TRANSGLOBE ENERGY CORPORATE PRESENTATION MARCH 2017 TSX:TGL/NASDAQ:TGA

Transcription

1 TRANSGLOBE ENERGY CORPORATE PRESENTATION MARCH 2017 TSX:TGL/NASDAQ:TGA

2 CAUTIONARY STATEMENT The information provided in this presentation is provided as of January 31, 2017 for informational purposes only, is not complete, is based (in part) on information prepared for internal evaluation purposes and may not contain certain material information about TransGlobe Energy Corporation ("TransGlobe", "TGL" or the "Company"), including important disclosures and risk factors associated with the information disclosed in this presentation. This presentation does not constitute an offer to sell or a solicitation of an offer to buy any security in Canada, the United States or any other jurisdiction. The content of this presentation has not been approved or disapproved by any securities commission or regulatory authority in Canada, the United States or any other jurisdiction, and TransGlobe expressly disclaims any duty to make disclosure or any filings with any securities commission or regulatory authority, beyond that imposed by applicable laws. See "Cautionary Statements" beginning on slide 21 for other important disclosures regarding forward looking information, future orientated financial information and other financial matters, oil and gas information and other important information. 2

3 ABOUT TRANSGLOBE Over 20 years of history as an International Oil and Gas Company Strong track record with proven abilities in development drilling and reservoir management Operations in Egypt began in 2004 Averaged 14,000 Bopd in January MMbl 2P Gross Reserves (18.3 MMbl 1P Gross) (12/31/16) 1 Re-entry to Canada in December 2016 Averaged 2,800 Boed in January MMboe 2P Gross Reserves (9.0 MMboe 1P Gross) (12/31/16) 1 Diversified portfolio of development and exploration opportunities Focused on building a diversified, profitable and growth oriented portfolio 1. Based on D&M evaluation effective 12/31/16. See Cautionary Statements "Oil and Gas Information". 3 Drilled over 400 gross wells in Canada, Egypt and Yemen over past 20 years Produced over 50 million WI barrels equivalent during past 20 years in Canada, Egypt and Yemen Sold ~1,500 Boed of W. Canada production in 2007 for C$57 million Extensive development (Canada and Egypt) and exploration portfolio (Egypt) Management focus is on cash flow and building shareholder value over the long term

4 VALUE PROPOSITION AND GO-FORWARD PLAN 2 Very attractive valuation, with 2P reserves (NPV10) of $346MM¹ or ~$4.79/share Diversified and growing production base - >17,000 boe/d guidance mid-point Q re-financing of Convertible Debentures High working interest, oil-focused operated assets torqued to commodity price recovery Egypt Canada Near Term Catalysts (2017) WB K Field development/acceleration WG Red Bed acceleration NWG exploration/development (15 wells) SA (Boraq) appraisal/development Medium Term Catalysts (2018+) WB acceleration NWG full development Western Desert exploration in SA, NWS and SG 4 Near Term Catalysts (2017) Cash flow and growth of Canadian Assets Initial drilling of up to 8 horizontal oil wells Additional acquisitions Medium Term Catalysts (2018+) Expand Cardium resource footprint through synergistic acquisitions Ramp-up Cardium HZ drilling program Unlock and develop Ellerslie HZ potential Focused on building a diversified, profitable and growth oriented International Portfolio 1. Based on D&M evaluation effective 12/31/ See Cautionary Statements "Forward-Looking Statements and Information".

5 BALANCE SHEET SUMMARY TransGlobe has a strong balance sheet with net cash position of Dec 31, 2016 Simple capital structure Convertible bond of US$75MM to be refinanced with proceeds from Prepayment Agreement (interest of ~6.75%) Shares Outstanding (31/12/16) ~72.2 Market Capitalization (10/02/17) Debt (CD +VTB) 1 Working Capital (est 31/12/16) 2, 3, 5 US$62 Enterprise Value 4 1. Estimated US$ value of Convertible Debenture of US$75MM and $11MM for vendor take back loan 2. Current Assets (including cash and cash equivalents) minus Current Liabilities (including convertible bond) 3. Working capital estimate for 31/12/16 excludes any fair value increment over cost of `1.25 MM barrels of crude oil entitlement held in inventory 4. Enterprise value calculated as Market Capitalization + Long term debt Working capital (Current Assets - Current Liabilities) 5. See Cautionary Statements "Forward-Looking Statements and Information" 5 Closed acquisition of Canadian assets on December 20, 2016 MM C$ US$ 1 Purchase Price Financing Cash Vendor Take Back Note Based on Bank of Canada noon exchange rate on December 20, 2016 of US$1.00= C$ Subject to customary purchase price adjustments 3. Vendor take back note bears interest at 10% per annum and is repayable over a maximum of 24 month term MM US$130 US$86 USD$154

