corporate presentation september 2018...r26 r24 r22 r20 r18 r16 r14 r12 r10 r3 r1w6 r9 r7 r5 current...
TRANSCRIPT
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
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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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