Investor Presentation June 2016

Investor Presentation June 2016 Touchstone Exploration Inc. is a publically traded Canadian oil and gas company with production and assets in Trinidad and Tobago and Canada. As an early adopter of proven technologies, we focus on developing plays with large oil in place to maximize 1 shareholder returns.

Corporate Foundation 2 21 Onshore blocks Well Established Trinidad E&P 11 producing blocks 91% average working interest on producing blocks 10 non-producing blocks 1 Billion Barrels Total Petroleum Initially-in-Place(1) TPIIP is based on our 5 key producing blocks (1) Approximately 9.5% recovery factor (2) 208 Drilling locations(3) Discovered Petroleum Initially-in-Place (DPIIP) 10 years of drilling inventory Less than 40% of the locations are booked Discovered Petroleum Initially-in-Place Exploitation and Consolidation (DPIIP) Opportunity Commence continuous drilling program Evaluate and pursue current regional acquisition opportunities

Why Trinidad? 3 11 kilometres off of the coast of Venezuela world s largest proven oil reserves Situated at the triple junction formed by the meeting of three plates; the Caribbean, South American and North Atlantic Plates provides structure, trap, and kitchen Principle industry is oil and gas (represents ~45% of country GDP) Established service industry presence (e.g.. BJ, Tucker, Schlumberger, Haliburton) Oil refining plant with a capacity of 168,000 bbls/d, throughput ~113,000 bbls/d One of the largest natural gas processing facilities in the Western Hemisphere, processing 2 bcf per day and output of 70,000 bbls/d of NGL Produces approximately 42.8 billion cubic metres per year (4.1 bcf/d) of natural gas Exports liquefied natural gas to over 19 different countries World s largest exporter of ammonia, 2 nd largest exporter of methanol

Corporate Snapshot 4 Port of Spain * Capital City Common shares (June 17, 2016) 83,137,143 Local Access to World Markets Point Fortin Pointe-a-Pierre Atlantic LNG Liquefaction Plant Commissioned in 1999 Capacity: LNG: 14.8 mtpa NGLs: 28,000 bpd Petrotrin Oil Refinery Commissioned in 1917 Capacity: 168,000 bopd Throughput: 113,000 bopd San Fernando Market capitalization (June 17, 2016) $20.8 million (1) Net debt (March 31, 2016) $1.16 million (2) Enterprise value (March 31, 2016) $15.7 million (3) Q1 2016 average production 1,361 bbls/d Proved Plus Probable Reserves (Gross) 15,565 Mbbl (4) 2P NPV (10% discount Atax) $125 million (4) Reserves

Repeatable Low Risk Asset Base 5 Conventional Resource Play with Significant Total Petroleum Initially-in-Place (TPIIP) Development Block Working Interest Acres Lease Type Current wellbores (1) TPIIP (MMbbls) (2) Cumulative Production to Date (MMbbls) (3) Oil Parameters ( API) Total Potential Locations (Gross) (4) WD-8 650 LOA 116 314 18.4 16-30 63 WD-4 700 LOA 72 265 14.4 14-35 36 Coora (1&2) 1,699 LOA 358 325 47.8 17-28 47 Fyzabad 804 Crown & Private 322 101 14.6 20-22 27 Sub-Total 3,853 868 1,005 95.2 14-35 173 Minor Properties 4,264 FOA, Crown & Private 264 ++ ++ 16-42 35 ** Total 8,117 1,132 14-42 208

