only in term deposits with reputable banking institutions.

Market risk



2016		41

Commodity price risk

The Company’s operational results and financial condition are partially dependent on the commodity prices received for its production of oil, natural gas and NGLs. As such, the Company uses derivative commodity contracts from time to time as part of its risk management strategy to manage commodity price fluctuations.

The estimated fair value of unrealized commodity contracts is reported on the Consolidated Balance Sheets, with any change in the unrealized positions recorded to earnings. The Company assesses these instruments on the fair value hierarchy and has classified the determination of fair value of these instruments as Level 2, as the fair values of these transactions are based on an approximation of the amounts that would have been received from counter-parties to settle the transactions outstanding as at the date of the Consolidated Balance Sheets with reference to forward prices and market values provided by independent sources. The actual amounts realized may differ from these estimates.

As there were no outstanding derivative commodity contracts at December 31, 2016 or December 31, 2015, no assets or liabilities have been recognized on the Consolidated Balance Sheets for the respective periods.

Foreign currency exchange risk

As the Company’s business is conducted primarily in U.S. dollars and its financial instruments are primarily denominated in U.S. dollars, the Company’s exposure to foreign currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, convertible debentures, accounts payable and accrued liabilities denominated in Canadian dollars. When assessing the potential impact of foreign currency exchange risk, the Company believes 10% volatility is a reasonable measure. The Company estimates that a 10% increase in the value of the Canadian dollar against the U.S. dollar would result in an increase in the net loss for the year ended December 31, 2016 of approximately $8.1 million and conversely a 10% decrease in the value of the Canadian dollar against the U.S. dollar would decrease the net loss by $6.6 million for the same period. The Company does not utilize derivative instruments to manage this risk.

Interest rate risk

Fluctuations in interest rates could result in a significant change in the amount the Company pays to service variable-interest debt. No derivative contracts were entered into during 2016 to mitigate this risk. When assessing interest rate risk applicable to the Company’s variable-interest, U.S.-dollar-denominated debt the Company believes 1% volatility is a reasonable measure. Since the Company did not have any amounts drawn on its variable-interest, U.S.-dollar-denominated debt at any time in 2016, the effect of interest rates increasing or decreasing by 1% would have no impact on the Company's net earnings for the year ended December 31, 2016.

Liquidity risk

The Company actively maintains credit facilities to ensure it has sufficient available funds to meet current and foreseeable financial requirements at a reasonable cost. The following are the contractual maturities of financial liabilities at December 31, 2016:



(000s)		Payment Due by Period^{1 2}
	Recognized
	in Financial	Contractual		Less than						More than
	Statements	Cash Flows		1 year		1-3 years		4-5 years		5 years
Accounts payable and accrued liabilities	Yes - Liability	$	24,529	$	24,529	$	—	$	—	$	—
Convertible debentures	Yes - Liability	72,655		72,655		—		—		—
Note payable	Yes - Liability	11,162		5,581		5,581		—		—
Office and equipment leases³	No	3,732		1,200		1,556		976		—
Minimum work commitments⁴	No	17,986		8,335		9,651		—		—
Total		$	130,064	$	112,300	$	16,788	$	976	$	—
¹ Payments exclude on-going operating costs, finance costs and payments required to settle derivatives.
² Payments denominated in foreign currencies have been translated at December 31, 2016 exchange rates.
³ Office and equipment leases includes all drilling rig contracts.
⁴ Minimum work commitments include contracts awarded for capital projects and those commitments related to exploration and drilling obligations (see Note 23).

The Company actively monitors its liquidity to ensure that its cash flows, credit facilities and working capital are adequate to support these financial liabilities, as well as the Company’s capital programs.

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



42		2016

Capital disclosures

The Company’s objective when managing capital is to ensure the Company will have the financial capacity, liquidity and flexibility to fund the ongoing exploration and development of its petroleum assets. The Company relies on cash flow to fund its capital investments. However, due to long lead cycles of some of its developments and corporate acquisitions, the Company’s capital requirements may exceed its cash flow generated in any one period. This requires the Company to maintain financial flexibility and liquidity.

The Company sets the amount of capital in proportion to risk and has historically managed to ensure that the total of the long-term debt is not greater than two times the Company’s funds flow from operations for the trailing twelve months. For the purposes of measuring the Company’s ability to meet the above stated criteria, funds flow from operations is defined as cash generated from operating activities before changes in non-cash working capital. As a direct result of a lower oil price environment, TransGlobe’s debt-to-funds flow from operations ratio continued to deteriorate throughout the year and was negative 10.0 at December 31, 2016 (December 31, 2015 - negative 7.2) as a result of negative funds flow for the year. Despite the deterioration of this particular ratio, the Company remains in a strong financial position due to prudent capital resource management. The Company's capital programs are funded by its existing working capital and cash provided from operating activities. Funds flow from operations may not be comparable to similar measures used by other companies.

The Company defines and computes its capital as follows:



(000s)	2016			2015
Shareholders’ equity	$	285,316		$	371,684
Long-term note payable, including the current portion	11,162			—
Convertible debentures	72,655			63,848
Cash and cash equivalents	(31,468		)	(126,910		)
Total capital	$	337,665		$	308,622

The Company’s debt-to-funds flow ratio is computed as follows:



(000s)	2016			2015
Long-term note payable, including the current portion	$	11,162		$	—
Convertible debentures	72,655			63,848
Total debt	83,817			63,848

Cash flow from operating activities	(1,065		)	77,526
Changes in non-cash working capital	(7,296		)	(86,428		)
Funds flow from operations	$	(8,361	)	$	(8,902	)
Ratio	(10.0		)	(7.2		)

The Company’s financial objectives and strategy as described above have remained substantially unchanged over the last two completed fiscal years. These objectives and strategy are reviewed on an annual basis. The Company's debt-to-funds flow from operations ratio continued to deteriorate from the prior year. This deterioration is principally due to the current oil price environment. However, the Company remains in a relatively strong financial position, and will continue to focus on cost reductions and prudent stewardship of capital with the objective of maintaining a strong balance sheet. The Company was not subject to financial covenants as at December 31, 2016 due to the termination of the Borrowing Base Facility. The Borrowing Base Facility was terminated in December 2016, and the Company entered into a prepayment arrangement subsequent to year end (Note 33).

8. PETROLEUM AND NATURAL GAS SALES



(000s)	2016		2015
Petroleum and natural gas sales	$	122,360	$	187,665
Less: Royalties	59,226		95,453
Petroleum and natural gas sales, net of royalties	$	63,134	$	92,212

9. FINANCE REVENUE AND COSTS

Finance revenue relates to interest earned on the Company’s bank account balances and term deposits.

Finance costs recognized in earnings were as follows:



(000s)	2016		2015
Interest expense	$	5,344	$	5,425
Amortization of deferred financing costs	724		849
Finance costs	$	6,068	$	6,274



2016		43

10. SELLING COSTS

Selling costs include transportation and marketing costs associated with the direct sale of the Company's Egyptian crude oil production to third party buyers. The Company completed three direct crude sales to a third party buyer during the year ended December 31, 2016.