6 2016 FINANCIAL HIGHLIGHTS Sales volumes averaged 11,165 boepd in 2016 and 7,305 boepd in Q4 Production volumes averaged 12,105 boepd in 2016 and 13,148 boepd in Q4 Inventory at end of year was 1,265,080 barrels of Egypt entitlement oil $87.7 million net loss ($1.21/share-diluted) in 2016 which includes $33.4 million non-cash impairment loss on the Company s exploration and evaluation assets Negative Funds Flow of $8.4 million ($0.12/share-diluted) in 2016 Decreased Operating and G&A expenses Operating expenses decreased 23% compared with 2015 (18% decrease on a per bbl basis) Gross G&A expenses (including capitalized G&A) decreased by 24% compared with 2015 (18% decrease on a per bbl basis) $49.8 million in cash and cash equivalents (inclusive of restricted cash) $16.8 million in working capital deficiency (includes convertible debentures of $72.2 million) Acquired producing oil and gas assets in Canada for total consideration of $59.5 million 6

7 NEW PREPAYMENT AGREEMENT Feb 10/17 Announced US$75MM Prepayment Agreement & Marketing Agreement with Mercuria a world leading commodities group Proceeds to be used to redeem maturing Convertible Debentures by March 31/17 1 Prepayment Agreement interest cost of ~6.75% Dedicated 9MM barrels of Egypt production to be marketed by Mercuria 1 Sales price at market rates Mercuria marketing fee dependent on achieved sales price 1. See Cautionary Statements "Forward-Looking Information and Statements". 7

8 2017 OPERATIONAL PLAN Capital $MM Firm EGYPT Complete Eastern Desert Exploration program Appraise/Develop 2016 discoveries adjacent to NWG 3/38 development lease (NWG 3/38 development lease approved December 2016 with first production prior to 1,000 Bopd from NWG 3) West Bakr and West Gharib optimization and infill/ development drilling opportunities Re-entry and test of Boraq 2 discovery and drill offset appraisal well evaluating Boraq ridge in South Alamein Acquire 600 Km 2 of 3D seismic at NW Sitra in Western Desert CANADA Integration and optimization of Harmattan operations Execute 2H-2017 Cardium oil drilling program consisting of 4 to 8 horizontal (multi-stage frac) wells Develop multi-year development plans representing stable and predictable production growth 8 Firm & Contingent Canada $9.4 $16.2 Egypt $25.8 $40.2 Total $35.2 $56.4 Wells Canada 4 8 Egypt 9 18 Total See Cautionary Statements "Forward Looking Information and Statements" and "FOFI and Other Financial Measures".

9 Production (boepd) DAILY PRODUCTION 1 20,000 TRANSGLOBE TOTAL DAILY ,000 10,000 Canada 5,000 NWG West Bakr West Gharib 0 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 DEC 2016 Q EST JAN 2017 YTD 2017 GUIDANCE 1 Egypt ~13,074 Bopd ~12,790 Bopd ~14,013 Bopd ~ MBopd Canada ~1,066* Boepd ~365* Boepd ~2,804 Boepd ~ MBoepd Total Company ~14,140 Boepd ~13,155 Boepd ~16,817 Boepd ~ MBoepd * Canadian production from December 21 st, 2016 with 6 Mcf to 1 Boe 1. See Cautionary Statements "Forward-Looking Information and Statements" and "Oil and Gas Information". 9