NPV10 - C$ Price per Common Share - C$ NPV10 - C$ Brent Oil Price - C$ Scalable Resource Play 6 GLJ Reserves Report (effective December 31, 2015) 5 th consecutive year of positive reserve additions in Trinidad Replaced 219% (1) of 2015 Trinidad production and increased Proved plus Probable Reserves by 4.6% to 15,465 Mbbls $400,000 $350,000 $300,000 $250,000 $200,000 $150,000 $100,000 Booked Net Present Value (2) (10% Discount Before Tax) $140 $120 $100 $80 $60 $40 Achieved total Proved plus Probable finding and development costs of $5.83 per barrel (3) including changes in future development costs $50,000 $- 1P NPV10 2010 2011 2012 2013 2014 2015 2P NPV10 $20 $- Average Brent Price for reporting year Brent Price at Report effective date 2015 Reserves Bookings (2) Total Proved Total Proved plus Probable Gross Reserves (Mbbls) 8,815 15,465 Net Reserves After Royalties (Mbbls) 6,141 11,111 $160,000 $140,000 $120,000 Booked Net Present Value (2) (10% Discount After Tax) $2.50 $2.00 NPV10 Before Tax ($MM) 141.9 304.7 NPV10 After Tax ($MM) 67.4 124.8 Future Development Capital ($MM) 46.7 70.7 Finding & Development Costs ($/bbl) (3) 15.81 5.83 $100,000 $80,000 $60,000 $40,000 $20,000 $1.50 $1.00 $0.50 $- 2010 2011 2012 2013 2014 2015 $- 1P NPV10 2P NPV10 NPV10 per common share

$/bbl Mbbls Trinidad Reserve Growth 7 Annual Trinidad Segment Finding, Development and Acquisition Costs (1) 2014 2015 2 Year Average 1P 2P 1P 2P 1P 2P Finding & Development Costs ($/bbl) 16.79 9.88 15.81 5.83 16.60 8.81 Finding, Development & Acquisition Costs ($/bbl) 10.85 8.23 15.81 5.83 11.06 8.05 Trinidad Recycle Ratio 1.96x 2.58x 0.55x 1.48x 1.25x 1.72x 18.00 Finding & Development Costs ($/bbl) (1) 18,000 Booked Reserves (2) 16.00 16,000 14.00 14,000 12.00 12,000 10.00 10,000 8.00 8,000 6.00 6,000 4.00 4,000 2.00-2014 2015 2 Year Avg. 2014 2015 2 Year Avg. 2,000-2010 2011 2012 2013 2014 2015 Proved F&D Costs Proved + Probable F&D Costs 1P Reserves 2P Reserves 2015 2P Reserve life index of 22.9 Years (3)

Average Daily Oil Production (bbls/d) Cumulative Production (bbls) Undiscounted Cash Flow ($US) Compelling Well Economics (Internal Estimates) 8 Assumptions Current estimated cost per well (DCC&E) US$800,000 Historical average IP (bbls/d) 55 Average production (initial 10-years, bbls) 87,292 Agreement type LOA 2,000,000 1,500,000 1,000,000 500,000 - (500,000) (1,000,000) New LOA Well Undiscounted Cash Flow vs. Time 1 13 25 37 49 61 73 85 97 109 121 Production Month High Case Average Case Low Case Brent (USD) GLJ Price Forecast January 1, 2016 2016 $45.00 2017 $54.00 2018 $61.00 2019 $67.00 2020 $73.00 2021 $78.00 2022 $83.00 2023 $88.00 2024 $91.39 2025 $93.22 Per January 1, 2016 GLJ Brent Pricing Forecast Initial (IP30) production (bbls/d) Low WELL TYPE Average High 35 55 100 120 New LOA Well Forecast January 2016 Forecast Pricing 180,000 Cumulative production Initial 10 years (bbls) Net present value at 10% discount (US$) 55,550 87,292 158,713 $800 $292,000 $878,870 Payback period (months) 61 34 20 100 80 60 160,000 140,000 120,000 100,000 80,000 Estimated internal rate of return 10% 26% 61% 40 60,000 40,000 IP30 Cost per flowing barrel (US$) Cash operating netback per barrel - Initial 10 years (US$) 22,857 14,545 8,000 19.30 16.65 14.49 20 0 1 12 23 34 45 56 67 78 89 100 111 Production Month 20,000 0 F&D cost per barrel Initial 10 years (US$) 14.40 9.16 5.04 High Case - Daily Average - Daily Low Case - Daily High Case - Cumulative Average - Cumulative Low Case - Cumulative

