Corporate Presentation September 2021 - Tourmaline Oil
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Corporate Presentation September 2021
Tourmaline Overview 2
The Scale, Resource, and Infrastructure Required to Profitably
Grow in the WCSB and Provide Returns to Shareholders Sept 2021
Tourmaline Overview 3.0 MM Net Acres, 3.3 Billion Boe 2P Reserves(1)
Conroy
• Largest natural gas producer in Canada
Drilled to Date
• 5th largest Canadian gas processing midstream operator Aitken
Birley T95
• 3.3 Billion Boe 2P Reserves, 15.5 Tcf Gas, 738 MMbbls liquids Gundy
>75yrs of 2021 Drilling
• Lowest capital cost operator in the basin Drilling
Inventory(1) Booked
• Lowest net emissions and intensity of Canadian senior producers T85
Locations
• 39% emission intensity reduction since ‘13(1); rated “A” by MSCI Montney
Unbooked
Gas/Cond Resource
• Peer-leading cash flow growth & free cash flow generation (Third Largest
Montney Peace T75
• Investment Grade BBB (High) rated by DBRS NE
Producer) River High BC
• Largest insider ownership amongst Seniors, 4x peer average Alberta
Wapiti
Tourmaline’s scale in Canada’s premium gas plays, production base and Alberta Deep Basin
low cost infrastructure, provide investors a suite of advantages with (Largest Deep Basin T 65
Tourmaline Lands Producer)
efficiency, profitability, growth, and return on (and of) capital Cutpick
unparalleled by peers Three massive operated
T 55
Current Production complexes, derisked by
1,765 wells drilled to date
• Q3 production forecast 450,000 – 460,000 boepd with company constructed
infrastructure in place
• 2021 Average production forecast 440,000 - 445,000 boepd Brazeau
T 45
Financial Position(2) Investment Proposition(2)
Market Capitalization (Sept 15th) $13.9B Debt Adj. Cash Flow Per Share Growth 2022/2021 >40%
Net Debt (2021E) / net of TPZ Equity Stake (Sept 15th) $1.0B / $0.1B Total Payout Ratio (2021 / 2022) 63% / 38%
Enterprise Value (2021E) $14.0B Free Cash Flow Yield (2021 / 2022) 12% / 18%
Net Debt (2021E) to Cash Flow (2021E) 0.3x 2021 Dividend Yield (Base / Base + Special) 2% / 3%
2021 Cash Flow (Guidance) $3.0B Five Year Plan Cumulative Free Cash Flow $8.1B
(1) See schedule A in corporate presentation appendix; inventory life at 2021 pace of development (hz locations only), reserves and acreage as of December 31st 2020; Intensity reduction proforma 2019 Pneumatic Devices Program
(2) DACFPS, liquids growth and FCF per five year plan, see current five year plan slide for definition of FCF, all market data as per September 15th, 2021; EV presented net of TPZ equity value; TPZ equity stake proforma Sept 21 sale.
3
GHG Emissions – Peer Comparison
May 2021
Tourmaline has the lowest GHG emissions intensity (CO2e/boe) among Canadian Senior E&P peers
Canadian E&P GHG Emissions 2019
30,000,000
Tourmaline has achieved a 31% reduction in C02 0.12
emissions intensity between 2013 and 2019
Pneumatic devices program to reduce intensity to
25,000,000 39% effective 2020 0.10
We are targeting a 25% reduction in total methane
20,000,000 emissions by 2023 (on track for 2021) and reduce 0.08
(tonnes CO2 (e)/boe)
Gross CO2 Emissions
corporate emissions intensity by 25% by 2027(4)
(tonnes CO2 (e))
CO2 Intensity
15,000,000 0.06
10,000,000 0.04
5,000,000 0.02
- -
CNRL Suncor Imperial Husky Cenovus Crescent Point MEG Tourmaline
Q4 2019 Production 1,156,000 778,000 362,000 311,000 467,000 145,000 95,000 300,000
Notes:
1. Based on CDP (Carbon Disclosure Project) data and includes Scope 1 and 2 emissions. Gross CO2 Emissions
2. Represents 2019 data. CO2 Intensity
3. Emission intensity derived by Gross CO2 Emissions divided by total production for the year.
4. See sustainability report for details; reductions based off 2018 levels, corporate reduction targets on a Scope 1 basis.
4
A History of Full Cycle Profitability
Mar 2021
$800 $5.00
Earnings before taxes ($mm) AECO (CAD$/mcf) NYMEX (USD$/MMbtu)
$4.50
$700
$4.00
$600
Earnings before tax ($ millions)
$3.50
$500
$3.00
(Gas Price)
$400 $2.50
$2.00
$300
$1.50
$200
$1.00
$100
$0.50
$0 $0.00
2012 2013 2014 2015 2016 2017 2018 2019 2020
• Tourmaline focuses on generating earnings and full cycle profitability/returns.
• Tourmaline has grown cash flow per share by a 15% CAGR since the November 2010 IPO.
• The EP strategy focusses on selecting premium subsurface targets and continually reducing
capital and cash costs as the development plans are executed.
• The focus on economic sweet spots will yield superior returns.
• Tourmaline has a free cash flow breakeven on a maintenance budget at US$1.50/Mcf.
5
Largest North American Natural Gas
Producers Sept 2021
Tourmaline is the largest natural gas producer in Canada, and the fifth largest gas focused producer in North America
MMcf/d 2022E Natural Gas Production – Canada & US
6,000
5,000
Scale is a key component in driving down
costs, leveraging transport & marketing
opportunities, and remaining relevant in the
4,000
current market environment
3,000
1
2,000
1,000
0
TOU CNQ ARX OVV CA CVE PEY BIR EQT SWN COG CHK AR RRC CNX CRK
TOU as per guidance, Peer data as per Bloomberg consensus Sept, 2021. OVV Canada 2021 assumes Q2/21 CA/US proportions.
6
Tourmaline: A Significant Canadian Liquids Producer
Sept 2021
Tourmaline is a significant liquids producer in Canada, with continued peer leading growth
• Tourmaline is the 5th largest producer of conventional liquids, the largest producer of NGLs, and
the second largest condensate producer
• Tourmaline has transitioned its previously rapid growing liquids profile towards methodical liquids
growth at a 3-5% CAGR in the 5 year plan (organically)
• Gundy Phase 2, will provide significant liquids growth, another ~15 Mbpd of predominantly condensate and
pentanes rich liquids production
• Inorganic growth through acquisition continues to accretively add liquids in 2020 and 2021. This is consistent with
TOU’s approach of owning more of the supply through A&D, vs rapid drilling to grow supply
Conventional Liquids (Mbpd) Tourmaline Liquids Growth (Mbpd)
219 Canadian Peer Producers 2022 Mix
C2
5th Largest Total Conv. Liquids Producer 140 4% CAGR 131
200 21% Condensate 126
2nd Largest Condensate Producer 29% 120
Largest NGL Producer 120 115
144 98
150 136 100 23% 8%
C3 Oil
117 4%
80 15%
98 C5 64
100 84 C4 55
80 60
70 48
63 39
47 40
50
20
0 0
CNQ CVE* ARX* CPG* TOU* SU WCP* ERF* BTE VET 2017 2018 2019 2020 2021E 2022E 2023E 2024E 2025E
Conventional Oil & Condensate NGLs Gundy Ph 2
Peer data sourced to most recent public filings or 2021 guidance where available +15 mbpd
*ARX, CVE, WCP, ERF, CPG are proforma recent acquisitions. CVE inclusive of heavy oil / EOR.
