Corporate Presentation May 2019 - Tourmaline Oil...R26 R24 R22 R20 R18 R16 R14 R3 R1W6 T57 T55 Smoky...

Corporate Presentation

May 2019

Current Status

Production Overview • 2019 average production forecast of 300,000 boepd

• 1H 2019 production 290,000-300,000 boepd, 2H 2019 production 310,000 – 320,000 boepd

• 2019 average liquid production of 66,000 bpd

Three Major Core Areas • Alberta Deep Basin: largest land position/largest producer

• NEBC Montney Gas/Condensate: Canada’s third largest Montney producer by 2H 2019

• Peace River Triassic Oil: Three large, regional, light oil and gas resource plays

• All three core areas completely de-risked via 1,400 wells drilled by Tourmaline since

February 2009

Reserves • 2P gas reserves of 11.7 TCF (Jan 1, 2019)

• 2P liquid reserves of 505.2 mmbbls (Jan 1, 2019)

Drilling Inventory • Approximately 6,865 horizontal locations in the Deep Basin; 3,565 hz Montney locations in

NEBC; 1,850 locations in Peace River High Charlie Lake core area (see Schedule A)

Financial Position • Net Debt $1.71 billion (March 31, 2019)

• Top quartile debt to cash flow ratio will be maintained

• EP Capital budgets generate free cash flow for 2019 and beyond

• Continued strong earnings reflect Tourmaline’s capability to generate growing full cycle

returns for shareholders

Shares OS • 272.1 million (March 31, 2019)

• Insiders have purchased over 22% of OS (fully diluted) (D&O ownership 8.0%)

May 2019

2

Historical EP Performance

0

2

4

6

8

10

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Reserves p

er S

hare (B

OEs)

Reserves Growth Per Share*

0

50

100

150

200

250

300

350

400

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

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 2018

2009-2018 Op Costs/BOE

Mar 2019

3

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Cash Flo

w per Share ($

)

Cash Flow Per Share

• 2010-2018 Production growth per share CAGR of 29%. • 2P Reserve Value of $15.9 billion after 10 years.

• Lowest capital costs and low cash costs allow Tourmaline to grow profitably on a full cycle basis at natural gas prices above CAD$1.80/mcf.

* debt adjusted

A History of Full Cycle Profitability

May 2019

*

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

Q32018

Q42018

Q12019

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 425% 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 full cycle returns at gas prices above CAD$1.80/mcf.

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

4

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

TOU ECA CNQ ARX VII CVE PEY POU BIR HSE BNP AAV NVA VET SRX IMO KEL BXE PNE CR CPG

Production (M

mcf/d)

2016A 2017A 2018E 2019E 2020E

Source: Peters and Co

Largest WCSB Gas Producers

5

Mar 2019

Tourmaline will be the largest

natural gas producer in Canada

(Based on 2019 Estimates)

A Significant Liquids Producer

Mar 2019

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).

2-3 active rigs on the Peace River

High yielding record oil volumes for

the overall complex.

Tourmaline has doubled liquids production over the past 1.5 years with strong liquids growth across all three operated

complexes. The 2019 liquid production growth rate of 35-40% is amongst the highest in the Canadian oil and gas sector.

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 2019 Ave (E) Q4 2019 (E)

20,138 28,028

34,215 36,127

47,540

66,000 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

May 2019

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 15 months.

AECO &

Station 2

16%

Fixed Price

9%

NYMEX

Basis

11%

NYMEX-Based Delivery

23%

NGL

10%

Oil and Condensate

31%

2019 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)

$MM

Free Cash

Flow(5)

$MM

Dividend

$MM

Ending

(Net Debt)(3)

$MM

2019E 300,000 $1,521 $5.58 $1,200 $290 ($125) ($1,554)

2020E 322,000 $1,665 $6.11 $1,155 $475 ($131) ($1,206)

2021E 337,000 $1,764 $6.47 $1,278 $449 ($131) ($887)

2022E 361,000 $1,834 $6.73 $1,322 $473 ($131) ($544)

2023E 377,000 $1,974 $7.24 $1,407 $526 ($131) ($149)

8

May 2019

(1) 5 year plan derived by utilizing, among other assumptions, historical Tourmaline production performance and current cost assumptions inflated at 2.5% annually after 2019. 2020 and beyond provided for illustration only. Budgets and

forecast beyond 2019 have not been finalized and are subject to a variety of factors including prior year’s results.

