Aug ugust ust 2018 2018 2 Current Status Aug 2018 Production - - PowerPoint PPT Presentation

Cor

• rpo

porat ate e Presentation entation Aug ugust ust 2018 2018

Current Status

Production Overview  2018 average production forecast of 267,500-275,000 boepd  2018 average liquid production of 50,000 bpd  2018 production exit estimate of 290,000-297,500 boepd. Three Major Core Areas  Alberta Deep Basin: Approximately 1.8 million acres (largest Deep Basin land position)  NEBC Montney Gas/Condensate: One of Canada’s largest Montney producers  Peace River Triassic Oil: Three large, regional, light oil and gas resource plays  All three core areas completely de-risked via 1,200 wells drilled by Tourmaline since February 2009. Reserves  2P gas reserves of 10.7 TCF (Jan 1, 2018)  2P liquid reserves of 431.6 mmbbls (Jan 1, 2018)  Only 14% of existing drilling inventory booked (2,074 of 14,471 locations – see Schedule A) Drilling Inventory  Approximately 6,167 horizontal locations in the Deep Basin; 3,633 hz Montney locations in NEBC; 1,898 locations in Peace River High Charlie Lake core area (see Schedule A) Financial Position  Net Debt $1.5 billion (June 30, 2018)  Top quartile debt to cash flow ratio will be maintained  EP Capital budgets will generate free cash flow for 2018 and beyond  Cash flow increased by 65% to $1.2 billion in 2017, from $732 million in 2016  Continued strong earnings reflect Tourmaline’s capability to generate growing full cycle returns for shareholders. Shares OS  272.1 million (June 30, 2018)  Insiders have purchased over 22% of OS (fully diluted) (D&O ownership 7.0%)

Aug 2018

2

Historical EP Performance

1 2 3 4 5 6 7 8 9

2009 2010 2011 2012 2013 2014 2015 2016 2017

Reserves per Share (BOEs)

Reserves Growth Per Share*

50 100 150 200 250 300 350

2009 2010 2011 2012 2013 2014 2015 2016 2017

Production per Thousand Shares (BOEs)

Production Growth Per Share*

$3.00 $4.00 $5.00 $6.00 $7.00

2009 2010 2011 2012 2013 2014 2015 2016 2017

2009-2016 Op Costs/BOE Mar 2018

3

$0.00 $1.00 $2.00 $3.00 $4.00 $5.00

2009 2010 2011 2012 2013 2014 2015 2016 2017

Cash Flow per Share ($)

Cash Flow Per Share

• 2010-2017 Production growth per share CAGR of 30%.
• 2P Reserve Value of $15.1 billion after 9 years.
• Lowest capital costs and low cash costs allow Tourmaline to grow profitably on a full cycle basis at natural gas prices above $2.20/mcf AECO

* debt adjusted

A History of Full Cycle Profitability

Aug 2018

* 0.00 00 1.00 00 2.00 00 3.00 00 4.00 00 5.00 00 6.00 00

• 5

50 1 100 1 150 2 200 2 250 3 300 3 350 4 400 Q1 Q1 201 012 Q2 Q2 201 012 Q3 Q3 201 012 Q4 Q4 201 012 Q1 Q1 201 013 Q2 Q2 201 013 Q3 Q3 201 013 Q4 Q4 201 013 Q1 Q1 201 014 Q2 Q2 201 014 Q3 Q3 201 014 Q4 Q4 201 014 Q1 Q1 201 015 Q2 Q2 201 015 Q3 Q3 201 015 Q4 Q4 201 015 Q1 Q1 201 016 Q2 Q2 201 016 Q3 Q3 201 016 Q4 Q4 201 016 Q1 Q1 201 017 Q2 Q2 201 017 Q3 Q3 201 017 Q4 Q4 201 017 Q1 Q1 201 018 Q2 Q2 201 018

AECO ($/m $/mcf) Earnings s befo fore e tax x ($ mi millions) s)

Earning ngs s be before re t taxes es ( (000 00,000 00s) AECO CO ( (CAD$/ $/mcf cf)

• Tourmaline focusses on generating earnings and full cycle profitability/returns.
• Tourmaline has increased cash flow by 416% per share 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 can generate attractive full cycle returns, as evidenced by the corresponding strong

earnings, at AECO gas prices above $2.20/mcf Cdn.

*

Q4 2014 earnings enhanced by the sale of 25% of the Peace River High Complex.

4

Largest Canadian Gas Producers

5

Mar 2018

• 200

400 600 800 1,000 1,200 1,400 1,600 1,800 Production (Mmcf/d) 2016A Natural Gas (Mmcf/d) 2017E Natural Gas (Mmcf/d) 2018E Natural Gas (Mmcf/d)

2016 WCSB Gas production was based on publicly available data 2017E production based on Peters and Co as at June 15, 2017 except for Tourmaline which is based on official guidance 2018E production for Tourmaline is based on Tourmaline’s 2018 forecast.

Tourmaline is currently producing between 1.3 and 1.35 bcf/day

A Significant Liquids Producer

May 2018

Increased volumes accessing Saturn deep cut and acceleration of new liquid rich targets (Cardium, Viking, Falher D). Acceleration of Montney Turbidite development with incremental condensate production through the new Doe 2-11 plant (2H Mar, 2017 start-up). Four active rigs on the Peace River High yielding record oil volumes for the overall complex.

Tourmaline has doubled liquids production over the past 15 months with strong liquids growth across all three operated

• complexes. Condensate production will grow from current levels of 12,000 bpd to 22,500-25,000 bpd by Q4 2019.

Tourmaline grew total 2P liquid reserves by 73% in 2017 to 431.6 mmboe, underpinning the strong liquids production growth.

Deep Basin NEBC Peace River High

• 10,000

20,000 30,000 40,000 50,000 60,000 70,000 80,000 Q3 2016 Q4 2016 Q1 2017 Q2 2017 2018 (E) 2019 Ave (E) Q4 2019 (E) 20,138 28,028 34,215 36,127 50,000 64,500 72,500

Oil and NGLs (bbl/d)

Liquids Production Growth

6

Balanced Revenue and Cash Flow Streams

Through Product, Marketing and Transportation Diversification

Aug 2018

7

 Tourmaline consistently outperforms the quarterly AECO index price (every year for seven years)  Tourmaline’s transportation diversification strategy allows for direct participation in natural gas price rallies at multiple hubs (Dawn, Chicago, Ventura, San Francisco, etc)  Oil, condensate and NGLs now generate over 1/3 of the Company’s revenue. These volumes are expected to grow by a further 50% over the next 18 months.

