Creating Sustainable Value - July 2021 - Tamarack Valley Energy
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TVE : TSX
Creating Sustainable Value
July 2021
See Disclaimers and Forward-Looking Statements attached
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,
focus and five year plan; the development of the Company’s significant position in the Charlie Lake area through the acquisition of Anegada Oil Corp.; Tamarack’s commitment to ESG principles and Indigenous relationships, including as disclosed in the Company’s 2020
Sustainability Report; Tamarack’s liquidity and financial position, the factors contributing thereto, the impact thereof and plans relating thereto; and Tamarack’s updated 2021 capital budget and guidance, including the timing and level capital expenditures; future production
levels, including annual average production; oil and liquids weighting and changes thereto; development opportunities; drilling locations; economics and payouts of our wells; corporate decline rate; hedging positions and targets; future waterflood plans, outlook, estimates
and forecasts; future land and seismic investments; additional consolidation opportunities in 2021; 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 concerning Tamarack and the assets acquired pursuant to acquisitions 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, including the assets acquired pursuant to acquisitions, 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 on 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, 2020 (the “AIF”) and Tamarack’s management’s discussion and analysis for the period ended June 30, 2021 (the “MD&A”) . The AIF
and MD&A 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 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 and production, debt, net debt, cash flow, adjusted funds flow, free adjusted funds
flow breakeven, half-cycle returns, long-term free adjusted funds flow growth, balance sheet strength, cash costs, ARO, netbacks, corporate netbacks, operating netbacks, operating costs, corporate decline rate, tax pools, capital structure 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 assumptions 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.
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
BOPD barrels of oil per day ERH extended reach horizontal
bbls/d barrels per day AECO the natural gas storage facility located at Suffield, Alberta, connected to TransCanada’s Alberta System
NAV net asset value EUR estimated ultimate recovery
boe/d barrels of oil equivalent per day IFRS International Financial Reporting Standards as issued by the International Accounting Standards Board TTM trailing twelve months FX foreign exchange
GJ gigajoule ROR rate of return EOR Enhanced Oil Recovery ESG Environmental, Social and Governance
2 w w w . t a m a r a c k v a l l e y. c a 2
Disclaimers (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. The reserve estimates
contained herein were derived from (i) a reserves assessment and evaluation prepared by GLJ Ltd., a qualified independent reserves evaluator, dated February 8 ,2021 with an effective date of December 31, 2020; (ii) in the case of the assets acquired pursuant to the acquisitions completed in March 2021, an internal estimate
prepared by the Company’s internal Qualified Reserve Evaluators, with an effective date of March 1, 2021; and (iii) in the case of the assets acquired pursuant to the acquisition completed on June 1, 2021, an internal estimate prepared on April 7, 2021 by the Company’s internal Qualified Reserve Evaluators, with an effective
date of June 1, 2021, in each case prepared in accordance with National Instrument 51-101 (“NI 51-101”) and the most recent publication of the Canadian Oil and Gas Evaluations Handbook (the “COGE Handbook”). 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. References in this presentation to peak rates, IRR, initial 30 day production rates (IP30) and other short-term production rates are useful in confirming the
presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the
aggregate production of Tamarack. Analogous Information: In this presentation, the Company has provided certain information on the prospectivity and the production rate of wells on properties adjacent to the Company's acreage which is "analogous information" as defined by applicable securities laws. This analogous
information is derived from publicly available information sources which the Company believes are predominantly independent in nature. Some of this data may not have been prepared by qualified reserves evaluators or auditors and the preparation of any estimates may not be in strict accordance with the COGE Handbook.
Regardless, estimates by engineering and geotechnical practitioners may vary and the differences may be significant. The Company believes that the provision of this analogous information is relevant to the Company's activities and forecasting, given its property ownership in the area; however, readers are cautioned that
there is no certainty that the forecasts provided herein based on analogous information will be accurate. 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 COGE 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.
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, year-end net debt to Q4 annualized adjusted funds flow, market capitalization, 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. Free adjusted funds flow is calculated as adjusted funds flow less capital
expenditures, excluding acquisitions and dispositions. Field level free adjusted funds flow is calculated as free adjusted funds flow before the effect of interest and general & administrative expenses. Debt adjusted free adjusted funds flow yield is calculated as free adjusted funds flow, adjusted for growth (to add back capital in
excess of maintenance and ARO capital and to remove the adjusted funds flow associated with growth volumes), plus finance costs, the sum of which is divided by enterprise value. Year-end net debt to Q4 annualized adjusted funds flow is calculated as net debt divided by the annualized adjusted funds flow for the most
recently completed quarter. 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.