(2) Price assumptions: Gas price - $3.00 2019 NYMEX US, $3.10 2020-2023 NYMEX US, $1.80 2019 AECO, $2.00 2020 AECO, 2.25 2021-2022 AECO, $2.50 2023 AECO. Oil price - $60.00/bbl 2019 WTI US, $55.00/bbl 2020-2023

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.

-

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

2016 2017 2018 2019 2020 2021 2022 2023

Boe/d Spirit River

NEBC

Deep Basin

Feb 2019

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 185,000-190,000 boepd

• Current Reserves 1,041.4 mmboe (Jan 1, 2019)

• Tourmaline Land Base 1.77 million acres

• Drilling Inventory 2,486 locations (vertical)

(~1.5wells per section only)

6,865 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

185,000 – 190,000 boepd from the Deep Basin

through the drilling of only 580 hz wells to date.

The Company has a future hz drilling inventory of

over 6,865 locations.

T59

Oldman

2015 Significant New Discoveries

9

Mar 2019

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 Lands

Tourmaline Cardium Locations

Tourmaline Pipelines

Liquids Rich Cardium Fairway

Cardium Faults

10-25-50-23W5 PAD (1 Vert + 1 Hztl)

IP 90 - 28.5 mmcfpd, 360 bbls/day cond.

CR - 16.2 mmcfpd, 260 bbls/d

CUM - 10.2 bcf, 200 mstb

EUR - 28.5 bcf, 493 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.

10

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 - 5.9 mmcfpd

CUM - 6.30 bcf, 184 mbbls


16-20-50-22W5 PAD (2 Hztls)

02/05-29 - 16.9 mmcf/d, 620 bpd cond.

03-21 – 17.1 mmcf/d, 670 bpd cond.

72 hour test average rates Feb 2019

6-1-51-23W5 PAD (2 Hztls)

IP 90 - 21.7 mmcfpd

CR - 11.9 mmcfpd

CUM - 4.3 bcf, 92 mstb


NEBC Montney Gas/Condensate Complex

TCPL Mainline

Westcoast

McMahon

Gas Plant

Feb 2019

11

* See Schedule A

Current Prod. 375-400 mmcf/d

12,500-13,500 bpd condensate

4,000-4,500 bpd ngl

Current Reserves 1,230.6 mmboe (Jan 1, 2019)

Montney Drilling In excess of 3,565 horizontal

Inventory* locations.

Tourmaline is the 4th

largest Montney producer in

NEBC with production in excess of 85,000 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 boepd of primarily

condensate production in Q4 2018

• Production acceleration at Gundy

in Q4

2019 Facilities • 200 mmcfpd deep cut plant at

Gundy in late Q2 2019

• 15,000-17,500 bpd condensate

and ngls

Gundy Ck Montney Development

Mar 2019

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

June 2019

Gundy

Current Production: 15,000-17,500 BOEPD

No of wells drilled by TOU: 50

Free Liquid Content: 30-100 bbls/mmcf

Completed well cost: $3.3-3.7M

TWP 8894-B-9

94-B-16 94-A-13

Spectra Fort

Nelson Mainline

12

South Gundy

Townsend Tie-In

40-50 MMCF/D

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 June 2019.

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

A-078-A PAD Avg Rate Number Avg Free Avg Total

9 wells to Date of Days Cond Yield Liquid Yield

Rig Released June 2017 (mmcf/d) (bbl/mmcf) (bbl/mmcf)

Upper Montney Lobe 5.2 434 31.3 46.5

Middle Montney Lobe 3.7 457 33.6 48.9

Lower Montney Lobe 2.9 400 30.5 45.6

B-093-I PAD Avg Rate Number Avg Free Avg Total


Rig Released Nov 2017 (mmcf/d) (bbl/mmcf) (bbl/mmcf)


Upper Middle Montney Lobe 4.1 140 58.3 94.4



A-032-I PAD Avg Rate Number Avg Free Avg Total


Rig Released Sept 2018 (mmcf/d) (bbl/mmcf) (bbl/mmcf)





C-023-I PAD Avg Rate Number Avg Free Avg Total


Rig Released Aug 2017 (mmcf/d) (bbl/mmcf) (bbl/mmcf)





A-078-A PAD

B-093-I PAD

A-032-I PAD

C-023-I PAD

Mar 2019

Gundy Horizontal Well Performance

Nov 2018

13

2017/2018 average completed well costs of $3.3-3.5 million, and along with Sunrise-Dawson, the least expensive for the entire Canadian Montney sector.

