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1 Corporate Presentation June 2016

2 2 Future Oriented Information (See additional advisories at the end of this presentation document) In the interest of providing information regarding Trilogy Energy Corp. ("Trilogy or the Company") and its future plans and operations to shareholders and investors, this presentation contains certain forward-looking information and forward-looking statements. The projections, estimates and forecasts contained in such forward-looking information and statements necessarily involve a number of assumptions, and are subject to both known and unknown risks and uncertainties which may cause the Company's actual performance and financial results in future periods to differ materially from those projections, estimates and forecasts. The Advisories Appendix lists some of the material assumptions, risks and uncertainties that these projections, estimates and forecasts are based on and are subject to. Accordingly, shareholders and potential investors are cautioned that events or circumstances could cause actual results to differ materially from those predicted. Any use of information contained within this presentation is expressly forbidden.

3 3 Trilogy Corporate Profile Q Results: Average production: 22,786 Boe/d (~30% Oil and NGL) Operating netback: $9.46/Boe Funds flow: $8.3 million ($4.01/Boe, $0.07/share) Net debt: $300.0 million Senior Unsecured Notes % due December 2019 $264.4 million Three Year Revolving Credit Facility - $450 million secured - under review (1) $564.4 million as at March 31, 2016 Current Market Cap.: ~ million shares at $5.00/share ~ $630 Million Insider Ownership: ~50% (1) Includes working capital deficit

4 4 Trilogy Assets Geographically concentrated assets Multi-zone development and exploration potential in the Deep Basin Significant NGL-rich, high heat content natural gas and light oil resource potential Large prospect inventory of high quality unconventional and tight resource plays with potential to be exploited with vertical and horizontal drilling and completion technologies 232,566 net acres of developed land and 397,112 net acres undeveloped land (as at December 31, 2015) Significant operated processing and gathering infrastructure in the Kaybob area (six gas plants and three oil batteries) GRANDE PRAIRIE Grande Prairie 1,584 Boe/d 2015 $1.7 MM 2015 Capex EDMONTON Kaybob 26,191 Boe/d 2015 ~$80 MM 2015 Capex CALGARY

5 Operations Update

6 Trilogy: Key Growth Plays 6

7 7 Kaybob Montney Oil Pool Development Discovered in Hz Montney oil wells/section; ~ 400 potential drilling opportunities Approximately 50 net sections at average 10 MMBbl DOIIP/section; ~500 MMBbl DOIIP for pool (1) Drilled 111 wells to date Drilling and completions costs for 2016 are expected to average ~ $2.9 MM per well; a 30% reduction from 2014 Average 1-mile horizontal lateral 22 fracs/well; 75 m spacing Net pay ranges from 5 m - 15 m Q drilled 2 (net) wells Plan to drill 3 (net) additional wells in third quarter Average Proved plus probable reserves/well (2): ~245 MBoe ~164 MBbl Oil + NGLs ~0.5 Bcf Solution Gas (1) Please refer to the heading Internal Estimates in the Advisories Appendix of this presentation for more information. DOIIP denotes Discovered Oil Initially in Place. Refer to Oil & Gas Measures and Definitions in the Advisories Appendix for further information. (2) McDaniel & Associates Consultants Ltd. at December 31, 2015

8 Kaybob Montney Oil Pool Development Total Wells Drilled Drilling/ Completion $98 MM $109 MM $133 MM $111 MM $8MM $459 MM Infrastructure $33 MM $51 MM $33 MM $24 MM $2MM $143 MM Land $36 MM $36 MM Total Capital $167 MM $160 MM $166 MM $135 MM $10MM $638 MM Average Production (Boe/d) 2,446 9,829 11,653 10,214 7,562 Total Production (MBoe) 893 3,597 4,280 3,728 2,760 15,258 Operating Income $54 MM $172 MM $199 MM $179 MM $71 MM $675 MM Gas (Bcf) Oil (MMBbl) NGL (MMBoe) Total (MMBoe) Total Production to Dec. 31, P+P Reserves at Dec. 31, 2015 (1) Total P+P Reserves (1) McDaniel & Associates Consultants Ltd. 8

9 Economics - Kaybob Montney Oil Pool West Side Capital: $2.9 MM D/C/T per well IP 30 : 640 Bbl/d oil Reserves per well: 354 MBoe (2) Bcf natural gas MBbl oil - 14 MBbl C3+ WTI $US/Bbl AECO $2.00/GJ $20 $30 $40 $50 $60 NPV 10% $MM ($0.2) $1.6 $3.1 $4.5 $5.9 BT ROR % >500 Payout years (1) Please refer to the heading "Type Curves" in the Advisories Appendix of this presentation for more information (2) Please refer to the heading Internal Estimates in the Advisories Appendix of this presentation for more information 9