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), operating field netback or OFN (total petroleum and natural gas sales, less
royalties and net production and transportation expenses) NPV-10 (meaning the net present value (net of capex) of net income discounted at 10%), RLI (calculated by dividing reserves volumes by estimated production), EUR (meaning estimated ultimate recovery, an approximation of the quantity of oil or gas that is potentially
recoverable or has already been recovered from a reserve or well), internal rate of return ("IRR") (a rate of return measure used to compare the profitability of an investment and represents the discount rate at which the net present value of costs equals the net present value of the benefits. The higher a project's IRR, the more
desirable the project), adjusted funds flow (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 interest expense), free adjusted
funds flow (calculated by subtracting adjusted funds flow in a period by the capital expenditures spent during that same period) and recycle ratio (measured by dividing the operating netback for the applicable period by finding and development cost per boe for the year, which is intended to compare netback from existing
reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves), finding and development costs (calculated as the sum of field capital plus the change in future development capital (“FDC”) for the period
divided by the change in reserves that are characterized as development for the period) and finding, development and acquisition costs (calculated as the sum of field capital plus acquisition capital plus the change in FDC for the period divided by the change in total reserves, other than from production, for the period). 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 two categories: (i) booked locations; and (ii) un-booked locations. Booked locations are proved and probable locations derived from an internal evaluation using standard practices as prescribed in the most recent publication of the COGE Handbook and account
for drilling locations that have associated proved and/or probable reserves, as applicable. Un-booked locations are internal estimates 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. Of
the approximately 853 (767.4 net) drilling locations identified herein, 131 (125.0 net) are proved locations, 32 (30.3 net) are probable locations and 690 (612.1 net) are unbooked locations. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of
applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company
actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing
wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if
drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
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.
3 w w w . t a m a r a c k v a l l e y. c a 3
Corporate Snapshot (TSX: TVE)
Corporate/Market Summary Tamarack
Market Capitalization(1) ($mm) $1,034
Net Debt(1) ($mm) $506
Charlie Lake
Enterprise Value(1) ($mm) $1,540 Light Oil
Bank Line Capacity ($mm) $600
Tax Pools ($mm)(2) $1,030 Clearwater
Medium Oil
P+P Reserves (mmboe)(3) 162.3
2021 Capital Budget and Guidance(4) Full Year H2 2021
Capital Budget ($mm) $165-$180 $85-$100
Average Production (boe/d) 33,000 38,000 Cardium
Light Oil
Free Adjusted Funds Flow(1) ($mm) $120-$125 $85-$90 Spirit River
Gas
Year-End Net Debt to Q4 Annualized Adj.
Q2 2021 & Year to Date Highlights
• Closed the acquisition of Anegada Oil Corp. on June 1st, 2021
Strategic
• Added greater than 350+ locations in the Clearwater and Charlie Lake oil
Acquisitions
plays
Financial • Increased credit facilities to $600 million in Q2 and extended to May 2022
Flexibility • Path to < 1.2x Debt to Q4 Annualized Adjusted Funds Flow(1) by YE2021
Optimized
• Quarterly production volumes of 32,416 boe/d in Q2 with 69% liquids
Production
Free Adjusted • Generated free adjusted funds flow(1) of $40.9 million in Q2
Funds Flow • Acquisitions enable positive FAFF(1) growth to $120-125+ million for 2021
