The document provides an overview of Tourmaline Oil Corp.'s current status and operations. It summarizes that Tourmaline has a 2014 average production forecast of 120,000 boepd, with core areas in the Alberta Deep Basin, NEBC Montney, and Peace River High Charlie Lake plays. It also details Tourmaline's drilling inventory, financial position, and recent acquisition of Santonia's Deep Basin assets, which provide an additional 184 sections of land and 3,800 boepd of current production.

1. Tourmaline Oil Corp.
Corporate Presentation
May 2014

2. Current Status
Production Overview  2014 average production forecast of 120,000
 Target Q2 115,000 – 120,000 boepd production range achieved 2H April
 Additional 16,000 boepd tied in awaiting facility expansions
 Additional 10,000 boepd tested, behind pipe volumes, awaiting tie-in
Three Major Core Areas  Alberta Deep Basin: 2,150 gross sections (largest Deep Basin land position)
 NEBC Montney Gas/Condensate: 5th/6th largest Montney producer in W. Canada
 Peace River High Charlie Lake: Large, regional, light oil and gas resource play
Drilling Results  18 rig program in 2H 2014
Drilling Inventory  3,200(+) vertical locations with downspacing at two wells per section and
approximately 4,000 horizontal locations in the Deep Basin: 800 locations in
NEBC, 1,200 locations in Peace River High Charlie Lake core area
Financial Position  Net Debt - $818.6 million (Mar 31, 2014)
 Equity financing completed Feb 2014 for net proceeds of $219.2 million
Current Shares OS (million)  199.9
Apr 2014
2

3. EP Performance 2009-2013
0
0.5
1
1.5
2
2.5
3
3.5
2009 2010 2011 2012 2013
ReservesperShare(BOEs)
Reserves Growth Per Share*
0
20
40
60
80
100
120
140
160
2009 2010 2011 2012 2013
ProductionperThousandShares
(BOEs)
Production Growth Per Share*
$3.00
$4.00
$5.00
$6.00
$7.00
2009 2010 2011 2012 2013
2009-2013 Op Costs/BOE
0.00
1.00
2.00
3.00
4.00
5.00
0.00
1.00
2.00
3.00
4.00
5.00
6.00
7.00
2009 2010 2011 2012 2013
NaturalGasPrice$/mcf
NPV10%
$Billion
Reserves NPV
Reserve NPV-2P AECO Ave Nat Gas Price
* debt adjusted
Mar 2014
3

4. Deep Basin Overview
 Tourmaline has assembled the largest land position (1.1 million acres), delineated the
largest drilling inventory (7,200 locs) and has become the second largest producer
(current 75,000 boepd) in the Deep Basin within the first 5 years of operation.
 The Company utilizes 3D seismic to select almost every horizontal and vertical location
and believes this technical approach provides a competitive advantage.
 Tourmaline staff have been at the leading edge of new horizontal and vertical completion
technologies and the Company is consistently drilling the highest deliverability/reserve
recovery Wilrich and Notikewin horizontals.
 The Company has constructed a large, low cost, gas and liquid processing infrastructure
with current capacity of 400 mmcfpd, growing to 475 mmcfpd by exit 2014. Tourmaline
will be the largest Deep Basin producer by 2H 2014.
 2H 2015 gas production levels of 550 mmcfpd and cond/ngl production levels of 20,000
bpd are currently anticipated (110,000 boepd).
Apr 2014
4

5. Note: All land and well information is provided on a gross interest basis
Apr 2014
Alberta Deep Basin
DEEP BASIN - Deep Basin Overall Area
T. 57
T. 59
Tourmaline
Wild R. 14-20
Hinton
Ansell
Edson
Marsh
Harley
Pine Ck.
Wroe
Minehead
Horse
Cecilia
Wild River
Sundance
Obed
T. 59
R. 26
Tourmaline
Hinton 6-32
Tourmaline
Minehead 5-12
Tourmaline
Berland R.
14-15
Musreau
/Kakwa
Lovett
R. 9 R. 7 R. 5 R. 3 R. 1, W6M R. 24 R. 22 R. 20
T. 61
T. 63
R. 24 R. 22 R. 20 R. 18 R. 16
T. 43
R. 14
AlbertaNE
BC
T. 51
Tourmaline Gas Plant
Tourmaline 3D
Tourmaline Lands
Possible Facility Locations
2013 Significant New Discoveries
 Current Production 75,000 boepd
 Current Reserves 304.9 mmboe (Jan 1, 2014)
 Tourmaline Land Base 2,150 sections
 Drilling Inventory 3,200 locations (vertical)
(2 wells per section only)
4,000(+) locations (hz)
 2014 Drilling Program Approx. 8-10 verticals,
70-75 horizontals
Q1 2014 Update
30 hz wells drilled and completed
(Wilrich, Notikewin, Falher).
27 tied in by late April. 16 of 17 wells
with 30 days of production exceed
Company template/guidance of 5.0
mmcfpd 30 day IP.
The actual 30 day IP average for these
17 wells is 10.4 mmcfpd.
T. 53
T. 55
T. 57
T. 51
T. 49
T. 47
T. 45
Cardium
Viking
Mannville/Notikewin
Falher
Cadomin
Dunvegan
Nikinassin
Bluesky
Gething
Wilrich
Gething
5