AECO & Station 2 14% Fixed Price 18%

NYMEX Basis 7%

NYMEX-Based Delivery 20% NGL 12% Oil 29%

201 018 8 BUDGE GETED TED REVENUE VENUE

Current 5 Year Plan(1)

Prod’n BOEPD After-tax Cash Flow $MM(2)(3) After-tax CFPS - Diluted E&P Capital Program(4) (6) $MM Free Cash Flow(5) $MM Dividend $MM Ending (Net Debt)(3) $MM 2018E 270,000 $1,343 $4.94 $1,082 $232 ($101) ($1,576) 2019E 291,000 $1,621 $5.96 $1,354 $235 ($109) ($1,448) 2020E 314,000 $1,733 $6.37 $1,155 $544 ($109) ($1,009) 2021E 333,000 $1,794 $6.59 $1,278 $479 ($109) ($639) 2022E 355,000 $1,888 $6.94 $1,322 $526 ($109) ($221)

8

Aug 2018

(1) 5 year plan derived by utilizing, among other assumptions, historical Tourmaline production performance and current cost assumptions inflated at 2.5% annually after 2018. 2019 and beyond provided for illustration only. Budgets and forecast beyond 2018 have not been finalized and are subject to a variety of factors including prior year’s results. (2) Price assumptions: Gas price - $3.00 2018 NYMEX US, $3.10 2019-2022 NYMEX US, $1.85 2018 AECO, $2.25 2019-2022 AECO (approximately 85% of Tourmaline's Q3 – Q4 2018 natural gas production is not exposed to AECO spot pricing). Oil price - $65.00/bbl 2018 WTI US, $60.00/bbl 2019 WTI US, $55.00/bbl 2020-2022 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. (6) 2018 E&P Capital Program is presented net of non-core dispositions.

• 50,000

100,000 150,000 200,000 250,000 300,000 350,000 400,000 2016 2017 2018 2019 2020 2021 2022 Boe/d Spirit River NEBC Deep Basin

May 2018

Alberta NE BC Fir Wild River

Cardium Viking Mannville/Notikewin Falher Cadomin Dunvegan Nikinassin Bluesky Gething Wilrich Gething

T43 T45 T47 T49 T51 T53 T55 T57 T59 T61 T63 T65 R10 R12 R14 R16 R18 R20 R22 R24 R26 R1W6 R3 R5 R7 R9

 Current Production 180,000-185,000 boepd  Current Reserves 984.4 mmboe (Jan 1, 2018)  Tourmaline Land Base 1.77 million acres  Drilling Inventory 2,322 locations (vertical)

(~1.5wells per section only)

6,167 hz locations

• T. 51

Tourmaline Gas Plant Tourmaline Lands Possible Facility Locations

Alberta Deep Basin

Hinton Ansell Marsh Harley Minehead Smoky Cecilia Musreau /Kakwa Lovett Brazeau Edson Sundance

TCPL Main Line

Leland

Tourmaline has reached production levels of 180,000 boepd from the Deep Basin through the drilling of only 490 hz wells to date. The Company has a future hz drilling inventory of over 6,167 locations.

T59

Oldman

2015 Significant New Discoveries 9

Tourmaline Deep Basin EP Performance

Jul 2018

Top Alberta Viking Wells

(March to May)

Top Alberta Cardium Wells

(March to May)

Tourmaline consistently drills a significant proportion of the best performing new wells in the Alberta Deep Basin. The Company attributes this to a combination of a dominant position in the subsurface sweet spots for multiple Cretaceous Formations, utilization of 3D seismic to select the majority of the horizontal locations, and continuously improving completion technology. Deep Basin liquid rich gas horizons, such as the Cardium and Viking, are yielding total condensate/ngl production that out-performs the

• il production from the conventional oil plays.

Source: NBF 10

Aug 2018

Alberta Deep Basin

Liquids Rich Cardium Fairway

T43 T45 T47 T49 T53 T55 T57 T59 R14 R16 R18 R20 R22 R24 R26 R1W6 R3 T57 T55 T59

Smoky Cabin Creek Stolberg Anderson

Tourmaline Gas Plant Tourmaline Lands Tourmaline Cardium Locations Tourmaline Pipelines Liquids Rich Cardium Fairway Cardium Faults

10-25-50-23W5 PAD (1 Vert, + 1 Hztl) IP 90 – 14.2 mmcfpd, 293 bbls/day cond. CR - 23.5 mmcfpd, 660 bbls/d CUM – 5.6 bcf, 110 mstb EUR – 21.0 bcf, 365 mbbls

Tourmaline Cardium Wells 2017-2018 Tourmaline Cardium Wells

The combination of extensive 3D seismic coverage and the lowest cost drilling/completion capability make the liquids rich Cardium play a significant new incremental opportunity in the overall Tourmaline Deep Basin portfolio.

11 Only the initial Cardium delineation locations are depicted, the potential location inventory is significantly larger. Note that each depicted surface location represents two hz wells (hanging wall/footwall)

12-36-50-23W5 Pad ( 1 Hztl) IP 90 - 15 mmcfpd CR - 5.7 mmcfpd CUM – 4.86 bcf, 135 mbbls EUR - 12.0 bcf, 320 mbbls

6-7 Proposed 2018 – 2019 Cardium Wells

6-1-51-23W5 PAD (2 Hztls) 5 day Test Average Rates 2-11

• 22.9 mmcfpd, 485 bbls/d cond.

13-36 - 24.3 mmcfpd, 510 bbls/d cond.

NEBC Montney Gas/Condensate Complex

TCPL Mainline

Westcoast McMahon Gas Plant

May 2018

12

* See Schedule A

Current Prod. 350-360 mmcf/d 7,500-8,500 bpd condensate Current Reserves 1,079.4 mmboe (Jan 1, 2018) Montney Drilling In excess of 3,600 horizontal Inventory* locations. Liquid rich Lower Turbidite horizon will add incremental locations. Tourmaline is the 4th largest Montney producer in NEBC with production in excess of 75,000 boepd.