7
Current 5 Year Plan(1)
Sept 2021
600,000
500,000
400,000
Spirit River
Boe/d
300,000
NEBC
200,000 Deep Basin
100,000
-
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
After-tax Declared Ending
Cash After-tax E&P Capital Free Cash Topaz Tourmaline Special Surplus
Prod’n Flow CFPS - Program(4) Flow(5) Dividend(6) Dividend Dividend (Net Debt)(3)
BOEPD $MM(2)(3) Diluted $MM $MM $MM $MM $MM $MM
2021E 442,500 $3,000 $9.49 $1,375 $1,587 ($11) ($210) ($244) ($958)
2022E 500,000 $3,705 $11.24 $1,125 $2,525 - ($235) - $1,333
2023E 515,000 $3,125 $9.48 $1,255 $1,805 - ($235) - $2,903
2024E 540,000 $2,520 $7.64 $1,395 $1,055 - ($235) - $3,723
2025E 560,000 $2,540 $7.70 $1,385 $1,080 - ($235) - $4,569
(1) 5 year plan derived by utilizing, among other assumptions, historical Tourmaline production performance and current cost assumptions inflated at 2.5% annually after 2022. 2023 and beyond provided for illustration only. Budgets and
forecast beyond 2022 have not been finalized and are subject to a variety of factors including prior year’s results. 5 year plan includes Topaz Energy Corp. (“Topaz”) ceasing to be a fully consolidated subsidiary of Tourmaline Oil
Corp. during June 2021.
(2) Price assumptions: Gas price - $3.77 2021 NYMEX US, $4.27 2022 NYMEX US, $3.33 2023 NYMEX US, $2.96 2024 NYMEX US, $2.92 2025 NYMEX US, $3.77 2021 AECO, $4.08 2022 AECO, $3.23 2023 AECO, $2.89 2024
AECO, $2.99 2025 AECO. Oil price - $66.22/bbl 2021 WTI US, $67.66/bbl 2022 WTI US, $62.35/bbl 2023 WTI US, $58.39/bbl 2024 WTI US, $55.53/bbl 2025 WTI US.
(3) See “Non-GAAP Measures” in Forward Looking Statement Advisories.
(4) E&P Capital Program is defined as total capital spending before acquisitions, dispositions and other corporate expenditures.
(5) Free Cash Flow is defined as Cash Flow less Total Net Capital Expenditures. Total Net Capital Expenditures is defined as the sum of E&P Capital Program and other corporate expenditures, net of non-core dispositions . Free Cash
Flow is prior to dividend payments made by Tourmaline and Topaz.
(6) Topaz Dividend includes dividends paid out by Topaz, excluding dividends paid to Tourmaline Oil Corp.
8
Tourmaline Free Cash Flow Allocation &
Dividend Growth Track Record Sept 2021
The majority of Tourmaline’s free cash flow will be returned to shareholders; special dividends will be
the preferred method of shareholder returns during periods of high commodity prices
• Base dividend will continue to grow alongside the base EP business and will remain sustainable even in sub
US$2/mcf gas prices
• Special dividend offers an instrument for cash return to shareholders during periods of strong commodity prices
• Tactical share buybacks remain an opportunistic tool of shareholder return
• Alongside dividends, free cash flow will be allocated towards: (1) maintaining the pristine balance sheet, net
debt $1.0 - $1.2bn (2) high return infrastructure and liquids investment opportunities (3) accretive bolt on M&A
$/Share Dividends Per Share – Base & Special $/Share Free Cash Flow per Share
$0.80 $8.00 $7.75
$0.75
$0.70 $7.00
$0.60 $6.00 $5.54
$5.06
$0.50 $5.00 The majority of future
free cash flow will be
$0.40 $4.00 returned to shareholders
$3.24 $3.32
$0.30 $3.00
$0.20 $0.17 $0.18 $2.00
$0.16
$0.12 $0.14
$0.10 $1.01
$0.10 $0.08 $1.00 $0.51 $0.75
$0.42
$0.46 $0.50 $0.67
$0.37
$0.00 $0.00
1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q 1Q 2Q 3Q SP. Q4 2018 2019 2020 2021E 2022E 2023E 2024E 2025E
2018 2019 2020 2021
Base Raised Base Maintained Special Annual DPS Announced Special Excess FCF/Share
For capital and commodity price assumptions and definition of free cash flow please see 5 year plan slide
9
Alberta Deep Basin
Sept 2021
The contiguous Tourmaline interconnected Deep Basin
Cretaceous gas asset is effectively Alberta’s Largest Gas Field.
R13 R11 R9 R7 R5 R3 R1W6 R25 R23 R21 R19 R17 R15 R13 R11
TCPL
T71
Main Line
1 • Current Production 250,000 boepd
• Current Reserves 1,475 mmboe (Dec
T69 31, 2020)
TCPL Main Line • Tourmaline Land Base 2.3 million acres (gross)
Elmworth
16
• Drilling Inventory 13,504 hz locations
T67
Chinook
Ridge Wapiti
T65
9
Musreau
/Kakwa T63
Netook
8
Lynx The Company has drilled 888 T61 wells to date with a
Cardium Leland Fir future drilling inventory of 13,504 hz locations.
Dunvegan Cutpick T59
1
Cecilia
Viking
T57
Mannville/Notikewin
16 Oldman
Harley Wild
T55
River TCPL
Falher
Edson
T53
12
9
Marsh
Wilrich T51
Bluesky Edson
Hinton T49
Gething Ansell
Gething
Tourmaline Lands Minehead T47
Tourmaline Gas Plant TCPL Main NE Alberta
Line
T45
Cadomin Tourmaline pipelines Lovett BC
T43
Nikinassin
Brazeau
T41
R1W6 R27 R25 R23 R21 R19 R17 R15 R13
10
NEBC Montney Gas/Condensate Complex
Sept 2021
D-48-C Sour
Current Prod. 200,000 – 210,000 boepd Gas Plant.
30 MMcfpd
b-24-H
Comp/Dehy
Current Reserves 1,578 mmboe (Jan 1, 2021) 140 MMcfpd.
(2021 Acq. not included)
Northriver D-72-F Comp Sta.
Montney Drilling In excess of 6,974 horizontal North Jedney 50 MMcfpd
Inventory locations.
12” Sour Gas P/L
190MMcfpd Sales
Tourmaline is one of the largest Montney
producers in Western Canada with
Altagas
C-60-A Gas Plant Aitken current N.E. B.C. production of
200 MMcfpd Creek Hub
Phase 2 Jan 2022
200 MMCF/D 15,000 bpd 200,000 boepd, a 2021 development
15,000 bpd
Phase 2 Q1 2022
200 MMcfpd program of 125 wells and a 2021 exit
15,000 bpd
production target of 210,000 boepd
A-21-I Comp Sta.
180 MMcfpd
13-25 Gas Plant
C-60-A Gundy Gas Plant 110 MMcfpd
Westcoast
McMahon
Gas Plant
Doe 1-32 Comp. Station
3-18 Gas Plant TOU 12 MMcfpd
80 MMcfpd
Sunrise
2-11 Gas Plant Dawson
60 MMcfpd TCPL
Mainline
TOU Land Groundbirch
TOU Acquisitions Coastal
TOU Pipelines Gaslink P/L
TOU Gas Plants Sundown
3rd Party Processing Plants
B-67-H Gas Plant
Major Pipelines 132 MMcfpd
13-25 West Doe Plant11
NEBC Montney Consolidation
Black Swan Energy & Paramount Birch
July 2021
Legend
Black Swan Energy Black Swan Lands
▪ Current production ~50,000 boepd TOU Conroy D-48-C
Paramount Lands
Sour Gas Plant.
Tou/Saguaro b-24-H
▪ Exit 2021 50,000-54,000 boepd, Q2 2022 60,000 boepd 140 MMcf/d Comp.
30 MMCF/D TOU Land
▪ ~ 231,000 Net acres of Montney Rights Tou/Saguaro TOU Pipelines
Water Facility
▪ 492 MMboe (23% liquids) 2020 YE 2P Reserves TOU Facilities
Black Swan Facilities
▪ 50% WI in 2 Gas Plants with current capacity of 270
TOU Martin Ck Competitor Facilities
MMcf/d Expandable to 360 MMcf/d 20 MMcf/d
Major Pipelines
B-34-L Sour Gas Plant
▪ 2 Water Storage Ponds with a capacity of 108,000 m3 TOU Conroy/Birley
Locations
Water Infrastructure
Paramount Birch Black Swan Energy
Acquisition
▪ 2,400 boepd, 40 mmboe 2P Reserves TOU Comp. Sta.