11. CASH AND CASH EQUIVALENTS



(000s)	December 31, 2016		December 31, 2015
Cash	$	31,392	$	64,139
Cash equivalents	76		62,771
	$	31,468	$	126,910

As at December 31, 2016 the Company's cash equivalents balance consisted of high interest short-term deposits with an original term to maturity at purchase of three months or less. All of the Company's cash and cash equivalents are on deposit with high credit-quality financial institutions.

12. ACCOUNTS RECEIVABLE

Accounts receivable is comprised principally of amounts owed from EGPC. There were no amounts due from related parties and no loans to management or employees as at December 31, 2016 or December 31, 2015.

As at December 31, 2016, the Company was utilizing $9.7 million of its accounts receivable from EGPC as a guarantee to support work commitments on the North West Sitra concession (see Note 23).

The Company’s exposure to credit, currency and interest rate risks related to trade and other receivables is disclosed in Note 7, Financial Instruments and Risk.

13. RESTRICTED CASH

As at December 31, 2016, the Company had restricted cash of $18.3 million (December 31, 2015 - 0.9 million). In 2016, restricted cash represents a cash collateralized letter of credit facility that is used to guarantee the Company's commitments on its Egyptian exploration concessions. In 2015, restricted cash was set aside in a debt service reserve account, as required by the Borrowing Base Facility, which was terminated in December 2016.

14. PRODUCT INVENTORY

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

As at December 31, 2016, the Company held 1,265,080 barrels of entitlement oil in inventory valued at $15.49 per barrel (December 31, 2015 - 923,106 barrels valued at $18.73 per barrel).

15. INCOME TAXES

The Company’s deferred income tax assets and liabilities are as follows:



(000s)	2016			2015
Balance, beginning of year	$	3,009		$	39,050
Expenses related to the origination and reversal of temporary differences for:
Property and equipment	(13,788		)	(31,290		)
Non-capital losses carried forward	(2,936		)	(1,655		)
Long-term liabilities	(1,724		)	(2,029		)
Transactions costs	—			172
Share issue expenses	178			231
Changes in unrecognized tax benefits	15,261			(1,470		)
Balance, end of year	$	—		$	3,009

The Company has non-capital losses of $70.8 million (2015 - $62.2 million) that expire between 2027 and 2036. No deferred tax assets have been recognized in respect of these unused tax losses. The Company has an additional $18.3 million (2015 - $8.5 million) in unrecognized tax benefits arising in foreign jurisdictions.

Current income taxes represent income taxes incurred and paid under the laws of Egypt pursuant to the PSCs on the West Gharib, West Bakr and NW Gharib concessions.



2016		44

Income taxes vary from the amount that would be computed by applying the average Canadian statutory income tax rate of 27.0% (2015 – 26.0%) to income before taxes as follows:



(000s)	2016			2015
Income taxes calculated at the Canadian statutory rate	$	(20,175	)	$	(30,201	)
Increases (decreases) in income taxes resulting from:
Non-deductible expenses	3,641			1,124
Changes in unrecognized tax benefits	15,261			(1,470		)
Effect of tax rates in foreign jurisdictions¹	18,635			23,978
Changes in tax rates and other	(4,916		)	(3,989		)
Income tax expense	$	12,446		$	(10,558	)
¹ The statutory tax rates in Egypt are 40.55%.

The Company's consolidated effective income tax rate for 2016 was 16.7% (2015 - 9.1%). The Company's impairment losses in the amount of $33.4 million had a significant impact on the Company's effective income tax rate. Prior to the effect of the impairment losses, the Company's consolidated effective income tax rate for 2016 was 30.14%.

16. INTANGIBLE EXPLORATION AND EVALUATION ASSETS



(000s)
Balance at December 31, 2014	$	100,594
Additions	21,426
Balance at December 31, 2015	122,020
Additions	19,425
Transfer to petroleum and natural gas assets	(2,150		)
Impairment loss	(33,426		)
Balance at December 31, 2016	$	105,869

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 intends to relinquish its interest in South West Gharib in the first half of 2017 as no commercially viable quantities of oil have been discovered on either concession.

The Company's policy regarding the assessment of impairment for exploration and evaluation assets is disclosed in Note 3, Significant Accounting Policies.



2016		45

17. PROPERTY AND EQUIPMENT

The following table reconciles the change in TransGlobe's property and equipment assets:



	PNG			Other
(000s)	Assets			Assets		Total
Balance at December 31, 2014	$	523,833		$	13,204	$	537,037
Additions	22,723			753		23,476
Disposals	(1,005		)	—		(1,005		)
Balance at December 31, 2015	545,551			13,957		559,508
Acquisitions through business combination	59,475			—		59,475
Additions	6,618			615		7,233
Asset retirement obligations	12,099			—		12,099
Transfer from exploration and evaluation assets	2,150			—		2,150
Balance at December 31, 2016	$	625,893		$	14,572	$	640,465

Accumulated depletion, depreciation, amortization and impairment losses at December 31, 2014	$	262,096		$	7,614	$	269,710
Depletion, depreciation and amortization for the year	49,665			1,376		51,041
Impairment loss	77,193			—		77,193
Accumulated depletion, depreciation, amortization and impairment losses at December 31, 2015	388,954			8,990		397,944
Depletion, depreciation and amortization for the year	26,912			1,337		28,249
Balance at December 31, 2016	$	415,866		$	10,327	$	426,193



Net Book Value
At December 31, 2015	$	156,597	$	4,967	$	161,564
At December 31, 2016	$	210,027	$	4,245	$	214,272

The Company completed impairment tests on all of its CGUs in accordance with IAS 36 resulting in no impairment losses on its petroleum properties as at December 31, 2016.

A five percent increase in the discount rate used in the impairment assessments would result in an impairment loss of $4.3 million in Canada. A five percent decrease in the forward oil prices used in the impairment assessments would result in an impairment loss at North West Gharib of $0.3 million. Neither a five percent increase in the discount rate nor a five percent decrease in the forward price estimates used in the impairment assessments would result in an impairment loss on the West Gharib or West Bakr concessions.

The Company recorded a non-cash impairment loss on its petroleum properties of $77.2 million for the year ended December 31, 2015. The impairment loss was split between the West Gharib concession ($50.9 million), the West Bakr concession ($23.1 million) and the East Ghazalat concession ($3.2 million). At West Gharib and West Bakr, the impairment losses were recorded to reduce the carrying value of the assets to their recoverable amounts of $82.9 million and $81.9 million, respectively, which were estimated as the net present value of proved plus probable reserves, discounted at 15%. The recoverable amounts of the assets declined from prior year due to the continued decline in oil prices throughout 2015. The East Ghazalat concession was sold in October 2015, and an impairment loss was booked in Q3-2015 to reduce the carrying amount of the assets to the value being paid for the assets in the disposal transaction.

Future development costs of $139.5 million (2015 - $29.4 million) for Proved plus Probable reserves were included in the depletion calculation for the year ended December 31, 2016.