TOU Land TOU Pipelines Major Pipelines

TCPL North Morntney 2019 Spectra Ft. Nelson Mainline

3-18 Sunrise Gas Plant 75 MMCF/D A-21-I Gundy

• Comp. Station

10 MMCF/D 2-11 Doe Gas Plant Start-up Mar 30, 2017 60 MMCF/D 13-25 Doe Gas Plant 100 MMCF/D 1-32 Doe

• Comp. Station

TOU 12 MMCF/D B-67-H Sundown Gas Plant 50 MMCF/D Mid-2018 expansion to 150 mmcfpd C-60-A Gas Plant 200 MMCF/D Q4 2019 Black Swan

• Comp. Station, dehy

25 mmcf/d TOU Gas Plants TOU Compressor Station TOU Wells

2018/2019 NEBC Development Plan 2018 Drilling  57 wells (D,C,T) 2018 Facilities  Doe 2-11 sweetening facility will add 3,500 bpd condensate production in Q4 2018  Production acceleration at Gundy in Q4 2019 Facilities  200 mmcfpd deep cut plant at Gundy in Q4 2019  17,500 bpd condensate and ngls.

Gundy Ck Montney Development

Aug 2018

AltaGas North Gathering Line Pembina Gundy Line 2017 Alliance TCPL North Montney Line 2019

A-21-I Gundy

• Comp. Station

10 MMCF/D C-60-A Gas Plant 200 MMCF/D 2H 2019

A-078-A PAD

9 Wells Rig Released June 2017 Average Rate to Date (mmcf/d) Number

• f Days

Average Free Condy Yield (bbl/mmcf) Average Total Liquid Yield (bbl/mmcf) Upper Montney Lobe 6.0 260 35.4 50.1 Middle Montney Lobe 4.5 224 35.1 49.8 Lower Montney Lobe 3.8 199 32.6 47.2

Gundy Current Production: 13,000-15,000 BOEPD No of wells drilled by TOU: 28 No of potential locations: 1600 (100% TOU) Free Liquid Content: 30-50 bbls/mmcf

Black Swan

• Comp. Station, dehy

25 MMCF/D TWP 88 94-B-9 94-B-16 94-A-13

Spectra Fort Nelson Mainline 2.0 bcf/d (Sales)

Tourmaline Land Tourmaline Montney Well Tourmaline Future Padsite Tourmaline 2017 Drilled Wells Tourmaline 18/19 Schedule Wells Tourmaline Pipelines Tourmaline Proposed Gas Plant

Spectra Fort Nelson Mainline

C-023-I PAD

7 Wells Rig Released August 2017 Average Rate to Date (mmcf/d) Number

• f Days

Average Free Condy Yield (bbl/mmcf) Average Total Liquid Yield (bbl/mmcf) Upper Montney Lobe 8.0 220 19.6 31.7 Upper Middle Montney Lobe 3.6 216 25.9 39.4 Middle Montney Lobe 3.3 233 26.9 41.0 Lower Montney Lobe 3.0 227 38.1 52.1

13

A-32-I Pad 6 Wells Spud July 2018 B-93-I Pad 11 Wells Frac August 2018 South Gundy Townsend Tie-In 40-50 MMCF/D

Drilling Execution Efficiency

Current Plan 2013 - 2014 Days 10 14 14.6 Cost ($MM) 1.3-1.7 2.1 3.5

Pacesetter 6.4 Days 1.31MM

Construction of Phase 1 Deep Cut Gas Plant has commenced in the field, a 50,000 boepd operated production increment to be realized by Tourmaline in approximately 12 months

Gundy Deep Cut Plant Construction

Aug 2018

Cryogenic Skid Construction Gundy Sales Line Right of Way

• Phase 1 50,000 boepd deep cut facility is on schedule for a Q3

2019 start-up.

• Phase 1 construction designed to facilitate the potential Phase

2 expansion (incremental 50,000 boepd, not in the current 5 year development plan).

• Phase 1 installed cost of $175-200M, Phase 2 installed cost

estimated at $150M for a second 200 mm/d deep cut.

14

Mar 2018

• T. 79
• R. 9
• R. 7
• R. 5
• T. 77
• T. 83
• T. 81
• T. 75
• R. 11

Tourmaline 2017 Upper Charlie Lake HZ Tourmaline HZ Wells Tourmaline Gas Plant Tourmaline HZ Well Locations

Legend

Tourmaline Lands

* See Schedule A

16-14 Lwr Ch Lk New Pool Test

90 day production rates 841 bopd, 1.9 mmcf/d, 1,158 boepd Cum oil 80,330 bbls in first 103 days

15

3-10 Spirit River Gas Plant 12-6 Mulligan Oil Battery 5-14 Mulligan Oil Battery 15-13 Mulligan Oil Battery 6-3 Spirit River Oil Battery

Tourmaline Battery Site

Upper Charlie Lake Type Log 6-11-77-8 W6 Lower Charlie Lake

Tourmaline Lower Charlie Lake HZ Tourmaline Montney HZ Lower Charlie Lake Fairway Upper Charlie Lake Fairway

Progress 1-4 Lwr MNTN Q4 2016

IP90: 466 BOPD, 2.5 MMSCF/D, 891 BOEPD

Mulligan 8-15 Upper Trcl Pad Q3 2016

90 day production rates 1-21: 285 bopd, 0.3 mmcf/d, 335 boepd 4-13: 631 bopd, 1.0 mmcf/d, 798 boepd 5-13: 594 bopd, 0.5 mmcf/d, 678 boepd 8-21: 349 bopd, 0.5 mmcf/d, 429 boepd 12-13: 533 bopd, 0.6 mmcf/d, 642 boepd

6-10 Lwr Ch Lk Pad Q3 2016

90 day production rates 5-9: 156 bopd, 0.7 mmcf/d, 273 boepd 12-9: 149 bopd, 1.1 mmcf/d, 329 boepd 13-9: 246 bopd, 1.7 mmcf/d, 536 boepd 11-11: 285 bopd, 1.9 mmcf/d, 604 boepd

Mulligan 5-30 Upper Trcl Pad Q3 2017

5 day production rates 12-20: 257 bopd, 0.4 mmcf/d, 327 boepd 12-36: 550 bopd, 0.5 mmcf/d, 632 boepd 8-19: 228 bopd, 0.3 mmcf/d, 284 boepd

