Creating Sustainable Value September 2020 See Disclaimers and - - PowerPoint PPT Presentation

See Disclaimers and Forward-Looking Statements attached

September 2020

Creating Sustainable Value

T V E : T S X

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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, objectives, strength and focus, revised 2020 capital budget and guidance, including the timing and level capital expenditures; future acquisition and disposition opportunities; future production levels; oil and liquids weighting and changes thereto; development opportunities; drilling locations; economics and payouts of our wells; corporate decline rate; hedging positions; future waterflood plans, outlook, estimates and forecasts; future waterflood, land and seismic investments; commitment to ESG principles and Indigenous relationships; 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, price volatility, price differentials and the actual prices received for the Company’s products, 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. In addition, the Company cautions that current global uncertainty with respect to the spread of the COVID-19 virus and its effect on the broader global economy may have a significant negative effect on the Company. While the precise impact of the COVID-19 virus

• n the Company remains unknown, rapid spread of the COVID-19 virus may continue to have a material adverse effect on global economic activity, and may continue to result in volatility and disruption to global supply chains, operations, mobility of people and the financial markets,

which could affect interest rates, credit ratings, credit risk, inflation, business, financial conditions, results of operations and other factors relevant to the Company. These and other risks are set out in more detail in Tamarack’s annual information form for the year ended December 31, 2019 (the “AIF”) and Tamarack’s management’s discussion and analysis for the year ended December 31, 2019 and each of the periods ended March 31, 2020 and June 30, 2020 (collectively, the “MD&As”) . The AIF and MD&As can be accessed on Tamarack’s website at www.tamarackvalley.ca or under Tamarack’s profile on www.sedar.com. 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
• therwise, 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 and production, debt, net debt, cash flow, adjusted funds flow, balance sheet strength, cash costs, netbacks, operating netbacks, operating costs, corporate decline rate 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 approved by management 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 bbls/d barrels per day AECO the natural gas storage facility located at Suffield, Alberta, connected to TransCanada’s Alberta System boe/d barrels of oil equivalent per day IFRS International Financial Reporting Standards as issued by the International Accounting Standards Board GJ gigajoule ROR rate of return mmcf/d million cubic feet per day P3 proved + probable + possible reserves BOPD barrels of oil per day ERH extended reach horizontal NAV net asset value EUR estimated ultimate recovery TTM trailing twelve months FX foreign exchange EOR Enhanced Oil Recovery ESG Environmental, Social and Governance

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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, adjusted funds flow, free adjusted funds flow, field-level free adjusted funds flow; estimated year-end net debt to trailing annual adjusted funds flow, total payout ratio, market capitalization, annual net operating income, annual net operating income multiple, enterprise value and capital efficiency 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. Adjusted funds flow is calculated by taking net income or loss before taxes and adding back items, including transaction costs, and certain non-cash items including stock-based compensation; accretion expense on decommissioning obligations; depletion, depreciation

and amortization; impairment; unrealized gain or loss on financial instruments; unrealized gain or loss on foreign exchange; unrealized gain or loss on cross-currency swap; and gain or loss on dispositions. Field-level free funds flow is calculated as field level net operating income less capital expenditures. Free adjusted funds flow is calculated as adjusted funds flow less capital expenditures, excluding acquisitions and dispositions. Estimated year-end net debt to trailing annual adjusted funds flow is calculated as estimated year-end net debt divided by estimated year-end adjusted funds flow for the previous four quarters. Market capitalization is calculated as shares outstanding multiplied by the closing market price of the shares on the day referenced. Enterprise value is calculated as market capitalization less net debt. Capital efficiency is calculated as capital expenditures for a project or period divided by the incremental production attributable to the expenditures. Total payout ratio is calculated as capital expenditures, excluding acquisitions and dispositions, divided by adjusted funds flow. Annual net

• perating income is calculated as total petroleum and natural gas sales prior to hedging, less royalties, and net production and transportation costs. Management also expresses this as operating field netback within other disclosures. Annual net operating income multiple is

calculated as the total purchase price of the Asset divided by the annual net operating income expressed as a ratio or multiple. 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). 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. Drilling Locations: This presentation discloses drilling locations in two categories: (i) proved and probable locations; and (ii) un-booked locations. Proved plus probable drilling locations set forth herein are based on the Company's most recent independent reserves evaluation as prepared by GLJ as of December 31, 2019. Un-booked locations are internal estimates based on the Company’s prospective land and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Un-booked locations do not have attributed reserves or resources. Please refer to page 80 of the Company’s Annual Information Form for the year ended December 31, 2019 dated March 4, 2020 for assumptions related to drilling locations.