Daily Fluid (bbls) Water Cut (%) Low Risk Upside (Internal Estimates) 9 Recompletions Assumptions 400 350 Accessible Wellbores Per January 1, 2016 GLJ Brent Pricing Forecast Estimated recompletion cost (US$) 35,000 Initial (IP30) production (bbls/d) 10 2 Year cumulative production (bbls) 6,021 300 Net present value at 10% discount (US$) 30,335 250 200 150 100 Payback period (months) 12 Estimated internal rate of return 145% IP30 Cost per flowing barrel (US$) 3,500 50 0 WD-8 Coora WD-4 Fyzabad San Francique Barrackpore Palo Seco Other Cash operating netback per barrel Initial 2 years (US$) 11.85 F&D cost per barrel Initial 2 years (US$) 5.81 Frac Stimulations Evaluating results of pilot project Small fracs (10 to 30 tonne) 60.00 50.00 Sunty 2 Production Analysis Flowing Pumping 100% 90% 80% Get past near wellbore damage Sand control via resin coated proppant 40.00 30.00 70% 60% 50% Initial results promising 400% Increase in Production (before vs. after) 20.00 10.00 0.00 40% 30% 20% 10% 0% 200% increase in forecast ultimate recovery Date Sunty 2 Oil Water Cut

Forecast Average Daily Oil Production (bbls) Estimated Cumulative Capital Required for Development Program ($C) Production Growth Forecast 10 3,500 3,000 Trinidad Daily Oil Production Investment Case Forecast (1) January 2016 through December 2018 $60,000,000 $50,000,000 2,500 $40,000,000 2,000 $30,000,000 1,500 1,000 $20,000,000 500 $10,000,000 - Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Forecast Period Investment Case $0 Base Production Recompletions Minimum Work Obligations Upside Development Recompletion Capital Minimum Work Obligation Captital Upside Development Capital (Total - includes RCP and MWO Capital)

C$ C$ Increasing Our Funds Flow Netbacks 11 $70 $60 $50 $40 $8.47 Funds Flow Netback Base Case Forecast (1) $7.06 $3.01 $30 $20 $10 $0 2016 2017 2018 $70 Funds Flow Netback Investment Case Forecast (2) $60 $50 $6.89 $15.76 $23.71 $40 $30 $20 $10 $0 2016 2017 2018 Royalties Operating costs General and admin Finance expenses Current taxes - SPT Current taxes - other Funds flow netback

$M $M Continuously Improving Netbacks - More With Less 12 Operating Expenses Annual 2015 Corporate operating expenses per barrel reduced by 16% from 2014 Annual 2015 Trinidad operating expenses per barrel reduced by 17% from 2014 In 2016 we continue to renegotiate contracts and increase performance to further reduce costs G&A Expenses Annual 2015 Corporate G&A reduced by 7% (excluding severance) from 2014 Annual 2015 Canada G&A reduced by 25% (excluding severance) from 2014 In 2016 we continue to evaluate costs, cut expenses to further reduce general and administrative expenses $3,000 Corporate G&A (excluding severance charges) $7,000 Corporate Operating Expenses $2,500 $2,000 $1,500 $1,000 $6,000 $5,000 $4,000 $3,000 $2,000 $500 $1,000 $0 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 $0 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016

Exploration Catalyst 13 ORTOIRE BLOCK 35,785 Net acres 80% Working interest 74 wells drilled to date 4 known pools Technical work supports low risk exploration and highlights potential for reactivation, recompletion, and infill development of vintage fields on the block. Four established pools on the block Surface Expression Balata West (1953) Herrera FM conventional oil Mayaro (1937/1968) Gros Morne FM conventional gas Balata West Balata East, 1952 Oil Herrera Formation 10 MMbbls Mayaro Maloney (1946) Lower Cruse FM conventional oil Maloney Lizard Springs (1928) Lengua/Karamat FM fractured shale oil Carapal Ridge 2002 Gas/Condensate Largest onshore discovery in 50 years Herrera Formation 500 bcf / 25 MMboe condensate Catshill, 1952 Oil Forest & Cruse Formations 30 MMbbls Lizard Springs Navette, 1952 Oil Gros Morne Formation 60 MMbbls

Analogous Opportunities 14 Offsetting Blocks Discovery Year Producing Formation Producing Depth (max) Number of Wells Cumulative Production Carapal Ridge 2002 Herrera 8,500 ft. 4 104 million boe Catshill 1952 Forest / Cruse 3,000 ft. 55 30 million bbls Balata East 1952 Herrera 3,500 ft. 47 10 million bbls Navette 1952 Gros Morne 4,000 ft. 140 60 million bbls Discovered Pools (on Ortoire Block) Discovery Year Producing Formation Producing Depth (max) Number of Wells Known Production Balata West 1953 Herrera 6,300 ft. 1 27,000 bbls Mayaro 1937 Gros Morne 2,800 ft. 3 10 bcf Maloney 1946 Lower Cruse 4,600 ft. 1 45,000 bbls Lizard Springs 1928 Lengua/Karamat 1,200 ft. 13 50,000 bbls