10 Kaybob Presley Montney Gas Development Approximately 60 net sections with DGIIP estimate of Bcf per section (1) 5 Hz wells/section: ~ 300 potential drilling opportunities 81 horizontal wells drilled as of December 31, 2015 Potential recoverable reserves (1) of > 600 Bcf raw gas and 15 MMBbl NGLs Average D/C/T costs: ~1 mile $3.9 MM ~2 mile $5.3 MM Long-reach horizontal wells have had positive results Two (1.5 net) extended reach wells drilled in Q (1) Please refer to the heading Internal Estimates in the Advisories Appendix of this presentation for more information. DGIIP denotes Discovered Gas Initially in Place. Please refer to Oil & Gas Measures and Definitions in the Advisories Appendix for further information. 10

11 Presley Montney Gas Economics Capital: $5.3 MM D/C/T per well IP 30 : 6.8 MMcf/d NGL: $CDN 30.13/Bbl Condensate: $CDN 59.00/Bbl Reserves per well: 822 MBoe (2) 4.5 Bcf natural gas 72 MBbl NGLs AECO Gas $Cdn/GJ WTI US$ 40/Bbl $0.00 $1.00 $2.00 $3.00 NPV 10% $MM ($3.33) ($0.37) $3.13 $6.66 BT ROR % N/A Payout years N/A (1) Please refer to the heading "Type Curves" in the Advisories Appendix of this presentation for more information (2) Please refer to the heading Internal Estimates in the Advisories Appendix of this presentation for more information 11

12 Emerging Duvernay Shale Play

13 13 Duvernay Unconventional Shale Play- Kaybob Area ~75 sections in gas/condensate area ~115 additional sections in volatile oil area Participated in > 50 horizontal wells in this play to date Approximately $350 MM capital spent on Duvernay projects to date 2016 spending principally to manage expiries (~$18 MM)

14 South Kaybob Duvernay 14

15 South Kaybob Duvernay Shale Gas/Condensate Play IP 30 : 4.6 MMcf/d P+P Reserves (2) : 1,218 MBoe 4.1 Bcf Natural Gas 307 MBbl Condensate 223 MBbl NGLs Condensate to Sales Gas Ratio: 75 Bbl/MMcf Capital Cost: $11.0 MM D/C/T (multi-well pad, 2,000 m laterals) Operating Cost: $4,250/month + $0.50/Mcf AECO Gas Price: $2.00/GJ FX: $1.3 CDN / $1 US (1) Please refer to the heading "Type Curves" in the Advisories Appendix of this presentation for more information (2) Please refer to the heading Internal Estimates in the Advisories Appendix of this presentation for more information WTI $US/Bbl NPV 10% $MM ($3.4) ($0.5) $2.2 $4.9 $7.7 BT ROR % Payout years

16 North Kaybob Duvernay 16

17 North Kaybob Duvernay Shale Type Curve IP 30 : 2.0 MMcf/d P+P Reserves (2) : 856 MBoe 1.5 Bcf Natural Gas, 473 MBbl Condensate 130 MBbl NGLs Capital Cost: $9.0MM D/C/T (multi-well pad, 2,000m laterals) Condensate to Sales Gas Ratio: 312 Bbl/MMcf Operating Cost: $4,250/month +$0.50/Mcf AECO Gas Price: $2.00/GJ FX: $1.3 CDN / $1 US (1) Please refer to the heading "Type Curves" in the Advisories Appendix of this presentation for more information (2) Please refer to the heading Internal Estimates in the Advisories Appendix of this presentation for more information WTI $US/Bbl NPV 10% $MM ($2.0) $2.7 $7.2 $11.5 $16.0 BT ROR % Payout years

18 Financial Update

19 Quarterly Review 19

20 Reserves (McDaniel & Associates Consultants Ltd. at December 31, 2015) Proved Reserves Probable Reserves Reserve Category Natural Gas BCF Crude Oil MBbl NGL MBbl Total MBoe % BT NPV 10% $MM Proved Developed Producing ,377 7,051 58, Proved Developed Non-Producing ,250 1,143 4, Proved Undeveloped ,275 10,766 32, Total Proved ,902 18,959 94, Probable Developed Producing ,093 2,043 16, Probable Developed Non-Producing , Probable Undeveloped ,945 17,775 43, Total Probable ,506 20,323 63, Total Proved plus Probable ,408 39, , , % 20

21 21 Summary Extensive high working interest land base in the Deep Basin Montney oil and gas pool development opportunities Significant exposure to Duvernay Shale play Large inventory of low-risk, liquid-rich natural gas resource opportunities suitable for horizontal drilling and multi-stage fracture stimulation completion techniques Significant operated gathering and processing infrastructure in Kaybob area High capital efficiency resulting in low F & D costs Experienced staff with proven track record High insider ownership Strategy to adapt to changing commodity prices through strategic capital spending allocation

22 Advisories Appendix

23 23 Advisories Appendix Forward Looking Information Certain statements included in this document constitute forward-looking statements under applicable securities legislation. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "intend", "estimate", project, forecast, budget, goal, objective, potential, possible, probable, projected, scheduled, will, plan, propose, or similar words suggesting future outcomes, or statements regarding an outlook. Forward looking statements or information in this document include, but are not limited to statements regarding: the nature and extent of the Montney oil and gas pools and the Duvernay shale play, estimates as to the number and type of potential drilling opportunities and drilling locations therein and Trilogy's plans to delineate same; forecast capital expenditures, the amount, timing and relative allocation thereof including, without limitation, 2016 spending to manage Duvernay expiries; exploration, development and associated operational plans for the Presley Montney gas, Kaybob Montney oil and Kaybob Duvernay shale plays, including drilling and completion plans, and the scope, timing, cost and expected results thereof; projected production levels and sales volumes (including the liquids component thereof) and the timing thereof; projected drilling, completion, tie-in, operating, finding and development, royalty and other costs; estimates of reserves, DOIIP and DGIIP, including internal estimates, related to Trilogy properties and net present values associated therewith; projected type well production profiles, economics, net present value and payout estimates (including assumptions as to capital, initial production rates, NGLs and condensate yields; reserves, shrinkage, commodity pricing, royalties and other assumptions used to generate such estimates); estimates of undeveloped land holdings, estimated drilling inventories and potential drilling opportunities per section; projected commodity prices; interest rates; operating income and cash flow; net revenue; royalty rates and the expected impact of royalty programs and other incentives ; general business strategies and objectives; and statements regarding reserves, DOIIP and DGIIP 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. Such forward-looking statements or information are based on a number of assumptions which may prove to be incorrect. Assumptions have been made regarding the following matters, in addition to any other assumptions identified in this presentation or Trilogy s continuous disclosure documents: future oil, natural gas and natural gas liquids (including condensate) supply and prices; foreign currency, exchange and interest rates; Trilogy s ability to obtain on acceptable terms the required capital to finance its exploration, development and other operations in the Montney oil and gas pools and the Duvernay shale play (including credit facility availability consistent with expectations); projected capital investment levels and the successful and timely implementation of capital projects;

24 24 Advisories Appendix con't anticipated timelines and budgets being met in respect of drilling programs and other operations; the ability of Trilogy to service its debt and re-pay its debt when due; royalty rates, taxes and capital, operating, general & administrative and other costs; current production forecasts and the relative content of crude oil, natural gas and NGLs therein; geology applicable to Trilogy s land holdings; assumptions inherent in estimating reserves and resources (including internal estimates of DOIIP and DGIIP and the associated net present value) and the likelihood that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future; the ability of Trilogy and its industry partners to obtain drilling and operational results, improvements and efficiencies consistent with expectations (including in respect of anticipated production volumes, reserves additions and NGLs yields); well economics; the timing and costs of plant turnaround, pipeline and storage facility construction and expansion and the ability to secure adequate product, processing, fractionation and transportation; Trilogy s ability to obtain equipment, services and supplies in a timely manner to carry out its activities; Trilogy s ability to market oil and natural gas successfully to current and new customers; cash flow consistent with expectations; the timely receipt of required regulatory approvals; the ability of Trilogy to obtain financing and access to capital markets on acceptable terms; continuity of government royalty and regulatory regimes, including drilling and royalty incentive programs and their application to Trilogy s operations and assumptions regarding the applicability of the Alberta Government's Modernized Royalty Framework; the continuation of assumed tax regimes including estimates and availability of deferred tax amounts, tax assets and tax pools; the extent of Trilogy's liabilities; general business, economic and market conditions; and other assumptions inherent in Trilogy s current guidance. Although Trilogy believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Trilogy can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Trilogy and described in the forward-looking statements or information. These risks and uncertainties include and/or relate (but are not limited) to: fluctuations in oil, natural gas and natural gas liquids prices, foreign currency exchange rates and interest rates; the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand; risks and uncertainties involving geology of oil and gas deposits; risks associated with processing, storing, and transporting crude oil, natural gas and related products; the ability of management to execute its business plan; risks associated with obtaining timely access to areas where Trilogy s operations are to be conducted; risks inherent in Trilogy s marketing operations, including credit risk; the ability to generate sufficient cash flow from operations to meet current and future obligations, including costs of anticipated projects and repayment of debt; the uncertainty of reserves and resource estimates (including internal estimates of DOIIP, DGIIP); Trilogy s ability to replace and add production and reserves through development and exploration activities and acquisitions; the uncertainty of estimates and projections relating to production, drilling, and other costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures including without limitation the possibility that regulatory approvals may be delayed or withheld; potential disruptions or unexpected technical difficulties in designing, developing or operating new, expanded or existing facilities, including third-party operated facilities; Trilogy's ability to enter into or renew leases;