6. T. 59
Tourmaline
Wild R. 14-20
Hinton
Ansell
Edson
Marsh
Harley
Pine Ck.
Wroe
Minehead
Horse
Cecilia
Wild River
Sundance
Obed
T. 59
R. 26
Tourmaline
Hinton 6-32
Tourmaline
Berland R.
14-15
Musreau/
Kakwa
Lovett
R. 9 R. 7 R. 5 R. 3 R. 1, W6M R. 24 R. 22 R. 20
Note: All land and well information is provided on a gross interest basis
T. 61
T. 63
T. 53
T. 55
T. 57
T. 51
T. 49
T. 47
T. 45
R. 24 R. 22 R. 20 R. 18 R. 16
Tourmaline Gas Plant
Tourmaline 3D
Tourmaline Lands
Possible Facility Locations
2012-2013 Horizontal Wells
Kakwa 1-2
25.8 mm/d @ 14.1MPa Kakwa 13-20
21.0 mm/d @ 12.8MPa
Wild R 2-9
21.9 mm/d @ 6.7MPa
Ansell 16-3
10.1 mm/d @ 5.9MPa
Marsh 1-10
7.7 mm/d @ 37.7MPa
Falher A
Gething
Cadomin
Falher B
Viking
Notikewin
Falher C
Cardium
Viking
Notikewin
Falher
Cadomin
Dunvegan
Nikinassin
Bluesky
Gething
Wilrich
Gething
Horizontals Drilled to Feb 2014
Notikewin/Falher hz drilled 25
Total Locations in Inventory 570
Alberta Deep Basin:
Notikewin/Falher Hz Program
Tourmaline
Minehead 5-12
Marsh 16-26
14.7 mm/d @ 6.0MPa
Wild R 12-28
37.0 mm/d @ 11.0MPa
Apr 2014
6

7. T. 57
T. 59
T. 59
R. 9 R. 7 R. 5 R. 3 R. 1, W6M R. 24 R. 22
Note: All land and well information is provided on a gross interest basis
T. 61
T. 63
T. 53
T. 55
T. 57
T. 51
T. 49
T. 47
T. 45
R. 24 R. 22 R. 20 R. 18 R. 16
Alberta Deep Basin: Wilrich Regional Resource Play
Tourmaline
Wild R. 14-20
Hinton
Ansell
Marsh
Harley
Pine Ck.
Wroe
Minehead
Horse
Cecilia
Wild River
Obed
R. 26
Tourmaline
Hinton 6-32
Tourmaline
Minehead 5-12
Tourmaline
Berland R.
14-15
Musreau/
Kakwa
Lovett
Kakwa13-20 HZTL
Test Rate 21.2 mmcf/d
@13.0 Mpa (csg)
Minehead 1-19
Test Rate 24.5 mmcf/d
@ 24.3 Mpa (csg)
Edson 15-35 HZTL
Test Rate 18.4 mmcf/d
@ 21.5 Mpa (csg)
Minehead
Test Rate 35.0 mmcf/d
@ 19.7 Mpa (csg)
Musreau 8-25 HZTL
Test Rate 18.4 mmcf/d
@ 20.1 Mpa (csg)
Wilrich Opportunities
Total Hztl’s Loc’s 1,625
(2 wells /Section)
2014 Drilling Program 55-60 hzs
Horse/Smoky 13-3 HZTL
Test Rate 8.6 mmcf/d
@ 14.9 Mpa (csg)
Edson
Tourmaline Gas Plant
Tourmaline 3D
Tourmaline Lands
Possible Facility Locations
2012-2013 Horizontal Wells
Wilrich Sand Reservoir
Wild River 4-17 HZTL
Test Rate 17.5 mmcf/d
@ 5.8 Mpa (csg)
Horse/Smoky
Test Rate 70.1 mmcf/d @ 15.0 Mpa
IP 35.0 mmcfpd
Lovett 7-15
Test Rate 25.5 mmcf/d
@ 7.8 Mpa (csg)
Edson 14-19 (Oct/13)
22 mmcf/d IP
Kakwa 13-15/4-10 Pad (Nov/13)
54.6 mmcf/d IP, 360 bbls/day cond
Apr 2014
7