10 2016 YEAR-END RESERVES SUMMARY Reserves Summary 1P 2P 3P 2015 Year End Reserves (MMbbl) Adds/Revisions Canadian Acquisition (MMBoe) Production (4.4) 2016 Year End Reserves (MMBoe) Change vs Year End 2015 (%) 71% 74% 65% Production Replacement Ratio (%) pre acquisition Year End Reserves (mmbbl) 2016 Year End Reserves (mmbbl) 116% 114% 105% 1P 2P 3P Reserve Category Total proved plus probable ( 2P ) gross reserves increased 74% from year-end 2015 to 50.0 MMboe noting the following: Canadian acquisition added 20.7 MMboe of gross 2P reserves net of production including 46 BCF 2P of conventional natural gas Positive technical additions of 5.0 MMbbls of gross 2P reserves primarily attributed to the Arta Red Bed pool performance/simulation results and performance at West Gharib, West Bakr Replaced 114% of 2016 production (~4.4 MMboe), pre Canadian acquisition At year-end 2016, 2P reserves were comprised of 59% Egypt medium/ heavy oil, 15% Canada conventional natural gas, 16% Canada natural gas liquids and 10% Canada light oil 1. Based on D&M evaluations effective 12/31/15 and 12/31/16. See Cautionary Statements "Oil and Gas Information". 2. 6:1 BOE MCF. 10

11 CANADA: CORNERSTONE ACQUISITION Acquired Canadian Cardium Light Oil and Liquids-Rich Gas Production Dec 20 th, 2016 Stable geopolitical environment with favourable tax structure and attractive royalty regime Purchase price of C$80 Million (~US$60 Million) September 2016 average production of ~3,100 Boepd (57% oil and NGLs) Acquisition metrics C$25,806/Boed Acquisition Adds Low-Risk Development Upside Well defined Cardium drilling locations provide for significant production and cash flow growth for the foreseeable future Access to surplus infrastructure capacity to accommodate production growth Current asset decline rate of ~12% provides stable production platform 149 gross potential drilling opportunities identified on acquired assets (49 booked, 100 unbooked) 2 Significant liquids-rich Ellerslie gas opportunity exists on acquired lands Acquisition Adds Material Reserves and Significantly Increases Reserve Life and NAV Identifiable growth supported by offsetting production in proven plays Gross 2P Reserves of 20.7 Mmboe 1 Reserve life index of 18.3 years 1 After Tax 2P NPV10 of US$78.2MM 1 Acquisition metrics C$3.76/2P Boe Well Positioned to Grow Current post transaction corporate production over ~16,817 boepd (Jan/17), and extensive inventory of low-risk development growth in Canada and Egypt, plus high-impact exploration in Egypt High working interest in largely operated assets Scalable growth in a rising commodity price environment 1. See Cautionary Statements Oil and Gas Information. All reserves and net present value estimates in respect of the Harmattan assets based on D&M evaluation effective 12/31/16 2. Booked drilling locations based on D&M evaluation effective 12/31/16. Potential unbooked drilling opportunities based on TransGlobe internal estimate prepared in accordance with the COGE Handbook by a nonindependent qualified reserves evaluator. See Cautionary Statements "Oil and Gas Information". 11

12 Working Interest Production (boe/d) Producing Well Count TRANSGLOBE CANADIAN ASSET PORTFOLIO Canadian Lands Historic Production 7,000 6,000 5,000 4,000 3,000 2,000 1, Land Position: >95,000 net acres (>110,000 gross acres) Production: 2,800 Boepd 1 (Jan/17) (57% liquids-weighted) 2P Reserves: 20.7 MMBoe 2 (41% liquids-weighted) Producing Gross Locations 4 Wells Boepd 2P Unbooked Cardium Ellerslie/Mannville 61 1, Other Total 120* *Of which 82 are HZ wells 1. Average production for January See Cautionary Statements Oil and Gas Information ; All reserves and net present value estimates in respect of the Canadian acquisition based on D&M evaluation effective 12/31/ See Cautionary Statements "Forward-Looking Information and Statements". 4. Booked drilling locations based on D&M evaluation effective 12/31/16. Potential unbookeddrilling opportunities based on TransGlobe internal estimate prepared in accordance with the COGE Handbook by a non-independentqualified reserves evaluator. See Cautionary Statements "Oil and Gas Information" Q Q2 Oil (bbl/d) Q Q Q1 Natural Gas Liquids (bbl/d) Q Q Q Q1 Gas (boe/d) Q Q3 - Q4 Producing Well Count (Gross) Zero wells drilled on acquired lands over past 3 years Last Cardium HZ drilled in 2013 Existing production declining at ~12% in 2016 Production can be increased materially through development of existing locations 3 0

