T V E : T S X. Predictable & Sustainable Per Share Growth

Transcription

1 T V E : T S X Predictable & Sustainable Per Share Growth

2 Disclaimers Forward Looking Statements 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, statements about: our corporate strategy, including a new frac strategy in Cardium; timing and level of 2018 capital expenditures; future acquisition and disposition opportunities, including tuck-in acquisitions in core areas; future production levels; 2018 netbacks and cash flows; 2018 exit debt, annual and exit production and unutilized liquidity on existing credit facilities; oil and liquids weighting and changes thereto; development opportunities, including the expansion of the oil battery in Veteran; drilling locations; economics and payouts of our wells; corporate decline rate; future waterflood, land and seismic investments; and future commodity prices and exchange rates. Statements relating to reserves are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. 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. 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, the success of future drilling, development and completion activities, the performance of existing wells, the performance of new wells, the performance of enhanced oil recovery projects, the availability and performance of facilities and pipelines, the geological characteristics of Tamarack s properties, the successful application of drilling, completion and seismic technology, prevailing weather and break-up conditions and access to our drilling locations, commodity prices, royalty regimes and exchange rates, the application of regulatory and licensing requirements, the availability of capital, labour and services, our ability to complete planned capital expenditures within budgeted cost estimates, the ability to market our and gas successfully, our ability to integrate assets and employees acquired through acquisitions, the creditworthiness of industry partners and our ability to acquire additional assets. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Although Tamarack believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Tamarack can give no assurance that they will prove to be correct. 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), incorrect assessment of the value of acquisitions, failure to realize the benefits of acquisitions, constraint in the availability of services, commodity price and exchange rate fluctuations, changes in legislation (including but not limited to tax laws, royalty regimes and environmental legislation), adverse weather or break-up conditions and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Production forecasts are directly impacted by commodity prices and the actual timing of our capital expenditures. Actual results may vary materially from forecasts due to changes in interest rates, oil differentials, exchange rates and the timing of expenditures and production additions. These and other risks are set out in more detail in Tamarack s Annual Information Form (the AIF ) for the year ended December 31, The AIF can be accessed either on Tamarack s website at or under Tamarack s profile on 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 forwardlooking 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. FOFI Disclosure. This presentation contains future-oriented financial information and financial outlook information (collectively, FOFI ) about Tamarack s prospective results of operations, debt, net debt, cash flow, adjusted funds flow, net debt to cash flow/ adjusted funds flow ratio, cash costs, debt adjusted production per share ( DAPPS ), netbacks, operating netbacks, adjusted operating field netbacks, operating costs and components thereof, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs and the assumption outlined in the Non-IFRS measures section below. FOFI contained in this presentation was made as of the date of this presentation and was provided for the purpose of providing further information about Tamarack s anticipated future business operations. Tamarack disclaims any intention or obligation to update or revise any FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this presentation should not be used for purposes other than for which it is disclosed herein. Abbreviations bbls barrels WTI West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade mmcf/d million cubic feet per day P3 proved + probable + possible reserves bbls/d barrels per day AECO the natural gas storage facility located at Suffield, Alberta, connected to TransCanada s Alberta System BOPD barrels of oil per day ERH extended reach horizontal boe/d barrels of oil equivalent per day IFRS International Financial Reporting Standards as issued by the International Accounting Standards Board NAV net asset value EUR estimated ultimate recovery 2 GJ gigajoule ROR rate of return TTM trailing twelve months FX foreign exchange 2