▪ 100+ Tier 1 plus locations (8-10 Bcf, 400-500 Mbbl/well) D-26-K
50 MMcf/d
▪ 20,800 acres of Montney Rights
49km 6” condensate P/L to
AltaGas Truck Terminal. H
TOU 12” Sour Pipeline
H
H HH
H H
H HH
H
H
190 MMcf/d Sales
Black Swan North Aitken Facilities
H H H
HH H
H
HHHH
HH
H HHH
Black Swan 25 MMcf/d HHH H HH HH
N. Aitken Gas Plant Nig Creek Gas Plant
H
H Black Swan Aitken Gas Plant
Compressor Stations H HHH
110 mmcf/d shallow cut 160 mmcf/d shallow cut 110 MMcf/d
Expandable to 180 mmcf/d Expanding to 180 mmcf/d Black Swan Nig Gas Plant
(Q2/22) deep cut 160 MMcf/d
Strategic Partnership with Altagas
Aitken core area dedication
50/50 Ownership in entire processing complex
Enbridge Paramount Birch Acquisition
Buyback provision, NGLs permanently dedicated T-North Pipeline
Processing complex P/L connected to Altagas for NGL transport/export Aitken Ck Hub
Sales gas lines Access to Alliance, North Montney, Fortis
10” to Enbridge Aitken Creek Lateral C-60-A Gas Plant BC Gas Storage, and Enbridge System
16” to TCPL NMML 200 MMCF/D 2021 TOU 3D Seismic
6” Condensate line to Aitken block currently unutilized 15,000 bpd
Phase 2 Q1 2022
200 MMCF/D A-21-I Comp Sta.
15,000 bpd 180 MMCF/D Alliance
pipeline12
Significant Montney Growth Potential
June 2021
Tourmaline has access to significant potential Montney growth through fully delineated assets that are economic on
current strip.
Mboe/d
Tourmaline Montney BC and Alberta Montney Peers
500
450 >400
Sundown Full Development •
400 Aitken Creek •
Conroy with Infrastructure buildout •
350 340
300
300
•Gundy Ph2
•Conroy Ph1
250 •N. Aitken
220 222
Expansion
200
200 • ‘21 EP Program
• Sundown Ph1
150 140
118
40
100 Base 90 90 84
83 80
(Inclusive 12 17
of A&D) 35 30 49 40
50 100 78
49 5 30
74 50 14
44 10
26 20
0
Q3 Exit 2021 Exit 2022+ Future Dev Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer
Tourmaline growth projections include development of Current Announced Expansions (2021-2026)
existing assets, all are fully delineated and are economic /
full cycle profitable on current strip pricing. This analysis
excludes Red Creek / Attachie, Noel, Tupper, Jedney, new
pool delineation, and potential additional acquisitions.
Peer data as per most recent disclosure; Accumap, GS research. Expansions include publicly announced growth, and/or 2021 budgeted volume growth.
Peers include AAV, ARX (proforma VII), BIR, CNQ, Mitsubishi (Diamond Gas), MUR, NVA, OVV, PIPE, Petronas JV, SRX, Shell Canada13
Peace River High Complex Triassic Oil
Charlie Lake, Montney and Wapiti Cardium Plays
Mar 2021
Peace River High Legend R. 11 R. 9 R. 7 R. 5
Tourmaline Lands
• 2,062 Horizontal Locations* along Regional Play
Tou UpperCharlie Lake HZ Drills
Fairways 15-13 Mulligan
Tou Lower Charlie Lake HZ Drills Oil Battery
• Current Reserves of 262 mmboe (Dec 31, 2020) Tourmaline Montney HZ
T. 83
• Regional pools defined by 318 hztl and 143 existing Tourmaline HZ Well Loc.
vertical wells Tourmaline HZ Wells
• 225 - 600 mboe 2P reserves per horizontal Charlie Tourmaline Battery Site
Lk/Montney/Cardium Tourmaline Gas Plant
• $2.0 - $2.2M Charlie Lk/Cardium horizontal Lower Charlie Lake Fairway 12-6 Mulligan
Oil Battery
Drill/Complete Cost Upper Charlie Lake Fairway
T. 81
Montney Fairway
• Upper Charlie Lake wells are profitable on a full cycle
basis at $25/bbl (U.S. WTI)
• 13 Upper/Lower Charlie Lake delineation wells in 2021 6-3 Spirit River
Oil Battery
Wapiti Cardium Complex Spirit River 6-10-78-8W6M Pad Average’s T. 79
R. 9 R. 8 R. 7 R. 6 R. 5. W6M
IP30 production rates (normalized)
IP30 OIL IP30 GAS IP30BOED
15-32 Pad T. 68 (4) Lower CLLK 740 2,395 1,121
(3 Crdm wells) (3) Montney 650 5,595 1,542
T. 67
T. 77
Spirit River 5-3-76-8W6M Pad Average’s
IP90 production rates (normalized)
IP90 OIL IP90 GAS IP90BOED
T. 66
(2) Lower CLLK 245 377 310 3-10 Spirit River
(1) Upper CLLK 704 1,450 935 Gas Plant
T. 65 T. 75
IP 30 OIL units bbl/d, IP30 GAS units mscf/d * See Schedule A14
Tourmaline Mid Stream Assets
July 2021
The infrastructure skeleton in all three core operated complexes is now complete.
This infrastructure is essentially all new and in the ‘growth’ areas of the WCSB.
Conroy
• 25 Working interest gas plants, 13 of which are 100% owned
Montney Birley and operated, 4 Topaz interest plants
Gas/Cond
• 24 compressor stations
Gundy
Peace River High • Current Tourmaline operated gas processing
Charlie Lk Oil capacity of 2.4 bcf/day. (2.0 bcf/day net)
Mulligan/Earring
Alberta Sunrise-
Dawson
British Spirit River
Two oil processing batteries with combined
Columbia Sundown processing capacity of 50,000 bpd.
Tupper
Legend
Oil, condensate and ngl storage
Tourmaline Lands
capability of 325,000 bbls.
Chinook Musreau/
Tourmaline Gas Plant Site Kakwa
Ridge
16 MW gas fired electrical
Tourmaline Oil Battery Route Alberta Deep generating capacity.
Leland
Tourmaline Main Laterals Lynx Fir Basin
Main Sales Pipelines Cutpick
Cecilia 6,900 km of Tourmaline
Harley
Edson
Wolf Operated Pipelines
H
Marsh Creek
This revenue is in addition to the
estimated $350MM(+) per year of Hinton Ansell
Water Infrastructure
cash flow that is effectively preserved Minehead
by owning the operated infrastructure • 10 Major Frac Water
Lovett
and not processing gas through third source/ Recycling Facilities,
party/midstream plants. Brazeau
B
A 550,000 m3 capacity15
Historical Reserves Summary
Sept 2021
Reserves (GLJ) Reserves
2016 2017 2018 2019 2020 2013 2014 2015 2016 2017 2018 2019 2020
3,500
(mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe)
3,000 PDP 122.3 177.8 263.2 352.1 436.5 473.5 527.4 736.4
2,500 TP 316.5 472.3 644.1 859.2 1,056 1,207 1,294 1,691
MMBOE
2,000 2P 590.1 855.8 1,108 1,747 2,217 2,458 2,602 3,314
Finding & Development Costs ($/boe)
1,500
2P FDA(i)
$11.84 $10.40 $5.89 $5.94 $3.76 $5.15 $4.26 $3.80
1,000 _With FDC
(i) See March 2021 press release for full FD&A disclosures
500 (ii) Reserves figures include the Company’s working interest share of reserves prior to the deduction of
interest owned by others (burdens) and include royalty interest reserves owned by the Company.