Gundy Creek Phase 1 Construction

May 2019

14

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.

15

Tourmaline Montney

Efficiency + Execution

Apr 2019

16

Select Montney Peers

ARC Resources, Birchcliff, EnCana, NuVista, Painted Pony, Paramount & Seven Generations

0

200

400

600

800

1,000

1,200

1,400

Montney Net Production (MMCFE/d)

Source: Goldman Sachs except for Tourmaline (Q2/19E)

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

Corporate 2019E D/CF(1)

Source: All data Peters & Co except for PPY (Scotia)

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

Montney D&C Costs ($MM)

Source: Publicly Available Information

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

Montney Op Costs per BOE

Source: Publicly Available Information

Encana Operating costs converted to CAD + $0.80

incremental cost per MCF for processing(1) See “Non-GAAP Measures” in Forward Looking Statement Advisories.

Mar 2019

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 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

• 1,850 Horizontal Locations* along Regional Play Fairway

• Current Reserves of 185.8 mmboe (Jan 1, 2019 GLJ)

• Regional pool defined by 225 horizontal and 140 existing

vertical wells

• 300-550 mboe 2P reserves per horizontal Charlie Lk/Montney

• $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)

Spirit R Acq

(Q4 2018)

3,264 ha

6.82 mmboe

800 boepd

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.

Mar 2019

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

• 8 Major Frac Water source/

Recycling Facilities,

450,000 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

2019 (F) $50-55M

2020 (Target) $65-75M

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.

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)

20,000 bpd corporate condensate

production milestone achieved in

late October 2019.

Tourmaline Condensate Production Outlook

2018-2020Nov 2018

(not included in 5 year plan)

19

Historical Reserves Summary

Feb 2019

Reserves

2012 2013 2014 2015 2016 2017 2018

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

PDP 91.9 122.3 177.8 263.2 352.1 436.5 473.5

TP 249.2 316.5 472.3 644.1 859.2 1056.0 1206.7

2P 438.1 590.1 855.8 1108.3 1747.2 2216.6 2457.8

2012 2013 2014 2015 2016 2017 2018

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

2P FDA(i)

$10.35 $11.84 $10.40 $5.89 $5.94 $3.76 $5.15

With FDC

(i) See February 2019 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

3000

PDP TP 2P

MM

BO

E

Reserves (GLJ)

2014 2015 2016 2017 2018

4.35

6.19

7.658.25

12.71

15.1015.93

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

16.00

18.00

2012 2013 2014 2015 2016 2017 2018*

$ B

illion (*Jan 201

9 P

ricing)

Reserves Value (GLJ, 2P)

• Total Proved Reserve life index a reasonable 11

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 six years.

• 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

(1) Based on Canadian Reserves from public information.

21

Gas Development Location

Inventory and EconomicsMar 2019

22

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, 2019 escalated price forecast, adjusted for transportation, quality and heat content.

(4) See Schedule A.

AB Deep

Basin

Vertical

Outer

Foothills

Vertical

AB Deep

Basin

Horizontal

B.C. Gundy

Montney

Horizontal

B.C.

