Transformational Acquisition Increases Growth Profile

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1 Transformational Acquisition Increases Growth Profile CAPP Scotiabank Investment Symposium April 11-12, 2017 T V E : T S X 1

2 Forward Looking Information Certain information included in this presentation constitutes forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as anticipate, believe, expect, plan, intend, estimate, propose, project or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this presentation may include, but is not limited to, (i) potential development opportunities and drilling locations, expectations and assumptions concerning the success of future drilling and development activities, the performance of existing wells, the performance of new wells, decline rates, recovery factors, the successful application of technology and the geological characteristics of properties, (ii) cash flow, (iii) oil & natural gas production growth, (iv) debt and bank facilities, (v) primary and secondary recovery potentials and implementation thereof, (vi) potential acquisitions, (vii) drilling, completion andoperating costs, and (viii) realization of anticipated benefits of acquisitions. Forward-looking information is based on a number of factors and assumptions which have been used to develop such information but which may prove to be incorrect. Although the proposed management believes that the expectations reflected in its forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because there can be no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding and are implicit in, among other things, expectations and assumptions concerning the performance of existing wells and success obtained in drilling new wells, anticipated expenses, cash flow and capital expenditures and the application of regulatory and royalty regimes. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Forward-looking information is 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 the proposed management and described in the forward-looking information. The forward-looking information contained in this presentation is made as of the date hereof and the proposed management undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward looking information contained in this presentation is expressly qualified by this cautionary statement. This presentation contains the term net backs which is not a term recognized under IFRS. This measure is used by the proposed management to help evaluate corporate performance as well as to evaluate acquisitions. Management considers net backs as a key measure as it demonstrates its profitability relative to current commodity prices. Operating net backs are calculated by taking total revenues and subtracting royalties, operating expenses and transportations costs on a per BOE basis. BOE Disclosure The term barrels of oil equivalent ( BOE ) may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All BOE conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil. In this presentation: (i) mcf means thousand cubic feet; (ii) mcf/d means thousand cubic feet per day (iii) mmcf means million cubic feet; (iv) mmcf/d means million cubic feet per day; (v) bbls means barrels; (vi) mbbls means thousand barrels; (vii) mmbbls means million barrels; (viii) bbls/d means barrels per day; (ix) bcf means billion cubic feet; (x) mboe means thousand barrels of oil equivalent; (xi) mmboe means million barrels of oil equivalent and (xii) boe/d means barrels of oil equivalent per day. This presentation is not an offer of the securities for sale in the United States. The securities have not been registered under the U.S. Securities Act of 1933, as amended, and may not be offered or sold in the United States absent registration or an exemption from registration. This presentation shall not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of the securities in anystate in which such offer, solicitation or sale would be unlawful. 2

3 2017 Plan Highlights Top priorities: Achieve 7-8% production per share growth (Q4/17 to Q4/16) Increase oil weighting to at least 52% from 45% in Q4/16 Increase in oil weighting will result in higher cash flow netbacks; forecasting 15-18% increase under normalized prices Overall retain financial flexibility by keeping debt to cash flow < 1.0 times to protect downside risk of commodity price volatility while leaving the option to accelerate growth How is this accomplished? Continue to fund projects that build long term value and achieve highest rate of return Capital allocated to projects with 1.5 or less payouts or better Increase corporate netbacks by drilling in higher oil weighted areas Improve capital efficiency through program drilling, longer reach wells and drilling in areas with existing under utilized infrastructure capacity 3

4 Debt to production ($000 s of debt per boe/d) Debt to trailing (12-month) cash flow ratio Production (boe/d) Production per share (boe/d per million shares) Building Per Share Growth While De-levering Achieving Leverage Neutral Production Per Share Growth 25,000 23,000 21,000 19,000 17,000 15,000 13,000 11,000 9,000 7,000 5,000 3,000 1,000 Leverage neutral prod n per share growth of 10% and 186% prod n growth over last 3 years Oil & liquids Natural gas Prod'n per share Completed Echoex Ltd. acquisition Completed $60 Sure mm Energy equity acquisition financing ,000 Q4/14 Q4/15 Q4/16 Q4/17 est* 90.0 Leverage neutral adjusts shares outstanding to adjust debt to 1.0x Q4 annualized D/CF Reducing Debt Debt per boe/d prod n decreased by 60% and debt to cash flow by 47% over last 3 years Debt to BOE Debt to Cash Flow Q4/14 Q4/15 Q4/16 Q4/17 est* Majors began exiting WCSB Closed transformational Wilson Creek Acquisition $168.5 mm Focus: Production per share growth 2015 Severe commodity downturn 2015 Focus: Strengthen balance sheet and position for accretive acquisitions: acquired Cardium assets in Wilson Creek $54 mm 2016 High quality assets at low part of the cycle Acquired strategic asset packages: Penny and Redwater $85 mm; transformational Viking Acquisition $407.5 mm 2017 Focus: Production per share growth 4 * 2017 estimates based on achieving internal production targets

5 Tamarack Corporate Snapshot TVE : TSX 5 Operational 2017 Guidance Average production (boe/d) 19,000 20,000 % Liquids average production Exit Q4 avg. production (boe/d) 20,000 21,000 % Liquids exit production Cash flow ($mm) Not disclosed Capital (excluding acquisitions) ($mm) Exit debt to cash flow (Q4/17 annualized) < 1.0 Corporate Shares outstanding (mm) Fully diluted (mm) Share price April 3, 2017 $2.90 Market cap ($mm) (F.D.) $690 Enterprise value ($mm) (F.D.) $828 Available bank line ($mm) $220 Est. net debt on January 11, 2017 ($mm) $138 Average Price Assumptions 2017 Guidance WTI ($/bbl) Edmonton Par ($/bbl) AECO ($/GJ) 2.65 Canadian dollar 0.76 First Half 2017 Guidance Average production (boe/d) 18,500 19,000 % Liquids average production Capital (excluding acquisitions) ($mm) Exit debt to cash flow (Q2/17 annualized) < Tamarack will adjust spending levels as commodity prices fluctuate.

6 2017 Production (boe/d) 2017 CFPS Growth to 2016 (%) 2017 CAPEX ($millions) *2017 Cash Flow Netback ($/boe) Sensitivities to Oil Prices Maintaining Q4/17 D/CF at 1.0x CAPEX Sensitivities to Oil Prices 157 Completed Echoex Ltd. acquisition 165 Completed $60 Sure mm Energy equity acquisition financing Cash Flow Netback Sensitivities to Oil Prices $18.35 $19.80 $ ,000 19,000 17,000 15,000 6 $48 $50 $55 Oil Prices ($WTI/bbl)** 2017 Production Sensitivities to Oil Prices 20,000 19,000 19,300 $48 $50 $55 Oil Prices ($WTI/bbl)** 0 * Excludes the effect of hedges ** Natural gas price $2.50 AECO $48 $50 $55 21% Oil Prices ($WTI/bbl)** 2017 CFPS % Growth to 2016 Sensitivities to Oil Prices 31% Oil Prices ($WTI/bbl)** 40% $48 $50 $55

7 Financial Stats per BOE 2015 Actuals 2016 Actuals 2017 Budget Average pricing $48.80/bbl WTI $43.32/bbl WTI $55.00/bbl WTI Edm Par $56.95/bbl $51.69/bbl $64.47/bbl AECO (monthly index) $2.63/GJ $2.00/GJ $2.65/GJ $/boe Revenue Royalties 3.43 (10.0%) 2.32 (8.0%) 4.65 (11%) Operating costs Operating income G&A Interest Hedge (gains) / losses (5.67) (3.25) 0 (0.25) Cash flow* * Excludes transaction costs 7... Tamarack is expecting cash flow netbacks to improve 15-20% excluding hedges, with the increase in corporate oil weighting from 45% to 52%.

8 Current Hedges as at March 17, 2017 Term Hedge Type Volume Cdn Pricing January 1, 2017 to March 31, 2017 WTI fixed price 3,000 bbls/d Cdn $63.12/bbl April 1, 2017 to June 30, 2017 WTI fixed price 3,000 bbls/d Cdn $63.88/bbl July 1, 2017 to September 30, 2017 WTI fixed price 2,300 bbls/d Cdn $68.40/bbl WTI fixed price 400 bbls/d US $55.23/bbl October 1, 2017 to December 31, 2017 WTI fixed price 2,000 bbls/d Cdn $70.83/bbl 2017 average Cdn$66.04/bbl & US$55.14/bbl WTI fixed price 600 bbls/d US $55.08/bbl January 1, 2018 to March 31, 2018 WTI fixed price 200 bbls/d Cdn $73.50/bbl WTI fixed price 600 bbls/d US $55.07/bbl Term Hedge Type Volume Cdn Pricing January 1, 2017 to March 31, 2017 AECO fixed price swap 23,000 GJ/d Cdn $2.88/GJ April 1, 2017 to June 30, 2017 AECO fixed price swap 23,000 GJ/d Cdn $2.60/GJ July 1, 2017 to September 30, 2017 AECO fixed price swap 23,000 GJ/d Cdn $2.63/GJ 2017 average Cdn $2.75/GJ October 1, 2017 to December 31, 2017 AECO fixed price swap 23,000 GJ/d Cdn $2.90/GJ January 1, 2018 to March 31, 2018 AECO fixed price swap 21,000 GJ/d Cdn $3.15/GJ % of crude oil production and over 50% of gas production net of royalties are hedged for 2017.

9 Significant Cardium and Viking Light Oil Production Q Production* BOE/D % Liquids ALBERTA VIKING OIL CARDIUM OIL Redwater Edmonton Alder Flats Wilson Creek Garrington Lochend Calgary SASKATCHEWAN Lloydminster Veteran / Hoosier Saskatoon Cardium 7,380 53% Redwater Viking 1,150 92% Penny 1,160 69% Other 1,763 23% Total TVE 11,453 55% Spur Viking* 6,600 57% Pro forma 18,053 56% * Production at closing Jan 11/17 Regina Penny Barons Sand Lethbridge 9 All three oil plays have the same rock characteristics and utilize the same multi-fracture technology.

10 Viking Oil Infrastructure net sections of consolidated Viking Strategic owned and operated infrastructure Production estimated at close of 6,250 boe/d (52% liquids) Low operating costs < $11/boe 720 (695 net) locations Waterflood upside Rich in bolt-on opportunities

11 Veteran Viking Oil UPPER VIKING HZ TARGET UPPER SST-THICKER, FINE TO MEDIUM GRAINED DECENT PERMEABILITY NEGELECTED HISTORICALLY HAMILTON LAKE SST LOWER SST-THINNER, MEDIUM TO VERY COURSE GRAINED HIGH PERMEABILITY HISTORICALLY TARGETED ZONE Drilling 17 (16.5 net) wells in Q1/17 Forecasting 84+% oil weighting on new drills Up to 14 million bbls OOIP per section Re-oriented well placements to realize benefit of Hamilton Lake zone pressure support Current drilling inventory count assumes 200m well spacing, testing 150m and 100m spacing Infrastructure capacity to more than double oil production Initiate waterflood study and simulations to determine benefits 11 Q1/17 Veteran drilling program could lead to significant increase in new reserve bookings and additional drilling inventory.

12 bbls/d bbls/d 2017 Veteran Drills Horizontal Wells Q1/17 drills H2/17 drills Pre 2017 Horizontal Wells* Days on Production Days on Production *Normalized to 925m Early drilling results are on type curve and slightly higher than risked type curve used to build production guidance.

13 North Hoosier / Milton Viking Oil North Hoosier NEW HZ TARGET UPPER SST- THICKER, FINER GRAINED WITH LOWER GOR Hoosier Milton TVE land Existing wells Q1/17 drills Viking oil trend HISTORIC TARGET (HZ & VERT) LOWER SST- THINNER, COARSER GRAINED WITH HIGHER GOR North Hoosier drilling 4 net wells in Q1/17 Milton drilling 13 (10.6 net) wells in Q1/17 Testing Upper Viking zone in North Hoosier; conduct pressure tests to determine connectivity of Upper & Lower Viking; could lead to additional drilling inventory and reserve bookings Milton area has 14 (6-8 net) meters of Viking pay; up to 8-10 million bbls OOIP per section Milton drilling program to add additional production and reserves; de-bottlenecking infrastructure (approx. $1.5 million) to reduce line pressures and reduce third party processing fees 13 This area continues to demonstrate oil weighting and production rates higher than acquisition expectations.

14 BOE/D BOE/D 2017 Milton Viking Drills Q1/17 drills H2/17 drills Horizontal Wells Pre 2017 Horizontal Wells Days on Production Days on Production Early drilling results are slightly higher than type curve and higher than risked type curve used to build production guidance.

15 Un-risked Half Cycle Economics Number of net locations 1.5 year payout or less* Veteran/Consort Viking Half Cycle Economics N. Hoosier/ Milton Viking Wilson Creek Cardium Penny Barons Alder Flats Higher GOR Cardium Capital ($000s) ,585 3,175 2,835 Rate IP30 (boe/d) (liquid weighting) 73 (84%) 116 (74%) 393 (80%) 312 (95%) 645 (40%) Risked Rate IP budget (boe/d) Reserves (mboe) Finding costs ($/boe) $14.67 $15.25 $14.09 $11.8 $9.15 Recycle ratio NAV PV10BT ($000s) $697 $628 $4,450 $4,450 $1,516 Payout (years) ROR (%) 103% 198% 286% 100% 49% * Excludes 44 locations in the Other category which are primarily made up of Hatton and Mannville gas Commodity price assumptions $65/bbl Edm par or $55/bbl US WTI and $2.55/GJ AECO Viking oil inventory competes with Tamarack s existing high quality, quick payout Cardium inventory.

16 Quick Payback Drilling Inventory Payout 1.5 Years or Less Tamarack Quick Payback Drilling Inventory (<1.5 years) Oct ,400 1,200 1, Other (Hatton, Mannville) Spur Viking* Redwater Penny Cardium Estimate of booked PUD locations Total $64/bbl WTI, >25% ROR Over 1,300 Locations ,046 1, Edm. Par (CDN $/bbl) WTI USD/bbl $30.00 $40.00 $50.00 $60.00 $70.00 $80.00 $90.00 $22.50 $30.00 $37.60 $45.10 $52.60 $60.15 $ * Spur Viking inventory based on 200 m well spacing in Veteran... Acquisition adds material inventory with a 4x increase to Tamarack s existing quick payout inventory.

17 Key 6 Month Objectives and Look-back What we said we would do H2/16 prod n average 9,800 10,500 boe/d on capital of $20-22 million. Integrate new assets, implement TVE operating procedures in field; drive business focus to netbacks. What we did in Q / Q Produced over 11,100 boe/d in H2/16, capital inline with expectations; accelerated drilling 3 net 2017 Cardium wells in late Integrated Redwater and Penny assets; executed well workovers and increased water injection resulting in better than expected production. Objectives for H Average 18,500 19,000 boe/d H1/17 on $75 million capex resulting in capital efficiency of approx. $19,000/boepd on 32-33% corporate decline rate. Integrate new Spur assets; execute net well Q1/17 Viking oil drilling program. Execute cost saving and prod n additions on new assets: WF pattern review; cut opex in Redwater by $4/boe; re-direct remaining volumes in Wilson Creek going through third party facilities. Complete TAQA farm-in; drill last well by Q4/16. Integrate NRF including new waterflood and recompletion royalties; execute at least one HZ recompletion. Expand Wilson Creek truck terminal and identify business case to replicate in Redwater. Apply M&A criteria to do tuck-in acquisitions in core areas. Continue to review larger opportunities outside of existing operations. Seek regulatory approval for surface access and for HZ royalty for Penny HZ drilling. Redwater operating costs reduced by >$5/boe and Penny by $2/boe contributing to operating cost beat in Q3/16; 100% of Wilson Creek volumes now going through owned facilities. Taqa farm-in completed; agreement terminated; opportunity for tuck-in. NRF integrated; one HZ well drilled in Penny and executed one HZ recompletion in Wilson Creek Wilson Creek truck terminal expansion completed; still evaluating Redwater project. Completed Spur Resources acquisition adding a new core area that fits M&A criteria. Drilled one HZ Penny well. Implement Q1/17 learnings into H2/ well Viking oil drilling program; plan to reduce capital costs per well to target $650k. Increase Corporate oil weighting from 45% in Q4/16 to 48-49% in Q2/17, resulting in increased corporate netbacks per boe. Complete Spur third party reserve report effective Jan 31/17 and disclose pro-forma reserves with TVE year-end reserve report in 2017 AIF by March 24 th. Develop highest economic exploitation plan for Viking oil: optimal well densities, ERH applications, deliver waterflood study. Deliver new royalty program in Penny for summer drilling program. 17

18 18 Summary Prudent Management through Commodity Downturn Stopped spending at the right time, cut opex, capex and G&A to improve sustainability Paid down debt in 2015 and 2016 yet delivered modest growth using high quality drilling with lower cost structure and added significant inventory Lever off Strengths: Historical Operational Execution Delivered better than guided results on three major asset acquisitions over the past 3 years (Wilson Creek Cardium and Redwater Viking, Penny) Strategic infrastructure ownership in core areas resulted in lowest cost producer; able to accelerate growth quickly 2017 Focus Integrate new Viking assets into Tamarack operations and continue to improve efficiencies through program drilling Define upside above plan with successful Q1 drilling results, cost reductions on larger program drilling on Viking in Q3 and through a Viking waterflood study Continue to decrease costs capitalizing, on recently acquired infrastructure Deliver production and cash flow per share growth, while maintaining strong balance sheet

19 19 Appendix

20 EDM Light $/BBL Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 $million Production (boe/d) 2016 Acquisition Lookback- Significant Value Added AQN Cost vs Current Reserves Evaluation ($84.2) Acquisition ($6.0) Capital Oil Forecast Oil Acquistion Gas Forecast Gas Acquisition $7.0 NOI $110 PDP $53 Proved Pricing Assumptions $247 P+P AECO $/GJ 3,000 2,500 2,000 1,500 1, Actual Forecast Production Performance 11 Month Production Total Actuals= 690 mboe Forecast= 550 mboe Increase= 25% Produced 25% more than predicted to date Decline is flat relative to original acquisition forecast Invested $90 million (acquisition & capex) resulting in: $110 million of PDP (1.2x) and $247 million of reserve 2P value (2.7x)