Consolidation Opportunity 15 Company Trinity Current Production (1) 2,775 bopd LGO 400 bopd Range 500 bopd Massy 120 bopd Shell (onshore) Repsol 6,735 bopd 9,360 bopd Company Petrotrin (onshore) Current Production (1) 12,650 bopd

Corporate Foundation 16 21 blocks 1 billion barrels TPIIP (1) 208 potential drilling locations (2) Time to Exploit and Consolidate 208 potential drilling locations Compelling well economics Recompletion potential Exploration prospects Consolidation opportunities

Corporate Information 17 Corporate Information Head Office Suite 1100, 332 6 th Ave SW Calgary, AB T2P 0B2 Office: (403) 750-4400 Fax: (403) 266-5794 info@touchstoneexploration.com Website: www.touchstoneexploration.com Trinidad Office Touchstone Exploration (Trinidad) Ltd. #30 Forest Reserve Road Fyzabad, Trinidad Office: (868) 677-7411 Contacts Paul R. Baay President and Chief Executive Officer pbaay@touchstoneexploration.com (403) 750-4488 Scott Budau Chief Financial Officer sbudau@touchstoneexploration.com (403) 750-4445 James Shipka Chief Operating Officer jshipka@touchstoneexploration.com (403) 750-4455 Abbreviations bbl(s) barrel(s) Mbbl(s) thousand barrel(s) MMbbls(s) million barrel(s) bbls/d barrels per day bopd barrels of oil per day boe barrels of oil equivalent Mboe thousand barrels of oil equivalent MMboe million barrels of oil equivalent Mtpa million tonnes per annum bcf billion cubic feet C$ Canadian dollar US$ United States dollar TT$ Trinidad & Tobago dollar $M thousand dollars $MM million dollars Brent The reference price paid for crude oil FOB North Sea WTI Western Texas Intermediate, the reference price paid for crude oil and standard grade in U.S. dollars at Cushing Oklahoma Ha Hectare LOA Lease Operator Agreement FOA Farmout Agreement IP30 Average initial production in the first 30 days of well production Year End: Dec 31 Bankers: Engineers: Auditors: Legal: Transfer Agent: The Bank of Nova Scotia GLJ Petroleum Consultants Ltd. Ernst & Young LLP Norton Rose Fulbright Canada LLP LEX Caribbean Computershare Trust Company of Canada