18. ASSET RETIREMENT OBLIGATION



(000s)
Balance at December 31, 2015	$	—
Acquisitions through business combination	12,089
Effect of movements in foreign exchange rates	10
Balance at December 31, 2016	$	12,099

TransGlobe has estimated the net present value of its asset retirement obligation to be $12.1 million as at December 31, 2016 (2015 - $nil) based on a total undiscounted future liability, after inflation adjustment, of $19.0 million (2015 - $nil). These payments are expected to be made between 2017 and 2066. TransGlobe calculated the present value of the obligations using discount rates between 0.74% and 2.31% to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates. The inflation rate used in determining the cash flow estimate was 2% per annum.

The Company reviews annually its estimates of the expected costs to reclaim the net interest in its wells and facilities. The resulting changes are categorized as changes in estimates for existing obligations in the preceding table.



46		2016

As at December 31, 2016, the entire asset retirement obligation balance related to the Company's Canadian operations.

19. GOODWILL

An impairment loss of $8.2 million was recognized on the Company's goodwill balance on the West Gharib CGU during the year ended December 31, 2015. This impairment loss reduced the carrying value of goodwill to zero. The after-tax cash flows used to determine the recoverable amount of the cash-generating unit to which goodwill was assigned were discounted using an estimated weighted average cost of capital of 15%.

20. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

Accounts payable and accrued liabilities are comprised of current trade payables and accrued expenses due to third parties. There were no amounts due to related parties as at December 31, 2016 or December 31, 2015.

The Company’s exposure to currency and liquidity risk related to trade and other payables is disclosed in Note 7, Financial Instruments and Risk.

21. LONG-TERM DEBT

The Company's interest-bearing loans and borrowings are measured at amortized cost.

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 Sumitomo Mitsui Banking Corporation ("SMBC"). The issued letters of credit under the bilateral letter of credit facility are secured by cash collateral which is on deposit with SMBC (Note 13). The exploration commitments are expected to be fulfilled in 2017.

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

Note Payable

On December 20, 2016, the Company closed the acquisition of certain petroleum properties in west central Alberta, Canada (Note 6). The acquisition was partially funded by a vendor take-back note of C$15.0 million ($11.2 million). The note payable has a 24-month term and bears interest at a rate of 10% per annum. Principal repayments must be made on a quarterly basis, and must be equal to or greater than 50% of the operating income of the acquired assets.

22. CONVERTIBLE DEBENTURES



(000s)
Balance at December 31, 2014	$	69,093
Fair value adjustment	6,615
Foreign exchange adjustment	(11,860		)
Balance at December 31, 2015	63,848
Fair value adjustment	7,027
Foreign exchange adjustment	1,780
Balance at December 31, 2016	$	72,655

The convertible debentures are classified as financial instruments at fair value through profit or loss, and as such are measured at fair value with changes in fair value included in earnings. Fair value is determined based on market price quotes from the exchange on which the convertible debentures are traded as at the period end date. As at December 31, 2016 the convertible debentures were trading at a price of C$99.80 for a C$100.00 par value debenture. This represents an increase of $9.40 since December 31, 2015, and as a result the Company has recognized a net expense of $7.0 million with respect to the fair value adjustment for the year ended December 31, 2016.

23. COMMITMENTS AND CONTINGENCIES

The Company is subject to certain office and equipment leases.



2016		47

on November 7, 2013. As at December 31, 2016, the Company had expended $30.0 million towards meeting that commitment. The Company received a six month extension to the initial exploration period, which now extends to May 7, 2017.

Pursuant to the PSC for South East Gharib in Egypt, the Company had a minimum financial commitment of $7.5 million and a work commitment for two wells, 200 square kilometers of 3-D seismic and 300 kilometers of 2-D seismic during the initial three-year exploration period, which commenced on November 7, 2013. The Company met its financial commitment at South East Gharib in 2016, and relinquished its interest in the concession during the fourth quarter as no commercially viable quantities of oil have been discovered.

Pursuant to the PSC for South West Gharib in Egypt, the Company has a minimum financial commitment of $10.0 million ($3.4 million remaining) and a work commitment for four wells and 200 square kilometers of 3-D seismic during the initial three-year exploration period, which commenced on November 7, 2013. The Company received a six month extension to the initial exploration period, which now extends to May 7, 2017. Since no commercially viable quantities of oil have been discovered at South West Gharib, the Company intends to relinquish its interest in the concession during the first half of 2017. As at December 31, 2016, the Company had expended $6.6 million towards meeting its financial commitment.

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

Pursuant to the PSC for North West Sitra in Egypt, the Company has a minimum financial commitment of $10.0 million ($9.7 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, 2016, the Company had expended $0.3 million towards meeting that commitment.

The Company is not aware of any material provisions or other contingent liabilities as at December 31, 2016.

24. CORPORATE DISPOSITIONS

TransGlobe GOS Inc.

On October 13, 2015 the Company completed a share purchase agreement whereby a wholly-owned subsidiary of TransGlobe disposed of 100% of the common shares of TransGlobe GOS Inc., which holds a 50% non-operated working interest in the East Ghazalat concession in Egypt. Total consideration received for TransGlobe GOS Inc. was $3.5 million, which was satisfied by cash consideration of $1.0 million and the issuance of a $2.5 million note. Due to collection uncertainty and the low oil price environment the Company did not recognize the $2.5 million note receivable as part of the disposition gain or loss calculation. In September 2016, the note and interest due were settled entirely for $0.2 million.

The total net book value of identifiable assets and liabilities sold was equal to the cash consideration paid by the acquiring Company. As a result, no gain or loss was recognized for the year ended December 31, 2015 related to the disposal. The cash consideration of $1.0 million was received immediately upon completion of the transaction. The assets and liabilities disposed of in this transaction are summarized in the table below:



	(000s)
Estimated book value of disposition:
Petroleum properties	$	1,000
Accounts receivable	2,332
Accounts payable and accrued liabilities	(2,332		)
	1,000
Proceeds from disposition:
Cash consideration	1,000
	1,000
(Gain)/Loss on corporate disposition	$	—

TG West Yemen Inc.

On October 29, 2015 the Company completed a share purchase agreement whereby a wholly-owned subsidiary of TransGlobe disposed of 100% of the common shares of TG West Yemen Inc., which holds a 25% non-operated working interest in the Block S-1 and Block 75 concessions in Yemen. The Company received cash consideration of $0.5 million immediately upon closing of the transaction. TransGlobe will receive an additional $1.5 million if Block S-1 produces hydrocarbons for a period of 90 consecutive days or 180 days in any 360 day period, or if the acquiring company directly or indirectly acquires legal or beneficial title to all or substantially all of the equity interests in Block S-1. Due to ongoing political turmoil in the region and collection uncertainty the Company did not recognize the $1.5 million contingent consideration as part of the disposition gain or loss calculation.



48		2016

The total net book value of identifiable assets and liabilities sold was less than the cash consideration received by the Company, resulting in the recognition of a loss on the disposition. The assets and liabilities disposed of in this transaction are summarized in the table below:



	(000s)
Estimated book value of disposition:
Deposits and prepaid expenses	$	750
Accounts receivable	126
	876
Proceeds from disposition:
Cash consideration	500
Working capital adjustment	124
	624
(Gain)/Loss on corporate disposition	$	252

25. SHARE CAPITAL

Authorized

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

Issued



	December 31, 2016			December 31, 2015
(000s)	Shares	Amount		Shares		Amount
Balance, beginning of year	72,206	$	152,084	75,240		$	164,006
Purchase of common shares	—	—		(3,104	)	(12,221		)
Stock options exercised	—	—		70		208
Share-based compensation on exercise	—	—		—		91
Balance, end of year	72,206	$	152,084	72,206		$	152,084

On March 25, 2015, the Toronto Stock Exchange ("TSX") accepted the Company's notice of intention to make a Normal Course Issuer Bid ("NCIB") for its common shares. Under the NCIB, the Company was permitted to acquire up to 6,207,585 common shares, which was equal to 10% of the public float. The NCIB commenced on March 31, 2015, and terminated on March 30, 2016.

During the year ended December 31, 2015, the Company repurchased a total of 3,103,792 common shares. All common shares acquired were cancelled and the cost of shares repurchased (including transaction costs) was applied directly against share capital. No common shares were repurchased during the year ended December 31, 2016.

26. SHARE-BASED PAYMENTS

The Company operates a stock option plan (the "Plan") to provide equity-settled share-based remuneration to directors, officers and employees. The number of common shares that may be issued pursuant to the exercise of options awarded under the Plan and all other Security Based Compensation Arrangements of the Company is 10% of the common shares outstanding from time to time. All incentive stock options granted under the Plan have a per-share exercise price equal to the weighted average trading price of the common shares for the five trading days prior to the date of grant. Each tranche of an award with different vesting dates is considered a separate grant for the calculation of fair value and the resulting fair value is amortized over the vesting period of the respective tranches.

The following tables summarize information about the stock options outstanding and exercisable at the dates indicated:



	2016			2015
			Weighted-			Weighted-
	Number		Average	Number		Average
	of		Exercise	of		Exercise
(000s except per share amounts)	Options		Price (C$)	Options		Price (C$)
Options outstanding, beginning of year	5,348		9.05	6,027		9.58
Granted	1,470		2.19	1,024		4.99
Exercised	—		—	(70	)	3.64
Cancelled / Forfeited	(54	)	11.84	(896	)	9.73
Expired	(718	)	12.95	(737	)	8.35
Options outstanding, end of year	6,046		6.87	5,348		9.05
Options exercisable, end of year	3,527		9.14	3,075		10.75



49		2016



	Options Outstanding			Options Exercisable
		Weighted-			Weighted-
	Number	Average	Weighted-	Number	Average	Weighted-
Exercise	Outstanding at	Remaining	Average	Exercisable at	Remaining	Average
Prices	December 31, 2016	Contractual	Exercise Price	December 31, 2016	Contractual	Exercise
(C$)	(000s)	Life (Years)	(C$)	(000s)	Life (Years)	Price (C$)
2.19 - 3.59	1,470	4.2	2.19	—	—	—
3.60 - 6.13	1,024	3.4	4.99	341	3.4	4.99
6.14 - 9.12	1,118	2.4	7.38	752	2.4	7.39
9.13 - 9.32	1,381	1.2	9.13	1,381	1.2	9.13
9.33 -15.66	1,053	0.5	11.75	1,053	0.5	11.75
	6,046	2.4	6.87	3,527	1.5	9.14

Share–based compensation

Compensation expense of $1.3 million was recorded in general and administrative expenses in the Consolidated Statements of Earnings and Comprehensive Income and Changes in Shareholders’ Equity during year ended December 31, 2016 (2015 - $2.1 million) in respect of equity-settled share-based payment transactions. The fair value of all common stock options granted is estimated on the date of grant using the lattice-based trinomial option pricing model. The weighted average fair value of options granted during the period and the assumptions used in their determination are as noted below:



	2015		2015
Weighted average fair market value per option (C$)	0.72		1.36
Risk free interest rate (%)	0.54	%	0.67	%
Expected volatility (based on actual historical volatility) (%)	49.76	%	51.39	%
Dividend rate	—	%	4.79	%
Expected forfeiture rate (non-executive employees) (%)	—	%	—	%
Suboptimal exercise factor	1.25		1.25

All options granted vest annually over a three-year period and expire five years after the grant date. During the year ended December 31, 2016, no employee stock options were exercised (2015 – 70,000). The fair value related to the options exercised in 2015 was $0.1 million at time of grant and was transferred from contributed surplus to share capital. As at December 31, 2016 and December 31, 2015, the entire balance in contributed surplus was related to previously recognized stock-based compensation expense on equity-settled stock options.

Restricted share unit, performance share unit and deferred share unit plans

In May 2014, the Company implemented a restricted share unit ("RSU") plan, a performance share unit ("PSU") plan and a deferred share unit ("DSU") plan. RSUs may be issued to directors, officers and employees of the Company, and each RSU entitles the holder to a cash payment equal to the fair market value of a TransGlobe common share on the vesting date of the RSU. All RSUs granted vest annually over a three-year period, and all must be settled within 30 days of their respective vesting dates.

PSUs are similar to RSUs, except that the number of PSUs that ultimately vest is dependent on achieving certain performance targets and objectives as set by the board of directors. Depending on performance, vested PSUs can range between 50% and 150% of the original PSU grant. All PSUs granted vest on the third anniversary of their grant date, and all must be settled within 60 days of their vesting dates.

DSUs are similar to RSUs, except that they become fully vested on the date of grant and are only issued to directors of the Company. Distributions under the DSU plan do not occur until the retirement of the DSU holder from the Company's board of directors.

The number of RSUs, PSUs and DSUs outstanding as at December 31, 2016:



	Restricted		Performance		Deferred
	Share		Share		Share
(000s)	Units		Units		Units
Units outstanding, beginning of year	545		710		270
Granted	309		691		167
Exercised	(203	)	—		—
Forfeited	(105	)	(35	)	—
Reinvested	—		—		—
Units outstanding, end of year	546		1,366		437

Compensation expense of $1.1 million was recorded in general and administrative expenses in the Consolidated Statement of Earnings and Comprehensive Income and Changes in Shareholders' Equity during the year ended December 31, 2016 in respect of share units granted under the three plans described above (2015 - $0.7 million). The expense related to the share units granted under these plans is measured at fair value using the lattice-based trinomial pricing model and is recognized over the vesting period, with a corresponding liability recognized on the Consolidated Balance Sheet. Until the liability is ultimately settled, it is re-measured at each reporting date with changes to fair value recognized in earnings.



50		2016

27. PER SHARE AMOUNTS

The weighted-average number of common shares outstanding (basic and diluted) for the year ended December 31, 2016 was 72,205,369 (2015 - 73,489,746). These outstanding share amounts were used to calculate earnings (loss) per share in the respective periods.

In determining diluted earnings per share, the Company assumes that the proceeds received from the exercise of “in-the-money” stock options are used to repurchase common shares at the average market price. In calculating the weighted-average number of diluted common shares outstanding for the year ended December 31, 2016, the Company excluded 4,576,100 stock options (2015 – 5,348,100) as their exercise price was greater than the average common share market price in the year.

The convertible debentures are dilutive in any period in which earnings per share is reduced by the effect of adjusting net earnings for the impact of the convertible debentures, and adjusting the weighted-average number of shares outstanding for the potential shares issuable on conversion of the convertible debentures.

28. DIVIDENDS

The Company suspended its quarterly dividend effective March 8, 2016. During the year ended December 31, 2015, the Company paid quarterly dividends on its common shares of $0.05 per share for the first three quarters and $0.025 per share for the fourth quarter.

29. RELATED PARTY DISCLOSURES

Details of controlled entities are as follows*:



		Ownership Interest	Ownership Interest
	Country of	2016	2015
	Incorporation	(%)	(%)
TransGlobe Petroleum International Inc.	Turks & Caicos	100	100
TG Holdings Yemen Inc.	Turks & Caicos	100	100
TransGlobe West Bakr Inc.	Turks & Caicos	100	100
TransGlobe West Gharib Inc.	Turks & Caicos	100	100
TG Holdings Egypt Inc.	Turks & Caicos	100	100
TG South Alamein Inc.	Turks & Caicos	100	100
TG South Mariut Inc.	Turks & Caicos	100	100
TG South Alamein II Inc.	Turks & Caicos	100	100
TG Energy Marketing Inc.	Turks & Caicos	100	100
TG NW Gharib Inc.	Turks & Caicos	100	100
TG SW Gharib Inc.	Turks & Caicos	100	100
TG SE Gharib Inc.	Turks & Caicos	100	100
TG S Ghazalat Inc.	Turks & Caicos	100	100
TransGlobe Petroleum Egypt Inc.	Turks & Caicos	100	100

* Includes only entities that were active as at December 31, 2016.

30. COMPENSATION OF KEY MANAGEMENT PERSONNEL

Key management personnel have been identified as the board of directors and the five executive officers of the Company.

Key management personnel remuneration consisted of the following:



(000s)	2016		2015
Salaries, incentives and short-term benefits	$	3,237	$	2,485
Share-based compensation	1,775		1,994
	$	5,012	$	4,479



2016		51

31. SEGMENTED INFORMATION

The Company has two reportable operating segments for the year-ended December 31, 2016: the Arab Republic of Egypt and Canada. The Company, through its operating segments, is engaged primarily in oil exploration, development and production and the acquisition of properties. In January 2015, the Company relinquished its interests in Block 32 (13.81% working interest) and Block 72 (20% working interest) in Yemen (effective March 31, 2015 and February 28, 2015, respectively) due to ongoing political and tribal turmoil in the vicinity of the blocks. On October 29, 2015 the Company completed a share purchase agreement whereby a wholly-owned subsidiary of TransGlobe disposed of 100% of the common shares of TG West Yemen Inc., which holds a 25% non-operated working interest in the Block S-1 and Block 75 concessions in Yemen. The Company no longer owns any interests in Yemen.

In presenting information on the basis of operating segments, segment revenue is based on the geographical location of assets which is also consistent with the location of the segment customers. Segmented assets are also based on the geographical location of the assets. There are no inter-segment sales.

The accounting policies of the operating segments are the same as the Company’s accounting policies.



	Egypt						Yemen					Canada					Total
(000s)	2016			2015			2016		2015			2016			2015		2016			2015
Revenue
Oil sales, net of royalties	$	62,634		$	91,725		$	—	$	487		$	500		$	—	$	63,134		$	92,212
Finance revenue	102			369			—		2			—			—		102			371
Total segmented revenue	62,736			92,094			—		489			500			—		63,236			92,583

Segmented expenses
Production and operating	40,054			48,041			—		4,655			269			—		40,323			52,696
Transportation costs	—			—			—		—			12			—		12			—
Selling costs	875			4,557			—		—			—			—		875			4,557
Finance costs	—			—			—		—			31			—		31			—
Depletion, depreciation and amortization	28,386			42,366			—		—			303			—		28,689			42,366
Realized derivative loss on commodity contracts	956			688			—		—			—			—		956			688
Income taxes - current	15,455			25,284			—		199			—			—		15,455			25,483
Income taxes - deferred	(3,009		)	(36,041		)	—		—			—			—		(3,009		)	(36,041		)
Impairment loss	33,426			85,373			—		—			—			—		33,426			85,373
Loss on corporate disposition	—			—			—		252			—			—		—			252
Total segmented expenses	116,143			170,268			—		5,106			615			—		116,758			175,374
Segmented earnings (loss)	$	(53,407	)	$	(78,174	)	$	—	$	(4,617	)	$	(115	)	$	—	(53,522		)	(82,791		)

Non-segmented expenses (income)
General and administrative																	17,555			21,336
Foreign exchange (gain) loss																	3,607			(11,613		)
Depreciation and amortization																	488			509
Unrealized (gain) loss on financial instruments																	7,027			6,615
Finance revenue																	(571		)	(312		)
Finance costs																	6,037			6,274
Total non-segmented expenses																	34,143			22,809

Net earnings (loss) for the year																	$	(87,665	)	$	(105,600	)

Capital expenditures
Exploration and development	$	26,658		$	44,747		$	—	$	—		$	—		$	—	$	26,658		$	44,747
Property acquisition	—			—			—		—			59,475			—		59,475			—
Corporate																	—			155
Total capital expenditures																	$	86,133		$	44,902



52		2016

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



December 31, 2016
(000s)	Egypt		Yemen		Canada		Total
Assets
Intangible exploration and evaluation assets	$	105,869	$	—	$	—	$	105,869
Property and equipment
Petroleum properties	138,757		—		71,270		210,027
Other assets	2,785		—		—		2,785
Other	35,755		—		620		36,375
Segmented assets	283,166		—		71,890		355,056
Non-segmented assets							51,086
Total assets							$	406,142

Liabilities
Accounts payable and accrued liabilities	$	14,005	$	—	$	432	$	14,437
Current and long-term note payable	—		—		11,162		11,162
Asset retirement obligation	—		—		12,099		12,099
Segmented liabilities	14,005		—		23,693		37,698
Non-segmented liabilities							83,128
Total liabilities							$	120,826



December 31, 2015
(000s)	Egypt		Yemen		Canada	Total
Assets
Intangible exploration and evaluation assets	$	122,020	$	—	—	$	122,020
Property and equipment
Petroleum properties	156,597		—		—	156,597
Other assets	3,019		—		—	3,019
Other	66,438		2,239		—	68,677
Segmented assets	348,074		2,239		—	350,313
Non-segmented assets						105,187
Total assets						$	455,500

Liabilities
Accounts payable and accrued liabilities	$	10,080	$	1,388	—	$	11,468
Deferred taxes	3,009		—		—	3,009
Segmented liabilities	13,089		1,388		—	14,477
Non-segmented liabilities						69,339
Total liabilities						$	83,816

32. SUPPLEMENTAL CASH FLOW INFORMATION

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



(000s)	2016			2015
Operating Activities
(Increase) decrease in current assets
Accounts receivable	$	8,093		$	94,646
Prepaids and other	1,159			13,925
Product inventory¹	(3,242		)	(9,122		)
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	1,286			(13,021		)
	$	7,296		$	86,428
¹ The change in non-cash working capital associated with product inventory represents the change in operating costs capitalized as product inventory in the respective periods.



2016		53



(000s)	2016		2015
Investing Activities
Increase (decrease) in current liabilities
Accounts payable and accrued liabilities	5,556		(16,000		)
	$	5,556	$	(16,000	)

33. EVENTS AFTER THE REPORTING PERIOD

On February 10, 2017, the Company completed a $75 million crude oil prepayment agreement between its wholly owned subsidiary, TransGlobe Petroleum International Inc. ("TPI") and Mercuria Energy Trading SA ("Mercuria") of Geneva, Switzerland.

The initial advance under the prepayment agreement will be used to refinance the 6.0% convertible debentures of the Company maturing on March 31, 2017 and thereafter for working capital purposes of the Company and its subsidiaries.

TPI's obligations under the prepayment agreement will be 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. This funding arrangement has a term of four years, maturing March 31, 2021 and advances bear interest at a rate of Libor plus 6.0%. The funding arrangement is revolving with each advance to be satisfied through the delivery of crude oil to Mercuria. Further advances become available upon delivery of crude oil to Mercuria up to a maximum of $75 million and subject to compliance with the other terms and conditions of the pre-payment agreement. In conjunction with the 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 indexed market prices at the time of sale.



54		2016

SUPPLEMENTARY INFORMATION

(Unaudited – Expressed in thousands of U.S. Dollars, except per share, price and volume amounts)



	Year ended December 31
Financial	2016		2015		2014		2013		2012
Oil and gas sales	122,360		187,665		513,153		635,496		633,992
Oil and gas sales, net of royalties	63,134		92,212		274,594		315,316		317,666
Production and operating expense	40,323		52,696		76,468		65,791		52,367
Transportation	12		—		—		—		—
Selling costs	875		4,557		—		—		—
General and administrative expense	17,555		21,309		29,866		27,569		28,206
Depletion, depreciation and amortization expense	29,177		42,875		51,589		49,414		46,946
Income taxes	12,446		(10,558	)	53,226		85,351		88,075
Cash flow from operating activities	(1,065	)	77,526		146,977		199,508		93,992
Funds flow from operations¹	(8,361	)	(8,902	)	120,489		139,118		153,498
Basic per share	(0.12	)	(0.12	)	1.61		1.88		2.09
Diluted per share	(0.12	)	(0.12	)	1.46		1.70		2.03
Netback²
Egypt	6,250		13,843		136,453		160,781		168,703
Yemen	—		(4,367	)	(1,366	)	(107	)	7,993
Canada	219		—		—		—		—
Net earnings (loss)	(87,665	)	(105,600	)	11,482		58,512		87,734
Net earnings (loss) - diluted	(87,665	)	(105,600	)	(1,638	)	53,036		87,734
Basic per share	(1.21	)	(1.44	)	0.15		0.79		1.20
Diluted per share	(1.21	)	(1.44	)	(0.02	)	0.65		1.16
Capital expenditures	26,658		44,902		107,539		129,170		51,651
Dividends paid	—		12,865		18,752		—		—
Dividends paid per share	—		0.175		0.25		—		—
Purchase of common shares	—		12,221		—		—		—
Acquisitions	59,475		—		—		—		27,259
Loss on corporate dispositions	—		252		—		—		—
Working capital	(16,764	)	153,835		229,687		241,969		262,217
Long-term debt (including current portion)	—		—		—		—		16,885
Note payable	11,162		—		—		—		—
Convertible debenture	72,655		63,848		69,093		87,539		98,742
Shareholders’ equity	285,316		371,684		500,100		500,190		435,860
Common shares outstanding
Basic (weighted average)	72,206		73,490		74,944		73,962		73,380
Diluted (weighted average)	72,206		73,490		82,400		81,972		75,523
Total assets	406,142		455,500		654,058		675,800		653,425
¹ Funds flow from operations is a measure that represents cash generated from operating activities before changes in non-cash working capital, and may not be comparable to measures used by other companies.
² Netback is a measure that represents revenue, net of royalties, current income taxes (paid through production sharing) and operating expenses, and may not be comparable to measures used by other companies.



Reserves	2016	2015	2014	2013	2012
Total proved (MMBoe)²	29.9	17.5	22.1	31.6	32.8
Total proved plus probable (MMBoe)²	50.0	28.7	33.5	45.3	48.7

Production and Sales Volumes
Total production (Boepd)¹	12,105	14,511	16,103	18,284	17,432
Total sales (Boepd)¹	11,165	11,977	16,161	18,193	17,496
Oil and liquids (Bopd)	11,127	11,977	16,161	18,193	17,496
Average price - oil and liquids ($ per Bbl)	30.01	42.93	86.99	95.70	99.01
Natural gas (Mcfpd)	230	—	—	—	—
Average price - natural gas ($ per Mcf)	1.81	—	—	—	—
Operating expense ($ per Boe)	9.87	12.05	12.96	9.91	8.18
¹ The differences in production and sales volumes result from inventory changes.
² As determined by the Company's independent reserves evaluator, DeGolyer and MacNaughton Canada Limited ("DeGolyer") of Calgary, Alberta, in their reports with effective dates of December 31, 2016, December 31, 2015, December 31, 2014, December 31, 2013, and December 31, 2012. The reports of DeGolyer have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time, and National Instrument 51-101.



2016		55



Share Information	2016	2015
TSX: Price per share – TSX (C$)
High	2.85	5.84
Low	1.45	2.08
Close	2.27	2.51
Average daily trading volume	86,446	188,705

NASDAQ: Price per share – NASDAQ (US$)
High	2.25	4.83
Low	1.00	1.51
Close	1.69	1.80
Average daily trading volume	110,367	235,077



56		2016

SUMMARY OF INTERNATIONAL PRODUCTION SHARING CONCESSIONS (“PSC”)

International Land (Egypt)

Summary of PSCs



EASTERN DESERT EGYPT
Block	West Gharib	West Bakr	NW Gharib	SW Gharib
Basin	Gulf of Suez	Gulf of Suez	Gulf of Suez	Gulf of Suez
Year acquired	2007	2011	2013	2013
Status	Development	Development	Exploration/Development	Exploration
Operator	TransGlobe	TransGlobe	TransGlobe	TransGlobe
TransGlobe WI (%)	100%	100%	100%	100%
Block Area (acres)	22,775	11,600	148,300	48,000
Expiry date	2019-2026	2020	Dec 2036	May 2017
Extensions
Exploration	N/A	N/A	2 + 2 years	2 + 2 years
Development	+ 5 years	+ 5 years	+ 5 years	20 + 5 years



WESTERN DESERT EGYPT
Block	South Alamein	South Ghazalat	NW Sitra
Basin	Western Desert	Western Desert	Western Desert
Year acquired	2012	2013	2015
Status	Exploration	Exploration	Exploration
Operator	TransGlobe	TransGlobe	TransGlobe
TransGlobe WI (%)	100%	100%	100%
Block Area (acres)	197,000	349,302	480,850
Expiry date	May 2018¹	November 2018	July 2018
Extensions
Exploration	N/A	2 years	3.5 years
Development	20 + 5 years	20 + 5 years	20 + 5 years
¹ The Company received military approval to access South Alamein on September 8, 2016 and will have approximately 20 months until expiry.

Summary of PSC Terms

All of the Company’s international blocks are production sharing contracts between the host Government and the Contractor (joint interest partners). The Government and the Contractor take their share of production based on the terms and conditions of the respective contracts. The Contractor's share of all taxes and royalties are paid out of the Government's share of production.

The PSCs provide for the Government to receive a percentage gross royalty on the gross production. The remaining oil production, after deducting the gross royalty, is split between cost sharing oil and production sharing oil. Cost sharing oil is up to a maximum percentage as defined in the specific PSC. Cost oil is assigned to recover approved operating and capital costs spent on the specific project. Unutilized cost sharing oil or excess cost oil (maximum cost recovery less actual cost recovery) is shared between the Government and the Contractor as defined in the specific PSCs. Each PSC is ring fenced for cost recovery and production sharing purposes. The remaining production sharing oil (total production, less gross royalty, less cost oil) is shared between the Government and the Contractor as defined in the specific PSCs.

The following tables summarize the Company’s international PSC terms for the first production tranche for each block. All the PSCs have different terms for production levels above the first tranche, which are unique to each PSC. The Government’s share of production increases and the Contractor’s share of production decreases as the production volumes go to the next production tranche.



2016		57

PSC Terms



EASTERN DESERT EGYPT
Block	West Gharib	West Bakr	NW Gharib	SW Gharib
Production Tranche (MBopd)	0-5 / 5-10	0-50	0-5	0-5

Max. cost oil	30%	30%	25%	25%
Excess cost oil
Contractor	30%	0%	5%	5%
Depreciation per quarter
Operating	100%	100%	100%	100%
Capital	6.25%	5%	5%	5%
Production Sharing Oil:
Contractor	30% / 27.5%	15%	15%	15%

Government	70% / 72.5%	85%	85%	85%



WESTERN DESERT EGYPT
Block	South Alamein	S Ghazalat	NW Sitra
Production Tranche (MBopd)	0-5	0-5	0-5

Max. cost oil	30%	25%	28%
Excess cost oil
Contractor	0%	5%	10%
Depreciation per quarter
Operating	100%	100%	100%
Capital	5%	5%	5%
Production Sharing Oil:
Contractor	14%	17%	24%

Government	86%	83%	76%

RESERVES AND ESTIMATED FUTURE NET REVENUES

DeGolyer and MacNaughton Canada Limited (“DeGolyer”) of Calgary, Alberta, independent petroleum engineering consultants based in Calgary and part of the DeGolyer and MacNaughton Worldwide Petroleum Consulting group headquartered in Dallas, Texas, were retained by the Company’s Reserve Committee to independently evaluate 100% of TransGlobe’s reserves as at December 31, 2016 and December 31, 2015.

The reserves data set forth below was prepared by DeGolyer with an effective date of December 31, 2016 and December 31, 2015, respectively. The reserves data summarizes the crude oil reserves of the Company and the net present values of future net revenue for these reserves using forecast prices and costs and constant prices and costs. The Company reports in U.S. currency and therefore the reports have been stated in U.S. dollars. The reports of DeGolyer have been prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society), as amended from time to time (the "COGE Handbook") and the reserve definitions contained in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and the COGE Handbook.

Total Proved reserves for the Company increased 71% from 17.5 million barrels of oil (“MMBbl”) at December 31, 2015 to 29.9 MMBbl at December 31, 2016; 4.4 MMBoe of oil and gas were produced during 2016.

Total Proved plus Probable reserves for the Company increased by 74% from 28.7 MMBbl at December 31, 2015 to 50.0 MMBbl at December 31, 2016.

The Company’s Reserves, Health Safety, Environment and Social Responsibility Committee, comprised of independent directors, has reviewed and recommended to the Board of Directors acceptance of the 2016 and 2015 year-end reserve evaluations prepared by DeGolyer, which were approved respectively.



58		2016

In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of crude oil, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, among others, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves may vary and such variations may be material. The actual production, revenues, taxes and development and operating expenditures with respect to the reserves associated with the Company's properties may vary from the information presented herein and such variations could be material. In addition, there is no assurance that the forecast price and cost assumptions contained in the reports prepared by DeGolyer will be attained and variances could be material.

The recovery and reserve estimates of crude oil reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil may be greater than, or less than, the estimates provided herein. Note that columns may not add due to rounding.

The information relating to the Company's reserves contains forward-looking statements relating to future net revenues, forecast capital expenditures, future development plans and costs related thereto, forecast operating costs and anticipated production. See "Reader Advisories - Forward-Looking Statements".

Possible reserves are those additional reserves that are less certain to be recovered than probable resources. There is a 10% probability that the quantities actually received will equal or exceed the sum of proved plus probable plus possible reserves.

All reserves (gross and net) presented are based on Forecast Pricing.

Reserves



	2016										2015
	Light & Medium				Conventional		Natural
	Crude Oil		Heavy Oil		Natural Gas		Gas Liquids		Total Boe		Total Bbl
Company	Gross¹	Net²	Gross¹	Net²	Gross	Net	Gross	Net	Gross¹	Net²	Gross¹	Net²
By Category	(MBbls)	(MBbls)	(MBbls)	(MBbls)	(MMcf)	(MMcf)	(MBbls)	(MBbls)	(MBoe)	(MBoe)	(MBbls)	(MBbls)
Proved
Developed
producing	3,353	2,500	11,334	6,233	14,892	11,833	2,324	1,709	19,493	12,414	12,351	7,036
Developed non-
producing	876	581	1,240	654	254	217	29	23	2,187	1,294	1,831	987
Undeveloped	2,020	1,643	3,026	1,616	8,981	7,897	1,717	1,499	8,260	6,074	3,350	1,683
Total Proved	6,249	4,724	15,600	8,503	24,127	19,947	4,070	3,231	29,940	19,782	17,532	9,706
Probable	3,497	2,576	9,135	4,825	21,784	18,778	3,796	3,134	20,059	13,665	11,214	6,179
Proved plus Probable	9,746	7,300	24,735	13,328	45,911	38,725	7,866	6,365	49,999	33,447	28,746	15,885
Possible	2,607	1,855	9,299	4,671	11,414	9,366	2,050	1,568	15,858	9,655	11,133	5,865
Proved plus Probable plus Possible	12,353	9,155	34,034	17,999	57,325	48,091	9,916	7,933	65,857	43,102	39,879	21,750
¹ Gross reserves are the Company's working interest share before the deduction of royalties
² Net reserves are the Company's working interest share after the deduction of royalties. Net reserves in Egypt include the Company’s share of future cost recovery and production sharing oil after the Government's royalty interest but before reserves relating to income taxes payable. Under this method, a portion of the reported reserves will increase as oil prices decrease (and vice versa) as the barrels necessary to achieve cost recovery change with prevailing oil prices.



2016		59



	2016										2015
	Light & Medium				Conventional		Natural
	Crude Oil		Heavy Oil		Natural Gas		Gas Liquids		Total Boe		Total Bbl
Company	Gross¹	Net²	Gross¹	Net²	Gross	Net	Gross	Net	Gross¹	Net²	Gross¹	Net²
By Area	(MBbls)	(MBbls)	(MBbls)	(MBbls)	(MMcf)	(MMcf)	(MBbls)	(MBbls)	(MBoe)	(MBoe)	(MBbls)	(MBbls)
Proved
Canada	3,576	2,982	—	—	24,127	19,947	4,070	3,231	11,667	9,537	—	—
Egypt	2,673	1,742	15,600	8,503	—	—	—	—	18,273	10,245	17,532	9,706
Total Proved	6,249	4,724	15,600	8,503	24,127	19,947	4,070	3,231	29,940	19,782	17,532	9,706
Proved plus Probable
Canada	1,650	1,374	—	—	21,784	18,778	3,796	3,134	9,077	7,638	—	—
Egypt	1,847	1,202	9,135	4,825	—	—	—	—	10,982	6,027	11,214	6,179
Total Proved plus Probable	9,746	7,300	24,735	13,328	45,911	38,725	7,866	6,365	49,999	33,447	28,746	15,885
Proved plus Probable plus Possible
Canada	1,169	923	—	—	11,414	9,366	2,050	1,568	5,121	4,052	—	—
Egypt	1,438	932	9,299	4,671	—	—	—	—	10,737	5,603	11,133	5,865
Total Proved plus Probable plus Possible	12,353	9,155	34,034	17,999	57,325	48,091	9,916	7,933	65,857	43,102	39,879	21,750
¹ Gross reserves are the Company's working interest share before the deduction of royalties
² Net reserves are the Company's working interest share after the deduction of royalties. Net reserves in Egypt include the Company’s share of future cost recovery and production sharing oil after the Government's royalty interest but before reserves relating to income taxes payable. Under this method, a portion of the reported reserves will increase as oil prices decrease (and vice versa) as the barrels necessary to achieve cost recovery change with prevailing oil prices.

Estimated Future Net Revenues

All evaluations and reviews of future net cash flow are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of the Company’s properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGL and natural gas reserves may be greater than or less than the estimates provided herein.

The estimated future net revenues presented below are calculated using the independent engineering evaluator’s price forecast.



	Present Value of Future Net Revenues, After Income Tax
	Independent Evaluator’s Price Forecast
	December 31, 2016					December 31, 2015
	Discounted at					Discounted at
	Undis-					Undis-
($USMM)	counted	5%	10%	15%	20%	counted	5%	10%	15%	20%
Proved
Canada	118.4	75.3	52.2	38.5	29.7	—	—	—	—	—
Egypt	207.6	181.1	160.5	144.2	130.9	143.9	122.1	105.6	92.7	82.5
Proved	326.0	256.4	212.8	182.7	160.6	143.9	122.1	105.6	92.7	82.5
Proved plus Probable
Canada	207.2	120.0	78.2	54.8	40.4	—	—	—	—	—
Egypt	372.1	307.3	260.2	225.0	197.8	289.9	234.5	194.7	165.2	142.8
Proved plus Probable	579.4	427.3	338.4	279.8	238.2	289.9	234.5	194.7	165.2	142.8
Proved plus Probable plus Possible
Canada	300.3	157.3	99.8	69.9	51.9	—	—	—	—	—
Egypt	521.9	408.7	333.2	280.2	241.4	426.4	330.4	265.7	220.1	186.6
Proved plus Probable plus Possible	822.1	566.0	433.0	350.1	293.3	426.4	330.4	265.7	220.1	186.6

The following table summarizes the independent evaluator’s price forecast after adjustments for differentials used to estimate future net revenues.



60		2016



	Egypt²		Canada²
	Oil		Oil		Gas		Condensate		Butane		Propane		Ethane
Year	$US/Bbl		$US/Bbl		$US/Mcf		$US/Bbl		$US/Bbl		$US/Bbl		$US/Bbl
2017	44.86		49.28		2.52		51.66		29.82		15.81		7.64
2018	48.99		51.88		2.27		54.44		33.22		16.74		8.03
2019	53.26		53.69		2.35		55.48		33.47		17.00		8.31
2020	58.79		56.77		2.49		58.61		35.46		18.01		8.77
2021	62.37		57.97		2.57		60.78		37.41		18.86		8.95
Thereafter (%)¹	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%	2.0	%
¹ Percentage change represents the increase in each year after 2021 to the end of the reserve life.
² DeGolyer and MacNaughton Canada Limited (“DeGolyer”) price forecasts, effective December 31, 2016.

The estimated future net revenues presented below are calculated using the average price received as of December 31 of the respective reporting periods. The prices were held constant for the life of the reserves.



	Present Value of Future Net Revenues, After Income Tax
	Constant Pricing
	December 31, 2016						December 31, 2015
	Discounted at						Discounted at
	Undis-						Undis-
($USMM)	counted	5%	10%	15%	20%		counted	5%	10%	15%	20%
Proved
Canada	15.4	12.2	9.1	6.6	4.8		—	—	—	—	—
Egypt	56.1	51.7	48.0	45.0	42.3		81.2	73.6	67.3	62.1	57.7
Total Proved	71.4	63.9	57.1	51.6	47.1		81.2	73.6	67.3	62.1	57.7
Proved plus Probable
Canada	35.8	22.6	15.0	10.3	7.0		—	—	—	—	—
Egypt	95.7	84.0	74.8	67.4	61.3		146.2	127.7	113.2	101.6	92.2
Total Proved plus Probable	131.4	106.6	89.8	77.6	68.4		146.2	127.7	113.2	101.6	92.2
Proved plus Probable plus Possible
Canada	66.2	28.3	12.2	3.9	(0.8	)	—	—	—	—	—
Egypt	131.3	111.2	96.2	84.7	75.6		208.8	176.3	152.0	133.4	118.9
Total Proved plus Probable plus Possible	197.4	139.5	108.3	88.5	74.8		208.8	176.3	152.0	133.4	118.9

The following table summarizes the constant pricing used to estimate future net revenues.



	Egypt¹	Canada¹
	Oil	Oil	Gas	Condensate	Butane	Propane	Ethane
Year	$US/Bbl	$US/Bbl	$US/Mcf	$US/Bbl	$US/Bbl	$US/Bbl	$US/Bbl
2016	32.78	37.08	1.54	39.02	19.87	5.19	5.81
2015	44.37	—	—	—	—	—	—
¹ The constant price case is based on the average of the reference price received on the first day of each month during the respective year adjusted for respective differentials.



2016		61