0
PDP TP 2P
• Total Proved Reserve life index a reasonable 12
2020 BT NPV 10% Reserve vs Market Valuation
years.
$mm Owners of TOU continue to
$17,223 receive future development • 2P FDC realistic, at approximately 5 years of
value at a discount
future projected cash flow. Historically
$13,900 $14,000
$6,812 Tourmaline has systematically converted the 2P
$10,411 reserves to PDP reserves in the 4 - 5 year time
$3,931 frame.
$6,480
• Positive technical revisions each of the last
eight years.
• Considerable reserve value/NAV increase
PDP / PUD 1P Probable 2P Market 2021E EV
PDNP Cap (1) Net Debt
(1) opportunity with improving gas prices.
(1) As of Sept 15th 2021, Net debt presented net of Topaz equity value16
Development Location
Inventory and Economics Sept 2021
AB Deep NEBC North NEBC Gundy NEBC South PRH PRH
Basin AB Resthaven MNTN MNTN MNTN Charlie Lake Montney
Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal Horizontal
Total Well Costs
(Drill, Case, Complete, $ Million) 3.50 4.85 3.20 2.85 2.30 2.20 3.50
Average Reserves/Well (bcfe) 5.4 10.1 7.5 7.6 5.0 2.1 5.1
Year 1 Production Rate 4.0 mmcfepd 7.2 mmcfepd 4.5 mmcfepd 4.4 mmcfepd 3.2 mmcfepd 214 boepd 399 boepd
Development Cost/boe $3.90 $2.88 $2.56 $2.25 $2.76 $6.30 $4.13
Operating Expenses/boe (1) $2.29 $3.41 $5.77 $2.14 $1.96 $8.12 $7.48
Net Present Value @ 10% (000's) $3,927 $7,145 $6,227 $9,468 $4,745 $2,030 $3,398
Internal Rate of Return (2) 80% 118% 176% 345% 231% 59% 50%
Payback Period (months) 14 11 8 6 8 18 22
Year 1 Gas Price (3) $2.63 $2.48 $2.95 $2.65 $2.63 $2.76 $2.79
Future Development Locations (4) 13,222 282 3,313 2,011 1,650 1,179 631
Notes:
(1) Average operating expenses over the initial five years of production.
(2) Internal Rate of Return calculation is based on monthly cash flows.
(3) Independent Reserve Engineer Jan 1, 2021 escalated price forecast, adjusted for transportation, quality and heat content.
(4) See Schedule A.17
The TOU Engineering Execution Machine
Mar 2021
$mm Drill & Complete Costs
$8 Tourmaline has the lowest completed per stage (Equipping not included)
well costs in the overall Montney play in
6.8
$7 Western Canada and the Alberta Deep Basin. South Deep Basin
6.0
$6 5.7 5.5 NEBC (South Complex)
5.3
$5 4.5 PRH (Charlie Lake SR)
4.1 4.2
$4 3.5 3.4 3.6 3.4 3.4
3.2 3.2
2.8 2.7 2.7 2.6
$3 2.5 2.4 2.6
2.4 2.3
$2
$1
$0
2013 2014 2015 2016 2017 2018 2019 2020
• Since Feb 2009, Tourmaline has drilled 1,765 wells across all three core operated complexes.
(Deep Basin 888 wells, NEBC 560 wells, PRH oil 355 wells)
• Through continuous engineering design improvements in all aspects of drilling and completions
operations, Tourmaline has realized a cost reduction of over 50% in all 3 complexes since 2012.
• Tourmaline has the internal staff capability to efficiently operate 22(+) drilling rigs, the current 5
year financial outlook assumes a 11/15 rig program.Realizing the Upside, Accelerating FCF 18
From Q4 2019 – Q2 2021 Acquisitions
Sept 2021
1. Utilize the TOU Execution Machine – Lower capital costs,
Conroy improved well performance, superior long term
integrated development planning models.
Montney 2. Optimize the Existing Base – Enormous inventory of low
Birley cost, short term production addition opportunities.
Gas/Cond
3. Reduce All Aspects of Cash Costs – Full realization of
identified synergies.
Gundy
Peace River High 4. Grow the Liquids Business/Optimize Liquids Margins
Charlie Lk Oil
Alberta Mulligan/Earring
Sunrise- Black Swan/Saguaro/Polar Star Assets
Dawson • 20% reduction in TOU NEBC drill times further
British
Columbia Spirit River increases the identified Capex reduction on all
Sundown
acquired NEBC assets.
Jupiter/Modern Assets Tupper • Laprise drilling costs down to $1.25-1.30M/well.
• >40% D,C,E per well
capital cost reduction
realized. Chinook Musreau/ Accelerations of Gundy and Nig Creek Deep
• $0.50/boe opex reduction Ridge Kakwa Cuts/Liquids Growth
to date, target additional Route Alberta Deep • Additional 15,000 bpd by Q1 2022.
Leland
$0.25-0.50/boe reduction Lynx Fir Basin • Tie-ins to TOU Aitken liquids hub.
in 2022. Cutpick
Cecilia
Harley
Edson
Optimizing the Deep Basin Base Wolf Optimizing the NEBC Base/Margin Improvements
H
Marsh Creek
• Liquids pipeline connections and • North Montney downtime reduced by 45%
handling capabilities, detailed per well Hinton Ansell overall (2021 vs 2019).
production optimization. Minehead
• Gas and liquids processing fees reduced by 25%
• 4,000 boepd production uplift realized in Lovett on specific acquired assets.
Q3 2021, incremental 3,000 boepd
Brazeau
target in 2022.
B
A19
Consolidation Financial Lookback
Sept 2021
TOU’s acquisitions through 2019 – 2021 were strategic, expansive and very accretive
• TOU has acquired ~$2.3bn in assets since 2019, which now generate ~1/3 of TOU’s total free cash flow and
total cash flow. These acquired assets sum to 1.2 million net acres, 1.4 billion boe net 2P reserves1, and 4,500
gross drilling locations.
• The suite of acquired assets is generating a FCF yield well in excess of the base EP program, a key screening
criteria
• Tourmaline’s consolidation of the Alberta Deep Basin and BC Montney is now essentially complete
• With no future large transactions planned, only small asset deals or land purchases are envisioned through the
remainder of 2021 and into 2022
Consideration & Acquired Cash Flow ‘22 Consideration / Cash ‘22 Free Cash Flow /
Funding and Free Cash Flow Flow Multiple Consideration Yield
~$2.3bn aggregate consideration
2.8x 35%
since 2019 2.7x
Inf / Land ~$900mm
2.6x
/ Conroy / TPZ 30%
Modern / 2.4x 30%
Saguaro
2.2x 2.1x
>$500mm 25% 25%
Jupiter 2.0x
TOU
Cash 1.8x
& 20%
Black Stock 1.6x
Swan
1.4x 15%
1.2x
1.0x 10%
Consideration Funding 2022 CF 2022 FCF Pre TPZ Post TPZ Pre TPZ Post TPZ
All cash flow and free cash flow figures as per July15th strip. Consideration inclusive of Q4 2019 Gundy land acquisition; consideration excludes all TPZ historical consolidated activity.
1 All but approximately 140 mmboe of the acquired net 2P reserves have been evaluated by GLJ Petroleum Consultants or Deloitte LLP, independent reserve
evaluators, as at the respective transaction dates. The remaining 140 mmboe has been internally estimated by qualified reserve engineers.20
Continuous Capital Efficiency Improvements
Sept 2021
$22,500 • 2022 is expected to yield the best capital efficiency
$20,900 metrics in company history.
$20,000 • 2018 & 2021 are affected by the Gundy Deep Cut gas plant
expenditures.
$17,500
$15,500
$15,000
$12,500
$/boepd
$11,200
$10,000 $9,500 $9,500
$8,650
$7,800
$7,300
$7,500
$6,000
$5,000
$2,500
$- (1) (2) (1)
2014 2015 2016 2017 2018 2019 2020 2021E 2022E
(1) Based on 5 Year Plan Guidance released on September 22, 2021
(2) Includes $145 million related to major Gundy Phase 2 Deep Cut gas plant expenditures21
Continuous Cost Reduction Strategy
Sept 2021
Operating Costs General and Administrative Costs
($/boe) ($/boe)
$7.00 $1.50
$6.50 $6.34
$1.29
$6.00
$5.58 $1.02
$5.50 $1.00
$4.87 $0.79
$5.00 $0.74
$4.43 $4.35 $4.37
$4.50 $0.60
$0.56
$0.49 $0.49
$4.00 $0.50 $0.45 $0.44 $0.46
$3.50 $3.31 $3.33 $3.28
$3.19 $3.14
$3.00
$2.50 $0.00
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
• Tourmaline has the lowest effective interest rate/borrowing costs in the North American energy sector.
• $450mm of long term public debt issued at ~2.30% maturing in 2028 & 2029
• 2021 aggregate effective interest rate expected to be ~3%
• The staff required to effectively operate a 500,000 boepd and growing company already been assembled.22
2021 Natural Gas Transportation
and Marketing Overview July 2021
2021 Exit: 624 mmcf/d of gas will be to US/Other Markets
2022 Exit: 860 mmcf/d of gas will be to US/Other Markets
2023 Exit: 905 mmcf/d of gas will be to US/Other Markets 2021 Average Natural Gas Portfolio
Diversification (3)
38%
Station 2
9% 9%
(1)
AECO 28% 25%
25%
TCPL Mainline Dawn/Iroquois
~134 Mmcf/d
(2)
US/Other Markets Hedges Stn 2 Aeco
Kingsgate
(1) US/Other Markets access 26% physical markets + 2% of Nymex Basis
Differentials
(2) ~21% of Station 2 exposed at 7A/Hunt
California US Midwest/Other
(3) Black Swan Hedges are reflected August 1st 2021 Forward
~345 MMcf/d ~84 Mmcf/d
*Average volumes
*California exposure increases to 445 Mmcf/d in exit 2022, and 495 Mmcf/d in exit 2023
*150 Mmcf/d AB Express/Cheniere LNG starts exit 202223
Tourmaline/Cheniere LNG Export Overview
July 2021
Canada’s Largest Gas Producer and the
Largest U.S. LNG Company create a unique Overview
• Tourmaline is the largest natural gas producer in Canada at 2.1 Bcf/d
cross border marketing arrangement
• Natural gas supplied from Tourmaline’s Alberta Deep Basin and/or B.C
N. Montney North Montney core complexes.
• LNG Netback Supply Agreement provides international price exposure
to JKM for Tourmaline.
• Cheniere export capacity is currently up to ~6.5 Bcf/d
Deep • Tourmaline to supply 140,000 MMbtu/d (1 cargo/month), 15 year term
Basin • Low emission Tourmaline natural gas will now access Asian markets
TC Energy
TC Energy P/L MAINLINE
P/L NGTL
TC Energy
P/L GLGT
EXPRESS
Pipeline Pathway (US$/MMbtu)
TC Energy P/L NGTL
TC Energy P/L Mainline
TC Energy P/L GLGT/ANR
TOTAL Pipeline Tolls 0.86 TRANSCO
PIPELINES
TC Energy
P/L ANR
Corpus Christi Liquefaction
Corpus
Terminal Overview TRANSCO
PIPELINES
Cheniere
Corpus Christi Christi
• 3 Trains Complete, 2.4 Bcf/d Capacity Pipeline Liquefaction
Facility
• Stage 3 Expansion adds 1.6 Bcf/d See
export capacity Corpus Christi Corpus Christi Area Detail
Area Detail24
2021 & 2022 Guidance
Sept 2021
2021(1) 2022(1)
Production – Boe/d 442,500 500,000
Cash Flow(i) - $MM $3,000 $3,705
CFPS - Diluted(i) $9.49 $11.24
E&P Capital Program(ii) - $MM $1,375 $1,125
Total Net Capital Expenditures(iii) - $MM $1,413 $1,180
Free Cash Flow(iv) - $MM $1,587 $2,525
Exit Net Surplus (Net Debt)(i) - $MM ($958) $1,333
Debt to CF 0.3x N/A
(1) Price Assumptions: Gas price - $3.77/mmbtu 2021 NYMEX US, $4.27/mmbtu 2022 NYMEX US, $3.77/mcf 2021 AECO, $4.08/mcf 2022
AECO; 2021 Oil price - $66.22/bbl WTI US, 2022 Oil price - $67.66/bbl WTI US.
(i) See “Non-GAAP Measures” in the Forward Looking Statement Advisories section of this presentation.
(ii) E&P Capital Program is defined as total capital spending before acquisitions, dispositions and other corporate expenditures.
(iii) Total Net Capital Expenditures is defined as the sum of E&P Capital Program and other corporate expenditures, net of non-core
dispositions.
(iv) Free Cash Flow is defined as Cash Flow less Total Net Capital Expenditures. Free Cash Flow is prior to dividend payments made by
Tourmaline and Topaz.25
Environmental Performance
Investment & Returns July 2021
Focusing on investment opportunities that maximize cost savings & environmental impact
• Water: recycling, & pipeline infrastructure; ~100% recycling in NEBC, advancing AB towards 100%
• Land: reclamation, well abandonment, road management, pad optimization
• Air: diesel displacement, pneumatic / venting reduction, power (highline), energy efficiency, CCUS, RNG
• Technology: CCUS, NGIF, RNG, other initiatives
$mm/yr Capital Investment $mm/yr
Annual Cost Savings & Emission Reduction C02e/yr
$140 $140 600,000
$20 - $40mm/yr of capital to be invested in Investments to date have reduced
environmental performance improvement emissions ~250,000 C02e per year
$120 initiatives going forward $120
500,000
Substantial future annual carbon tax
Investments to date all have made an economic savings secured (~$24mm @ $100/ton)
$100 return, along with a substantial positive $100
environmental impact 400,000
>$30mm in yearly operating & capital
$80 cost savings already secured
$80 Future annual savings per year will far surpass
investment per year; environmental investment 300,000
is another source of free cash flow $60
$60
200,000
$24
$40 $40 $24
$25 $11 $11
$20 $11 100,000
$20 $11 $20
$11 $6 $10 $11
$11 $8 $15 $18
$8 $9 $10
$- $3 $0 0
2019 2020 2021 2022 2023 2024 2025 2026 2019 2020 2021 2022 2023 2024 2025 2026
Water Land Emission Technology / Scalable Investment Water Diesel Power/Vent Carbon Tax C02e / Year (Base) RHS
See Tourmaline Sustainability Report for more detail; forward looking estimates are illustrative only Illustrative Credit / Offset @ $100/ton26
Tourmaline 2022 Cash Flow Sensitivity
& Allocation Sept 2021
Tourmaline’s low cost structure drives sustainable return on, and of, capital opportunities
• TOU’s maintenance budget, dividend, and base EP growth fully funded at US$1.50/mcf
• Current strip provides meaningful free cash flow, >$1.0bn per year in every year of the five year plan
• Allocated to base and special dividends, tactical buybacks, bolt on acquisitions and liquids infrastructure
($mm)
$4,000
2022 Cash Flow NYMEX Sensitivity & Allocation
$3,750
>US$4.00/Mcf
$3,500 US$4.00/Mcf
FCF Available For:
$3,250 US$3.75/Mcf 2022 / 2023 Calendar Strip – Recent Trading Range
(1) Base Div Incr.
$3,000 US$3.50/Mcf (2) Special Div
US$3.25/Mcf (3) Tactical Share
$2,750
US$3.00/Mcf Buybacks
$2,500 US$2.75/Mcf (4) Bolt on Acq
US$2.50/Mcf (5) Liquids Inf.
$2,250 Investment
$2,000 US$2.25/Mcf
US$2.00/Mcf
$1,750
US$1.75/Mcf Maintenance + Dividend + Growth Coverage at US$1.50/Mcf
$1,500
$150mm
$1,250 Cash Flow at $235mm
$1,000 US$1.50/Mcf
$750 $1,050mm
$500
$250
$0
'22 Cash Flow Per Maintenance Budget TOU Base Dividend 3-5% Production Available Funds
NYMEX Price Level Growth Per Year
(Sept 15th Strip WTI)
For sensitivity capital and basis assumptions and definition of free cash flow please see 5 year plan slide.27
Tourmaline is North America’s Most
Attractive Natural Gas Investment Sept 2021
TOU offers the most compelling investment proposition amongst large cap North American peers
• Superior Margin: Stronger sales hub pricing and transport at ~50% the cost of US Appalachia peers
• Best FCF Offering: ~$6,000/boe capital efficiencies and an investment grade balance sheet combine to create the
best free cash flow offering which will flow to the benefit of equity holders sooner than deleveraging peers
• Deep Inventory: Multi decade outlook for return on and of capital, with no ‘exhaustion’ overhang
• Differentiated Demand Outlook: LNG Canada (+2-4 Bcfpd), Rockies Displacement (+1 Bcfpd), Local (+2 Bcfpd)
• Leader in ESG: Decade ahead on water recycling, methane capture, emission reduction, plus aligned governance
US$ Cash Flow / Boe(1)
2020A 2021E 2022 FCF/EV Yield(1) Years of Inventory(2)
20% >75 yrs
Healthy and organically … leading to further
$12. 00
US$15 18% As resource & inventory depth
driven cash flow through 18%
margin expansion in 2021 become a focus, TOU has multiple
the pandemic… 16%
$10. 00
decades of development and no
US$8 14%
$8.00
need for transformative M&A
12%
$6.00
10%
8%
6%
$4.00
$2.00
4%
2%
$0.00
0%
TOU EQT CNX AR RRC TOU EQT CNX AR RRC TOU EQT CNX AR RRC TOU EQT CNX AR RRC
Unhedged Realized Cash Hedge Gain 2021E Cash Flow /boe 2022E Strip FCF/EV Yield Years at 2019 Drilling Pace
1. TOU as per guidance, peers as per BMO “Post Q1 Model Book” August 10, 2021. All TOU data is converted to USD at $0.79. TOU FCF/EV as of June 15th, 2021, TOU EV net of Topaz Equity Value.
2. TOU as per Schedule A (Hz wells) – Pace at 2021 basis (accounts for acquired location pacing), peers as per BMO “Who’s Got What, Appalachia Edition” December 16, 2020 (Tier 1, 2, & 3) vs 2019 Drilling Pace.28
Growth Discipline Maximizes Margin &
Free Cash Flow Sept 2021
Our strategy is to pursue gradual organic production growth of 3-5% through the base EP program, and
continuing adding scale through select, bolt on accretive acquisitions, ultimately owning a larger
proportion of supply, at a higher margin, with more free cash flow, than we would if rapidly growing
• Tourmaline remains the largest Canadian natural gas producer and from a market share perspective
represents:
• ~13% of current WCSB Receipts
• ~20% of Canadian gas rig count
• ~20% of WCSB gas adds in 2020 Our Market Share Focus
• >40% of Aggregate 2022 Free Cash Flow generated by WCSB Natural Gas E&P peers(1)
Canadian Gas Drilling Rigs(2) Bcf/d WCSB Receipts(2) $mm 2022 Peer Gas E&P FCF(1)
19 $3,000 … Higher free cash flow,
250 Less drilling leads to… … Less overall supply which leads to…
particularly for those with the
18 $2,500 lowest supply cost
200
17 $2,000
150
(# rigs)
16 $1,500
100
15 $1,000
50
14 $500
0 13 $0
Jan
Apr
Sep
Oct
Nov
Dec
Feb
Mar
May
Aug
Jun
Jul
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec TOU Canadian Peers(1)
2018 2019 2020 2021 While growing organically at ~5% CAGR,
2015–20 range 5-yr avg 2020 2021 TOU will generate ~$8bn in Free Cash
1. TOU as per guidance, peers as per Bloomberg consensus Sept 15th 2021; WCSB Nat Gas peers AAV, ARX, BIR, KEL, PEY, POU, SDE
Flow over the next 5 years
2. Charts Sourced to: Peters & Co. and DesjardinAPPENDIX
30
Tourmaline / Topaz Deconsolidation
Illustrative Reporting Change May 2021
Following the second quarter 2021 Topaz equity raise, Tourmaline’s financial treatment of Topaz is expected to shift
from fully consolidated to equity method.
Illustrative 2020 Net Debt – Consolidated to Equity Method
Net Debt & Illustrative Topaz Value
Fully
Consolidated Changes
Equity
Method
Illustrative equity method 2020 net debt and
Net Debt (YE 2020) $1,785 $238 $2,023
cash flow items provided are a useful guide
Topaz Net Cash for post deconsolidation directional modeling
2021 Topaz Ownership Value (58mm Shares @$13.60/share (Dec 31 Close) $791
& reporting changes
Key 2021 Items
Illustrative 2020 Cash Flow – Consolidated to Equity Method • Q1 was reported on a consolidated basis
• Q2 will be reported on a deconsolidated basis as of
Netback Change the close of the TPZ equity raise. This means the
Fully Equity Fully Equity
Changes to Cash Flow (2020) Consolidated Changes* Method Consol. Method
cash flow statement will include consolidated
activity before the deconsolidation date (i.e., the
Revenue Ex Other Income & Unrealized $2,224 $1 $2,225 $/boe $19.56 $19.58 CVE clearwater transaction) but the balance sheet
Topaz Hedges will be presented on a deconsolidated basis (No TPZ
Other Income $40 -$22 $18 $/boe $0.35 $0.16
Other Income Allocated to Topaz
PP&E or net debt, but TPZ listed as a long term
Royalties $66 $59 $125 % of Rev 3% 6% financial asset). Q2 dividends paid will be TOU
Topaz TOU GORR dividends only, Q2 TPZ dividends received will be
Operating Expense $357 $15 $372 $/boe $3.14 $3.27 included in cash flow from operating activities.
Topaz TOU Tak e or Pay's
Transportation Expense $510 $0 $510 $/boe $4.48 $4.48
• Q3 will include the impact of the TOU/TPZ NEBC
transaction (July close) on TOU’s statements
G&A Expense $64 -$5 $59 $/boe $0.56 $0.52 ($245mm sale).
Cash Finance Expense $50 -$1 $49 % YE ND 2.8% 2.4%
Tourmaline’s 2021 guidance and 5 year plan
Other Expenses, Net $33 $0 $33 $/boe $0.29 $0.29 is now presented on a deconsolidated basis
Cash Flow before dividends received $1,186 -$89 $1,097 $/boe $10.43 $9.65
Dividends Received from Topaz $0 $47 $47
Cash Flow $1,186 -$43 $1,143 $/boe $10.43 $10.05
*Amounts added to or subtracted from the fully consolidated balances may not agree to the respective balances of Topaz's published financial statements,
as some amounts have been reclassified for presentation purposes.31
Tourmaline Financial Position
Excellent Liquidity, Resiliency & Capacity Sept 2021
Tourmaline has ample liquidity and capacity to weather adverse commodity prices
Debt Profile & Cash Flow Sensitivities Credit Facility & Term Loan Covenants
Debt Profile, Term, Capacity Total Debt / Total Capitalization must not exceed 0.6x
$mm $mm 0.6x
3500 3,250 3,250 3,250 3,200 3,200 3,200 12,000 0.6x
3000 2,800
10,000 >4x Debt Capacity 0.5x
2500 Increase
1,785 8,000 0.4x
2000 (Equity Held Flat)
6,000 0.3x
1500 Unsecured, highly flexible, 0.2x 0.1x
1000 long dated maturities 450 450
4,000 0.2x
500 200 2,000 0.1x
0
0 0.0x
YE Net 2021 2022 2023 2024 2025 2026 2027 2028 2029
YE 2020 2021 Curr. Budget Covenant
2020 Debt
YE20 Total Debt Total Capital Debt to Total Capital
Public Debt Credit Facility (2026) Term Loan (2026) Additional Lines
2022 Cash Flow Sensitivities TTM EBITDA / Interest Expense must exceed 3.0x
Change in: $mm
3,000 52x 60x
Sensitivity remains
Oil US$1/bbl $22 2,500 50x
primarily to
natural gas 2,000 40x
27x >$2bn EBITDA room
FX $0.01 $60 1,500 30x
1,000 20x
500 3x 10x
Gas US$0.10/Mcf $75
(NYMEX) 0 0x
YE 2020 2021 Curr. Budget Covenant
$mm $0 $10 $20 $30 $40 $50 $60 $70 $80
EBITDA Interest Expense EBITDA to Interest Expense
As per Tourmaline financial disclosure, and the current five year plan; sensitivities are full year.32
Historical EP Performance
Mar 2021
Production Growth Per Share* Reserves Growth Per Share*
500 14
Production per Thousand Shares
Reserves per Share (BOEs)
12
400
10
300 8
(BOEs)
200 6
4
100
2
0 0
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Op Costs/BOE Cash Flow Per Share
$7.00 $6.00
Cash Flow per Share ($)
$5.00
$6.00
$4.00
$5.00 $3.00
$2.00
$4.00
$1.00
$3.00 $0.00
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
• 2010-2020 Production growth per share CAGR of 25%. • 2P Reserve Value of $17.2 billion after 11 years.
• Leading low capital costs and low cash costs allow Tourmaline to grow profitably on a full cycle basis at natural gas prices above US$1.50/mcf.
* Debt adjusted33
Independently Recognized Canadian 2P Reserves(1)
Mar 2021
Tcf Natural Gas 2P Reserves MMbbl Conventional Liquid 2P Reserves
18 1,200
16 15 Tourmaline has historically converted 2P reserves
Tourmaline has booked only 13% of existing drilling inventory
to PDP reserves in approximately 4 - 5 years. 1,000
14 (2,579 of 20,014 locations – See Schedule A)
YE 2020 2P reserves are 3.3 billion boe.
12 800 738
10
600
8
6 400
4
200
2
0 0
Peer TOU Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer TOU Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer Peer
1 2 3 4 5 6 7 8 9 10 11 12 13 14 1 5 13 12 8 14 3 7 2 4 9 11 6
$bn 2020/2019 Change in Before Tax NPV 10% 2P Value
$3.0 $2.1
$2.0
$1.0
$0.0
-$1.0
-$2.0
-$3.0
-$4.0
-$5.0
TOU Peer 4 Peer 6 Peer 7 Peer 9 Peer 2 Peer 8 Peer 3 Peer 5 Peer 12 Peer 11 Peer 13 Peer 10 Peer 14
(1) Canadian Protocol, most recent disclosure. Peers include Advantage, ARC, Birchcliff, CNRL, Cenovus, Crescent Point, Crew, Kelt, NuVista, Paramount, Peyto, Seven Generations, Suncor, Whitecap34
EP Growth Plan
(Original Business Plan)
Sep 2008
This is essentially the same business plan that was executed for Duvernay Oil Corp. (2001-2008)
• Primary growth mechanism will be a conventional EP Program (including
Resource plays).
• Build 2-3 core EP areas during initial three years of operations.
• Strive for large land positions, operatorship and infrastructure control in
those core areas.
• Achieve profitable annual growth via low operating cost/high netback
properties.
• Operate with a relatively small, technically strong staff.
• Dispose of non-core assets on a continuous basis, as appropriate.35
Sundown
NEBC Montney Gas Complex Mar 2021
Current Prod. 120 mmcf/d
Current Reserves 2P 984 bcf (2P) TC Pipeline
Livingstone 2 MS.
Current OPEX $1.20/boe ~12km from CGL
Montney Growth In excess of 857 horizontal locations in inventory,
only 90 booked in current GLJ report.
Facility expandable to 250 mmcf/d by 2026
Murphy Oil Corp.
2019 21 bcf EUR wells
2020/21 Expansion and Land Consolidation:
• Expansion from 60 mmcf/d to 120 mmcf/d using inventoried equipment.
• 2020 land consolidation adds ~40 additional locations off existing TOU
pads. Allows for optimized 2,000-2,400m lateral development plan.
Reserve Growth and Cost Performance 2020 TOU 9-9 Pad
2P Reserves
5 wells, 1500m lat.
2,000 6.0
D/C/E Cost
2P Reserves (bcf)
Well Cost ($MM)
1,500 4.5
1,000 3.0 2020/21 4-4 Pad
5 wells, 2100m lat.
500 1.5
0 0.0
2015 2016 2017 2018 2019 2020 B-67-H Gas Plant
120 mmcf/d
10 Recent Sundown Results
Sundown 7.8 bcf Type 2019 C-51-H Pad
9-9 Pad (Nov. 2020) 6 wells, 1350m lat.
8
C-51-H Pad (Apr. 2019)
6
mmcf/d
TOU Land
4
TOU Pipelines
2
TOU Gas Plants
New Exploration Drilling in
0 Major Pipelines Montney C, and E Lobes
1 2 3 4 5 6 7 8 9 10 11 12 2021/2022 Prop Loc.
Month36
Alberta Deep Basin
Liquids Rich Cardium Fairway
Nov 2019
Only the initial Cardium delineation 16-20-50-22W5 PAD (2 Hztl) 6-1-51-23W5 PAD (2 Hztl) 12-36-50-23W5 PAD (1 Hztl)
locations are depicted, the potential IP 90 – 16.8 mmcfpd IP 90 – 21.7 mmcfpd IP 90 – 15 mmcfpd
location inventory is significantly CR - 10.5 mmcfpd, 184 bbls/d CR - 7.6 mmcfpd, 80 bbls/d CR - 4.5 mmcfpd, 60 bbls/d
larger. Note that each depicted
CUM – 3.1 bcf, 72.6 mbbls CUM – 6.3 bcf, 120.5 mbbls CUM – 7.4 bcf, 204 mbbls
surface location represents two hz
EUR – 14.5 bcf, 305 mbbls EUR – 18.0 bcf, 255 mbbls EUR – 13.0 bcf, 296 mbbls
wells (hanging wall/footwall)
16-30-50-22W5 PAD (1 Hztl)
T59 T59 R.24 R.23 R.22 R.21 Cardium Drilled Wells
Tourmaline
IP 90 – 8.2 mmcfpd T52
Smoky Tourmaline 2019 Cardium Wells
CR - 2.9 mmcfpd, 70 bbls/d
Tourmaline Cardium Locations
T57
CUM –T57
1.1 bcf, 34.6 mbbls
EUR – 4.3 bcf, 120 mbbls
T51
T55 T55
Cabin
Creek
T53 T50
7-11-51-23W5 PAD (1 Hztl)
Anderson
R3 R1W6
102/2-11 - 11.3 mmcfpd, 120 bbls/d
15-10 – 24.1 mmcfpd, 724 bbls/d
T49
120 hour Average Test Rate Sept. 2019
ANDERSON DEVELOPMENT 12 Wells T49
CR - 86 mmcfpd, 2033 bbls/d
10-25-50-23W5 PAD (1 Vert, + 1 Hztl)
CUM – 44.7 BCF, 1.01 mmbbls T47
IP 90 – 28.5 mmcfpd,
EUR – 123.0 BCF, 2.53 mmbbls CR - 14.5 mmcfpd, 185 bbls/d
T45
CUM – 13.5 bcf, 251 mbbls
The combination of extensive 3D seismic coverage and the
EUR – 28.0 bcf, 474 mbbls
lowest cost drilling/completion capability make the liquids
rich Cardium play a significant new incremental T43
Tourmaline Lands
opportunity in the overall Tourmaline Deep Basin portfolio. Stolberg Liquids Rich Cardium Fairway
R24 R22 R20 R18 R16 R14 Cardium Faults
R2637
Gundy Creek Deep Cut Plant
Sept 2021
Gundy Phase 1: Plant start-up in May 2019, constructed in 6 months, 200 mmcfpd/15,000 bpd capacity, on budget and
ahead of schedule
Gundy Phase 2: Plant start-up expected exit 2021 / Q1 2022; capacity of 200 mmcfpd/15,000 bpd, $145mm associated
capital expenditure included in 2021 budget38
Tourmaline Environmental Performance
• Tourmaline strives to continually improve all aspects of environmental performance including the
impact of its operations on air, land and water.
• Tourmaline has the lowest CO2 emissions and emission intensity of the Canadian Senior producers.
• Tourmaline is an industry leader in eliminating the use of diesel in all field operations (new
technology development, utilization of highline power).
• Tourmaline is Canada’s largest natural gas producer. Natural gas by far the ‘cleanest’ of the fossil
fuel group.
• Tourmaline is at the forefront of multi-well pad drilling in Western Canada, dramatically reducing
the surface impact of full cycle resource play development in all three core operated areas.
• Tourmaline has dramatically reduced CO2 and CH4 emissions by conducting all well testing in-line ,
utilizing low emission controllers, employing waste heat recovery, developing new methane
measurement and reduction techniques.
• Tourmaline is an industry leader in non-potable frac water sourcing with eight frac water
source/recycling facilities (>1,000,000 m3 capacity) avoiding the use of fresh water in frac
operations. Tourmaline is one of the first operators in B.C to utilize produced water in frac
operations and is the first company in Alberta to, with approval, employ this practice.39
Sustainability Performance Highlights
June 2021
Tourmaline has been aggressively and successfully pursuing a comprehensive environmental performance
improvement strategy for over six years. The Company is systematically improving its performance and reducing the
impact of all aspects of the Company’s activities upon air, land and water.
Achievements • 31% reduction in CO2 emission intensity since 2013 (39% inclusive of Pneumatics effective 2020)
+289%
• 95% of completion water recycled from gas operations (~100% elimination of fresh water in NEBC)
Production
• Initiation of methane reduction retrofit compliance plan in 2019; 3,400 controllers replaced
• A 50% reduction in the surface area per producing well in the Company’s operating areas
-31%
C02
• Broad replacement of diesel in Tourmaline’s drilling and completion operations with natural gas
‘13 ‘19
Targets
• Targeting a 25% reduction in total methane emissions from 2018 levels by 2023 (on track for 2021)
-25%
• Reduce corporate emissions intensity by 25% by 2027(1), through the application of new, innovative
Methane technologies including the electrification of assets
Emissions
by 2023 • Targeting elimination of fresh water usage in well stimulation operations (NEBC ✓)
‘18 ‘23
Initiatives
• Trial full electric (zero diesel) drilling rig in the Peace River High complex in 1H/2020
Work Towards • Migrate completion fleet to natural gas turbine technology (Trican JV 1H/2021)
0
Diesel rigs in PRH
Diesel Turbines • Migrate all field operations towards low bleed, zero venting three phase technology devices that
Venting in field ops reduces fugitive methane emissions
(1) Scope 1, using 2018 as a baseline. See 2020 sustainability report for details40
Diesel Displacement Initiatives
Sept 2020
Initiative Annual Emissions Impact Net Savings
Highline Power • 1.4mm litres/yr fuel displaced $400,000/yr savings
• PRH rig running on 100% electricity • 3,100 tC02e/yr
Natural Gas Fuel Gas Substitution • 15 mm litres/yr fuel displaced with $10mm/yr savings
TOU owns & operates 15 diesel displacement packages Natural Gas 3.5 month payout on
• Rigs & Frac spreads achieving ~40% substitution. • 9,500 tC02e/yr reduction install
• Path towards 100% natural gas powered D+C program
Natural Gas Power Generation
• 3,000 litres/d fuel displaced with ~$50k/pad savings
• 330 kW gas turbines operating across NEBC asset base since Natural Gas
July 2019
• 50 tC02e/pad reduction
• Two TOU designed natural gas powered electrical packages
• 44% emissions reduction
online in Alberta Completion operations since July 2020
Pad Electrification • Additional 9,000 litres/d to be displaced
~$150k/pad savings
• Working towards total pad electrification through natural gas; with Natural Gas and 5.5 tC02e/d
removal of all diesel generation by end of 2021 reduction once in place.
TOU diesel displacement with NG TOU diesel displacement fleet TOU Lease Electrification InitiativesContinuous Environmental Performance Improvement 41
Through Innovative Application of New Technologies
• Massive reduction in flaring
• Water recycling for fracs Tech Service
• Gas fired drilling rigs/fracs
• Methane leakage elimination across all
operating regimes
• COSIA & NGIF industry technology
development alliances
• Surface footprint reduction/pad drilling
• Widespread electrification.
Basic Research
• Multiple CO2 mitigation strategies/CCS
• Smart pipelines/wellsites
CANADIAN OIL & GAS IS THE WORLD LEADERTourmaline Environmental Performance 42
Improvement Highlights
June 2019
BC Water Management Alberta Water Management
• 95-100% of all water sourced for stimulation operations is • 1st, and only, company in Alberta to be licenced to store
recycled and recycle produced water from an in-ground storage pit
• 100% of all water flowed back from completion operations is • 50-75% of water sourced for stimulation operations is
recycled recycled and is growing
Drilling/Completion Emissions Reductions Methane Emissions Reduction
• 30% lower CO2, 75% lower Nox, 99% • 487 Tonnes of methane removed due
lower SOx emissions to modifications to facility controls on
• 90% lower particulate emissions our dehys/refridge units
• Drilling Rigs achieving ~60-70% • 326 controllers replaced to low
displacement of diesel emission models NOTE: Program
continues in 2019 to inventory all
natural gas pneumatic controllers
• In 2019 waste heat recovery
technology was incorporated into our
plant design43
Tourmaline Technology Curve/Future
Concepts, Requirements & Opportunities
• Cost saving via novel frac water sourcing/recycling
• New Waste heat recovery technology
• Alternative hz frac programs/processes
– Concurrent pairs, delayed flow-backs etc.
• Novel drilling technology to reduce time/cost • Utilizing gas fired turbines to reduce
in drilling builds costs for drilling, completions, facilities
• Refine drilling techniques/cost savings for • New mud systems to reduce drilling times
frontal foothills Wilrich/Notikewin hz drlg
• Improved horizontal stimulation techniques, new
• Ball drop/sliding sleeve completion approaches to maximize deliverability and
technique in vertical wells recovery
• Sour frac water sweetening technology
• Develop predictive reservoir/reserve tools
for horizontal clastic gas wells
• Improved Wilrich seismic imaging in strat
• Understanding controls on Wilrich settings and Outer Foothills settings
deliverability/develop predictive tools
• Paleozoic/New Deep Play concepts
• New shale/source rock plays
• AI applications in geophysical interpretation, reservoir
prediction and predictive drilling problem identification.
• Pasquia Hills oil shale recovery
mechanisms44
Schedule A
DRILLING LOCATIONS
Estimated Drilling Inventory
This presentation discloses drilling locations in four categories: (i) proved undeveloped locations; (ii) probable undeveloped
locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 22,810 (gross) locations disclosed in this
presentation, 1,675 are proved undeveloped locations, 24 are proved non-producing locations, 1,467 are probable undeveloped
locations, 0 are probable non-producing and 19,644 are unbooked. Proved producing wells, proved undeveloped locations,
proved non-producing locations, probable undeveloped locations and probable non-producing locations are booked and derived
from the Company's most recent independent reserves evaluation as prepared by GLJ and Deloitte LLP as of December 31,
2020, and internal estimates for assets acquired during 2021, and account for drilling locations that have associated proved
and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company's prospective acreage
and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review.
Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations
have been identified by management as an estimation of the Company's 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 will actually drill wells, including the number and timing
thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas
prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number
of the unbooked drilling locations have been derisked 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.
The following provides additional information on the Company's estimation of unbooked locations.You can also read