25 25 Advisories Appendix con't uncertainty regarding aboriginal land claims and consultations with local populations and industry participants; health, safety and environmental risks; uncertainties as to the availability and costs of financing; Trilogy s ability to generate sufficient cash flow from operations to meet its current and future obligations, including costs of anticipated projects and repayment of debt; Trilogy s ability to maintain targeted or required ratios within its credit and debt arrangements, and the risks of not maintaining such required ratios, including early debt repayment and/or other penalties; weather; general economic, market, industry and business conditions; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld, including risks related to the imposition of moratoriums; uncertainty in amounts and timing of royalty payments and the application of and potential changes to royalty and drilling incentive programs including without limitation the Natural gas Deep Drilling Program; imprecision in estimates of product sales tax, tax pools, tax shelter, and tax deductions available to Trilogy and changes to tax legislation and regulations applicable to Trilogy and the interpretation thereof; risks associated with Trilogy's mitigation strategies, including insurance and hedging activities; uncertainty regarding results of third party industry participants to Trilogy s development plans; changes to environmental legislation and regulations applicable to Trilogy including those relating to greenhouse gases and hydraulic fracturing among others; risks associated with existing and potential future law suits and regulatory actions against Trilogy; hiring/retaining staff; and other risks and uncertainties described elsewhere in this document or in Trilogy's other filings with Canadian securities authorities. The foregoing list of risks is not exhaustive. Additional information on these and other factors which could affect Trilogy s operations or finances are included: (1) under the heading Risk Factors in Trilogy s Annual Information Form; and (2) under the heading Management s Discussion and Analysis Advisories in Trilogy s Annual Report. The forward-looking statements and information contained in this document are made as of the date hereof and Trilogy 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. Oil and Gas Measures and Definitions This document contains disclosure expressed as "Boe", MBoe, MMBoe, Mcf, MMcf, Bcf, Bbl, MBbl and MMBbl. All oil and natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas 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 well head. For Q1 2016, the ratio between Trilogy s average realized oil price and the average realized natural gas price was approximately 14:1 ( Value Ratio ). The Value Ratio is obtained using the Q average realized oil price of $37.25 (CAD$/Bbl) and the Q average realized natural gas price of $2.70 (CAD$/Mcf). This Value Ratio is significantly different from the energy equivalency ratio of 6:1 and using a 6:1 ratio would be misleading as an indication of value. This presentation contains disclosure of Discovered Oil Initially in Place ( DOIIP ) and Discovered Gas Initially in Place ( DGIIP ). DGIIP is that quantity of gas that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of gas that is estimated, as of a given date, to be commercial and contained in known accumulations prior to production. DOIIP is that quantity of oil that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of oil that is estimated, as of a given date, to be commercial and contained in known accumulations prior to production. In each case where used herein, DOIIP or DGIIP is the most specific category that could be assigned. There is no certainty that it will be commercially viable to produce any portion of this DOIIP or DGIIP. The estimated net present values discussed in this document do not represent fair market value.