13 CARDIUM PRIMER The prolific Cardium formation has produced hydrocarbons in central Alberta for over 60 years; and is one of the most prolific hydrocarbon resource deposits in the Western Canada Sedimentary Basin Although conventionally produced since the 1950 s recent advances in horizontal drilling and multi-stage fracking have allowed producers to drill economic wells in increasingly tighter portions of the play In areas where the Cardium is developed it is often found stacked with multiple other potentially producible formations such as the Viking and Ellerslie There are currently ~10,000 producing wells (of which ~3,900 are horizontal wells) September total 1 Cardium production in Alberta was ~207,289 boep/d (not including NGL yields) 71,295 bbl/d oil 136 Mmcf/d gas Wells depths in the range of 2,000 to 2,300 metres Approximate location of acquired lands West Central Alberta Stratigraphic Chart with highlighted target formations present on acquired lands. Additional potential and production from the deeper Elkton and Wabamun 1. Production estimates for the month of September, 2016 based on Accumap data. Values reported are raw production and values and do not include Natural Gas Liquid yields or associated Natural Gas shrinkage. 13

14 CARDIUM LOCATIONS HARMATTAN CORE AREA 39 Cardium (mile-long) HZ wells on TransGlobe lands 36 drilled in Average fracs = 18 per well Industry standard is now 30 per well 17 Proved 1 locations, 5 1 probable locations assigned Future drilling, with improved frac density and technology may unlock additional bookable locations 8 Cardium HZ wells planned for 2H See Cautionary Statements Oil and Gas Information ; Booked drilling locations based on D&M 12/31/2016 evaluation. 14

15 Daily Barrels of Oil Equivalent (boe/d) Daily Barrels of Oil Equivalent (boe/d) CANADA TYPE CURVE ECONOMICS C$ Harmattan - Cardium Capex (mm) $2.7 Reserves (mbbl) 190 IP90 (boe/d) 164 IP365 (boe/d) 113 Yr1 Cap. Eff. (/boed) $28, Harmattan - Ellerslie Capex (mm) $3.2 Reserves (mbbl) 416 IP90 (boe/d) 595 IP365 (boe/d) 381 Yr1 Cap. Eff. (/boed) $8, Month Month WTI Harmattan Type Curve Economics Cardium 1 Fx (USD/CAD) Realized Price (Cdn/bbl) Aeco Gas Price (Cdn/mmbtu) Payout (yrs) IRR (%) NPV10 ($mm) F&D (/boe) Recycle ratio (x) $45.00 $0.76 $50.95 $ % 0.4 $ $50.00 $0.78 $55.97 $ % 1.1 $ $55.00 $0.80 $60.75 $ % 1.5 $ $60.00 $0.82 $65.29 $ % 1.9 $ WTI Harmattan Type Curve Economics Ellerslie 1 Realized Fx Price (USD/CAD) (Cdn/bbl) Aeco Gas Price (Cdn/mmbtu) Payout (yrs) IRR (%) NPV10 ($mm) F&D (/boe) Recycle ratio (x) $45.00 $0.76 $50.95 $ % 0.1 $ $50.00 $0.78 $55.97 $ % 0.7 $ $55.00 $0.80 $60.75 $ % 1.3 $ $60.00 $0.82 $65.29 $ % 1.8 $ Based on TransGlobe internal estimate prepared in accordance with NI guidelines and the COGE Handbook by a non-independent qualified reserves evaluator 15

16 INVESTMENT HIGHLIGHTS - EGYPT 1.3 Million gross acres of land 7 PSCs in Egypt (100% WI) Producing >14,000 Bopd Gross 2P reserves of 29.3 mmbbl (12/31/16) 1 AT NPV10 of 2P reserves of $260.2 million 1 New developments in NWG 2017 Exploration & Development focus In Eastern Desert, complete NWG exploration program and develop NWG discoveries In Western Desert, acquire 600km 2 3-D seismic in North West Sitra, develop South Alamein Boraq discovery South Alamein (100%) Exploration & Development Near Term Potential NW Sitra (100%) Exploration South Ghazalat (100%) Exploration CAIRO West Bakr (100%) SW Gharib (100%) NW Gharib (100%) Appraisal Development Growth Underway West Gharib (100%) 1. See Cautionary Statements Oil and Gas Information ; Based on D&M evaluation effective 12/21/16. 16