Capital • Invested $30.8 million in E&D expenditures to drill 21 (21.0 net) wells in Q2
Execution • Invested $79.5 YTD, excluding acquisitions
5 w w w . t a m a r a c k v a l l e y. c a 5
Tamarack – Strategic Free Adjusted Funds Flow(1) Growth
Strategic Principles Tactical Execution
BALANCE SHEET STRENGTH AND RISK MANAGEMENT
Low Leverage & Balance • Estimated 2021 year-end net debt to Q4 annualized adjusted funds flow(1)
7
IRR (%) PV-10 Breakeven WTI @ 20:1
Source: Enverus
HH:WTI ($/bbl)
200%
600%
0%
400%
$0
$20
$60
$80
$40
Clearwater - Marten Hills TVE Lwr Charlie
571%
$30
Lake
TVE Lower Charlie Lake
Midland
459%
$33
Montney - Progress-
Gordondale Delaware
$35
TVE Nipisi Clearwater TVE Nipisi
$36
376% 353%
Clearwater
Montney - Kakwa - Nest 1 Montney
$41
Deep Basin - Kakwa DJ
$42
Viking - Alberta Eagle Ford
$43
Midale Conventional -
Shaunavon
$44
Saskatchewan
182% 148% 126% 118%
Sparky - Eyehill Bakken - US
81%
$44
Montney - Wembley-
Viking Primary
Viking
78%
$45
Pipestone
Deep Basin - Resthaven Yeso
$45
73%
Source: National Bank Financial and Internal TVE Benchmarking (Jarvie); Pricing Assumption: US$55.00/bbl WTI C$2.50/GJ AECO
Midale Unconventional -
Bakken - CDN
$48
71%
Saskatchewan
TVE Jarvie Clearwater NM Shelf
$49
Mannville CHOPS 70% San Juan
$50
63%
Leading WCSB Play Benchmarking(1)
Charlie Lake - Upper Val Verde
$51
63%
Viking - Saskatchewan Unita
$55
North American Half-Cycle Breakevens by Play
57%
Montney - Kakwa - Nest 3 Cental Basin
$55
56%
Duvernay - Kaybob South SCOOP | Stack
$55
54%
North American Play Benchmarking
Top tier asset with leading WTI breakevens and half-cycle returns
0
1
3
2
Duvernay
$60
Payout (Years)
w w w . t a m a r a c k v a l l e y. c a
Legend
7
Successfully Executing on Acquisition Strategy
Improving sustainability and resiliency, while enhancing free adjusted funds flow(1) profile
Charlie Lake
West Central Alberta Clearwater Sparky / Clearwater
Light Oil Total
July 2020 December 2020 March 2021
June 2021
Acquisition Overview
Purchase Price $4 million $74 million $135 million $494 million $707 million
Production 2,500 boe/d 2,000 boe/d 2,800 boe/d 12,500 boe/d 19,800 boe/d
Op. Field Netback(1) $3 million $20 million $35 million $135 million $193 million
Implied Multiples
PP/Op. Field Netback(1) 1.4x 3.8x 3.9x 3.7x 3.7x
PP/Production $1,600 / boe/d $37,000 / boe/d $48,000 / boe/d $41,900 / boe/d $35,700 / boe/d
Asset Summary
Gross Locations(2) 50 locations 400+ locations 100+ CW / 50+ Sparky 250+ locations 850+ locations
Undiscounted ARO $36 million $3 million $11 million $18 million $68 million
Accretive acquisitions that reduce Tamarack’s breakeven pricing and add a deep
inventory of drilling locations in North America’s most economic oil plays
8 w w w . t a m a r a c k v a l l e y. c a 8
Capital Allocation Optionality Delivers Sustainability
Portfolio that can deliver near-term and long-term free adjusted funds flow(1)
Sustaining Capital(1)
Waterflood Management Economic Growth
Modest Growth
Highly Economic Inventory that Sustains
Low Decline,
Meaningful Production While Generating Highly Economic Production Growth
Stable Production Base
Significant Free Adjusted Funds Flow(1)
Veteran Viking Light Oil ~5 Mboe/d Charlie Lake Light Oil Wells ~30 Mboe/d Nipisi Clearwater Oil Wells ~5 Mboe/d
Eyehill Sparky Medium Oil Viking Primary Oil Wells Jarvie Clearwater Oil Wells
Clearwater Medium Oil ~20% Cardium / Falher Wells ~40% ~40%
Slave Point and Penny Light Oil
Capital Allocation Across a Portfolio of High Quality, Long-Life Oil Assets that Delivers
Production and Free Adjusted Funds Flow(1) per Share Growth
H2 2021 Percent of H2 2021
Production Capital Program
9 w w w . t a m a r a c k v a l l e y. c a 9
Meaningful Free Adjusted Funds Flow(1) from all Assets
Maintenance Capex FAFF $55 WTI FAFF $65 WTI
$180
$160
$140 $30
$23
$120
Run Rate NOI(1) ($MM)
$100
$76 $67
$80 $22
$60
$12
$34
$40
$30
$50 $55
$20 $35
$20
$0
Waterflood Charlie Lake Clearwater Cardium
Additional Pricing Assumptions: AECO at $2.35/GJ as well as a CAD/USD exchange rate of 1.2500.