Spirit River 15-15 Upper Trcl Pad Q1 2017

10 day production rates 14-22: 876 bopd, 0.7 mmcf/d, 989 boepd 15-22: 507 bopd, 0.6 mmcf/d, 608 boepd 16-22: 873 bopd, 1.5 mmcf/d, 1129 boepd

Peace River High Charlie Lake Play

• 1,898 Horizontal Locations* along Regional Play Fairway
• Current Reserves of 148.0 mmboe (Jan 1, 2018 GLJ)
• Regional pool defined by 225 horizontal and 140 existing

vertical wells

• 300-400 mboe 2P reserves per horizontal
• $2.2-$2.4M Charlie Lk horizontal drill complete cost
• Upper Charlie Lake wells are profitable on a full cycle

basis at $25/bbl (U.S. WTI)

• 12 Lower Charlie Lake delineation wells in 2018
• 15 Lower Montney oil tests in 2018

Peace River High Complex Triassic Oil

Charlie Lake and Montney Plays

Valhalla pad (L. Montney)

Well 1: 905 bopd, 5.9 mmcf/d (26 d) Well 2: 532 bopd, 5.1 mmcf/d (7d)

2018/2019 Liquids Growth Projects

May 2018 Doe 2-11 Sweetening Facility

• Facility provides capacity for additional liquid rich

Montney turbidite condensate production (17 wells currently shut-in). 3,500 bpd (Q4 2018) NW Spirit River 13-28 Compression and Pipeline Project

• Acceleration of regional battery tie-in project, providing

additional oil production capacity.

• Q4 2018 start-up

2,500-3,500 bpd 5-10 mm/d gas (Q4 2018) Deep Basin Liquid Rich Target Acceleration

• Acceleration of Wroe Falher D, Brazeau Viking and

Anderson-Lambert Cardium liquid rich developments.

• 25 wells overall in both 2018 and 2019 Deep Basin

programs. 1,500-2,500 bpd (2018) 1,500-2,500 bpd (2019) Accelerated PRH Lower Montney and Lower Charlie Lake Development

(currently not in 5 yr plan)

• Additional rig/incremental 25-30 wells for 2H 2018/2019
• ver the 18 months.
• Facility capacity constraints may limit the maximum

realized upside. 2,000-3,000 bpd Gundy Deep Cut Plant

• Complete Gundy Deep Cut plant for a 2H 2019 start-up.
• Partial production acceleration at Gundy will add
• approx. 1,500 bpd in Q4 2018.

15,000-17,500 bpd total liquids 26,000-32,500 bpd The planned 2018/2019 liquids focused projects will grow total corporate liquids production to 70,000-75,000 bpd by Q4 2019 from a 2018 average of 50,000 bpd.

16

12,750 18,500 20,000 25,000 31,500(+) 5,000 10,000 15,000 20,000 25,000 30,000 35,000 1H 2018 2H 2018 1H 2019 2H 2019 2020 (preliminary est)

Condensate Production (bbls/day)

Current Base Deep Basin Kca Deep Basin Wroe Compressor Project Dawson 2-11 Facility South Gundy Townsend Tie-In Deep Basin Kca/KV/Kf Gundy Deep Cut Deep Basin Facility Mods Kca/Kv/Kcf Gundy Phase 2 Production totals reflect anticipated total condensate production by the end of the specified period.

(750 bpd) (3,500 bpd) (750 bpd) (750 bpd) (5,000 bpd) (1,500 bpd) (5,000 bpd) (1,500 bpd)

Tourmaline Condensate Production Outlook 2018-2020

Jun 2018

17

(not included in 5 year plan)

Peace Riv eace River er High igh Char Charlie lie Lk Lk Oil il Montney

• ntney

Gas as/Cond Cond

• R. 15W5
• R. 1W6
• R. 15W6

T45 T55 T65 T75 T85

Alber Alberta ta Deep Deep Bas Basin in

Chinook Ridge

Alberta NE BC

Tourmaline Mid-Stream Assets

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.

Sep 2017

Legend Tourmaline Lands Tourmaline Gas Plant Site Tourmaline Compressor Tourmaline Oil Battery Tourmaline Main Laterals Main Sales Pipelines

• Current Tourmaline gas processing capacity of

1.45-1.50 bcf/day. Two oil processing batteries with combined processing capacity of 48,000 bpd. Oil, condensate and ngl storage capability of 275,000 bbls. 12 MW gas fired electrical generating capacity. 4,425 km of Tourmaline Operated Pipelines

18

• 18 Working interest gas plants, 15 of which

are 100% owned and operated

• 15 compressor stations

Water Infrastructure

• 7 Major Frac Water source/

Recycling Facilities, 370,000 m3 capacity

Sundown Spirit River Sunrise- Dawson Mulligan/Earring Hinton Ansell Edson Marsh Harley Fir Minehead Horse Cecilia Musreau/ Kakwa Lovett Brazeau Kaybob Gundy

Third Party Revenue Growth 2017(E) $30-40M 2018(F) $40-50M 2019 (Target) $60-75M

A significant, growing business for Tourmaline.

This revenue is in addition to the estimated $300MM(+) per year of cash flow that is effectively preserved by owning the operated infrastructure and not processing gas through third party/midstream plants.

Historical Reserves Summary

Mar 2018

Reserves 2012 2013 2014 2015 2016 2017

(mmboe) (mmboe) (mmboe) (mmboe) (mmboe) (mmboe)

PDP 91.9 122.3 177.8 263.2 352.1 436.5 TP 249.2 316.5 472.3 644.1 859.2 1056.0 2P 438.1 590.1 855.8 1108.3 1747.2 2216.6 2012 2013 2014 2015 2016 2017

(/boe) (/boe) (/boe) (/boe) (/boe) (/boe)

2P FDA(i) $10.35 $11.84 $10.40 $5.89 $5.94 $3.76 With FDC

(i) See February 2018 press release for full FD&A disclosures (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.

500 1000 1500 2000 2500 PDP TP 2P

MMBOE

Reserves (GLJ)

2013 2014 2015 2016 2017

2.70 4.35 6.19 7.65 8.25 12.71 15.10

0.00 2.00 4.00 6.00 8.00 10.00 12.00 14.00 16.00 2011 2012 2013 2014 2015 2016 2017*

$ Billion (*Jan 2017 Pricing)

Reserves Value (GLJ, 2P)

• Total Proved Reserve life index a reasonable

10.7 years.

• 2P FDC realistic, at approximately 4.5 years of

future projected cash flow. Historically Tourmaline has systematically converted the 2P reserves to PDP reserves in the 4.0-4.5 year time frame.

• Material, positive technical revisions each of the

last five years, with 2017 the largest to date.

• Considerable reserve value/NAV increase
• pportunity with improving gas prices.

19

200 400 600 800 1000 MMboe

Independently Recognized Canadian 2P Reserves

May 2018 Tourmaline has booked only 14% of existing drilling inventory (2,074 of 14,471 locations – See Schedule A). Tourmaline has historically converted 2P reserves to PDP reserves in approximately 4 years. YE 2017 2P reserves are 2.2 billion boe.

2 4 6 8 10 12 TCF

Natural Gas (1) Conventional Oil & Liquids

18

(1) Based on Canadian Reserves from public information.

Gas Development Location Inventory and Economics

Mar 2018

AB Deep Basin Outer Foothills AB Deep Basin B.C. Montney Charlie Lake Vertical Vertical Horizontal Horizontal Horizontal Total Well Costs 2.55 3.70 3.85 3.05 2.10

(Drill, Case, Complete, $ Million)

Average Reserves/Well (bcfe) 2.4 5.8 5.4 5.8 2.2 Year 1 Production Rate 1.3 mmcfepd 2.8 mmcfepd 4.0 mmcfepd 4.6 mmcfepd 193 boepd Development Cost/boe $6.28 $3.86 $4.30 $3.14 $5.73 Operating Expenses/boe(1) $2.75 $2.45 $2.84 $2.24 $9.51 Net Present Value @ $1,311 $5,215 $5,190 $10,060 $3,261 10% (000’s) Internal Rate of Return(2) 24% 53% 75% 332% 87% Payback period (months) 45 23 16 7 13 Year 1 Gas Price(3) $2.28 $2.18 $2.28 $2.03 $2.36 Future Development Locations(4) 2,322 450 6,167 3,633 1,805

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, 2018 escalated price forecast, adjusted for transportation and heat content. (4) See Schedule A. 21

The TOU Engineering Execution Machine

Sep 2017

6.8 6.0 5.5 3.4 3.6 5.7 5.3 4.2 2.8 2.7 4.5 4.1 3.5 2.5 2.4

0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 2013 2014 2015 2016 2017 Capital Cost ($MM) Drill & Complete Costs

(Equipping not included)

South Deep Basin NEBC (South Complex) PRH

Tourmaline has the lowest completed per stage well costs in the overall Montney play in Western Canada and the Alberta Deep Basin.

• Since Feb 2009, Tourmaline has drilled 1035 wells across all three core operated complexes.

(Deep Basin 535 wells, NEBC 276 wells, PRH oil 224 wells)

• Through continuous engineering design improvements in all aspects of drilling and completions
• perations, 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 16/17 rig program.

22

Continuously Improving Well Performance and Recoverable Reserves

Mar 2018

23

• 500

1,000 1,500 2,000 1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73 76 79 82 85 88 91 94 97 100 103 106

Boe/d

• 500

1,000 1,500 1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73 76 79 82 85 88 91 94 97 100103106

Boe/d

Deep Basin NEBC Spirit River

EUR 895 mboe IP30 1,615 boe/d IP90 1,197 boe/d IP365 671 boe/d EUR 970 mboe IP30 1,359 boe/d IP90 1,165 boe/d IP365 762 boe/d EUR 367 mboe IP30 408 boe/d IP90 315 boe/d IP365 193 boe/d

41% % EUR Increase Since 2012 28% % EUR Increase Since 2012

• 100

200 300 400 500 1 4 7 10 13 16 19 22 25 28 31 34 37 40 43 46 49 52 55 58 61 64 67 70 73 76 79 82 85 88 91 94 97 100 103 106

Boe/d Months

Continuous Cost Reduction Strategy

$6.34 $5.58 $4.43 $4.35 $4.87 $4.37 $3.31 $3.19

$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 $6.50 $7.00

2010 2011 2012 2013 2014 2015 2016 2017

$/boe

Operating Costs

$1.29 $1.02 $0.79 $0.74 $0.60 $0.45 $0.44 $0.46

$0.00 $0.50 $1.00 $1.50

2010 2011 2012 2013 2014 2015 2016 2017

$/ $/boe

General and Administrative Costs  Tourmaline has achieved record low operating costs in 2017.  Tourmaline has the lowest effective interest rate/borrowing costs in the North American energy sector.  The staff required to effectively operate a 250,000 boepd company growing to 300,000 boepd has already been assembled. Mar 2018

24

2018 Guidance

Aug 2018

25

2018(1) Production – Boe/d 267,500 - 275,000 Cash Flow(i) - $MM $1,343 CFPS - Diluted(i) $4.94 E&P Capital Program(ii) - $MM (net of non-core dispositions) $1,082 Free Cash Flow(iii) - $MM $232 Exit Net Debt(i) - $MM $1,576 Debt to CF 1.2x

(1) Price Assumptions: Gas price - $3.00/mmbtu NYMEX US, $1.85/mcf AECO, approximately 85% of Tourmaline's Q3 - Q4 2018 natural gas production is not exposed to AECO spot pricing; 2018 Oil price - $65.00/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) 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.

2018 Natural Gas Transportation and Marketing Overview

16%

AECO TCPL Mainline

11%

Kingsgate California ~200 MMcf/d US Midwest/Other ~85 Mmcf/d Station 2

26 2018 Exit: 440 mmcf/d of gas will be to US/Other Markets 2019 Exit: 540 mmcf/d of gas will be to US/Other Markets 37% 35% 11% 16%

2018 Natural Gas Portfolio Diversification

US/Other Markets Hedges Stn 2 Aeco

(2)

(1) US/Other Markets access 23% physical markets + 14% of Nymex Basis Differentials (2) ~38% of Station 2 exposed at 7A/Hunt

(1)

Dawn ~115 Mmcf/d

Aug 2018

2017 Highlights/2018 Outlook

Mar 2018

• Tourmaline now a Senior with production exceeding 270,000 boepd.
• Tourmaline is currently the second largest producer of Canadian natural gas and is a top ten

Canadian liquids producer (excluding oil sands/thermal).

• Continued strong earnings in 2017 as the Company focuses on full cycle profitability and returns.
• Tourmaline grew cash flow by 65% to $1.2 billion in 2017, from $732 million in 2016.
• The Company has achieved a step change reduction in the commodity prices required for full

cycle profitability across all three operated areas.

• Tourmaline has a diversified revenue base resulting from rapidly growing liquids volumes and a

strong gas transportation and marketing portfolio that provides multiple pricing points at hubs across North America.

• Continued strong reserve growth in 2017 with Company reserves of 2.2 billion boe (Jan 1, 2018)

(10.7 tcf of natural gas and 431.6 mmboe of liquids - oil, condensate, ngl).

• Three expansive resource plays, completely derisked, with Tourmaline infrastructure in place and

86% of drilling inventory currently unbooked in the reserve report.

• Achieved 50% well cost reductions over the last 5 years in all 3 core areas.
• The list of industry leading Tourmaline operated ‘top’ wells continues in all 3 core areas.

27

APPENDIX

Natural Gas Flows From Western Canada

29

Completed Well Costs and EUR By

• N. American Play Type

Aug 2017

30

$9.6 MM $12.3 MM $8.7 MM $7.9 MM $4.7 MM $2.9 MM $4.5 MM $4.4 MM 20.5 Bcfe 17.9 Bcfe 12.5 Bcfe 7.0 Bcfe 6.7 Bcfe 6.2 Bcfe 4.5 Bcfe 5.6 Bcfe

5 10 15 20 25

Marcellus* Utica* Haynesville* AB Montney (Industry Average) BC Montney (Industry Average) TOU BC Montney Deep Basin (Industry Average) TOU Deep Basin

Well Costs (CAD) Vs. EUR by Play Type

Completed Well Cost $CDN EUR (Bcfe)

*USD Converted into CAD ($1USD = $1.30CAD) Based from publically available information and Peter's and Co.

$0.47/mcf $0.69/mcf $0.70/mcf $1.13/mcf $0.70/mcf $1.00/mcf $0.79/mcf $0.47/mcf

Tourmaline vs Natural Gas Peers

Cash Costs Per BOE

July 2017

31 $2.80 $3.22 $1.85 $2.25 $1.77

$5.42 $0.38 $0.75 $1.54 $0.38 $1.40 $1.45 $- $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 Tourmaline (USD)* Canada Peer Average (USD)** US Peer Average*** Costs Per BOE

Tourmaline Vs. Natural Gas Weighted Peers Cash Costs in USD* per BOE (Q1/17)

Operating Transportation G&A Interest

$5.82 $10.26

*CAD Converted into USD ($1USD = $1.25 CAD) ** Peer average consists of 6 CAD Peers (Weighted Gas Production > 50%) ***Peer average consists of 7 US Peers (Weighted Gas Production > 50%)

$7.15

5 10 15 20 25 30 35

2013 2014 2015 2016 2017

Days Average Drill Days

57%

Decrease Since 2013

$0.0 $1.0 $2.0 $3.0 $4.0 $5.0

2013 2014 2015 2016 2017

MM Average Drill Cost

South Deep Basin Peace River High

5 10 15 20

2013 2014 2015 2016 2017

Days Average Drill Days $0.0 $0.5 $1.0 $1.5 $2.0 $2.5 $3.0

2013 2014 2015 2016 2017

MM Average Drill Cost

NEBC

$- $1 $2 $3 $4

2013 2014 2015 2016 2017

MM Average Drill Cost 5 10 15 20

2013 2014 2015 2016 2017

Days Average Drill Days

Historical Drilling Performance and Cost Improvements

49%

Decrease Since 2013

41%

Decrease Since 2013

36%

Decrease Since 2013

55%

Decrease Since 2013

57%

Decrease Since 2013

32

Mar 2017

$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 2012 2013 2014 2015 2016

$ 000

Deep Basin - Completions

Historical Completions Performance Improvements

47%

Decrease Since 2012

$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 2012 2013 2014 2015 2016

$ 000

NEBC South Montney - Completions

$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 2012 2013 2014 2015 2016

$ 000

Peace River High - Completions

51%

Decrease Since 2012

72%

Decrease Since 2012 33

Tourmaline Montney Efficiency + Execution

Montney Peers Q2/17 Production >40,000 boe/d

34

Sep 2017

(1) Publicly Available Information (Peers include ARC Resources, Birchcliff, Encana, Painted Pony and Seven Generations) (2) Encana Operating Costs assume $CAD/USD = $0.80 + incremental $0.80/mcf for processing (EnCana groups processing into “Transportation and Processing”) (3) Peters and Co (October 3, 2017) except Painted Pony (National Bank)

• 0.5

1.0 1.5 2.0 2.5 3.0 3.5 Tourmaline Peer 1 Peer 5 Peer 4 Peer 2 Peer 3

2018 D/CF(3)

$0 $2 $4 $6 $8 $10 $12 $14

CAD$MM

Drilling and Completions Costs (1)

• 20,000

40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 Peer 5 Peer 4 Peer 1 Tourmaline (Sep/17) Peer 3 Peer 2

Boe/d

Montney Production (Q2/17) (1)

$- $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 Tourmaline Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

$/Boe

Montney Operating Costs Q2/2017(1) (2)

EP Growth Plan

(Original Business Plan)

• 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.

Sept 2008

35

This is essentially the same business plan that was executed for Duvernay Oil Corp. (2001-2008)

Banshee Alberta Gas Plant

36

• Simple, easy to construct dew point plants tied to

the main TCPL sales system

• Total cost (2 phases) of $80M, capacity of 130

mmcfpd with enhanced liquids recovery capability

Top Alberta Gas Wells

(March to May)

Jul 2018

Source: NBF 200 400 600 800 1000

1200 Tourmaline 04-05-053-23W5 Tourmaline 09-07-062-05W6 Tourmaline 09-05-055-22W5 Tourmaline 14-08-059-01W6 Jupiter 16-33-059-01W6 Tourmaline 13-12-059-02W6 Tourmaline 13-08-053-23W5 Vermilion 04-20-042-10W5 Tourmaline 12-13-057-02W6 Bonavista 06-26-050-17W5 Jupiter 09-33-059-01W6 Tourmaline 05-13-057-02W6 Tourmaline 13-07-055-23W5 Bonavista 03-26-051-20W5 Cdn Nat 01-11-055-25W5 mmcfe (cumulative)

37

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 ranks as a ‘top decile’ performer under the new Ab Government carbon emission

framework and despite the Company’s size and extensive facility capacity has zero ‘large emitter’ sites.

• Tourmaline is Canada’s second largest natural gas producer, by far the ‘cleanest’ of the fossil fuel

group, and has constructed a network of new, state of the art facilities to process and transport this gas.

• 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 systematically reduced CO2 and CH4 emissions by conducting all well testing in-

line and directly into Tourmaline facilities.

• Tourmaline is steadily expanding the use of CNG for drilling operations, reducing diesel usage.
• Tourmaline is an industry leader in non-potable frac water sourcing with six frac water

source/recycling facilities (>300,000 m3 capacity) avoiding the use of fresh water in frac

• perations. Tourmaline is one of the first operators in B.C to utilize produced water in frac
• perations and will be the first company in Alberta to employ this practice.
• Since inception Tourmaline has been an active participant in CAPP’s initiatives on environment,

health and safety and social responsibility under their Responsible Canadian Energy program.

38

GHG Emissions – Peer Comparison

Jul 2018

Tourmaline has the lowest GHG emissions intensity (CO2/boe) among Canadian Senior E&P peers

Notes: 1. Based on CDP (Carbon Disclosure Project) data and includes Scope 1 and Scope 2 emissions unless otherwise stated under "Notes“. 2. Represents 2016 data. 2017 data not yet available. 3. Encana excluded since Encana does not disclose Scope 2 emissions, so figures are not comparable. 4. Suncor intensity data has been derived from company website disclosure (Sustainability Reports). 5. Imperial CDP intensity disclosure includes only Scope 1 emissions so it is likely understated in graph relative to peers.

0.000 0.010 0.020 0.030 0.040 0.050 0.060 0.070 0.080

• 5,000,000

10,000,000 15,000,000 20,000,000 25,000,000 CNRL 807,045 Suncor 725,100 Husky 334,000 Imperial 378,000 Cenovus 295,414 Crescent Point 173,329 MEG 77,245 Tourmaline 233,278 CO2 Intensity (tonnes CO2(e)/boe) Gross CO2 Emissions (tonnes CO2(e))

Canadian E&P GHG Emissions 2016

Q1 2017 Production

39

BC Water Management

• 100% of all water flowed back from completion operations is recycled
• 90% of all water sourced for stimulation operations is recycled
• 187,000m3 of produced water storage capacity

– 3 produced water ponds South Montney and 1 North Montney

• 46 km of permanent pipeline infrastructure to transfer water to and from pads to produced water

pits

40

Natural Gas Substitution in Operations

• Raw Natural Gas cost (Feb 2017) ~$0.10/DLE (Diesel Equivalent Liter) vs $0.69/L rack price

for marked diesel

• 12 Drilling Rigs and all BC completion operations use a combination of NG/Diesel
• Drilling Rigs achieving ~40-50% displacement of diesel
• 6.8M liters of diesel displaced since May 2016
• $1.4M savings

Other benefits:

• 30% lower CO2 emissions – 2,800 tonnes avoided
• 75% lower NOx emissions
• 90% lower particulate emissions
• 99% lower SOx emissions

41

Tourmaline Technology Curve/Future Concepts, Requirements & Opportunities

• Utilizing gas fired turbines to reduce

costs for drilling, completions, facilities

• Develop predictive reservoir/reserve tools

for horizontal clastic gas wells

• Refine drilling techniques/cost savings for

frontal foothills Wilrich/Notikewin hz drlg

• Understanding controls on Wilrich

deliverability/develop predictive tools

• Paleozoic/New Deep Play concepts
• Improved horizontal stimulation techniques, new

approaches to maximize deliverability and recovery

• New shale/source rock plays
• Improved Wilrich seismic imaging in strat

settings and Outer Foothills settings

• Cost saving via novel frac water sourcing/recycling
• Alternative hz frac programs/processes

– Concurrent pairs, delayed flow-backs etc.

• Pasquia Hills oil shale recovery

mechanisms

• Ball drop/sliding sleeve completion technique

in vertical wells

• Novel drilling technology to reduce time/cost

in drilling builds

• New mud systems to reduce drilling times
• AI applications in geophysical interpretation, reservoir

prediction and predictive drilling problem identification.

42

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 14,471 (gross) locations disclosed in this presentation, 1,056 are proved undeveloped locations, 21 are proved non-producing locations, 997 are probable undeveloped locations, nil are probable non-producing and 12,397 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, 2017 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.

43

Schedule A continued

44

Deep Basin Vertical well count : Approximately 2,767 gross prospective sections at approximately 1.5 wells per section minus 10% for areas that are inaccessible or limited by spacing requirements minus approximately 963 existing wells. Includes 450 locations in the Outer Foothills area. Total Vertical Locations ~ 2,772 Deep Basin Horizontal well count : Approximately 2,767 gross prospective sections in the Deep Basin at approximately 2.5 wells per section in multiple horizons i.e. the Wilrich, Falher, Notikewin, Cardium, Dunvegan, Viking, Bluesky, Gething, Cadomin, or Nikanassin. Less existing horizontals, less 20% of existing vertical producers. In some instances there will be less than 2.5 wells per section at full development and in other cases there will be more than 3.5 wells per section due to the fact that there are multiple horizons. Total Horizontal Locations ~ 6,167 NE BC Well count : 300 gross sections in NE BC at 4-5 wells per sections in multiple lobes (2-5 depending upon location) yielding 3,633 locations. TOTAL NE BC = 3,633 locations Spirit River well count: 551 gross sections within the Charlie Lake Fairway x 3-4 wells per section = 2,171 wells Minus approximately 273 existing wells Total Spirit River ~ 1,898 wells Total gross locations ~ 14,471

Schedule B

45

Prospective locations are unbooked locations that are not included in inventory. Unbooked locations are internal estimates based

• n 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

• ther factors. While certain 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.

Forward Looking Information

Certain information contained in this presentation constitutes forward-looking information within the meaning of applicable securities laws. This information relates to future events or the Company's future performance. All information other than information of historical fact is forward-looking information. The use of any of the words "anticipate", "plan", "contemplate", "continue", "estimate", "expect", "intend", "propose", "might", "may", "will", "shall", "project", "should", "could", "would", "believe", "predict", "forecast", "pursue", "potential" and "capable" and similar expressions are intended to identify forward-looking information. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking information. No assurance can be given that these expectations will prove to be correct and such forward-looking information should not be unduly relied upon. This information speaks only as of the date of this presentation or, if applicable, as of the date specified in those documents specifically referenced herein. In addition, this presentation may contain forward-looking information attributed to third-party sources. Without limitation of the foregoing, this presentation contains forward-looking information pertaining to the following: the reserve potential

• f the Company's assets; the anticipated production from the Company's assets and anticipated future cash flows from such assets; the

Company's growth strategy and opportunities; the Company's capital exploration and development programs and future capital requirements; the estimated quantity and value of the Company's proved and probable reserves; expectations regarding the ability to raise capital and to continually add to reserves; the Company's estimates of future interest and foreign exchange rates; the Company's environmental considerations; the Company's assumptions regarding commodity prices; the Company's expectations regarding reduction in its operating costs; the timing of commencement of certain of the Company's operations and the level of production anticipated by the Company; the potential for production disruption and constraints; supply and demand fundamentals for crude oil and natural gas; the Company's access to adequate pipeline and other gathering, transportation and processing capacity; the Company's access to third-party infrastructure; the Company's drilling and recompletion plans; the Company's expected capital expenditures; expected debt levels and credit facilities; industry conditions pertaining to the oil and gas industry; the Company's plans for, and results of, exploration and development activities; the planned construction of the Company's gathering, transportation and processing facilities and related infrastructure; the timing for receipt of regulatory approvals; the Company's treatment under governmental regulatory regimes and tax laws and potential changes in such regimes and laws; the Company's future general and administrative expenses; and the Company's expectations regarding having adequate human resource staffing. 46

With respect to forward-looking information contained in this presentation, assumptions have been made regarding, among other things: future crude oil and natural gas prices; future interests rates and currency exchange rates; the Company's ability to obtain qualified staff and equipment in a timely and cost–efficient manner; the regulatory framework governing royalties, taxes and environmental matters; the Company's ability to market production of oil and natural gas successfully; the Company's future production levels; the applicability of technologies for recovery and production of the Company's reserves; the recoverability of the Company's reserves; future capital expenditures to be made by the Company; future cash flows from production meeting the expectations stated in this presentation; future sources of funding for the Company's capital program; the Company's future debt levels; geological and engineering estimates in respect of the Company's reserves; the geography of the areas in which the Company is conducting exploration and development activities; the impact

• f competition on the Company; and the Company's ability to obtain financing on acceptable terms.

Actual results could differ materially from those anticipated in this forward-looking information as a result of a number of factors including the risk factors set forth in the Company's reports and documents on file with Canadian securities regulatory authorities at www.sedar.com

• r the Company's website at www.tourmalineoil.com, which risk factors should not be construed as exhaustive. See specifically "Forward-

Looking Statements" and "Risk Factors" in the Company's most recently filed Annual Information Form and "Forward-Looking Statements" in the Company's most recently filed Management's Discussion and Analysis. Included in this presentation are estimates of the Company's 2018-2022 cash flow and cash flow per share which are based on various assumptions as to production levels, commodity prices and other assumptions and in the case of the years other than 2018 are provided for illustration only and are based on budgets and forecasts that have not been finalized and are subject to a variety of contingencies including prior years' results. To the extent such estimates constitute a financial outlook, they were approved by management of the Company in August 2018 and are included to provide readers with an understanding of the Company's anticipated cash flow based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes. In addition, information relating to "reserves" is deemed to be forward-looking information, as it involves the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated, and that the reserves described can be profitably produced in the future. See also "Statement of Reserves Data and Other Oil and Gas Information" and "Certain Reserves Data Information" in the Company's Annual Information Form. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed herein or

• therwise and the Company undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of

new information, future events or otherwise, unless specifically required to do so pursuant to applicable law.

Forward Looking Information

47

Forward Looking Statement Advisories

Oil and Gas Advisories Certain crude oil and natural gas liquids ("NGLs") volumes have been converted to millions of cubic feet equivalent ("mmcfe") or thousands of cubic feet equivalent ("mcfe") on the basis of one barrel ("bbl" of crude oil or NGLs to six thousand cubic feet ("mcf") of natural gas. Also, certain natural gas volumes have been converted to barrels of oil equivalent ("boe"), thousands of boe ("mboe") or millions of boe ("mmboe") using the same equivalency measure. Such equivalency measures may be misleading, particularly if used in

• isolation. A conversion ratio of one bbl to six mcf is based on an energy equivalency conversion method primarily applicable at the burner

tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. This presentation contains disclosure regarding finding and development costs. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. The estimated net present values disclosed in this presentation do not represent fair market value. Unless otherwise expressly stated, the information in this presentation pertaining to future drilling locations or drilling inventories is based solely on internal estimates made by management and such locations have not been reflected in any independent reserve or resource evaluations and have not been recognized as reserves or resources as defined in NI 51-101. See Schedule A - Drilling Locations. Similarly, unless otherwise expressly stated, the information in this presentation pertaining to targeted reserve volumes from future drilling is intended to indicate that in making its internal drilling decisions, the Company seeks to target drilling locations that, based on previous drilling results and its own internal assessments, it believes will on average ultimately generate the indicated volumes. Non-GAAP Measures This presentation includes references to financial measures commonly used in the oil and gas industry such as "cash flow" and "net debt", which do not have standardized meaning prescribed by Generally Accepted Accounting Standards (“GAAP"). Accordingly, the Company’s use of these terms may not be comparable to similarly defined measures presented by other companies. Management uses the terms “cash flow”, and “net debt”, for its own performance measures and to provide shareholders and potential investors with a measurement of the Company’s efficiency and its ability to generate the cash necessary to fund a portion of its future growth expenditures or to repay debt. However, investors are cautioned that these measures should not be construed as an alternative to net income determined in accordance with IFRS as an indication of the Company's performance. For these purposes, "cash flow" is defined as cash provided by operations before changes in non-cash working capital and "net debt" is defined as long-term bank debt plus working capital (adjusted for the fair value of financial instruments and future taxes). Additional information on these terms are included in the Company's most recently filed Management's Discussion and Analysis (See “Non-GAAP Financial Measures" therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or Tourmaline's website (www.tourmalineoil.com). 48