26 26 Advisories Appendix con't Internal Estimates In this presentation, Trilogy has provided information with respect to its Kaybob Montney oil and gas assets and Duvernay shale play which is analogous information as defined in NI This analogous information includes management s internal estimates of DOIIP and DGIIP, as defined in the Canadian Oil and Gas Evaluation Handbook ( COHEH ) and/or production type curves in respect of proved plus probable reserves. Except as noted, this analogous information is presented on an area basis utilizing data derived from Trilogy s internal sources based on existing wells as well as from a variety of publicly available information sources which are predominantly independent in nature. These internal estimates are subject to the specific assumptions identified by Trilogy in respect of such estimates plus other assumptions contained herein (including the forward-looking information advisories), and are not necessarily representative of the actual resources or production rates associated with Trilogy s properties and wells. Estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. Type Curves - Production type curves are based on a methodology of analog, empirical and theoretical assessments and reservoir modelling with consideration of the specific asset, and as depicted in this presentation, is representative of Trilogy s current program and interpretation. Some of this data may not have been prepared by qualified reserves evaluators or auditors and may have been prepared based on internal estimates. Estimates by engineering and geo-technical practitioners may vary and the differences may be significant. Trilogy believes that the provision of this analogous information is relevant to Trilogy s oil and gas activities, given its acreage position and operations (either ongoing or planned) in the areas, and such information has been updated as of the date hereof unless otherwise specified. The type curves presented are indicative of the average production volumes of analogous wells within the Company s area of interest that are geologically similar to the applicable prospect type. In the case of the Montney Oil Pool, the type curve presented is in respect of the west half of the pool, which has delivered better results as compared to the east half of the pool. Due to the relative immaturity of the Duvernay shale play, type curves for this play are less reliable than for other, more mature plays. No reserves or resources other than reserves are assigned to or associated with these type curves. There is no certainty that it will be commercially viable to produce any portion of the estimated volumes. Type curves should not be relied upon to predict actual well performance or be interpreted as applying equally throughout a play. Potential Drilling Opportunities - Disclosure regarding drilling opportunities and locations is based on internal estimates, may include proved, probable and unbooked locations, and assumes a number of wells that can be drilled per section based on industry practice and internal review. The drilling locations which Trilogy will actually drill will ultimately depend upon the availability of capital, regulatory and partner approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. No reserves or resources other than reserves are assigned or associated with the locations/ opportunities. Condensate gas ratios ( CGRs ) for wells are calculated by dividing total condensate produced by total raw natural gas produced at the wellhead. Sales volumes will be lower due to shrinkage. Finding & Development Costs: This document contains disclosure regarding finding and development ( F&D ) costs. The aggregate of the exploration and development costs incurred 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. Non-GAAP Measures Advisory Certain measures used in this document, including funds flow from operations, operating income, net debt, finding and development costs, operating netback and recycle ratio collectively the Non GAAP measures do not have any standardized meaning as prescribed by IFRS and previous GAAP and, therefore, are considered Non-GAAP measures. Non-GAAP measures are commonly used in the oil and gas industry and by Trilogy to provide shareholders and potential investors with additional information regarding the Company s liquidity and its ability to generate funds to finance its operations. However, given their lack of standardized meaning, such measurements are unlikely to be comparable to similar measures presented by other issuers. Funds flow from operations refers to the cash flow from operating activities before net changes in operating working capital. The most directly comparable measure to funds flow from operations calculated in accordance with IFRS is the cash flow from operating activities. Funds flow from operations can be reconciled to cash flow from operating activities by adding (deducting) the net change in operating working capital as shown in the consolidated statements of cash flows. "Net debt" is calculated as current liabilities minus current assets plus long-term debt. Management utilizes net debt as a key measure to assess the liquidity of the Company. Operating income is equal to petroleum and natural gas sales before financial instruments and bad debt expenses minus royalties, operating costs, and transportation costs. Operating netback refers to Operating income plus realized financial instrument gains and losses and other income minus actual decommissioning and restoration costs incurred. The components described for operating income, operating netback and net debt can be derived directly from Trilogy s consolidated financial statements. Finding and development costs refers to all current year net capital expenditures, excluding property acquisitions and dispositions with associated reserves, and including changes in future development capital on a proved and proved plus probable basis. Finding and development costs per Barrel of oil equivalent ( F&D $/Boe ) is calculated by dividing finding and development costs by the current year s reserve extensions, discoveries and revisions on a proved or proved plus probable reserve basis. Recycle ratio is equal to Operating netback on a production barrel of oil equivalent for the year divided by F&D $/Boe (computed on a proved or proved plus probable reserve basis as applicable). Investors are cautioned that the Non-GAAP measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with IFRS, as set forth above, or other measures of financial performance calculated in accordance with IFRS.

27

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