8. Note: All land and well information is provided on a gross interest basis
Apr 2014
DEEP BASIN - Deep Basin Overall Area
T. 57
T. 59
Edson
Harley
Minehead
Horse
Cecilia
T. 59
Musreau
/Kakwa
Lovett
R. 7 R. 5 R. 3 R. 1, W6M R. 24 R. 22 R. 20
T. 61
T. 53
T. 55
T. 57
T. 51
T. 49
T. 47
T. 45
R. 24 R. 22 R. 20 R. 18 R. 16
T. 43
R. 14
AlbertaNE
BC
16-36 Comp. 100%
30 MMcf/d
200m3/d oil cond. capacity
Sour rated to 20%
5% Keyera West Gas Plant
Pembina 150 MMcf/d
Minehead Facility 15-12-50-21-W5M
 Tourmaline’s 1.1 MM Acres, the largest land position in the
Deep Basin, is serviced by a network of 6 gas plants and a
series of large pipeline laterals.
 All gas plants have liquid recovery capability.
 Total current processing capacity of 400-425 mmcfpd.
 50-55 mmcfpd Musreau gas plant expansion in 2H 2014.
 50-55 mmcfpd expansion at Wild R with a Feb 2015 start-up.
 Infrastructure can be continually upsized to accommodate
growing production volumes ensuring lower future operating
costs and ever improving production efficiencies.
Tourmaline Pipelines
Tourmaline Gas Plant
Tourmaline Lands
Future Tourmaline Pipelines
Main Sales Pipelines
Tourmaline
Anderson 1-9
25-30 MMcf/d
Tourmaline
Minehead 15-12
110-120 MMcf/d
Tourmaline
Wildriver 14-20
110-120 MMcf/d
Tourmaline
Berland 14-15
35-40 MMcf/d
Tourmaline
Musreau 8-13
60 MMcf/d
Edson
Lateral
Lovett
Lateral
Cabin
Lateral
TCPL Main Line
Tourmaline
Hinton 6-32
60 MMcf/d
Alberta Deep Basin Infrastructure
R. 3
8

9. Note: All land and well information is provided on a gross interest basis
Feb. 2014
Alberta Deep Basin Santonia Acquisition
DEEP BASIN - Deep Basin Overall Area
T. 57
T. 59
Tourmaline
Wild R. 14-20
Hinton
Ansell
Edson
Marsh
Harley
Pine Ck.
Wroe
Minehead
Horse
Cecilia
Wild River
Sundance
Obed
T. 59
R. 26
Tourmaline
Hinton 6-32
Tourmaline
Minehead 5-12
Tourmaline
Berland R.
14-15
Musreau
/Kakwa
Lovett
R. 9 R. 7 R. 5 R. 3 R. 1, W6M R. 24 R. 22 R. 20
T. 61
T. 63
T. 53
T. 55
T. 57
T. 51
T. 49
T. 47
T. 45
R. 24 R. 22 R. 20 R. 18 R. 16
T. 43
R. 14
Cardium
Viking
Mannville/Notikewin
Falher
Cadomin
Dunvegan
Nikinassin
Bluesky
Gething
Wilrich
Gething
AlbertaNE
BC
T. 51
Tourmaline Gas Plant
Tourmaline 3D
Tourmaline Lands
Possible Facility Locations
2013 Significant New Discoveries
Santonia (Harlech) Lands
Santonia Acquisition
Current Production/Reserves
3,800 boepd from 72 producing wells
24.4 mmboe 2P Reserves
350(+) new locations
Land Base
184 Sections New to Tourmaline
78 Sections Partnered with Tourmaline
220,910 Gross Acres / 128,476 Net Acres
Majority of lands imaged with 3D seismic
16-36 Comp. 100%
30 MMcf/d
200m3/d oil cond. capacity
Sour rated to 20%
5% Keyera West Gas Plant
Pembina 150 MMcf/d
 Current Production 75,000 boepd
 Current Reserves 304.9 mmboe (Jan 1, 2014)
 Tourmaline Land Base 2,150 sections
 Drilling Inventory 3,200 locations (vertical)
(2 wells per section only)
4,000(+) locations (hz)
 2014 Drilling Program Approx. 8-10 verticals,
70-75 horizontals
9

10. Santonia Acquisition
Apr 2014
 Significant addition to, and contiguous with, Tourmaline’s existing Deep Basin core area (220,910
gross/128,416 net additional acres).
 A large contiguous land base already detailed with 3D seismic, consistent with the Tourmaline
technical approach that yields industry leading well results.
 Existing reserves acquired for $7.10/boe (2P) $10.54/boe (1P), with considerable potential
incremental reserve upside.
 Current production 3,800 boepd, Tourmaline plans to add one rig to Harlech in 2H 2014 and grow
2015 production to 6,000 boepd (+) via a series of low risk horizontals.
 Future inventory of approximately 350 horizontal locations (Wilrich, Notikewin, Viking, Falher,
Cardium), that is expected to increase over time. (Santonia currently indicates 650 locations)
 Existing working interest facility network at Harlech that complements Tourmaline’s significant
Deep Basin infrastructure complex.
 Tourmaline has more than doubled the production and reserve base in less than 2 years for all the
modest size corporate transactions completed to date (Altia Energy Ltd., Pienza Petroleum Inc.,
Vigilant Exploration Inc. Exshaw Oil Corp., Cinch Energy Corp., Huron Energy Corporation). The
Tourmaline share price has appreciated by 50% or greater within 12 months of the closing of
each of these transactions.
10