10 w w w . t a m a r a c k v a l l e y. c a 10Highly Economic Lower Charlie Lake Light Oil Locations
2 Mile Lateral Length Normalized Well Performance(1)
200
Cumulative Production (Mbbl)
~45% of wells ≥ 2 miles(3)
150
T10
T9
100 T8
T7
50
102/16-22-073-07W6
IP30 Rate(2): 0
0 4 8 12 16
1,048 boe/d(3)
Months
(650 bopd)
Payout Sensitivity
Flat Pricing
0.7
0.6
0.5
Payout (Years)
0.4
$55 WTI
100/12-16-071-08W6 0.3
IP30 Rate(2): $65 WTI
1,367 boe/d(4) 0.2
(1,157 bopd) TVE’s first 2 wells:
0.1 0.2 year payout
0
Tier 7 Tier 8 Tier 9 Tier 10
11 w w w . t a m a r a c k v a l l e y. c a 11Tamarack’s Clearwater Assets
400+ identified locations(1) in the Greater Nipisi area and 100+ identified locations(1) in the Jarvie area
Payout Sensitivity
Flat Pricing
15-29 West 14-26 West
Stepout Stepout 0.8
~300b/d ~240b/d
0.7
5-13 Marten 0.6 Current Results
Payout (Years)
Stepout
• ~118b/d 0.5 Exceeding
• 14 API Typecurves $55 WTI
0.4
0.3 $65 WTI
0.2
13-25 West
Stepout 0.1
• ~70b/d (3 legs) 15-17 West Main
• 19 API Stepout Development 0
~250b/d Area 6-Leg Tier 1 Typecurve 8-Leg Tier 1 Typecurve
• Average Peak
IP30: ~185b/d
25
Cumulative Oil (Mbbls)
>35% uplift in early
09-14 Partner Well 20
~150 b/d
cum production
15
10
5
New Competitor
Well 1-30 0
~185 b/d 0 1 2 3 4 5 6
Months
12 w w w . t a m a r a c k v a l l e y. c a 12Clearwater Waterflood Potential
Tamarack will develop the play with a long-term view to the application of EOR
Nipisi/Marten Hills EOR Pilots Evolution of Waterflooding Criteria/Applicability
Spur
Deltastream
Headwater
Spur
• Other companies have initiated EOR pilot projects (both waterflood and polymer floods) in the Clearwater formation
• Tamarack’s Clearwater assets have the key attributes required for successful EOR projects and management has extensive experience managing waterfloods
• Tamarack has identified the focus area for its initial waterflood pilot which will commence in Q4 2021
13 w w w . t a m a r a c k v a l l e y. c a 13Tamarack’s Waterflood Assets
Improving corporate declines with increasing exposure to assets under waterflood
Total Area Prod. Under Total Asset Est. Recovery Est. Ultimate
Asset Current Initiatives
Prod. Waterflood OOIP(1) to Date(2) Recovery(2)
Veteran Viking Adding ~8 new injection patterns in Veteran and East
2,400 bbl/d under 900 to 1,000
~4,500 bbl/d 2% 17% Veteran (new drills and conversions), start injection on first
Light Oil active waterflood MMbbl
3 patterns in North Veteran stepout area throughout 2021
Sparky Increase make-up water and expand existing
1,050 bbl/d under
~2,100 bbl/d 200 MMbbl 2% 15% waterflooded area by ~1-2 sections (injector conversions,
Medium Oil active waterflood
4-6 patterns) in the next 6 months
Slave Point Identify injector conversions to improve waterflood
575 bbl/d under
~575 bbl/d 40 MMbbl 8% 20% performance, evaluate opportunities for infill producers
Light Oil active waterflood
after injection optimization
Penny 875 bbl/d under Actively managing injection for optimal area-based
~875 bbl/d 60 MMbbl 15% 21%
Light Oil active waterflood recovery factors, additional infill locations identified
Clearwater 15 to 20 MMbbl
No active Up to 20% in selected
~5,200 bbl/d per section inTamarack’s Waterflood Assets
Improving corporate declines with increasing exposure to assets under waterflood
Net Waterflooded Oil – Includes 2021 Capital Program
Production (bopd)
Penny Barons Veteran Viking Nipisi Slave Point Eyehill Sparky
7,000
6,000
5,000
4,000
3,000
2,000
1,000
0
Jan-2020 Apr-2020 Jul-2020 Oct-2020 Jan-2021 Apr-2021 Jul-2021 Oct-2021 Jan-2022 Apr-2022 Jul-2022 Oct-2022 Jan-2023
Recent additions in Eyehill and Nipisi will complement stable performance in Penny and exciting growth in Veteran