Montney

Horizontal

PRH

Charlie Lake

Horizontal

PRH

Montney

Horizontal

Total Well Costs

(Drill, Case, Complete, $ Million) 2.40 3.70 4.10 3.30 2.80 2.20 3.40

Average Reserves/Well (bcfe) 2.3 5.8 5.4 8.3 5.5 2.1 4.6

Year 1 Production Rate 1.2 mmcfepd 2.9 mmcfepd 4.0 mmcfepd 5.6 mmcfepd 4.0 mmcfepd 197 boepd 461 boepd

Development Cost/boe $6.32 $3.83 $4.56 $2.39 $3.06 $6.27 $4.48

Operating Expenses/boe (1) $3.23 $2.45 $2.27 $3.05 $1.73 $7.72 $6.23

Net Present Value @ 10% (000's) $524 $4,020 $3,497 $10,835 $8,254 $3,587 $6,149

Internal Rate of Return (2)

16% 38% 40% 300% 221% 93% 89%

Payback Period (months) 25 25 25 6 8 14 15

Year 1 Gas Price (3) $1.73 $1.67 $1.73 $1.20 $1.60 $1.78 $1.78

Future Development Locations(4)

2,036 450 6,865 1,611 1,954 1,214 636

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

$3.33

$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 2018

$/boe

Operating Costs

$1.29

$1.02

$0.79$0.74

$0.60

$0.45 $0.44 $0.46$0.49

$0.00

$0.50

$1.00

$1.50

2010 2011 2012 2013 2014 2015 2016 2017 2018

$/boe

General and Administrative Costs

• Tourmaline has the lowest effective interest rate/borrowing costs in the North American energy sector.

• The staff required to effectively operate a 300,000 boepd company growing to 350,000 boepd has already

been assembled.

Mar 2019

24

2019 Guidance

May 2019

25

2019(1)

Production – Boe/d 300,000

Cash Flow(i)

- $MM $1,521

CFPS - Diluted(i)

$5.58

E&P Capital Program(ii)

- $MM $1,200

Free Cash Flow(iii)

- $MM $290

Exit Net Debt(i)

- $MM $1,554

Debt to CF 1.0x

(1) Price Assumptions: Gas price - $3.00/mmbtu 2019 NYMEX US, $1.80/mcf 2019 AECO; 2019 Oil price - $60.00/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.

2019 Natural Gas Transportation

and Marketing Overview

29%

AECO

TCPL Mainline

10%

Kingsgate

California

~300 MMcf/d*

US Midwest/Other

~85 Mmcf/d

Station 2

26

41%

20%

10%

29%

Q2-Q4 2019 Average Natural Gas Portfolio

Diversification

US/Other Markets Hedges Stn 2 Aeco

(2)

(1) US/Other Markets access 28% physical markets + 13% of Nymex Basis

Differentials

(2) ~30% of Station 2 exposed at 7A/Hunt

(1)

Dawn

~115 Mmcf/d

May 2019

2019 Exit: 540 mmcf/d of gas will be to US/Other Markets

*Exit volumes

Highlights and Outlook

Apr 2019

• Tourmaline now a Senior with production exceeding 300,000 boepd.

• Tourmaline is the largest producer of Canadian natural gas and is a top ten Canadian liquids

producer (excluding oil sands/thermal).

• Continued strong earnings in 2018 as the Company focuses on full cycle profitability and returns.

• Tourmaline can provide growth and pay a dividend from excess annual free cash flow.

• 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 2018 with Company reserves of 2.46 billion boe (Jan 1, 2019)

(11.7 tcf of natural gas and 505.2 mmboe of liquids - oil, condensate, ngl).

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

85% of drilling inventory currently unbooked in the reserve report.

• Achieved 50% well cost reductions over the last 5 years, targeting a further 10% reduction in

2019/2020.

• The list of industry-leading Tourmaline operated ‘top’ wells continues in all 3 core areas.

27

APPENDIX

Return Metrics Price to Earnings

0x

10x

20x

30x

40x

50x

60x

Price to Earnings M

ultiple

Price / 2019E Earnings Per Share (United States)

0x

20x

40x

60x

80x

100x

Price to Earnings M

ultiple

Price / 2019E Earnings Per Share (Canada)

Source Bloomberg

Metrics based on the average for each respective sector (as at April 8, 2019).