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2020 Revised Budget Assumptions: WTI US$39.00/bbl, MSW/WTI differential of US$6.00/bbl and Aeco at $2.00/GJ as well as a CAD/USD exchange rate of $1.36.

1) See “Non-IFRS Measures” 2) As at December 31, 2019 3) Based on the sum of independent reserves evaluation prepared by GLJ Petroleum Consultants dated January 31, 2020 and effective December 31, 2019 and internal estimates of July 9, 2020 acquisition 4) Based on December 2020 to December 2021 estimates

Revised 2020 Capital Budget and Guidance (July 9/20)

Full Year Capital Budget ($mm) $101 Annual Average Production (mboe/d) 20.9-21.3 Free Adjusted Funds Flow(1) ($mm) $15-20

• Est. Year-End Net Debt to Trailing Annual Adj. Funds Flow(1)

~1.5x Average Annual Oil and NGL Weighting (%) 60-62% 2021 Estimated Corporate Decline Rate (4) (%) 22-24%

Corporate/Market Summary (as at September 9/20)

Market capitalization(1) ($mm) $174 Enterprise value(1) ($mm) $376 Bank Line ($mm) % Drawn $275 ~74% Tax Pools ($mm)(2) $859 P+P Reserves (mmboe)(3) 112.3

Corporate Snapshot (TSX: TVE)

ALBERTA SASKATCHEWAN

VIKING OIL CARDIUM / SPIRIT RIVER LIQUIDS-RICH GAS

Edmonton Lloydminster Calgary Saskatoon Regina

Penny Barons / Banff Light Oil Wilson Creek Redwater Alder Flats

Lethbridge

Veteran/ Consort Lochend Westerose

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• Defensive yet flexible capital program
• Industry leading balance sheet strength
• Ample liquidity/capacity on bank line
• Strong hedge book/risk management initiatives
• Improving sustainability through EOR initiatives driving

lower corporate decline rate

• Dynamic approach to reducing costs in low price

environment

• Continued focus on ESG and Indigenous relationships

Balance Sheet Strength Enhancing Sustainability through EOR Risk Management

(Robust Hedge Book)

Defensive / Flexible Capital Program Continue to Advance ESG Initiatives

Duration through Sustainability and Balance Sheet Strength

The Tamarack Advantage

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Environment, Social & Governance

• 98% of all gas production conserved in 2019
• Fresh water use in 2019 from the 3 waterflood projects has been reduced to 11% from 45% in 2018
• In 2019 and beyond, will comply with new proposed regulations to retire 3-4% of total corporate

liability per year

• Rigorous pipeline integrity program maintained to mitigate risk of environmental damage
• In 2020, ~$7.5 million in abandonment and emissions reduction projects

Environment

• Awarded 2018 Global Petroleum Show Award for Corporate Social Responsibility for bettering the

broader community that is directly linked to the oil & gas industry

• Tamarack supports employees who give back to the community in the form of time or financial

resources and supports ongoing community involvement and investment

• Brian Schmidt, CEO, is honorary Chief of the Blood Tribe (Kainai First Nation)

Social

• Tamarack maintains clear oversight with a diverse and independent board aligned with

shareholders and adheres to governance best practices

• All board committees are majority independent and have independent committee chairs
• Independent HSE & Governance Committee oversees internal ESG milestones
• Third party independently measures performance-based awards & total compensation review

Governance

Tamarack remains a committed & responsible steward of nature, people and shareholder capital