Advisories 18 Advisories This presentation is for information purposes only and is not, and under no circumstances is to be construed as a prospectus or an advertisement for a public offering of such securities. No securities commission or similar authority in Canada or elsewhere or the Toronto Stock Exchange has in any way passed upon this presentation, or the merits of any securities of Touchstone Exploration Inc. and any representation to the contrary is an offence. An investment in Touchstone Exploration Inc. s securities should be considered highly speculative due to the nature of the proposed involvement in the exploration for and production of oil and natural gas. This presentation and the information contained herein does not constitute an offer to sell or a solicitation of an offer to buy any securities in the United States. The securities of Touchstone Exploration Inc. have not been registered under the United States Securities Act of 1933, as amended (the U.S. Securities Act ) or any state securities laws and may not be offered or sold within the United States or to U.S. Persons unless registered under the U.S. Securities Act and applicable state securities laws or an exemption from such registration is available. Forward-looking Information The information provided in this presentation contains certain forward-looking statements and forward-looking information about the Company within the meaning of applicable securities laws. All statements and information, other than statements of historical fact, made by Touchstone that address activities, events, or developments that Touchstone expects or anticipates will or may occur in the future are forward-looking statements and information, including, but not limited to statements and information preceded by, followed by, or that include words such as "may", "would", "could", "will", "likely", "except", "anticipate", "believe", "intends", "plan", "forecast", "project", "estimate", "outlook", or the negative of those words or other similar or comparable words. Forward-looking statements and information involve significant risks, assumptions, uncertainties and other factors that may cause actual future results or anticipated events to differ materially from those expressed or implied in any forward-looking statements or information and, accordingly, should not be read as guarantees of future performance or results. These risks and factors include, but are not limited to, risks relating to Touchstone's ability to execute its exploration and development program, drilling and operating risks, dependence on key personnel, compliance with environmental regulations and competition. In particular, forward-looking statements contained in this presentation may include, but are not limited to, statements with respect to: crude oil production levels; the size of, and future net revenue from, oil and natural gas reserves; projections of market prices and costs; the performance characteristics of the Company's oil and natural gas properties; drilling and recompletion plans, and the anticipated timing thereof; financial and business prospects and financial outlook; results of operations; activities to be undertaken in various areas including the fulfillment of minimum work obligations and exploration commitments; terms of exploration and production contracts and the expected renewal of certain contracts; expectations regarding the ability of the Company to add continually to reserves through acquisitions and development; treatment under governmental regulatory regimes and tax laws; tax horizon, royalty rates and future tax and royalty rates enacted in the Company s areas of operations; access to facilities and infrastructure; future capital expenditures, the timing thereof and the method of funding; the potential of future acquisitions or dispositions; receipt of anticipated regulatory approvals; financial condition, access to capital and overall strategy; the Company's ability to continue to operate as a going concern; the Company's risk management strategy and the use of commodity derivatives to manage movements in the price of crude oil; the Company s expected completion of the sale of its East Brighton License; the Company's future bank loan borrowing base and future sources of liquidity; terms of the Company's contractual commitments and their timing of settlement and estimated amounts, timing and the anticipated sources of funding for the Company's decommissioning obligations. Statements relating to reserves and resources are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. Such statements represent the Company s internal projections, estimates or beliefs concerning future growth, results of operations based on information currently available to the Company based on assumptions that are subject to change and are beyond the Company s control, such as: production rates and production decline rates, the magnitude of and ability to recover oil and gas reserves, plans for and results of drilling activity, well abandonment costs and salvage value, the ability to secure necessary personnel, equipment and services, environmental matters, future commodity prices, changes to prevailing regulatory, royalty, tax and environmental laws and regulations, the impact of competition, future capital and other expenditures (including the amount, nature and sources of funding thereof), future financing sources, business prospects and opportunities, among other things. Many factors could cause the Company s actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, the Company. Internal Forecasts The Company has presented herein three-year growth plans based on certain assumptions, including commodity prices, foreign exchange rates and future sources of capital. Such growth plans do not represent management's expectations of the Company's future performance but rather is intended to present management's belief in the economic viability of the Company's business based on such scenarios. Readers should not use such three-year growth model as a presentation of the Company's future performance. The forward-looking statements contained in this presentation are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Advisories 19 Business Risks The Company is exposed to numerous operational, technical, financial and regulatory risks and uncertainties, many of which are beyond its control and may significantly affect anticipated future results. The Company is exposed to risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities. Operations may be unsuccessful or delayed as a result of competition for services, supplies and equipment, mechanical and technical difficulties, ability to attract and retain qualified employees on a cost-effective basis, commodity and marketing risk. The Company is subject to significant drilling risks and uncertainties including the ability to find oil reserves on an economic basis and the potential for technical problems that could lead to well blow-outs and environmental damage. The Company is exposed to risks relating to the inability to obtain timely regulatory approvals, surface access, access to third party gathering and processing facilities, transportation and other third party related operation risks. The Company is subject to industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced. There are uncertainties in estimating the Company s reserve base due to the complexities in estimated future production, costs and timing of expenses and future capital. The Company is subject to the risk that it will not be able to fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its properties. The financial risks the Company is exposed to include, but are not limited to, the impact of general economic conditions in Canada and Trinidad, continued volatility in market prices for oil, the impact of significant declines in market prices for oil, the ability to access sufficient capital from internal and external sources, changes in income tax laws or changes in tax laws, royalties and incentive programs relating to the oil and gas industry, fluctuations in interest rates, the Canadian dollar to United States dollar exchange rate and the Canadian dollar to Trinidad and Tobago dollar exchange rate. The Company is subject to local regulatory legislation, the compliance with which may require significant expenditures and noncompliance with which may result in fines, penalties or production restrictions or the termination of license, lease operating or farm-in rights related to the Company s oil and gas interests in Trinidad. Certain of these risks are set out in more detail in the Company s Annual Information Form dated March 24, 2016 which has been filed on SEDAR and can be accessed at www.sedar.com Actual results, performance or achievement could differ materially from that expressed in, or implied by any forward-looking statements or information in this presentation, and accordingly, investors should not place undue reliance on any such forward-looking statements or information. Further, any forward-looking statement or information speaks only as of the date on which such statement is made, and Touchstone undertakes no obligation to update any forward-looking statements or information to reflect information, events, results, circumstances or otherwise after the date on which such statement is made or to reflect the occurrence of unanticipated events, except as required by law, including securities laws. All forward-looking statements and information contained in this presentation and other documents of Touchstone are qualified by such cautionary statements. New factors emerge from time to time, and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on Touchstone's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. Oil and Gas Information The reserves information presented in this presentation is from reports prepared by Touchstone s independent reserves evaluator, GLJ Petroleum Consultants Ltd. ( GLJ ), dated March 8, 2016 with an effective date of December 31, 2015 and dated March 11, 2015 with an effective date of December 31, 2014. Each of these reports were prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ( NI 51-101 ). All December 31, 2015 reserves presented are based on GLJ s forecast pricing and estimated costs effective January 1, 2016, and December 31, 2014 reserves presented are based on GLJ s forecast prices and estimates of future costs as at January 1, 2015. Additional reserves information as required under NI 51-101 are included in the Company s Annual Information Form dated March 24, 2016. The recovery and reserves estimates of crude oil provided herein are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil reserves may be greater than or less than the estimates provided herein. The estimated future net revenue figures contained in this presentation do not necessarily represent the fair market value of the Company's reserves. There is no assurance that the forecast price and costs assumptions contained in the Company s reserves evaluation will be attained and variances could be material. The recovery and reserves estimates attributed to the Company's properties described herein are estimates only. The actual reserves attributable to the Company's properties may be greater or less than those calculated. This presentation uses the term total petroleum initially-in-place ( TPIIP ) which means the quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. There is uncertainty that it will be commercially viable to produce any portion of the resources.