11. AlbertaNE
BC
NEBC Montney Gas Condensate and Peace
River High Charlie Lake Oil Core Areas
T77
T81
T83
T79
T69
T73
T75
T71
T67
T85
R19R21 R 7R 9R11 R 1, W6MR 3R 5R23
T66
Dawson Ck
Montney
Pool
R15R17 R13
Parkland
Wabamun
Gas Pool Parkland
Montney
Pool
Devonian
Non-Deposition
Dunvegan
Gas Field
Tourmaline Gas Property
Tourmaline Oil Property
Tourmaline Gas Plant
Tourmaline Drilling Rig
Current Prod. 45,000 boepd
2010 – Mar 2013  87 Montney Hz Gas Wells,
Drilling  70 Charlie Lake Hz Oil
Wells, 8 vertical oil wells
Drilling Inventory In excess of 800
Montney horizontal locations
Spirit River 1,200(+) Hz Charlie Lake
oil locations
Note: All land and well information is provided on a gross interest basis
Apr 2014
11

12. Sunrise/Dawson NEBC Montney/Doig
Development
Westcoast
McMahon
Gas Plant
Current Prod. 175-180 mmcf/d
3,500-4,000 bopd (cond,ngls)
5,000 boepd tested behind pipe
Current Reserves 235.0 mmboe (Jan 1, 2014)
2013 – Drilling 34 Montney Hz Gas
Drilling Inventory In excess of 550 horizontal
Montney locations
Sunset-Dawson Montney
Montney Wells Drilled: 99
No of Wells Tested: 97
Avg rates from the last 30 months drilling
Avg. Test Rate/IP : 11.41 mmcf/d
Avg. Liquid Rate : 315 bbls/d
Tourmaline has become the 5th largest
Montney producer in Western Canada in
the second quarter of 2014 with production
of 33,000-35,000 boepd.
Apr 2014
12

13. 7-3 Hztl
1550 bopd
1.9 mmcfpd gas
Tourmaline Mulligan 14-23 Vert.
Cum. 400 mtsb Oil
Cum. 1.5 Bcf Gas
14-8 Hztl
1283 bopd
2.0 mmcfpd gas
New Pool Discovery
Earring 13-8 Vert.
Test . Rate 700 boepd
Peace River High Regional Charlie Lake
Resource Play Apr 2014
T. 79
R. 9 R. 7 R. 5
T. 77
T. 83
T. 81
T. 75
Original Spirit River 2002
Discovery Well
DDV/APC 3-3-78-7-W6M
R. 10
Original Spirit River
Pool Boundary 2011
T. 76
R. 6
T. 76
Tourmaline Producing Oil Wells
Tourmaline Producing HZTL Wells
Tourmaline Producing Wells
Tourmaline Battery Site
Industry CLLK penetrations
Tourmaline 2012/2013 Prop. HZTL Wells
Legend
Charlie Lake 2011 Bdy.
Tourmaline Lands
Charlie Lake 2013 Bdy.
Lower
Charlie
Lake
Upper
Charlie
Lake
Type Log
2013 Spirit River Charlie Lake Drilling Summary
• 1,200 Horizontal Locations along Regional Play Fairway
• Current Reserves of 49.9 mmboe (Jan 1, 2014 GLJ)
• Total ultimate potential 0.5 billion boe (Company
estimate), Tourmaline capture 75-80%
• Regional pool defined by 75 horizontal and 140 existing
vertical wells
• 352 mboe 2P reserves per horizontal
• 2014 Drilling; 50-60 Horizontal wells
• $3.75-$4.0M horizontal drill complete cost
• Mulligan Battery 2H 2014, 3,000 bopd initial capacity
• Tourmaline operated sour gas injection plant Q3 2014, 60
mm/d planned capacity
TOU 1-30
300 bopd, 0.5 mm/d gas
6-10 Vert.
Cum. 55 mtsb Oil
Tourmaline Earring 15-16
440 bbls/d 30° API Oil
2.7 mmcfpd Gas
Trcl hz
800 boepd
5-29/1-30 Pad
2450 bopd
(Oct/13)
TOU Mulligan 1-14
200 bopd
1.1 mm/d
TOU 1-14
310 bopd
3.5 mmcfpd gas
13