29

Natural Gas Flows From Western Canada

30

$10.2 MM

$10.6 MM

$12.0 MM

$5.3 MM

$6.0 MM

$3.5 MM

$3.9 MM

$4.5 MM

15.5 Bcfe

9.7 Bcfe

12.8 Bcfe

4.3 Bcfe

7.8 Bcfe

6.9 Bcfe

4.1 Bcfe

5.4 Bcfe

0

2

4

6

8

10

12

14

16

18

Marcellus* Haynesville* Utica* Duvernay Montney

(Industry Average)

TOU BC Montney ** Deep Basin

(Industry Average)

TOU Deep Basin

Well Costs DC,T (CAD) Vs. EUR by Play Type

Completed Well Cost $CDN EUR (Bcfe)

*USD Converted into CAD ($1USD = $1.32CAD)

** Montney is the average BCFE type curve of South MNTN and Gundy

Source: Scotiabank "September 2018 - The Playbook" except for Tourmaline Figures

$0.66/mcf

$1.10/mcf

$0.94/mcf

$1.25/mcf

$0.77/mcf

$0.95/mcf

$0.83/mcf

$0.51/mcf

Completed Well Costs and EUR By

N. American Play TypeMar 2019

31

Tourmaline vs Natural Gas Peers

Cash Costs Per BOEMar 2019

32

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

Tourmaline (USD)* Canada Peer Average (USD)** US Peer Average***

Costs P

er B

OE

Tourmaline Vs. US Gas Weighted Peers

Cash Costs in USD* per BOE (Q3/18)

Operating Transportation G&A Interest

$6.24

$9.52

*CAD Converted into USD ($1USD = $1.32 CAD)

** Peer average consists of 7 Canada Peers of which weighted gas production > 50% (AAV, ARX, BIR, CR, PEY, POU and PPY)

***Peer average consists of 7 United States Peers weighted gas Production > 50% (AR, CHK, CNK, COG, EQT, RRC and SWN)

$7.89

Doe 2-11 Condensate/NGL Facility

A 3,000-3,500 boepd project started up in late September 2018

Sep 2018

33

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

34

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

Banshee Alberta Gas Plant

35

• 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

(September to November)Jan 2019

Source: NBF

0

100

200

300

400

500

600

700

800

900

1000

Tou

rmal

ine

02-1

9-0

50

-20

W5

Tou

rmal

ine

10-1

4-0

58

-01

W6

Tou

rmal

ine

12-1

7-0

49

-19

W5

Tou

rmal

ine

12-0

8-0

50

-20

W5

Tou

rmal

ine

13-1

8-0

50

-20

W5

Ad

van

tage

09-1

9-0

75

-10

W6

Bo

nav

ista

14-0

2-0

44

-28W

4

Tou

rmal

ine

02-2

3-0

58

-01

W6

Tou

rmal

ine

10-1

8-0

49

-19

W5

Tou

rmal

ine

13-1

8-0

50

-20

W5

Tou

rmal

ine

14-0

6-0

50

-20

W5

Enca

na

04-1

8-0

63

-20

W5

Enca

na

01-1

8-0

63

-20

W5

Enca

na

01-1

8-0

63

-20

W5

Tou

rmal

ine

04-2

8-0

52

-22

W5

CTD

(m

mcf

pd

)

Liquids

Gas

36

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.

37

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

38

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

39

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

40

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.

41

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 14,766 (gross) locations disclosed in this

presentation, 1,192 are proved undeveloped locations, 37 are proved non-producing locations, 1,012 are probable undeveloped

locations, 2 are probable non-producing and 12,523 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, 2018

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.

42

Schedule A continued

43

Deep Basin Vertical well count :

Approximately 2,582 gross prospective sections at approximately 1.5 wells per section minus 10% for areas

that are inaccessible or limited by spacing requirements minus approximately 1,000 existing wells. Includes

450 locations in the Outer Foothills area.

Total Vertical Locations ~ 2,486

Deep Basin Horizontal well count :

Approximately 2,582 gross prospective sections in the Deep Basin at approximately 3 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 3 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 ~ 6,865

NE BC Well count :

300 gross sections in NE BC at 12-16 wells per sections in multiple lobes (2-5 depending upon location)

yielding 3,565 locations.

TOTAL NE BC = 3,565 locations

Spirit River well count:

602 gross sections within the Charlie Lake/Montney Fairway x 2-4 wells per section = 2,188 wells

Minus approximately 338 existing wells

Total Spirit River ~ 1,850 wells

Total gross locations ~ 14,766

Schedule B

44

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 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 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

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'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.

45

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

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 2019-2023 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 2019 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

March 2019 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

46

http://www.tourmalineoil.com/

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).

47

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