17 WEST GHARIB/WEST BAKR/NWG: 100% WI - OPERATED Eastern Desert Production December average rate 13,074 Bopd January average rate 14,023 Bopd with the addition of NWG 3/38 development lease production 2017 Plan 1 Develop/appraise NWG discoveries Arta Red Bed infill development production online 1Q-2017 Advance K-South development and evaluate additional optimization opportunities in West Bakr Integrate NW Gharib operations into established Joint Venture leveraging operating best practices and utilizing existing infrastructure 1. See Cautionary Statements "Forward-Looking Information and Statements" 17

18 NW GHARIB EXPLORATION & DEVELOPMENT Nukhul Structure Map (CI=50 ft) Phase Name Status IP (BOPD) Inventory locations 1 NWG-3_16 Producing Discovery 1000 (NWG-3X) 7 2 NWG-38 Producing Discovery NWG-27 Discovery drilling appraisal well 7 4 NWG-26 Discovery 3 5 Exploration 3 Firm locations 15 First oil production from NWG 3 ~1,000 Bopd flowing Dec/16 NWG-27A oil discovery in Red Bed (23 API) conglomerates and sands NWG-38A oil discovery in Red Bed (21.8 API) sandy conglomerate, 750 Bopd Feb/2017 NWG-26ST oil discovery in the Red Bed conglomerates 18

19 Daily Barrels of Oil (bbl/d) EGYPT NWG TYPE CURVE ECONOMICS US$ 900 Egypt - Red Bed Month Egypt Type Curve Economics - Red Bed 1,2 Capex (mm) $0.7 Reserves (mbbl) 800 IP90 (bbl/d) 759 IP365 (bbl/d) 672 Yr1 Cap. Eff. ($/Bpd) $1,041 Brent 3 ($/bbl) Realized Price (USD/bbl) Payout (yrs) IRR (%) NPV10 ($mm) F&D (/bbl) Recycle ratio (x) $45.00 $ % 3.1 $ $50.00 $ % 4.3 $ $55.00 $ % 5.4 $ $60.00 $ > $ Based on TransGlobe internal estimate prepared in accordance with NI guidelines and the COGE Handbook by a non-independent qualified reserves evaluator 2. Assumes use of sunk cost pools 3. Escalated by 2.0% per year 19

20 EGYPT ASSETS: WESTERN DESERT Three operated 100% WI concessions (1.03 million acres) Map & evaluate the South Ghazalat 3-D (400 km 2 ) NW Sitra 3-D seismic acquisition program in early 2017 (600 km 2 ) 1 Finalize prospect inventory for 2017/18 NWS, S. Ghazalat and S. Alamein S. Alamein access approvals granted, initial Boraq area drilling in See Cautionary Statements "Forward-Looking Statements and Information". 20

21 SOUTH ALAMEIN WESTERN DESERT Acquired 2012 with Boraq discovery (included ~$80 million of cost pools), suspended in 2014 pending resolution of access Military access approval received September 2016, ending the suspension of this concession (20 month access period) The Boraq ridge contains discovered light oil (Boraq 2) in 2 zones, and could contain significant oil volume that will be tested with 3 of the anticipated drilling permits. Boraq 2 tested a total of ~1,600 Bopd of light oil from 2 zones Drill Boraq 5 and re-enter Boraq 2 in Q2 Targeting Exploration drilling in late 17 early 18 - multiple prospects defined 1. Boraq 2X discovery tested approximately 1,600 Bopd from two zones. The primary Cretaceous zone tested at a rate of 800 to 1,323 Bopd of 34 API oil with no water and a 13% pressure drawdown during a 28 hour drill stem test (DST). A secondary Cretaceous zone tested at a rate of 274 Bopd of API oil and 4% water during a 23 hour DST. Test rates are not necessarily indicative of long-term performance but it is anticipated that the well should be capable of producing approximately 1,600 Bopd. 21