Advisories 20 Oil and Gas Metrics This presentation uses the following oil and gas metrics that are commonly used in the oil and gas industry such as finding and development costs, finding, development and acquisition costs, reserves additions, recycle ratio, and costs per flowing barrel. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this presentation, should not be relied upon for investment or other purposes. Trinidad based finding and development costs are the sum of total Trinidad segment capital expenditures incurred in the period and the change in future development costs required to develop those reserves. Finding, development and acquisition costs are the sum of finding and development costs and the costs of acquisitions less proceeds from dispositions. Finding, development and acquisition costs have been presented because acquisitions and dispositions can have a significant impact on the Company's ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company's cost structure. Finding and development costs per barrel is determined by dividing current period net reserve additions to the corresponding period s finding and development cost. Reserve additions are calculated as the change in reserves from the beginning to the end of the applicable period excluding period production. 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. Trinidad based recycle ratios are calculated by dividing the current period Trinidad segment finding and development costs per barrel to the corresponding period s Trinidad segment funds flow netbacks (see Non-GAAP Measures below). Finding and development costs and recycle ratios do not have a standardized meaning and may not be comparable to similar measures presented by other companies. The Company uses finding and development costs and recycles ratios as a measure of the efficiency of its overall capital and operational activities. Management uses finding and development cost and recycle ratio metrics for its own performance measurements and to provide shareholders with measures to compare the Company s operations over time. Cost per flowing barrel is calculated as the total capital expenditure for any particular project (drilled well or well recompletion) divided by the initial production rates. Unless otherwise stated, initial production rates are typically calculated as average production rates over a thirty-day period. Costs per flowing barrel do not have a standardized meaning and may not be comparable to similar measures presented by other companies. The Company uses costs per flowing barrel as a measure of the efficiency of its overall capital program. Any references in this document to test rates, flow rates, initial and/or final raw test or production rates, early production, test volumes and/or "flush" production rates are useful in confirming the presence of hydrocarbons, however, such rates are not necessarily indicative of long-term performance or of ultimate recovery. Such rates may also include recovered "load" fluids used in well completion stimulation. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Drilling Locations This presentation discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Company's reserves evaluation of GLJ Petroleum Consultants Ltd. effective December 31, 2015 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the prospective acreage associated with the Company s assets and an assumption as to the number of wells that can be drilled based on industry practice and internal review. Unbooked locations do not have attributed reserves. Of the approximately 208 (net) drilling locations identified herein, 53 are proved locations, 26 are probable locations and the remaining are unbooked locations. Unbooked locations have been identified by management as an estimation of our 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 or production. The drilling locations on which we actually drill wells will ultimately depend 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 de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, 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 or production. Non-GAAP Measures This presentation contains terms commonly used in the oil and natural gas industry, such as funds flow from operations, funds flow from operations per share, operating netback, funds flow netback and net debt. These terms do not have a standardized meaning under IFRS and may not be comparable to similar measures presented by other companies. Funds flow from operations includes all cash generated from operating activities and is calculated before changes in non-cash working capital. The Company calculates funds flow from operations per share by dividing funds flow from operations by the weighted average number of common shares outstanding during the applicable period. Operating netbacks are presented on a per barrel basis and are calculated by deducting royalties, operating expenses and realized gains/losses on derivative contracts from petroleum revenues. Funds flow netbacks are presented on a per barrel basis and are calculated by deducting royalties, operating expenses, realized gains/losses on derivative contracts, general and administrative expenses, net cash finance expenses and current income tax expenses from petroleum revenues. Net cash finance expenses include all cash finance expenses incurred during a period and exclude the amortization of prepaid bank loan fees. Net surplus/debt is calculated by summing the Company s working capital and non-current interest bearing instruments. Working capital is defined as current assets less current liabilities. Management uses these non-gaap measures for its own performance measurement and to provide stakeholders with measures to compare the Company s operations over time.

Endnotes 21 Slide 2 Corporate Foundation (1) Total Petroleum Initially-in-Place (TPIIP), as recognized by the Canadian Oil and Gas Evaluations Handbook (COGEH) includes volumes which may have already been produced and includes commercial and non-commercial volumes of petroleum. TPIIP should not be confused with oil and gas reserves. TPIIP is based upon internal volumetric estimations. See advisories. (2) Recovery factor is based on five producing blocks: Coora 1, Coora 2, Fyzabad, WD-4 and WD-8. As per slide 5, Cumulative production per date is 95.2 MMbbls and TPIIP is 1,006 MMbbls, resulting in a 9.5% recovery factor. (3) Drilling locations are based on December 31, 2015 GLJ Petroleum Consultants Ltd. independent reserves evaluation and internal estimates. See advisories. Slide 4 Corporate Snapshot (1) Based on the closing share price ($0.25/share) and 83,137,143 shares outstanding as at June 17 th, 2016. (2) Net debt is a non-gaap measure and is calculated as follows: (3) Enterprise Value is a non-gaap measure and is calculated as follows: Share Price (March 31, 2016) $ 0.18 Shares outstanding (March 31, 2016) 83,087,143 Market Capital $ 14,955,686 Bank loan balance 2,594,000 Less cash balance (1,826,000) Enterprise Value $ 15,723,686 (4) Based on the Company s December 31, 2015 GLJ Petroleum Consultants Ltd. independent reserves evaluation.

Endnotes 22 Slide 5 Repeatable Low Risk Asset Base (1) Touchstone Exploration s abandonment liability is limited to the pro-rate share of production from individual wellbores operated under the terms of its Lease Operatorship Agreements. (2) TPIIP, as recognized by COGEH, includes volumes which may have already been produced and includes commercial and non-commercial volumes of petroleum. TPIIP should not be confused with oil and gas reserves. TPIIP is based upon internal volumetric estimations. See advisories. (3) Cumulative production is per the Petroleum Company of Trinidad and Tobago through December 2015. (4) Drilling locations are based on the Company s December 31, 2015 GLJ Petroleum Consultants Ltd. independent reserves evaluation and internal estimates. See advisories. Slide 6 Scalable Resource Play (1) 2015 replacement of reserves is calculated as follows: (2) Based on the Company s December 31, 2015 GLJ Petroleum Consultants Ltd. independent reserves evaluation. (3) 2015 finding and development costs: refer to calculation on note (1) on slide 23 (footnotes).