3 Disclaimers (continued) Oil and Gas Advisories Reserves Disclosure. All reserve references in this presentation are to gross reserves as at the effective date of the applicable evaluation. Gross reserves are Tamarack s total working interest reserves before the deduction of any royalties and including any royalty interests of Tamarack. The recovery and reserve estimates of Tamarack s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. It should not be assumed that the present worth of estimated future cash flow presented herein represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of Tamarack s crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein. Type Curves. Certain type curves disclosure presented herein represents estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. The type curves represent what management thinks an average well will achieve, based on methodology that is analogous to wells with similar geological features. 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. 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 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. OOIP Disclosure. The term original-oil-in-place ( OOIP ) is equivalent to total petroleum initially-in-place ( TPIIP ). TPIIP, as defined in the Canadian Oil and Gas Evaluation Handbook, is that quantity of petroleum that is estimated to exist in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. A portion of the TPIIP is considered undiscovered and there is no certainty that any portion of such undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. With respect to the portion of the TPIIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce any portion of such discovered resources. A significant portion of the estimated volumes of TPIIP will never be recovered. US Registration. 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 any state in which such offer, solicitation or sale would be unlawful. Non-IFRS Measures. Certain financial measures referred to in this presentation, such as net debt, DAAPS, cash flow, adjusted funds flow, net debt to cash flow/ adjusted funds flow ratio, adjusted operating field netbacks and net debt to adjusted operating field netback ratio are not prescribed by IFRS. Tamarack uses these measures to help evaluate its financial, operating performance, and liquidity and leverage. These non-ifrs financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other issuers. Net debt is calculated as long-term debt plus working capital surplus or deficit adjusted for risk management contracts. Debt adjusted production per share (DAAPS) represents Tamarack s production per share after adjusting for debt. Cash flow is determined as gross oil, natural gas and natural gas liquids revenues including realized gains on commodity risk management contracts, less the following: royalties, operating costs, transportation costs, general and administrative costs and finance expenses. Adjusted funds flow is calculated based on cash flows from operating activities before changes in non-cash working capital, transaction costs and decommissioning obligation expenditures incurred. Net debt to cash flow/ adjusted funds flow is calculated as net debt divided by cash flow/ adjusted funds flow. Adjusted operating field netbacks are calculated by reducing operating netback by interest expenses and general and administrative expenses as shown on slides 11 and 24. Net debt to adjusted operating field netback ratio is calculated as net debt divided by adjusted operating field netback. This presentation contains metrics commonly used in the oil and natural gas industry, such as operating netbacks (calculated on a per unit basis as oil, gas and natural gas liquids revenues less royalties, hedging gains (losses) and operating costs as shown on slide 11). These terms have been calculated by management and do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Tamarack s operations over time. 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. 3 3

4 Proven Management Team Brian Schmidt President & CEO Ron Hozjan VP Finance & CFO Dave Christensen VP Engineering Kevin Screen VP Production & Operations Scott Reimond VP Exploration Ken Cruikshank VP Land Spearpoint Energy - President & CEO; sold to NAL Oil & Gas Trust in Aug 2009 Apache Canada (7 yrs) President for last 3 yrs. Grew from 17,000 to 120,000 boe/d during tenure; invested $4.5 billion earning 28% ROR Shell Canada (19 years) Currently, Board of Governors of CAPP and Indian Oil & Gas Co-Management Board member Vaquero Resources - VP Finance & CFO; sold to RMP Energy Vaquero Energy - VP Finance & CFO; merged with Highpine Oil & Gas Limited Storm Energy, Beau Canada Exploration Ltd. & Renaissance Energy - senior finance positions Over 20 years with CFO experience and over 30 years of oil and gas experience Bonavista Energy (5 yrs) - Development Engineering Manager - West Region (areas where Tamarack s Cardium assets are situated) for 4 yrs and managed production growth from 15,000 boe/d to 45,000 boe/d Norcen Energy, Storm Energy, Piper Energy - various management positions Over 30 years of oil & gas experience Apache Canada (9 years) - Production Engineer, Asset Team Leader and Manager Horn River Business Unit. Grew from 20 mmcf/d to 250 mmcf/d during tenure Apache + Shell Canada - various management positions (started career at Shell in 1989) Over 25 years of oil & gas experience Spearpoint Energy (Senior Geologist), Rock Energy and Fletcher Challenge Energy Apache Canada (4 years) and started career at Suncor Active member of the Association of Professional Engineers and Geoscientists (APEGA) Over 20 years of oil & gas experience as a geologist working E&D projects in Western Canada Vaquero Resources - VP Land; sold to RMP Energy Vaquero Energy - VP Land; merged with Highpine Oil & Gas Limited Beau Canada Exploration Ltd (7 yrs) - VP Land. Grew from 2,150 boe/d to 21,900 boe/d during tenure Over 35 years of oil & gas experience 4 4

5 Tamarack Valley Sustainable Growth into 2018 Market Summary TVE: TSX Share price $4.68 Shares outstanding (mm) Fully diluted (mm) Average 20-day trading volume (shares) (TTM) 1,380,000 Available bank line ($mm) $290 Percentage drawn (%) 62% Capital Structure Market capitalization (F.D.) ($mm) (1) $1,067 Enterprise value (1) $1,248 Drilling inventory in place for long-term, sustainable per share growth at current commodity prices. (1) Market capitalization and enterprise value based on TVE share price as at September 6, (2) See Disclaimers Non-IFRS Measures. (3) See disclosures on slide 11 and 24 for calculation explanation and reconciliation. +985,000 Tamarack s executive increased ownership by over 985,000 shares in 2017 & H1/18 NCIB Purchased and cancelled 1,081,000 shares and purchased 970,000 shares to settle future RSU s Net debt at June 30, 2018 (including net working capital) ($mm) (2) $181 Net debt to adjusted operating field netback ratio (2)(3) 0.7x 0.7x Q2/18 net debt to adjusted operating field netback ratio (2) 5 5

6 Managing Through a Commodity Downturn Optimizing Returns During Various Commodity Price Cycles LOWER COMMODITY PRICES Immediately cut capital to protect balance sheet Redesign wells to achieve profitability in a low price environment Acquire high-quality assets at attractive metrics in low price environment CAPITAL ALLOCATION STRATEGY HIGHER COMMODITY PRICES Focus on program development to increase rate of return on capital Shift strategy to achieve organic per share growth Generate superior netbacks, stronger production, reserves and cash flow growth per share 6 6

7 Executing a Longer-Term Strategy For Success Taking the right action at the right time in the commodity price cycle FOCUS ON DEBT REDUCTION Q1 2015: 2.2x D/CF (1) Production = 8,092 boe/d Q2 2018: 0.7x D/CF (1) Production = 23,853 boe/d Q ASSEMBLED ASSET BASE WITH LONG RUNNING ROOM Core Cardium & Viking operating areas with potential to double production Significant inventory of drilling locations with <1.5 yr payouts Controlled infrastructure enables growth and controls costs Land prices lowest in years REDUCE & REALLOCATE CAPITAL Focus on highest return projects Use new technology plus redesign drilling & completion techniques to optimize well economics CAPITALIZE ON ACCRETIVE HIGH QUALITY ACQUISITION OPPORTUNITIES : Closed numerous tuck-in acquisitions Summer 2016: Closed two acquisitions and formed new core areas, Wilson Creek & Penny January 2017: Closed transformative Spur acquisition FOCUS ON PER SHARE GROWTH Commodity price recovery or decline will drive capital allocation decisions Improving netbacks (1) Based on period end net debt to annualized cash flow / adjusted funds flow for the quarter. 7 7

8 How Our Strategy is Working Another production beat H1/18 at 23,693 boe/d vs. guidance range 22,750 to 23,250 boe/d Strong liquids weighting at 63% driven by capital shift to oil weighted drilling First half production beat primarily due to the outperformance of the Viking assets acquired in 2017 Replaced 1.2x inventory drilled in 2017 and now have 9 years of drilling focused in Cardium and Viking light oil Q netbacks (excluding hedging) improved by 55% over Q2/17; 18% from increasing oil weighting and cutting operating costs (1) and by 37% due to higher oil prices Management increased ownership by over 985,000 shares since Jan 2017 Q2/18 was the strongest quarter in Tamarack s history (1) Forecast only. Actual results may differ due to a number of factors. See Disclaimers Forward Looking Statements 8 8

9 2018 Areas of Focus ALBERTA VIKING OIL SASKATCHEWAN Q Production BOE/D % Liquids Viking light oil 12,163 72% Cardium light oil 9,005 55% Penny light oil 1,273 72% Other 1,412 32% Total 23,853 63% CARDIUM OIL Alder Flats Wilson Creek Lochend Edmonton Calgary Redwater Veteran Penny Barons Sand Lethbridge Lloydminster Hoosier Milton Saskatoon 2018 Budgeted Capi tal Drills (net) Capex ($ millions) % Viking oil 87.4 $ % Cardium oil 17.3 $ % Other oil (Penny, Redwater) 11.7 $ % Land, Seismic, Facilities n/a $ % Total $205.0 (1) Regina (1) Excluding M&A expenditures and tuck-ins and 2019 capital acceleration. Tamarack Valley Energy is focused on tight light oil in the Viking and Cardium. 9 9

10 2018 Plan & Preliminary 2019 Plan 2018 Guidance (1) Annual production increased to 23,500 24,000 boe/d (64-66% oil & liquids) (10-15% DAPPS growth) Exit production between 24,000 24,500 boe/d (65-67% oil & liquids) (7-10% DAPPS growth) Capital expenditures of $205 million plus 2019 capex acceleration of $28 million, within projected adjusted operating field netbacks (2) Estimated year end 2018 debt to fourth quarter annualized adjusted operating field netback ratio of less than 1.0 times, with an estimated $100+ million of liquidity on existing credit facilities (2) 2019 Prelim Guidance (1) Annual production between 25,000 26,000 boe/d (65-67% oil & liquids) (10-15% DAPPS growth) Exit production between 27,500 28,000 boe/d (66-68% oil & liquids) (10-15% DAPPS growth) Capital expenditures of $250 million including $28 million spent in late 2018, within projected adjusted operating field netbacks (2) 2019 Price Assumptions WTI US$60.00/bbl, Edmonton Par Cdn$68.50/bbl AECO $1.65/GJ expecting to receive $ /GJ higher than AECO in 2019 due to recent physical marketing arrangements that removed AECO exposure for 40% of natural gas volumes in 2019 Canadian / US dollar exchange rate of $ (1) Forecast only. Actual results may differ due to a number of factors. See Disclaimers Forward Looking Statements. (2) See Disclaimers Non-IFRS Measures and slide 11 and 24 for reconciliation. 10

11 11 Financial Stats per BOE 2017 Actuals Q4/17 Q1/18 Q2/ Budget WTI ($USD) $51.00/bbl $55.39/bbl $62.91/bbl $67.88/bbl $56.75/bbl Edm Par ($Cdn) $62.23/bbl $66.86/bbl $72.30/bbl $78.90/bbl $64.60/bbl AECO ($Cdn) (monthly index) $2.41/GJ $1.95/GJ $1.84/GJ $1.02/GJ $1.65/GJ Financial stats ($/boe) Revenue Hedge gains / (losses) (0.59) (3.36) 0.25 Royalties 3.96 (10%) 4.03 (9%) 5.16 (11%) 5.06 (10%) 4.50 (11%) Operating costs Operating netback G&A Interest Adjusted operating field netback (1) Adjusted operating field netbacks (1) are expected to improve in 2018, with a reduction in cash costs and an increase in the corporate liquids weighting from 62% to 67%. (1) Adjusted operating field netback is a non-ifrs measures. See Disclaimers Non-IFRS Measures and reconciliation on slide

12 Cash Netbacks (excl. hedges $/boe) Q1 18 Cash Flow Netback Performance (E&Ps >60% liquids) $45 99% 99% 100% $40 $35 87% 90% 85% 81% 87% 79% 90% 80% $30 $25 $20 63% 68% 70% 60% 50% 40% $15 30% $10 20% $5 10% $0 Peer 1 Peer 2 TVE Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Cash Flow Netbacks % Liquids 0% 12 12

13 Price per boe ($) Production (boe per day) Improving Cash Costs All-in cash costs have steadily declined while production continues to grow $20 $16 $12 $1.21 $3.11 $1.66 $2.35 $0.90 $1.95 Total Cash Costs 23% 2014 to 2017 $0.97 $1.10 $1.70 $1.60 $1.00 $ ,000 25,000 20,000 15,000 $8 $13.68 $12.81 $11.64 $11.19 $10.95 $ ,000 $4 5, $ Budget(1) 2018 Actual(2) Operating Costs (per boe) G&A (per boe) Interest Cost (per boe) (1) Forecast only. Actual results may differ due to a number of factors. See Disclaimers Forward Looking Statements. (2) 2018 Actual is the 6 month 2018 actuals. Production (boe/d) 6 month 2018 actuals stronger than 2018 forecasted budget - 13

14 Current Hedges Internal Report (as at September 6, 2018) Term Hedge Type Volume Pricing % hedged July 1, 2018 to September 30, 2018 WTI fixed price 5,200 bbls/d US $56.08/bbl 38% October 1, 2018 to December 31, 2018 WTI fixed price 6,200 bbls/d US $58.79/bbl 45% January 1, 2019 to March 31, 2019 WTI fixed price 3,400 bbls/d US $62.39/bbl 23% April 1, 2019 to June 30, 2019 WTI fixed price 2,700 bbls/d US $64.60/bbl 19% July 1, 2019 to September 30, 2019 WTI fixed price 1,900 bbls/d US $63.63/bbl 13% October 1, 2019 to December 31, 2019 WTI fixed price 1,700 bbls/d US $62.52/bbl 11% % hedged average USD $63.27/bbl Term Hedge Type Amount / month Cdn Price Vol equiv. %USD hedged July 1, 2018 to September 30, 2018 Exchange rate $8,500,000 USD Cdn $ ,000 bbls/d 96% October 1, 2018 to December 31, 2018 Exchange rate $9,000,000 USD Cdn $ ,100 bbls/d 82% January 1, 2019 to March 31, 2019 Exchange rate $6,000,000 USD Cdn $ ,200 bbls/d 94% April 1, 2019 to June 30, 2019 Exchange rate $4,000,000 USD Cdn $ ,900 bbls/d 100% July 1, 2019 to September 30, 2019 Exchange rate $3,000,000 USD Cdn $ ,500 bbls/d 80% Tamarack will continue to hedge to protect the downside. October 1, 2019 to December 31, 2019 Exchange rate $3,000,000 USD Cdn $ ,500 bbls/d 88% 14 14

15 Wilson Creek Cardium Stable Growth Through A Downturn 10,000 Production (boe/d) (1) 8,000 6,000 4,000 Gas Oil 2,000 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q (3) 15 Operating netback ($/boe) (2) Q $21.58 $18.90 $24.82 $32.44 (1) Represents proved plus probable reserves. Reserves numbers were derived from an internal qualified reserves evaluator as defined in National Instrument Standards of Disclosure for Oil and Gas Activities ( NI ) in accordance with the Canadian Oil and Gas Handbook and have an effective date of January 15, (2) See Disclaimers Non-IFRS Measures. (3) Forecast only. Actual results may differ due to a number of factors. See Disclaimers Forward Looking Statements. Drilled 9.0 net Cardium ERH wells in Q Plan to drill 17.3 net Cardium ERH wells in 2018 Throughput at approx. 65% of facility capacity 9+ years drilling inventory of 1.5 years payback or better based on 2017 activity 4 operated oil batteries and 2 operated gas plants, over 400 km of pipeline infrastructure Over 300 sections of land 15

16 BOPD BOPD Optimizing ROR in the Cardium Strategic Frac Density Average Rock High Density Frac Target 2 Joint Spacing (High Density) Frac Net Pay (m) 10m + Ave Porosity (%) 6 9% 3% Cutof f Bioturbated (Lower Shore Face) Better Rock Low Density Frac Target 4 Joint Spacing (Low Density) Frac Net Pay (m) 5-8m Ave Porosity (%) 9 15% 3% Cutof f High quality rock does not require high density fracs, whereas low quality bioturbated rock can benefit from increased frac density. OOIP (bbls/section) 5+ million OOIP (bbls/section) 5+ million ~58 Fracs * ~58 Fracs * 500 ~115 Frac ~115 Frac MONTHS MONTHS *1.5 mile wells adjusted proportionally to 2 miles 16 16

17 Viking Area Growing a New Core Viking Opportunity ~1.1 billion bbls of OOIP on TVE lands 14,000 Production (boe/d) (1) 12,000 10,000 8,000 6,000 4,000 Gas Oil Closed Spur acquisition 2, Q Operating netback ($/boe) (2) $21.56 $27.50 $40.63 Drilled 28.0 net ERH Viking wells in Q Plan to drill 87.4 net ERH Viking wells in years drilling inventory of 1.5 years payback or better Up to 14 million bbls OOIP per section Identified three waterflood opportunities to pursue on existing lands; will determine benefits by mid Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q (3) Veteran has outperformed expectations and has the largest OOIP, most drilling inventory, highest NAV and highest oil weighting in TVE s Viking portfolio. (1) Represents proved plus probable reserves. Reserves numbers were derived from an internal qualified reserves evaluator as defined in National Instrument Standards of Disclosure for Oil and Gas Activities ( NI ) in accordance with the Canadian Oil and Gas Handbook and have an effective date of January 15, (2) See Disclaimers Non-IFRS Measures (3) Forecast only. Actual results may differ due to a number of factors. See Disclaimers Forward Looking Statements 17 17

18 Veteran Area Overview Low Recovery to Date Presents Opportunity 5.4% 8-10% 1.6% 87% Total OOIP Primary Recovered to date Secondary Acquisition cost $415 million, plus 2017 capital investment of $95.6 million with exit production at 9,900 boe/d = $52,000/boepd Current land 247 net sections; added 30 net sections in 2017 OOIP is 815 million barrels, 1.6% recovered to date 2017 tuck-in acquisitions added 86 sections (56 at acquisition) of P3 reserve potential 18 18

19 TVE Veteran Pressure Support Makes Viking Better UPPER VIKING UPPER SST-THICKER, TIGHT PERMEABILITY 2017 drills 2018 drills 2017 infrastructure 2018 infrastructure HAMILTON LAKE HIGHER PERMEABILITY ZONE WATER FLOODED IN 80 S By drilling into the Viking and fracking into the Hamilton Lake, wells benefit from underlying pressure support. Effectively and efficiently reducing well decline rate, increasing EUR and reserves. Drilled 28 net ERH Viking oil wells in Veteran in Q1/18 42 net wells came on production in Q1/18 (including 14 that were drilled in Q4/17) Water disposal and oil battery expansion will eliminate water trucking and disposal costs by Q3/18 Clean oil trucking costs to be eliminated by Q1/19 with third party owned Provost Viking Pipeline Project Better than expected drilling results at Veteran supports decision to accelerate facility expansion

20 Oil Rate (bbl/d) boe/d Material Production Build from Less Viking Decline TVE Wells vs. Industry Viking Wells 140 TVE Wells Peer Peer 2 Peer Peer 4 Peer 5 80 Peer 6 Well Count ,000 9,000 8,000 7,000 6,000 5,000 4,000 Veteran Production Performance Base Production New Drills Oil New Drills Gas ,000 10,000 15,000 20,000 25,000 Cumulative Production - Bbls 3,000 2,000 1,000 0 Estimated First Year Decline: With Hamilton Lake: 30% Without Hamilton Lake: 62% +40 new wells on production in Q1/18 Underlying Hamilton Lake zone contributes to lower declines in Viking Veteran upside is still being quantified with EUR s appearing to be best in class 20 Increased production from 300 boe/d to over 6,000 bbls/d in one year and infrastructure expanded to 10,000 bbls/d in Q1/18. 20

21 Oil Rate (bbl/d) Well Count TVE Actual Production vs. Sproule Type Curves Rate vs. Time After 420 days on production, TVE wells are producing twice the rate of Sproule s best type curve Days On Production oil (bbl) Tier 3 Tier 4 Tier 5 Tier 6 Tier 7 Well Count 21 21

22 2018 Delivering on Promises & 2018 H2 Outlook What we said we would accomplish in H What we accomplished to end of Q2/18 Second Half 2018 Objectives H1/18 average production 22,750-23,250 boe/d (64-66% liquids) H1/18 capital expenditures $ million 36-37% corporate decline rate Drill 41 net wells: 26 Veteran Viking, 9 Cardium, and 6 Redwater Bring on production 14 Veteran wells drilled late in 2017 Expand the Veteran oil battery to 10,000 bbls/d Design, procure equipment and obtain permits for water disposal project to reduce operating costs and re-pressurize Viking to add drilling inventory on existing lands Find a solution to eliminate clean oil trucking by year end 2018 Implement new frac strategy in Cardium and measure results Continue to dispose non-core assets H1/18 production - 23,693 boe/d - beat high end of range Liquids weighting 63% H1/ million accelerated capital due to favorable spring breakup Drilled 83 net wells: 60 Viking, 16 Cardium, 2 penny and 5 Redwater Battery expansion completed under budget Started injection in two Veteran Hz wells commencing waterflood Midstream commitment to install 120 km P/L to Hardisty Viking Pipeline. TVE corporate opex to drop $ /boe in 2019 by eliminating trucking New strategy in place saving $300k/well in Cardium Completed $5.12 million of disposals in H1/18 H2 Production 23,300-24,300 Liquids Weighting 65-67% 2018 Capital $205 million + $28 million 2019 acceleration = $233 million in 2018 No production in 2018 from 2019 acceleration 2019 capex $250 million less $28 million accelerated into 2018 = $222 million in 2019 Drill 73 net wells (excluding 2019 acceleration): 61 Viking, 4 Cardium, 3 Penny, 5 Redwater and one source water well Accelerate 26 Viking wells from Q1/19 program late in 2018 Complete Consort waterflood simulation Commence Consort waterflood: drill 8 wells, a source water well and install injection lines, Viking Pipeline to be 85+% completed by yearend Penny maintain voidage replacement with injectors offsetting two newly drilled wells Drill Redwater exploration well & up to 4 follow-up wells if successful De-risk lands west of Veteran Unit with 2 Hz wells Continue to screen for tuck-in acquisitions using balance sheet room that meets acquisition criteria 22 22

23 Summary 2017 and Q1/18 results have outperformed expectations, driven by positive execution post the acquisition of the Spur Viking Less Viking decline than anticipated resulting in increase corporate performance (exit production beat, higher netbacks) The company is demonstrating sustainability and resilience Building debt adjusted production per share Top tier balance sheet (D/CF) Netback continues to improve through organic growth; more capital results in higher oil weighting driving increases in netbacks Management believes continued operational outperformance will lead to improvement in valuation and share price Management shows commitment through increasing ownership. Tamarack s executive increased ownership by over 840,000 shares in

24 Corporate Social Responsibility Environmental Stewardship & Community Involvement Community Sponsorship & industry fundraising for Juvenile Diabetes Research Foundation, Inn from the Cold, plus support of Drug Awareness campaigns through advertising & sponsoring ambassadors to speak with schools Awarded 2018 Global Petroleum Show Award for Corporate Social Responsibility for bettering the broader community that is directly linked to the oil & gas industry Staff-initiated clothing drives and provision of food and household items for families in need Culture Tamarack sponsored the production of two First Nations docudramas designed to record and preserve historical sacred sites, instill pride and recognize the benefits of cultural preservation Brian Schmidt, CEO, was inducted as an honorary Chief by the Blood Tribe (Kainai First Nation), serves as an advisor to Indian Oil and Gas and is a volunteer teacher of oil and gas courses aimed at helping First Nations realize optimal value from resources on their lands 24 Environment Rigorous pipeline integrity program maintained to mitigate risk of environmental damage 19% improvement of LMR rating from April 2017 to March 2018 Recycle produced water for completion operations (vs fresh water usage) 24

25 Appendix

26 Financial Reconciliation-Adjusted Operating Field Netback (1) Q and 2017 Actuals 2017 Actuals Q Actuals $000 s Per boe $000 s Per boe Income (Loss) before taxes -17,535 -$ ,851 -$8.03 Unrealized loss/(gain) on financial instruments -3,495 $ ,496 $6.43 Disposition of property, plant and equipment Transaction costs 5,663 $ Stock based compensation 4,360 $0.59 1,137 $0.54 Accretion expense on decommissioning obligations 3,741 $0.51 1,035 $0.49 Depletion, depreciation and amortization 148,649 $ ,766 $19.91 Impairment 17,000 $ , Adjusted Non-IFRS measure 158,383 57,583 Volumes (boe) 7,350 2,098 Adjusted operating field netback (1) $21.55 $21.55 $27.44 $27.44 Previously reported operating field netback per boe (pre-hedging) (2) $23.45 $28.54 (1) Adjusted operating field netback is a non-ifrs measure based on adjustments to earnings of the various financial statement line items as shown in the table above. (2) As previously reported in the Company s MD&A for the periods shown, and excludes transaction costs

27 Financial Reconciliation-Adjusted Operating Field Netback (1) Q1 2018, Q and 2018 Budget (3) Q Actuals Q Actuals 2018 Budget (3) $000 s Per boe $000 s Per boe Per boe Income (Loss) before taxes 5,073 $2.39 4,731 $2.18 Unrealized loss/(gain) on financial instruments 7,499 $ ,197 $4.70 Disposition of property, plant and equipment -6 -$ Transaction costs Stock based compensation 1,514 $0.71 1,461 $0.67 Accretion expense on decommissioning obligations 1,007 $0.48 1,015 $0.47 Depletion, depreciation and amortization 43,458 $ ,601 $20.08 Impairment Adjusted Non-IFRS measure 58,545 61,005 Volumes (boe) 2,118 2,171 Adjusted operating field netback (1) $27.64 $27.64 $28.10 $28.10 $23.10 Previously reported operating field netback per boe (pre-hedging) (2) 27 (1) Adjusted operating field netback is a non-ifrs measure based on adjustments to earnings of the various financial statement line items as shown in the table above. (2) As previously reported in the Company s MD&A for the periods shown, and excludes transaction costs. (3) 2018 adjusted operating field netback estimates based on Tamarack s 2018 guidance of annual average production ranging from 22,500 23,500 boe/d (64-66% oil and liquids), 2018 exit production estimated between 24,000 24,500 boe/d (65-67% oil and liquids); capital expenditure range of $195 - $205 MM; estimated year end 2018 net debt to Q4 annualized adjusted funds flow ratio of less than 1.0x; assumed 2018 commodity prices averaging approximately: WTI US$56.75/bbl, Edmonton Par price averaging C$64.60/bbl, AECO averaging $1.65/GJ and a Canadian/US dollar exchange rate of $0.79. Tamarack has also assumed an interest rate increase of 0.5% in

28 Tamarack Valley Key Strategic Guidelines Key Strategy & Principles: Growth company with a long term focus Internal processes and skills to grow to a much larger size than current Multi-play strategy ensures risk management through diversity remain light oil weighted in the highest rate of return plays Target repeatable and predictable plays to ensure sustainability at low prices Own and operate infrastructure to control core areas Experts on plays both technically and operationally Shareholder / Management alignment through compensation plan Per share growth targets Full cycle return goals Cost reduction targets Transparency / shareholder trust is a cornerstone 28 28