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Indigenous Partnerships – Kainaiwa First Nation

• Tamarack is partnered with the Kainaiwa First Nation in Southern Alberta on

its emerging Banff light oil play

• Tamarack is committed to building a strong working relationship with the

First Nation and preserving the culture of the Blackfoot Confederacy through education, film and elder interviews

• The Tamarack/Kainaiwa Partnership uses qualified First Nations businesses

and employees in our operations

• Our commitment to working with the First Nations extends beyond the

Kainaiwa to all oil & gas producing First Nations through the Indian Resource Council and Indian Oil & Gas Canada

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Sensitivity(1) – July Budget

WTI ($US/Bbl) - remainder of year(3) $20 $30 $40 $50

FX (USD/CAD) $0.76 $0.76 $0.76 $0.76 US$ MSW/WTI Differential ($/Bbl) $4.75 $4.75 $4.75 $4.75 AECO ($Cdn) (monthly index) $2.60/GJ $2.60/GJ $2.60/GJ $2.60/GJ Adjusted Funds Flow(2) ($MM) $91 $105 $119 $133 Capex ($MM) $101 $101 $101 $101 Free Adjusted Funds Flow(2) ($MM) ($10) $4 $18 $32 Total Payout Ratio(2) (%) 111% 96% 85% 76% Hedging Losses (Gains) ($MM) ($57) ($46) ($34) ($25) Estimated Year-End Net Debt to Trailing Annual Adjusted Funds Flow(2) 2.2x 1.8x 1.5x 1.2x

1) Sensitivities based on the production and capital expenditure revised guidance July 9/20, including acquisition 2) See “Non-IFRS Measures”: Total Payout Ratio is Capex/Adjusted Funds Flow 3) Remainder of year from August 1, 2020 – December 31, 2020

Strong Balance Sheet of ~1.5x at US$40/Bbl WTI while generating Free Adjusted Funds Flow(2)

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Duration in Dynamic Pricing Environment

Low Corporate Breakeven Prices & Industry-Leading Balance Sheet

• $20
• $10

$0 $10 $20 $30 $40 $50 $60 $70 $20 $30 $40 $50 $60 Free Adjusted Funds Flow(1) (mm) Oil Price (US$/bbl)

Forecast 2020 Adjusted Funds Flow(3) in Excess of Budgeted Capital(1) by Oil Price

$62 $52 $40 $37

25 35 45 55 65 75

2018 2019 2020* 2021* WTI Oil Price (US$/bbl)

Minimum Unhedged Oil Price Required to Sustain Production(2) With Adjusted Funds Flow(3) Alone

(1) See Disclaimers – “Non-IFRS Measures”. (2) Includes waterflood capital; all operating, G&A and interest costs covered in addition to maintenance capital (3) Adjusted funds flow is a Non-IFRS measure based on adjustments to earnings of the various financial statement line items. See the Company’s MD&A for the period ended June 30, 2020. * 2020 and 2021 numbers reflect proforma financial data including the July 2020 acquisition

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5,000 10,000 15,000 20,000 25,000 30,000 BOE/D BASE WATERFLOOD 2020 DRILLS/ACQUISITIONS 2021 DRILLS

2021 Stay Flat Scenario

Waterflood 2020 + Acquisitions 2021

Base Decline Capital Efficiency ($/boe/d) 2021 22 - 24% $17,000 - $19,000

Base

Improving Declines while Maintaining Production 2021 Commodity Sensitivity

• Oil: +/- $1 USD/Bbl = $4.5MM Adjusted Funds Flow
• Gas at Aeco: +/-$0.10/GJ = $1.1MM Adjusted Funds Flow

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Additional Hedges:

• Winter 20/21 Physical Gas: 48% @ $2.745/GJ (estimated AECO CAD equivalent)
• Summer ‘21 Physical Gas: 37% @ $2.430/GJ (AECO)
• Winter 21/22 Physical Gas: 31% @ $2.805/GJ (AECO)

