Corporate Presentation

September 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

0

1

2

3

4

5

6

7

8

9

2009 2010 2011 2012 2013 2014 2015 2016 2017

Reserves p

er S

hare (B

OEs)

Reserves Growth Per Share*

0

50

100

150

200

250

300

350

2009 2010 2011 2012 2013 2014 2015 2016 2017

Productio

n p

er Thousand Shares

(B

OEs)

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 Flo

w 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

1.00

2.00

3.00

4.00

5.00

6.00

-

50

100

150

200

250

300

350

400

Q12012

Q22012

Q32012

Q42012

Q12013

Q22013

Q32013

Q42013

Q12014

Q22014

Q32014

Q42014

Q12015

Q22015

Q32015

Q42015

Q12016

Q22016

Q32016

Q42016

Q12017

Q22017

Q32017

Q42017

Q12018

Q22018

AEC

O (

$/m

cf)

Earn

ings

be

fore

tax

($ m

illio

ns)

Earnings before taxes (000,000s)

AECO (CAD$/mcf)

• 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 (

Mm

cf/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

NG

Ls (

bb

l/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%

2018 BUDGETED REVENUE

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

AlbertaNE

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

R10R12R14R16R18R20R22R24R26

R1W6R3

R5R7R9

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

oil 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

R14R16R18R20R22R24R26

R1W6R3

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.

Doe 2-11 Sweetening Facility

Aug 2018

The 2-11 facility will allow an additional

17 existing liquid rich Montney turbidite

wells to come on-stream in Oct 2018,

adding 3,000-3,500 bpd of incremental

condensate production.

13

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

of 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 8894-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

of 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

14

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.

15

Tourmaline Long Term NEBC Montney Growth

Aug 2018

Sunrise,Dawson,

Sundown,Gundy

Doe 2-11

S. Gundy Tie-in

Gundy

Phase One

Gundy

Phase Two

Sundown

Phase One

Development

50,000

75,000

100,000

125,000

150,000

175,000

200,000

Current Q4 2018 2H 2019 2020 2020-2022

(Gas Price Contingent)

Productio

n (

boepd)

(Assumes all

volumes directed

to TOU facility)

• Tourmaline can grow to a 200,000 boepd NEBC

Montney producer within the current 5 year plan

time frame.

• Gundy Phase Two and Sundown developments are

not in the current five year plan, both projects are

completely de-risked with 20 years of drilling

inventory and will produce into Tourmaline operated

infrastructure. Both could be on-stream by 2020.

16

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

17

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 201690 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 201690 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 20175 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 201710 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)

12,750

18,500

20,000

25,000

31,500(+)

0

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 P

roduction (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

2018-2020Jun 2018

18

(not included in 5 year plan)

Peace River High

Charlie Lk Oil

Montney

Gas/Cond

R. 15W5R. 1W6R. 15W6

T45

T55

T65

T75

T85

Alberta Deep

Basin

Chinook

Ridge

AlbertaNE

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

19

• 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

SundownSpirit River

Sunrise-

Dawson

Mulligan/Earring

Hinton

Ansell

EdsonMarsh

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. 0

500

1000

1500

2000

2500

PDP TP 2P

MM

BO

E

Reserves (GLJ)

2013 2014 2015 2016 2017

2.70

4.35

6.19

7.658.25

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*

$ B

illion (*Jan 201

7 P

ricing)

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

opportunity with improving gas prices.

20

0

200

400

600

800

1000

MM

bo

e

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.

0

2

4

6

8

10

12

TC

F

Natural Gas (1)

Conventional

Oil & Liquids

18

(1) Based on Canadian Reserves from public information.

Gas Development Location

Inventory and EconomicsMar 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.

22

The TOU Engineering Execution Machine

Sep 2017

6.8

6.0

5.5

3.43.6

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

Capit

al

Cost (

$M

M)

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

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 16/17 rig program.

23

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 TypeAug 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 Bcfe6.7 Bcfe

6.2 Bcfe

4.5 Bcfe

5.6 Bcfe

0

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 BOEJuly 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 P

er B

OE

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

Gundy Horizontal Well Performance

Aug 2018

32

0

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

0

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

0

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

33

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

34

Tourmaline Montney

Efficiency + Execution

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

35

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

CA

D$M

M

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

$/B

oe

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

36

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

Banshee Alberta Gas Plant

37

• 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

0

200

400

600

800

1000

1200

Tou

rmal

ine

04-0

5-0

53-

23

W5

Tou

rmal

ine

09-0

7-0

62-

05

W6

Tou

rmal

ine

09-0

5-0

55-

22

W5

Tou

rmal

ine

14-0

8-0

59-

01

W6

Jup

ite

r16

-33

-05

9-0

1W

6

Tou

rmal

ine

13-1

2-0

59-

02

W6

Tou

rmal

ine

13-0

8-0

53-

23

W5

Ve

rmili

on

04-2

0-0

42-

10

W5

Tou

rmal

ine

12-1

3-0

57-

02

W6

Bo

nav

ista

06-2

6-0

50-

17

W5

Jup

ite

r09

-33

-05

9-0

1W

6

Tou

rmal

ine

05-1

3-0

57-

02

W6

Tou

rmal

ine

13-0

7-0

55-

23

W5

Bo

nav

ista

03-2

6-0

51-

20

W5

Cd

n N

at01

-11

-05

5-2

5W

5

mm

cfe

(cu

mu

lati

ve)

38

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

operations. Tourmaline is one of the first operators in B.C to utilize produced water in frac

operations 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.

39

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

CO

2Intensity

(tonnes C

O2(e)/boe)

Gross C

O2

Em

issions

(tonnes C

O2(e))

Canadian E&P GHG Emissions 2016

Q1 2017 Production

40

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

41

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

42

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.

43

Schedule A

DRILLING LOCATIONS

Estimated Drilling InventoryThis 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 drilledper 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.

44

Schedule A continued

45

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

46

Prospective locations are unbooked locations that are not included in inventory. 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 andprospective). 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 nocertainty 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 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-lookinginformation 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 of 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'senvironmental 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'sexpectations regarding having adequate human resource staffing.

47

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 capitalexpenditures 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 of 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 or 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 otherwise 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

48

Forward Looking Statement Advisories

Oil and Gas AdvisoriesCertain 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 filedManagement'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).

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