22 CAUTIONARY STATEMENTS Forward-Looking Information and Statements Certain information regarding TransGlobe set forth in this document contains forward-looking information or statements (collectively, "forward-looking statements") that involve substantial known and unknown risks and uncertainties. The use of any of the words "plan", "expect", prospective, "project", "intend", "believe", "should", "anticipate", "estimate" or other similar words, or statements that certain events or conditions "may" or "will" occur are intended to identify forward-looking statements. Such statements represent TransGlobe's internal projections, estimates or beliefs concerning, among other things, future growth, commodity price forecasts, diversification, results of operations, reserves (including estimated recoveries), plans for and results of drilling activities, production, future capital and other expenditures, business prospects and opportunities and other matters. These statements are only predictions and actual events or results may differ materially. Although the Company s management believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause TransGlobe's actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, TransGlobe. In particular, forward-looking statements contained in this document include, but are not limited to plans for and results of the prepayment agreement and repayment of the convertible debentures; terms of the prepayment agreement and marketing agreement; anticipated drilling and completion plans; exploration and development activities and estimated costs of the foregoing; 2017 production; TransGlobe's plans for future acquisitions; potential results and production from future developments; capital expenditure estimates; reserves estimates (including estimated recoveries); the anticipated benefits of third party processing arrangements; anticipated trends in drilling and completion costs and related savings; expected reduction of geological risk exposure; anticipated decline rates and the resulting benefits; and realization of the anticipated benefits of diversification. Statements relating to "reserves" and "resources" are forward-looking statements, as they involve the implied assessment, based on estimates and assumptions that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. These forward-looking statements are subject to numerous risks and uncertainties, including but not limited to, 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 and interest rate fluctuations, imprecision of reserve and resource estimates; environmental risks; competition from other producers; inability to retain drilling rigs and other services; the impact of general economic conditions; industry conditions including changes in laws and regulations including adoption of new environmental laws and regulations, and changes in how they are interpreted and enforced; lack of availability of qualified personnel; the results of exploration and development drilling and related activities; risks related to obtaining required approvals of regulatory authorities; risks associated with negotiating with governments; changes in income tax laws, tax rates and/or incentive programs relating to the oil industry; changes to pipeline capacity; ability to access sufficient capital from internal and external sources; failure of counterparties to perform under the terms of their contracts; incorrect assessment of the value of acquisitions; and other factors, many of which are beyond the control of the Company. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could effect TransGlobe's operations and financial results are included in reports on file with Canadian and United States securities regulatory authorities and may be accessed through the SEDAR website ( or the EDGAR website at and Although the forward-looking statements contained in this document are based upon assumptions which management believes to be reasonable, the Company cannot guarantee that actual results will be consistent with these forward-looking statements. With respect to forward-looking statements contained in this document, TransGlobe has made assumptions regarding, among other things: current commodity prices and royalty regimes; availability of skilled labour; future growth; timing and amount of capital expenditures; future currency, exchange and interest rates; future commodity prices; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; receipt of partner, regulatory and community approvals; royalty rates; future operating costs; effects of regulation by governmental agencies; uninterrupted access to areas of TransGlobe's operations and infrastructure; recoverability of reserves and future production rates; timing of drilling and completion of wells; 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 and Mercuria to successfully market and receive payment for its oil and natural gas product; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; on-stream timing of production from successful exploration wells; operational performance of non-operated producing fields; pipeline capacity; that TransGlobe will benefit from diversification; that TransGlobe will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that TransGlobe's conduct and results of operations will be consistent with its expectations; that TransGlobe will have the ability to develop its oil and gas properties in the manner currently contemplated; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; that the estimates of reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; that TransGlobe will be able to fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its undeveloped properties; and other matters. Management has included the above summary of assumptions and risks related to forward-looking information provided in this document in order to provide investors with a more complete perspective on TransGlobe's current and future operations and such information may not be appropriate for other purposes. TransGlobe's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits TransGlobe will derive. These forward-looking statements are made as of the date of this document and TransGlobe disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. The forward-looking statements contained in this presentation are expressly qualified by this cautionary statement. 22

23 CAUTIONARY STATEMENTS FOFI and Other Financial Matters This document also contains future oriented financial information ("FOFI") within the meaning of applicable securities laws, including but not limited to the information regarding future capital expenditures, estimated working capital, internal rates of return, net present value, payout, recycle ratio, and finding and development costs set forth on slides "2017 Operational Plan", "Canada Type Curve Economics C$" and "Balance Sheet Summary". The FOFI has been prepared by TransGlobe s management to provide an outlook of the Company's activities and results. The FOFI has been prepared based on a number of assumptions including those set forth in the presentation, the assumptions discussed above and assumptions with respect to the costs and expenditures to be incurred by the Company, capital equipment and operating costs, foreign exchange rates, taxation rates for the Company, general and administrative expenses and the prices to be paid for the Company's production. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the FOFI or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results will likely vary from the amounts set forth in the analysis presented in this presentation, and such variation may be material. The Company and its management believe that the FOFI has been prepared on a reasonable basis, reflecting the best estimates and judgments, and represent, to the best of management's knowledge and opinion, TransGlobe's expected expenditures and results of operations. However, because this information is highly subjective and subject to numerous risks including the risks discussed above, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, TransGlobe undertakes no obligation to update such FOFI and forward-looking statements and information. 23