Risk Management – Current Hedges

1) As at September 9th, 2020 2) For July 1, 2020 through December 31, 2020 3) Inclusive of shut-in volumes

45%

Oil price protection 2020

50-60%

Target oil hedging for 2020

Adding stability in a volatile commodity price environment Hedging Summary(1) Q3 2020 Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021

Proportion of production hedged (WTI oil price) 53% 38% 29% 19%

• Swap production hedged (bbls/d)

4,000 4,000 1,500 500

• Average swap price (USD$/bbl)

$50.24 $50.93 $40.18 $40.00

• Put production hedged (bbls/d)

1,700

• Average put price (USD$/bbl)

$58.00

• Collar production hedged (bbls/d)
• 1,500

1,500

• Average collar floor/ceiling price (USD$/bbl)
• $40.00/$51.17

$40.00/$51.17

• Proportion of production hedged (WTI-MSW differential)

65% 66% 19% 18% 9% 9% Swap production hedged (bbls/d) 7,000 7,000 2,000 2,000 1,000 1,000 Average swap price (USD$/bbl) $7.54 $7.54 $6.13 $6.13 $6.50 $6.50

(3) (2)

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• Nat. Gas/Liquids-Rich Multi-Zone Drilling Inventory

Taking advantage of stronger natural gas prices to enhance full cycle economics

~77 Gross (54 net) high-quality drilling locations identified in the Cardium and Spirit River (Falher & Notikewin) within our West Central core area Additional opportunities in the Hoadley Glauconitic complex and Ellerslie channels

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West Central AB – Nat Gas/Liquids-Rich Economics(1)

200 400 600 800 1,000 1,200 6 12 18 24 BOE/D MONTHS

Falher Type Curve(2)

200 400 600 800 1,000 1,200 6 12 18 24 BOE/D MONTHS

Cardium Type Curve(2)

Falher 2-mile Type Curve Economics

DCET $3.4 MM EUR 575 Mboe 1st Year Oil/Liquids % 0% / 15% ROR 56% Payout 1.4 years NPV10 $2.0 MM 1st Year Cap. Efficiency $6,883/boe/d

Cardium 3-mile Type Curve Economics

DCET $4.0 MM EUR 463 Mboe 1st Year Oil/Liquids % 18% / 30% ROR 78% Payout 1.4 years NPV10 $2.9 MM 1st Year Cap. Efficiency $9,911/boe/d

1) Economics based on September 3rd 2020 Strip Prices 2) Type curves based on internal estimates

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500 1,000 1,500 2,000 2,500 3,000 3,500

BOPD

BASE WF 2020 WF Drills Actuals

Veteran Waterflood Wedge

2021 Exit: 2,975 bopd

Base Waterflood 2020 WF Drills

2020 Capital Efficiency using peak rate of 1,800 bopd - $19,000/bopd

2020 Exit = 2,100 bopd Aug Actuals = 1,371 bopd

Building sustained long-term, high-netback, low-decline oil production

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50 100 150 200 250 Oil Rate Per Well (bbl/d) 102/05-24 Waterflood Pattern Performance – 2019 Infill (200m Spacing, 16-24 Pad)

Final Injector Online Feb-2020 Peak Oil Rate >150 bbl/d Partial Offset Injection Online Feb-2019

East Veteran Waterflood Performance - 200m Patterns from 2018 and 2019

Sample well performance shown from 2019 infill producer Higher initial rates due to prior injection, reliable ramp to 150 bbl/d similar to 2018 pilot patterns after full injection support in place Average well performance shown from original 2018 pilot patterns Decline has softened in Q3/20 due to tight VRR operating parameters and consistently optimized wellbores

50 100 150 200 250 Oil Rate Per Well (bbl/d)

Average Waterflood Pattern Performance - 2018 Pilot

(200m Spacing, 12-19 Pad)

All Injectors Online Feb-2019 Peak Oil Rate >150 bbl/d

EUR per 200m Pattern = 200 to 250 Mbbl

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Veteran Waterflood ONLY – 5+ Year Plan Update; Building Long-Term Free Cash Flow Growth