Endnotes 23 Slide 7 Trinidad Reserve Growth (1) 2014 2015 Average Trinidad funds flow netback $ 8,874,000 $ 5,039,000 $ 13,913,000 Trinidad production (bbls) 418,368 583,929 1,002,297 Trinidad funds flow per barrel ($/bbl) $ 21.21 $ 8.63 $ 13.88 Trinidad property and equipment and exploration capital expenditures 23,634,000 4,449,000 14,041,500 Trinidad acquisition cost 33,448,000-16,724,000 Proved reserves Reserve additions from acquisitions (bbls) 7,520,000-3,760,000 Future development costs associated with reserves at time of acquisition $ 37,203,000 $ - $ 18,601,500 Trinidad total reserve additions (bbls) 1,836,000 426,200 1,131,100 Trinidad change in forecast future development costs (post acquisition) 7,185,000 2,290,000 4,737,500 2P F&D costs $ 16.79 $ 15.81 $ 16.60 2P FD&A costs $ 10.85 $ 15.81 $ 11.06 Recycle Ratio 1.96 0.55 1.25 Proved plus probable reserves Reserve additions from acquisitions (bbls) 11,697,000-5,848,500 Future development costs associated with reserves at time of acquisition $ 57,067,000 $ - $ 28,533,500 Trinidad total reserve additions (bbls) 3,483,000 1,252,200 2,367,600 Trinidad change in forecast future development costs (post acquisition) 10,790,000 2,852,000 6,821,000 2P F&D costs $ 9.88 $ 5.83 $ 8.81 2P FD&A costs $ 8.23 $ 5.83 $ 8.05 Recycle Ratio 2.58 1.48 1.72 (2) (3) Based on the Company s December 31, 2015 GLJ Petroleum Consultants Ltd. independent reserves evaluation.

Endnotes 24 Slide 10 Production Growth Forecast (1) I. Funded via 2016 $10 million equity raise, $15 million term loan and operating cash flows II. Estimated average drilling cost of new well - US$880,000 III. Estimated average initial production for a new well - 52 bbls/d IV. Estimated average decline for a new well - 3% in the first year, 2% in the second year and 1% for the third year V. Estimated average cost for a recompletion - US$35,000 VI. Estimated average initial production for a recompletion - 10 bbls/d VII. Estimated average decline for a recompletion - 1% VIII. Estimated average decline on base production - 1% IX. 2016 2017 2018 Average foreign exchange (USD/CAD) 1.33 1.27 1.25 Total wells drilled 10 20 20 Total recompletions 13 24 24

Endnotes 25 Slide 11 Increasing Our Funds Flow Netbacks (1) Assumptions on Base Model I. 2016 Includes realized gain on derivatives II. 2016 2017 2018 Oil price per barrel US$ (based on GLJ Strip pricing) $43.37 $54.00 61.00 Average foreign exchange (USD/CAD) 1.33 1.27 1.25 Total wells drilled - - - Total recompletions 13 24 24 Total production 466,339 468,565 498,268 (2) Assumptions on Capital Raise Model I. 2016 Includes realized gain on derivatives II. Funded via US$10 million equity raise, US$15 million term loan at LIBOR plus 8.5% interest and operating cash flows III. 2016 2017 2018 Oil price per barrel US$ (based on GLJ Strip pricing) $43.37 $54.00 61.00 Average foreign exchange (USD/CAD) 1.33 1.27 1.25 Total wells drilled 10 20 20 Total recompletions 13 24 24 Total production 507,482 770,578 1,049,721 Slide 15 Consolidation Opportunities (1) Production data is as of April 2016 as reported by the operators. Slide 16 Corporate Foundation (1) TPIIP, as recognized by COGEH, includes volumes which may have already been produced and includes commercial and non-commercial volumes of petroleum. TPIIP should not be confused with oil and gas reserves. TPIIP is based upon internal volumetric estimations. See advisories. (2) Drilling locations are based on the Company s December 31, 2015 GLJ Petroleum Consultants Ltd. independent reserves evaluation and internal estimates. See advisories.