15 w w w . t a m a r a c k v a l l e y. c a 15Sustainability at Tamarack
Environment, Social & Governance Focus Areas
• Reduce greenhouse gas emissions
• Understand climate change risks
• Innovate to lower energy intensity
• Prudently use water where required
• Recycle produced water in operations
• Innovate to minimize freshwater use
• Effectively manage inactive liabilities
• Understand and respect ecosystems
• Reduce environmental impact
• Actively engage with stakeholders
• Seek shared value opportunities Inaugural Sustainability Report: Released October 2020
• Facilitate inclusive partnerships
• Prioritize health and safety Understanding and managing risks enables sustainability
• Operate with integrity and transparency
• Proactively understand and manage risk and ESG to drive profit and enhance future value
16 w w w . t a m a r a c k v a l l e y. c a 16Sustainability at Tamarack
Indigenous Partnerships Emissions & Land Management
• Tamarack is committed to the principles of UNDRIP and participating in 2019 GHG Scope 1 + 2 Intensity by Company
reconciliatory activities (tCO2e/boe)
0.10
• The Kainai First Nation and Tamarack actively partner to create shared 0.08
value opportunities including: 0.06
• Capital projects such as the Banff light oil play 0.04
• Cultural initiatives 0.02
0.00
• Economic opportunities and employment for First Nations Peer 1 TVE Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8
individuals and businesses Peers Include: ARC, Baytex, Cenovus, Crescent Point, Enerplus, Suncor, TORC, Whitecap
• Indigenous site rehabilitation program support for indigenous Net ARO Spend / Inactive Liability
7 6.51% 7%
business opportunities and reduction of environmental liabilities
6 6%
Net ARO Spend (CAD$MM)
• Tamarack is actively engaging with Treaty 8 Nations in the Nipisi area
ARO Spend/Liability (%)
5 5%
3.97%
Through a decade-long partnership, the Blood Tribe 4 4%
and Tamarack have helped each other be successful. 3 3%
2.33%
Our oil production is growing as others’ shrink and
2 2%
we’ve done great work together to preserve our 1.15%
culture. We look forward to a full and equal partnership 1 1%
0.9 million 1.9 million 3.15 million 6.3 million
in developing our oil resources. 0 0%
2017 2018 2019 2020
– Roy Fox, Chief Blood Tribe
NET ARO spend ARO Spend/inactive liability
17 w w w . t a m a r a c k v a l l e y. c a 17Investment Summary
Track record of meeting and exceeding estimates
Sustainable Returns Focused Strategy to Grow Production and Free Adjusted Funds Flow(1) per Share
Management team that has demonstrated its ability to execute and capitalize on opportunities
Stable Base Economic Oil Balance Sheet
Leading ESG
Production and Weighted Optionality Strength and Risk
Practices
AFF(1) Inventory Management
38,000 boe/d Highly economic Commodity exposure, Low leverage and Indigenous partners,APPENDIX 19 w w w . t a m a r a c k v a l l e y. c a 19
Risk Management – Current Hedges(1)
58% Enhancing certainty with flexibility
to capture upside value (2),(3)
60%
Oil price protection in 2021 Target oil hedging for H2 2021
Q3 2021 Q4 2021 Q1 2022 Q2 2022
WTI Put
Oil Hedge Coverage(3) Volume (bbls/d) 3,250 4,750 9,250 5,500
Average Put/Premium (USD/bbl) $51.88 $2.43 $51.57 $2.15 $52.55 $2.55 $52.74 $2.74
70%
WTI 2-way collar
60%
Volume (bbls/d) 5,750 6,000 500 2,000
50% $37.83 $59.31 $0.52 $38.33 $59.33 $0.50 $52.00 $84.60 $2.00 $51.50 $87.78 $2.02
Average Put/Call/Premium (USD/bbl)
40% WTI 3-way collar
30% Volume (bbls/d) 1,000 1,000
20% Average Put/Call/Sold Put/Premium
$40 $60 $32 $2 $40 $60 $32 $2
10% (USD/bbl)
WTI 3-way collar alternate
0%
Q3 2021 Q4 2021 Q1 2022 Q2 2022 Volume (bbls/d) 500
Average Bought Put/Sold Call/Bought Call
$52 $70 $73.76 $2
WTI Total (%) MSW Diff (%) WCS Diff (%) Put/Premium (USD/bbl)
WTI Ext. (%) WCS Diff
Volume (bbls/d) 1,500 500 500
Average Fixed Price (USD/bbl) ($11.88) ($12.85) ($12.85)
Gas Hedge Coverage
Q3 2021 Q4 2021 Summer 21 Winter 21-22 Summer 22
60%
Edm Par Diff AECO 5A fixed price
40% Volume (bbls/d) 8,750 8,750 Volume (GJ/d) 33,000 40,000 30,000
20% Average Fixed Price (USD/bbl) ($5.15) ($5.15) Average Fixed Price (CAD/GJ) $2.49 $3.10 $2.42
WTI fixed price Malin fixed price
0%
Volume (bbls/d) 3,750 2,500 Volume (DTH/d) 4,000
Summer 21 Winter 21-22 Summer 22
Average Fixed Price (USD/bbl) $48.97 $48.35
Average Fixed Price (USD/DTH) $2.83
AECO (% of Total) US Markets (% of Total) WTI fixed price ext
Volume (bbls/d) 500
Average Fixed Price (USD/bbl) $50.00
20 w w w . t a m a r a c k v a l l e y. c a 20Notes
Page 4
1. See Disclaimers – “Non-IFRS Measures”
2. Estimated as at December 31, 2020, adjusted for the previously announced March acquisitions and June Anegada Acquisition
3. Tamarack Valley based on the independent reserves evaluation prepared by GLJ Ltd. dated February 8, 2021 and effective December 31, 2020. Total proved plus probable reserves for the strategic Clearwater and
Waterflood assets, announced on March 5, 2021, and the strategic Charlie Lake light-oil assets, announced April, 12, 2021, are internally estimated by the Company's internal qualified reserve evaluators ("QRE") and
prepared in accordance with National Instrument 51-101 – Standards of Disclosure of Oil and Gas Activities ("NI 51-101") and the most recent publication of the Canadian Oil and Gas Evaluations Handbook
("COGEH"). "Internally estimated" means an estimate that is derived by the Company's internal QRE and prepared in accordance with NI 51-101. Internal estimates contained in this presentation were prepared
effective as of: March 1, 2021 for the strategic Clearwater and Waterflood assets; and June 1, 2021 for the strategic Charlie Lake light-oil assets. Reserves values are based on working interest reserves of the Assets
before deduction of royalties and without including any of royalty interest reserves.
4. Updated guidance from April 12, 2021 incorporates the Acquisition and updated market pricing; capital adjusted on June 1, 2021.
Page 5
1. See Disclaimers – “Non-IFRS Measures”
Page 6
1. See Disclaimers – “Non-IFRS Measures”
Page 7
1. Assumes flat pricing; WTIUS$55.00/bbl, AECO C$2.50/GJ, Fx 1.2600 C$/US$, Ed. Light Diff (US$5.25/bbl), WCS Diff (US$12.50/bbl), Cromer Light is 98.6% of Ed. Light, C2, C3, C4, and C5+ are 11%, 36%, 62%, and
103% of Ed. Light respectively, no inflation
Page 8
1. See Disclaimers – “Non-IFRS Measures”
2. See “Oil and Gas Advisories”
Page 9
1. See Disclaimers – “Non-IFRS Measures”
Page 10
1. See Disclaimers – “Non-IFRS Measures”; NOI – Net Operating Income
21 w w w . t a m a r a c k v a l l e y. c a 21Notes
Page 11
1. Lateral length normalized to 3,000m, based on a 1:1 ratio of lateral length to well performance
2. See “Oil and Gas Advisories”
3. Comprised of 650 bbl/d light and medium oil, 74 bbl/d NGL and 1,942 mcf/d natural gas
4. Comprised of 1,157 bbl/d light and medium oil, 38 bbl/d NGL and 1,030 mcf/d natural gas
Page 12
1. See “Oil and Gas Advisories”
Page 14
1. See “Oil and Gas Advisories”
2. Internal estimates and forward-looking Development Summary based on internal management projections
Page 18
1. See Disclaimers – “Non-IFRS Measures”; AFF – Adjusted Funds Flow
Page 21
1. As at July 26, 2021, including hedges previously held by Anegada Oil Corp.
2. For July 1, 2021 through December 31, 2021
3. Includes the potential extension of WTI fixed price hedges in Q4 (500 bbls/day @ $50.00)
22 w w w . t a m a r a c k v a l l e y. c a 22You can also read