• Veteran Waterflood ONLY included in capital / production (excludes

existing primary base production and future development)

• Includes incremental production from existing West WF development but no

future drilling/expansion

• ~100 new patterns from 2021-2026 at a mix of 200-300-400m
• Represents ~40% of total development opportunity
• Includes >$50MM capital for major facilities/pipelines and sustaining

wellbore optimization

$0 $10 $20 $30 $40 $50 $60 2020 2021 2022 2023 2024 2025 2026 2027

$MM

Annual Capex

$0 $20 $40 $60 $80 $100 2020 2021 2022 2023 2024 2025 2026 2027

$MM

Field Level Free Funds Flow(1)

$50 WTI $60 WTI

$50 WTI STRIP

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 2020 2021 2022 2023 2024 2025 2026 2027

BBL/D

Waterflood Production ~10%-15% CAGR ~50% CAGR @ strip(2)

(1) See Disclaimers – “Non-IFRS Measures”. (2) As at September 3, 2020

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Waterflood Development Runway

2018 Drills 2019 Drills 2020 Drills

Internal Estimate(2) Waterflood 11% Remaining Primary 4% Recovered to Date 2% Estimated Ultimate Recovery 17%

1) See “Oil and Gas Advisories” 2) Internal estimates and forward-looking Development Summary based on internal management projections

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Investment Summary

Sector Leading Balance Sheet

~1.5x on Updated Budget

Operational Execution

Focus on Costs

Disciplined Capital Allocation

Full-Cycle Returns Focused

Improving Sustainability

Decreasing Corporate Declines Track Record of Meeting & Exceeding Estimates

Appendix

T V E : T S X

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West Central Alberta Asset Acquisition Summary

Production & Cash Flow Metrics Total Net Consideration ($MM) $4.25 MM Estimated Production (at closing) 2,500 boe/d % Oil & NGLs 52% Decline Rate 13% Annual Net Operating Income(1),(2) $3.1 MM Annual Net Operating Income Multiple(2) 1.4x Flowing Multiple $1,700 per boe/d

1) Based on 12 month strip July 3rd 2020 pricing 2) See Non-IFRS Measures 3) PDP Reserves, Total Proved Reserves, Total Proved + Probable Reserves are derived from the Company’s internal QRE and prepared in accordance with NI 51-101 and the COGEH.

Reserve Metrics PDP(3) 6.6 MMboe Proved(3) 7.5 MMboe TPP(3) 10.7 MMboe TPP RLI(3) 11 years PDP Acquisition Cost(3) $0.64/boe Total Proved Acquisition Cost(3) $0.57/boe TPP Acquisition Cost(3) $0.40/boe

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Asset Acquisition Highlights…

1

• Low decline, stable production base of ~13% further enhances Tamarack’s overall sustainability and free

adjusted funds flow profile into 2021 and beyond

• Consistent with Tamarack’s strategy to develop a portfolio focused on enhancing full cycle profitability
• Approximately 105,000 net acres of land concentrated in key developmental plays within Tamarack’s West

Central core area featuring ~50 high quality, multi-zone light oil and liquids rich drilling locations

• Opportunity to enhance the netback through operating cost reduction… ie redirecting natural gas through TVE
• perated facilities and infrastructure along with the integration of the Assets into TVE’s core fairway
• Discounted inactive ARO of ~$9 million… TVE forecasts to spend ~$1.5mm/year on these assets

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Variable Opex Shut-In Analysis(1)

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 $18.00 $20.00

Percentage of Corp Production Break-even Price Edm ($CDN)(2)

1) Based on internal estimates (excludes fixed costs,G&A and interest) 2) Break-even price EDM ($CDN) calculated as ((WTI ($USD) – MSW Differential ($USD))* FX Rate) Less Quality & Transport Differential ($CDN)

• TVE currently has ~800 boe/d shut-in (~½ Waterflood Efficiency, ¼ 3rd Party Shut-In, ¼ Uneconomic Volume/Workovers)
• TVE has >200mbbls of storage capacity corporately or ~10 days of production equivalent