14. Tourmaline Gas Plant
New E&P Plays and Opportunities
 Paleozoic Gas Play
• 200-300 bcf Targets
• 10 Prospects
• Sunset 11-17 Cased to
TD, 3 Paleozoic Pay
Zones, Prod Testing
after Break-up.
 Regional Charlie Lake Oil Play
 2013 Regional Discovery. Est
ultimate Reserves of 0.5 billion
boe (Company estimate),
Tourmaline 75-80% capture.
 Resthaven/Smoky Emerging Montney Play
• 100 Sections of Montney Rights
• 2 vertical, 1 hz gas well in 2014 program to
date
 Emerging Outer Foothills Cardium Oil Play
• Over 500 Locations in Inventory
• 2013 Drilling 2-3 Locations
 Emerging Fracture Enhanced Wilrich Play
•3 High Rate Verticals Drilled
•Over 150 Locations in Inventory
•2013 Drilling 5-7 Locations
•Initial short radius lateral successful
 Deep Basin Devonian Strat Traps
• 6 Prospects, 2H 2013 Drilling.
• Smoky 7-15 Cased to TD, 4
Potential Paleozoic Pay Zones,
Completion when accessible after
break-up.
Apr 2014
14

15. Production & Reserves Growth
Feb 2014
Reserves
2010 2011 2012 2013
(mmboe) (mmboe) (mmboe) (mmboe)
PDP 38.9 67.3 91.9 122.3
TP 93.0 149.0 249.2 316.5
2P 158.2 270.1 438.1 590.1
2010 2011 2012 2013
(/boe) (/boe) (/boe) (/boe)
2P FDA (i) $15.55 $13.34 $10.35 $11.84
With FDC
(i) See February 2014 press release for full FD&A calculations
0
20,000
40,000
60,000
80,000
100,000
120,000
2009 Avg 2010 Avg 2011 Avg 2012 Avg 2013 Avg 2014 Avg (F)
BOEPD
Production
0
100
200
300
400
500
600
PDP TP 2P
MMBOE
Reserves (GLJ)
2010 2011 2012 2013
15

16. Tourmaline Improving Capital Efficiencies
Apr 2014
$53,484
$47,643
$32,170
$27,224
$14,963
0
10,000
20,000
30,000
40,000
50,000
60,000
2010 2011 2012 2013 2014
$/boepd
• Migration to 90% hz wells in 2H 2012/2013
• Migration to multi-well pads in 2013/2014
• Fewer vertical pilots in 2014 vs 2013
• Proportionately less facilities expenditures
in 2013 and 2014.
16

17. Gas Development Location
Inventory and Economics
AB Deep Basin Outer Foothills AB Deep Basin B.C. Montney Charlie Lk
Vertical Vertical Horizontal Horizontal Horizontal
Total Well Costs 4.0 5.0 5.25 3.6 3.6
(Drill, Case, Complete, $ Million)
Average Reserves/Well (bcfe)* 2.5 5.5 5.0 5.6 2.2
Year 1 Production Rate 1.45 mmcfpd 3.0 mmcfpd 3.2 mmcfpd 3.3 mmcfpd 232 boepd
Development Cost/boe $9.60 $5.45 $6.30 $3.86 $9.82
Operating Expenses/boe $4.00 $5.00 $3.50 $3.50 $8.75
Royalty Rate 8% 8% 7% 22% 22%
Net Present Value @ $3,434 $10,695 $10,140 $11,680 $6,209
10% (000’s)
Internal Rate of Return 35% 72% 74% 128% 71%
Year 1 Gas Price ** $4.08 $4.08 $ 4.08 $ 3.98 $ 4.08
Future Development Locations 2,750 450 4,000 800 1,200
* management internal estimate (2 wells/section)
** GLJ Dec. 31, 2013 escalated price forecast
667 future locations in 2013 GLJ report
Apr 2014
17

18. 5 Year Development Outlook
2014 Dev. Drilling (67 Deep Basin)(34 Montney)(50 Spirit River)(2 Other)
Cumulative Production During Outlook Period 341.2 mmboe
Remaining Developed Reserves at End of Outlook Period 451.7 mmboe
Remaining Drilling Inventory at End of Outlook Period 7,863 (91% of current)
Natural Gas Price 2014 - $4.64/mcf (AECO)
Prod’n Annual Prod’n Pre-tax Pre-tax After Tax After Tax Capital (Net Debt)
BOEPD MBOE Cash Flow CFPS Cash Flow CFPS Expenditures Cash
*** ***
2014 120,000 43,800 1,086 5.30 1,086 5.30 1,100 (631)
2015 159,500 58,217 1,480 7.14 1,480 7.14 1,250 (360)
2016 189,095 69,209 1,738 8.36 1,738 8.36 1,250 168
2017 221,077 80,693 1,971 9.48 1,797 8.64 1,250 756
2018 244,633 89,291 2,182 10.50 1,952 9.39 1,250 1,499
* Outlook derived by utilizing, among other assumptions, historical Duvernay/Tourmaline production performance and reserve addition costs.
** 2015 and beyond provided for illustration only. Budgets and forecast beyond 2014 have not been finalized and are subject to a variety of factors including prior year’s results
*** See “Non-GAAP Measures” in Forward Looking Statement Advisories
**** Based on internal estimates by a qualified reserve evaluator
Reserves Per Well Utilized (bcfe)****
Deep Basin Horizontal 4.1
NEBC Montney Horizontal 4.4
Spirit River 2.2
Apr 2014
18
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
220,000
240,000
260,000
BOE/Day Production Outlook
2018 Production
2017 Production
2016 Production
2015 Production
2014 Production
Base

19. 2010-2013 Cost Reduction Strategy
$6.51
$6.34
$5.58
$4.43 $4.35
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
2009 Avg 2010 Avg 2011 Avg 2012 Avg 2013 Avg
$/boe
Operating Costs
$2.46
$1.29
$1.02
$0.79 $0.74
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
2009 Avg 2010 Avg 2011 Avg 2012 Avg 2013 Avg
$/boe
General and Administrative Costs
 The goal is to continue to be one of the lowest cash cost producers in the Basin in 2014.
 Tourmaline has ongoing facility plans and projects in the Deep Basin that will systematically improve
production efficiency and reduce costs.
 The staff required to effectively operate a 80,000 boepd growing to 100,000 boepd company, was built in
2010-2012 and only minimal staff additions will be necessary to accommodate further growth.
Mar 2014
19

20. 2014 Base Budget/2015 Outlook
2014 2015 (Prelim.)
Capital Spending (not including acquisitions/dispositions) $1,100.0 million $1,250.0 million
Annual Average Production 120,000 boe/d 159,500 boe/d
Average Q4 2014 /Q4 2015 Production 138,000 boe/d 176,667 boe/d
Annual Cash Flow(ii) $1,085.9 million $1,479.6 million
Cash Flow Per Share – Diluted(i) $5.30 $7.14
Q4 2014/Q4 2015 Annualized Cash Flow per share – Diluted (i) $6.12 $8.12
Year End Net Debt (ii) (iii) $(631.1) million $(360.4) million
Assumptions
1. 2014 Gas Price (NYMEX) - $4.57 (U.S.) $4.64 AECO; 2015 Gas Price (NYMEX) - $4.48 (U.S.) $4.43 AECO.
2014 Oil Price - $97.40 (W.T.I. – U.S.); 2015 Oil Price - $93.38 (W.T.I. – U.S.)
2. Year-end Debt projections assume no new equity issues or asset sales.
(i) based on 201.2 million basic shares outstanding
(ii) see “Non-GAAP Measures” in Forward Looking Statement Advisories
(iii) includes an estimate of net debt and related transaction costs associated with the acquisition of Santonia of approximately $42.0 million.
Apr 2014
20

21. EP Outlook Q2 – Q4 2014
 Major 2H 2014 Facility start-ups at Spirit River (new gas plant with enhanced liquid
recovery and power generation), Doe B.C. and Musreau Ab. (existing plant expansions) will
yield approximately 25,000 boepd of new production in Q4 2014.
 Drill and complete 60 Deep Basin horizontals in 2H 2014 including high potential drilling
targets on the Santonia Deep Basin land base.
 Post break-up completions of Paleozoic discoveries at Sunset B.C. and Smoky Ab. (7 new
deep zones to test).
 Results from multiple delineation wells following up the late 2013 Lower Montney
condensate rich discovery in Dawson-Sunrise.
 Completion of first Triassic Doig horizontal at Sundown.
Apr 2014
21

22. Capitalization to Date
Insiders Public Total
millions of shares Price millions of shares Price $
October 2008 15.00 3.50 22.00 7.00 301.0
13.50 7.00
December 2008 (Flow Thru) 1.25 10.00 1.25 10.00 25.0
April 2009 (Alberta Deep Basin) 3.00 8.00 24.0
May 2009 3.00 10.00 11.00 10.00 140.0
September 2009 (Pienza Acq.) 3.55 12.00 42.6
November 2009 (Vigilant) 3.84 12.00 46.1
(Exshaw) 1.10 12.00 9.78 12.00 130.5
(Financing common) 2.29 15.00 9.50 15.00 176.9
(Financing flow thru) 0.75 18.00 1.00 18.00 31.5
January 2010 (Altia) 6.41 15.00 96.2
March 2010 (Financing common) 1.50 18.00 8.00 18.00 171.0
(Financing flow thru) .45 21.60 2.00 21.60 52.9
June 2010 (Greater Hinton) 2.50 18.00 45.0
August 2010 (Financing flow thru) 0.30 22.00 0.85 22.00 25.3
November 2010
(IPO + Over-Allotment) 0.85 21.00 11.50 21.00 259.4
March 2011
(Financing flow thru) 0.38 30.00 1.20 30.00 47.4
May 2011
(Public offering + Private Placement) 0.50 25.50 6.33 25.50 174.0
July 2011
(Cinch) 6.36 33.02 210.1
October 2011
(Public Offering + Private Placement) 0.30 33.00 4.6 33.00 161.7
November 2011
(Flow Thru Public Offering + Private Placement) 0.16 41.00 1.20 41.00 55.8
April 2012
(Flow Thru Private Placement) 0.15 28.80 1.25 28.80 40.4
August 2012
(Public Offering + Private Placement) 0.04 29.00 4.6 29.00 134.5
November 2012
(Public Flow Thru + Private Placement) 0.05 36.90 1.0 36.90 38.7
December 2012
Huron 7.40 33.02 244.4
March 2013 (Public Offering) 0.03 34.25 5.75 34.25 198.0
Flow Thru 0.09 42.15 0.75 42.15 35.2
October 2013 (Public Offering + Private Placement) 0.05 41.75 3.45 41.75 145.9
Flow Thru Public + Private 0.08 51.60 0.85 51.60 47.7
February 2014 (Public Offering + Private Placement) 0.02 47.50 4.60 47.50 219.2
April 2014 Santonia 3.23 54.94 177.4
Shares issued for option exercise 9.36
51.18 148.75 3,497.9
Insiders and associates have 26% of the basic common stock (31% fully diluted) and have contributed 11% of the basic cash.
22

23. APPENDIX

24. Hedging Summary
Apr 2014
2014 Gas Hedges
(April – December)
Volume
mcf/d
Weighted Avg Price
$/mcf(2)
Fixed Price Hedges
AECO (CDN$)(1)
Fixed Nymex (CDN$)(3)
170,384
47,236
$ 4.12
$ 4.49
Total Fixed Hedges 217,620 $ 4.20
% gas hedged 36%
Basis Differentials (US$) 81,109 $ (0.49)
Tourmaline also has 27 mmcf/d of Nymex-AECO basis differentials at US$0.49 from 2015-2022.
Call Options/Swaptions (Writers)(CDN$) 22,861 $ 4.28
2014 Oil Hedges
(April – December)
Volume
bbl/d
Weighted Avg Price
$/bbl
Swaps (US$)
Costless Collars (US$)
1,098
1,100
$ 95.95
$ 80.91-94.29
Total Volume Hedged 2,198
% oil hedged 12%
(1) Includes Costless Collars, WAP is based on the floor
(2) Excludes heat content lift
(3) These US Dollar hedges have been converted to CDN$ for purposes of this presentation.
24

25. 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
25

26. NORTHWEST TERRITORIES
ALBERTAB.C.
Edmonton
Calgary
Peace River High
Charlie Lake
Deep Basin
Core Area
Alta. Deep Basin
Alta./NEBC
Resource Plays
Alta./NEBC
Resource Plays
Alta./NEBC
Resource Plays
Central Alberta
Devonian Oil
Western Canadian Sedimentary Basin
Selected Exploration & Production Opportunities
Tourmaline
Lands
NEBC
Montney
Gas
Condensate
Adapted from Canadian Society of
Petroleum Geologists Publications
Peace River High
Charlie Lk. Oil.
26

27. Deep Basin Historical Production/Reserves
(Remaining Cretaceous Potential)
Total Cumulative Production to Date ~9.1 Tcf (May 2012)
Remaining Reserve Potential ~16.5 Tcf (Aug 2009)
(Vertical Wells only)
Add 1 hz well per section ~ 36.6 Tcf (2012 est)
Utilization of multi-zone completions will improve per well
recoveries beyond the historical averages utilized in this analysis.
(2.0-3.0 bcf vs. 1.6 bcf). Assumed horizontal wells recover 3.5
bcf/well.
Area Analysed
Grande Prairie
Grande
Cache
Hinton
Whitecourt
Numbers behind the scene
 9200 gas wells, in 160 Twps.
 Average U.R.R. of 1.6 Bcf/Well
(single and dual zone completions)
 Equalling approx 8.1 Tcf. currently
produced.
 ~15 Tcf Total U.R.R.
 Using 4 Wells/Section over the Area
 An additional 5600 gas wells
 Equalling approx. 9.0 Tcf. U.R.R
The Alberta Deep Basin is one of the largest sweet gas provinces in the world. The unique geologic setting offers multiple, stacked
opportunities in a concentrated geographic area; 10-15 stacked tight gas sands exploited vertically, gas/carbonate targets
exploited horizontally, hybrid shale silt plays to be exploited horizontally.
5 Year Production Potential 5.0(+) BCF/D
*Contingent on natural gas price performance
27

28. Jan 2014
Alberta Deep Basin Development Summary
Cardium
Viking
Mannville/Notikewin
Falher
Cadomin
Dunvegan
Nikinassin
Bluesky
Gething
Wilrich
Gething
Depositional Seismic TOU Vertical Horizontal Wells/
Environment Mappability Completions Completions
(7 Geologists) (3 Geophysicists) (6 Pete Engineers, 4 Ops Engineers)
Widespread/Shallow Partial 72 14
Marine
Marine Bars/Channels Partial 58
Marine Bars Limited 28
Channels Full 70 20
Channels Full 72 12
Shoreline Sands Partial 50 60
Shoreline Sands, Partial 22 1
Bars
Fluvial Channels Partial 26 1
Widespread/ Occasional 69
Braid Plain
Tourmaline has 3,150 vertical locations and 3,650 hz locations in inventory.
28

29. North East BC Montney Water Management
May 2013
• Non-potable water sourced lined reservoir for frac operations (2 non-freshwater wells)
• Separate water pipeline system to existing and future pads.
• Frac water pumped to pads for fracs and returned to reservoir on well clean-up.
• Eliminates surface water/groundwater requirements, reduces completion costs ($250K/well),
eliminates trucking, etc.
29

30. Improving Montney Performance/
Efficiency History (More for Less)
0
5
10
0
5
10
15
20
Initial DDV Mntn Wells 2010 Tourmaline 2011 Tourmaline
Drill/CompleteCost($M)
InitialProductionRate(mmcfpd)
Montney Performance/Efficiency History
(Duvernay/Tourmaline)
Initial Production Rate (mmcfpd) Drill/Complete Capital Cost ($M)
30

31. Sept 2013
Tourmaline Gas Plant
Growing a 50,000 bpd Liquids Business
NEBC Montney
• Current Cond/ngl (09/13) 3,500 bpd
• 2014 Sunrise ESC 2,500 bpd
• 2016 C2+ Opportunity 7,500 bpd
Southern Deep Basin Deep Cut
• 2016 C2+ Opportunity 9,500 bpd
The Regional Charlie Lake oil resource play and the ngl/condensate projects in all
three core EP areas provide the opportunity to grow to 50,000 bpd within 3 years.
Spirit R./Peace R. High Trcl Oil
• Current Spirit R .Oil Prod Capability 6,000 bpd
• 2H 2014 Est Total Peace R. High Oil Prod 10,000 bpd
• 2016 Total Oil Prod Opportunity 20,000 bpd
• 2H 2014 Spirit R. ESC (C3+) 2,500 bpd
• 2016 C2+ Prod Opportunity via Assoc. 10,000 bpd
Gas Deep Cut
Wild River/Saturn Deep Cut Participation
• Q4 2013 S1 C2+ Prod 1,500 bpd
•2H 2015 S2 C2+ Est. Prod 9,500 bpd
Total Liquid Prod. Outlook
• Est 2013 Exit 13,000-13,500 bpd
• Est 2014 Exit 22,000-25,000 bpd
• Est 2015 Exit 35,000-37,000 bpd
• 2H 2016 Potential 50,000-70,000 bpd
(Incl. Deep Cuts)
31

32. The Golden Age of Gas?
 Technological change and low prices have dramatically improved the efficiency of the remaining
Natural Gas Business.
 Natural Gas is the logical ‘bridge’ energy source for the next 2-3 decades.
 Plentiful, clean, economic.
 North American (and Worldwide) demand is growing rapidly.
 Coal to gas switching for electric generation.
 Natural gas in the transportation sector (truck fleet).
 A relatively cheap, gas fueled Industrial Renaissance?
(Inexpensive feedstock for Chemical Industry, lower fuel costs for Manufacturing, etc)
 Worldwide LNG business expansion will create a truly Global commodity.
 Canadian gas will receive world price later this decade.
 Replacement of coal, oil and gasoline with natural gas presents the largest Global C02 emission
reduction opportunity.
32

33. Forward Looking Statement Advisories
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 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; the Company's future general and administrative expenses; and
the Company's expectations regarding having adequate human resource staffing.
33

34. 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; 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 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 Annual Information Form.
Included in this presentation are estimates of the Company's 2014-2018 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 2014 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 2014 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 "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 Statement Advisories
34

35. 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.
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-IFRS 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 any standardized meaning prescribed by International Financial Reporting Standards ("IFRS"). Management believes
that in addition to net income, cash flow and net debt are useful supplemental measures as they are a measure of a company's ability to
generate the cash necessary to repay debt or fund future growth through capital investment. 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. The method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to
similar measures used by other companies. 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).
35