24 CAUTIONARY STATEMENTS Oil and Gas Information The estimates of TransGlobe's December 31, 2016 reserves set forth in this presentation have been prepared by DeGolyer and MacNaughton Canada Limited ("D&M"), an independent qualified reserves evaluator, as of December 31, 2016 in accordance with National Instrument Standards of Disclosure for Oil and Gas Activities ("NI ") and the Canadian Oil and Gas Evaluations Handbook (the "COGE Handbook" or "COGEH") and using D&M's forecast prices and costs as at December 31, The estimates of TransGlobe's December 31, 2015 reserves set forth in this presentation have been prepared by D&M as of December 31, 2015 in accordance with NI and COGEH and using D&M's forecast prices and costs as at December 21, All of TransGlobe's reserves disclosed herein are heavy crude oil/medium crude oil/light crude oil, conventional natural gas or natural gas liquids. Light crude oil is crude oil with a relative density greater than 31.1 degrees API gravity, medium crude oil is crude oil with a relative density greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity, and heavy crude oil is crude oil with a relative density greater than 10 degrees API gravity and less than or equal to 22.3 degrees API gravity. "Proved" or "1P" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. "Probable" or "2P" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Estimates of the net present value of the future net revenue from TransGlobe's reserves do not represent the fair market value of such reserves. The estimates of reserves and future net revenue from individual properties or wells may not reflect the same confidence level as estimates of reserves and future net revenue for all properties and wells, due to the effects of aggregation. In this presentation NPV10 represents the net present value of net income discounted at 10%. The NPV estimates are net estimates and are prepared after the deduction of royalties and abandonment and reclamation costs. This presentation contains certain oil and gas metrics, including F&D, recycle ratios, production replacement ratio, reserve life index and internal rates of return ("IRR"), which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. A summary of the calculations of such metrics are as follows: F&D is calculated as exploration and development costs incurred in the year adjusted for the change in estimated future development costs. 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 is calculated by dividing the netback by the proved and proved plus probable finding and development cost on a per Bbl basis Reserve life index is calculated as 2P reserves divided by production at 3,100 Boepd, Sept 2016 Production replacement ratio is calculated as reserve additions (excluding the Canadian acquisition) during the year divided by the annual production. IRR is calculated as the discount factor applied to future cash flows at which the NPV is calculated to be zero 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 "BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. The recovery and reserve estimates of reserves provided in this document are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual reserves may eventually prove to be greater than, or less than, the estimates provided herein. All evaluations and reviews of future net revenue are stated prior to any provision for interest costs or general and administrative costs and after the deduction of royalties, development costs, production costs, well abandonment costs and estimated future capital expenditures for wells to which reserves have been assigned. Certain information in this document may constitute "analogous information" as defined in NI Such information includes production estimates, drilling results, test rates, reserves estimates and other information retrieved from the continuous disclosure record of certain industry participants from AccuMap or other publically available sources. Management of TransGlobe believes the information is relevant as it may help to define the reservoir characteristics and production profile of lands in which TransGlobe may hold an interest. TransGlobe is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor and is unable to confirm that the analogous information was prepared in accordance with NI Such information is not an estimate of the production, reserves or resources attributable to lands held or to be held by TransGlobe and there is no certainty that the production, reserves or resources data and economic information for the lands held or to be held by TransGlobe will be similar to the information presented herein. The reader is cautioned that the data relied upon by TransGlobe may be in error and/or may not be analogous to such lands held or to be held by TransGlobe. Certain other information contained in this presentation has been prepared by third-party sources, which information has not been independently audited or verified by TransGlobe. No representation or warranty, express or implied, is made by TransGlobe as to the accuracy or completeness of the information contained in this document, and nothing contained in this presentation is, or shall be relied upon as, a promise or representation by TransGlobe. 24

25 CAUTIONARY STATEMENTS This presentation discloses drilling locations that have associated proved and/or probable reserves based on D&M 12/31/2016 evaluation prepared in accordance with NI and the COGE Handbook and using D&M pricing forecasts as at 12/31/2016. Unbooked locations are internal estimates based on prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by management as an estimation of the Company s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells is ultimately dependent upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. Certain type curves referred to in this document represent estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. The type curves disclosed herein are management-generated type curves based on a combination of historical performance of older wells and management's expectation of what might be achieved from future wells. The type curves represent what management thinks an average well will achieve. Individual wells may be higher or lower but over a larger number of wells management expects the average to come out to the type curve. Over time type curves can and will change based on achieving more production history on older wells or more recent completion information on newer wells. Defined Terms MM PSCs WI Bbl Bopd or bopd MMBbl Mcf MMcf MMBoe Boepd 1P PDP PU 2P millions of dollars production sharing contracts. working interest barrels barrels of oil per day million barrels thousand cubic feet million cubic feet million barrels of oil equivalent barrels of oil equivalent per day proved reserves proved developed producing reserves proved undeveloped reserves proved plus probable reserves 25

26 APPENDIX

27 Netback ($/bbl) Netback ($/boe) 2017 NETBACK GUIDANCE Egypt (US$) Canada (US$) $25 $22.14 $25 $21.12 $20 $17.65 $20 $17.57 $15 $13.16 $15 $14.00 $10 $8.67 $10 $6.89 $10.45 $5 $4.18 $5 $0 $40 $50 $60 $70 $80 Brent $0 $40 $50 $60 $70 $80 WTI Egypt Assumptions: Using anticipated 2017 Egypt production profile Ras Gharib price differential estimate of $10.00 per bbl applied consistently at all price points Opex estimated at ~$9.30/bbl Maximum cost recovery resulting from accumulated cost pools Canada Assumptions: Using anticipated 2017 Canada production profile Edmonton Light to Harmattan discount = C$2.83/bbl Opex estimated at C$8.00/boe Aeco gas price C$2.00/mmbtu for $40 WTI and increases C$0.50/mmbtu for every $10/bbl WTI Edmonton Light = $3.25 off of WTI NGL mixture price = 40% of Edm. Light Takes into consideration Canadian tax pools 27

28 OIL MARKETING Marketing has improved EGPC AR Outstanding ($M) $140,000 liquidity and decreased $120,000 credit risk $100,000 $80,000 TransGlobe began marketing $60,000 its own entitlement oil in $40,000 $20,000 January 2015 $0 30 day payment in US$ from date of cargo liftings Successfully marketed 6.5 cargo liftings in the last 21 months Arranged for the sale of ~350,000 barrels of production in Q in equal monthly allotments Finalized a 2017 lifting schedule with EGPC for three cargos, scheduled for Q2 (June), Q3 and Q Signed long term Marketing Agreement (in conjunction with Prepayment Agreement) with Mercuria on Feb 10/17 28

29 NET PRESENT VALUE OF FUTURE NET REVENUE 1 Before Deducting Future Income Taxes Discounted At After Deducting Future Income Taxes Discounted At Effective December 31, % 5% 10% 15% 20% 0% 5% 10% 15% 20% (MM$) Proved Canada Egypt Total Proved Proved Plus Probable Canada Egypt Total Proved Plus Probable Proved Plus Probable Plus Possible Canada Egypt Total Proved Plus Probable Plus Possible Based on D&M evaluation effective 12/31/16 2. Egyptian taxes are paid from the Governments share of production, therefore the Company s share is always after tax 29

30 EXECUTIVES AND DIRECTORS Robert G. Jennings - Director, Chairman Ross G. Clarkson - Director, President and CEO Lloyd W. Herrick - Director, VP and COO Geoffrey C. Chase Director (retiring May, 2017) Fred J. Dyment - Director Susan MacKenzie Director David Cook - Director Bob MacDougall Director Matthew Brister Director Steve Sinclair - Director Randy C. Neely - VP, Finance and CFO Brett Norris - VP, Exploration 30

31 ANALYST COVERAGE Rita Guindy, CI Capital, Giza, Egypt David Phung, Credit Suisse Securities, Calgary, Canada David Dudlyke, Dundee Securities Europe, London, UK Darren B. Engels, GMP First Energy, Calgary, Canada Al Stanton, RBC Capital Markets, London, UK Gavin Wylie, Scotia Capital Inc., Calgary, Canada Shahin Amini, TD Securities, London, UK 31

32 For additional information contact us at: Phone: +1 (403) Or visit: