Tangle Creek Corporate Presentation - Global Banking … · uncertainties inherent in estimating...
Transcript of Tangle Creek Corporate Presentation - Global Banking … · uncertainties inherent in estimating...
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This presentation contains "forward-looking statements" including estimates of future production, cash flows and reserves, business plans for drilling and exploration,
the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based and related sensitivity analyses, and other expectations,
beliefs, plans, objectives, assumptions or statements about future events or performance (often, but not always, using words or phrases such as "expects" or "does not
expect", "is expected", "anticipates" or "does not anticipate", "plans", "estimated" or "intends", or stating that certain actions, events or results “may", "could", "would",
"might" or "will" be taken, occur or be achieved). In particular, this presentation contains forward-looking statements pertaining, to the following: Tangle Creek Energy
Ltd.’s (“Tangle Creek” or the “Company”) 2015 and 2016 production outlooks and cash flow forecasts; the Company’s 2016 capital budget, as well as drilling and
development plans and the timing and costs thereof; the Company's expected capital spending flexibility and ability to take advantage of available opportunities; the
ability of the Company to maintain its balance sheet strength; type well economics and performance; drilling inventory; estimated recycle ratios; the anticipated impact
of waterflood activities; the timing and cost savings associated with planned infrastructure; resource upside opportunities available to the Company; the possible upside
and the liquid expectations at the Company’s new Mannville play; and the ability of the Company to manage the current low oil price environment.
Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions,
that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. There are numerous
uncertainties inherent in estimating crude oil, natural gas and NGL reserves and the future cash flow attributed to such reserves. The reserve and associated cash
flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve
recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and
future operating costs, all of which may vary materially. Actual reserve values may be greater than or less than the estimates provided herein.
All forward-looking statements are based on Tangle Creek’s beliefs and assumptions based on information available at the time the assumption was made. Tangle
Creek believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to
be correct and such forward-looking statements included in this presentation should not be unduly relied upon. By their nature, such forward-looking statements are
subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated,
expressed or implied by such statements. In addition, risk factors include: financial risk of marketing reserves at an acceptable price given market conditions; volatility
in market prices for oil and natural gas; delays in business operations, pipeline restrictions, blowouts; the risk of carrying out operations with minimal environmental
impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are
interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at a reasonable cost;
uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things,
capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of
acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance;
fluctuations in foreign exchange and interest rates; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions;
uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk;
and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry. These risks and uncertainties could cause
actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements. The impact of any one risk, uncertainty or
factor on a particular forward-looking statement is not determinable with certainty as these are interdependent.
Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Tangle Creek assumes no obligation to update forward-
looking statements should circumstances or management's estimates or opinions change. Certain information contained herein have been prepared by third-party
sources. The information provided herein has not been independently audited or verified by the Company.
Forward Looking Statements
Tangle
Creek
Team
Building
The
Business
Founding Team of 7 Experienced Business Builders 12 full-time + 5 part-time & consultants + 10 field
Technical team - experienced with emerging technologies
5 years building Tangle Creek
Tangle Creek Energy Ltd. incorporated November 2010 - initial
equity raise completed March 2011
Equity invested of $185 million – 22 shareholders
ARC Financial & Camcor – longest standing energy PE firms in
Canada
Tangle Creek Corporate Profile
Business
Plan
Light tight oil & liquids rich gas
Candidates for emerging tight rock technologies
High margin – low risk – development opportunities
Operatorship, high working interests
Concentrated assets, material land positions & drilling inventory
Growth through combination of acquisitions & drilling
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5
Board of Directors
Jim Pasieka Glenn Gradeen
CEO
Camcor Partners Inc.
Cam McVeigh
Tangle Creek Energy
Lauchlan Currie
ARC Financial Corp.
Chairman
Dan Botterill
P.Eng.
Independent Director
Larry M Jones
Independent Director
McCarthy Tétrault
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Executive Team
Glenn Gradeen
Greg Kondro
Alison Essery Cam Virginillo
John Pantazopoulos
Berkana, Rosetta, Ocelot
Rosetta, Ocelot
Conoco-Burlington, Shell PetroBakken, Berens
Enerplus
EnCana, Berens, Skywest
Chief Executive
Officer
Vice President
Production
Vice President
Exploration
Vice President
Engineering &
Chief Operating Officer
Chief Financial
Officer
Steve Holyoake
Vice President,
Drilling & Completions
Petro-Reef, Terra
Mike McGeough
Berens, MarkWest
Vice President
Land
In November 2014, with the onset of weakening commodity prices, we established a
corporate strategy that presumed longer term weakness in oil & gas prices and the
opportunity to position the company for the future.
Our focus since the beginning of 2015… Protect the balance sheet & keep debt to cash flow at 2x or less – even in the face of weak pricing
Maintain financial strength and flexibility
Production – “pause” on continued growth Develop and strengthen relationships with equity providers
No drilling until Q4 2015 – preserve high value, high quality Dunvegan drilling inventory
Shut in high margin/low royalty/high performing wells – wait for improved prices
Focus on preserving & improving operating margins through reductions in costs – especially “structural”
changes: e.g. trucking, sales pipelines, improved processing, improved technologies, better efficiencies
and third party processing & handling
Maintain flexibility to acquire assets – in a prolonged weak price environment opportunities happen
Develop and strengthen relationships with equity providers
Position the company for future growth
Add new grassroots opportunities
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Tangle Creek Energy Ltd. – Dealing with Uncertainty
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Tangle Creek – Corporate Strategic Positioning
Efficient and Effective Light Oil Producer Best in class FD&A and Recycle Ratios
Capital costs driven down 50% BEFORE 2015 price adjustments by service companies
Proven Organic Growth Capacity 1st to identify & implement Kaybob Dunvegan horizontal technologies – including new drilling and
completions applications and EOR
Kaybob grown from 0 to 4,000 boe/d in 3 years – 75% light sweet crude with over 450 mmbbls OIP on
Tangle Lands
Most active, experienced Dunvegan oil operator
Grassroots Liquids Rich Opportunity Identified & Captured 66 net sections acquired with material liquids rich gas potential – estimating 30 to 60 bbls/mmcf
150+ potential net locations identified
Opportunistic Acquirer With Strong Balance Sheet Since inception, completed $130mm in acquisitions while keeping debt / cash flow under control
Over $50mm in 2015 including undeveloped land
69 net light oil sections in Kaybob acquired through 30 separate transactions
Counter cyclically acquired 80 net sections on two plays in 2015
Production – 2016 Forecast ~ 3,800 boe/d (70% light oil)
• Production Margins (Field Netbacks - before hedging, G&A, E&E, interest)
2014 Operating netback of $53/boe
2015 Operating netback ~ $24/boe (forecast before hedging)
• 90%+ operated production
2016 Cash Flow forecast ~ $25mm (strip) - $0.13/share
Reserves - 18mmboe (Jan 2016) – 75% light sweet crude (36°API)
Land – 135 net sections
Corporate historic FD&A - $20/boe (includes July 2015 acquisition & FDC)
2016 CAPEX ~$17mm • Maintain production of 3,800 – 4,000 boe/d
• Delever balance sheet to < $50mm of debt (target – 2.0x debt / cash flow)
Strategic use of hedges to support capital expenditures • 1,300 bbls/d Fiscal 2016 @C$72 / bbl (60% of production)
• 5.25 mmcf/d Fiscal 2016 @ C$3.00 / mcf (60% of production)
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Tangle Creek Energy Ltd. – Operations Snapshot
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Tangle Creek Energy Ltd. – Cash Flow Secured to Pursue CAPEX Program
-$10.0
-$5.0
$0.0
$5.0
$10.0
$15.0
$20.0
$25.0
$30.0
$35.0
$10.00 $15.00 $20.00 $25.00 $30.00 $35.00 $40.00 $45.00 $50.00 $55.00
C$
mm
US$ / bbl
Tangle Creek Energy Ltd. Forecasted Cash Flow
Hedging Gain Non Hedging Cash Flow
2016 CAPEX
Sustained production growth
17% CAGR on a production / debt adjusted share basis
27% annual cash flow growth (Strip pricing)
~40% of 2016 crude oil hedged at > C$70 / bbl
2015 CF $34mm - 2014 CF - $67mm
Q4 2015 debt - $60mm ($100mm credit line)
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Tangle Creek – Historic Performance
1,245
2,772
3,931 3,800
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
2012 2013 2014 2015E
bo
e/d
Production
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18 18 18
0
2
4
6
8
10
12
14
16
18
20
2012 2013 2014 2015
P+P
Res
erve
s (m
mb
oe)
Reserves
$15
$38
$67
$34
$0
$10
$20
$30
$40
$50
$60
$70
$80
2012 2013 2014 2015E
Cas
h F
low
($
mm
)
Cash Flow
Concentrated – High Interest Asset Base – Two Projects
Balanced Asset Base Single operating area on Hwy 43
between Edmonton & Grand Prairie
Excellent access & infrastructure
Balanced between solid cash flow
base & undeveloped lands
1. Kaybob Dunvegan
Light sweet crude oil – 36°API
3,500 – 3,700 boe/d – 90% operated
69 net sections – 90 net wells
Ownership of key infrastructure
120 to 200 net locations at 4 to 6
wells/section
450+ mmboe OOIP on Tangle Lands
Waterflood project commenced Q1
2015 – Preliminary results
encouraging
2. Windfall Mannville
Multi-zone liquids rich
66 net sections
2 wells drilled – 2-4 follow-up
locations in H2 - 2016
150 net locations identified
Estimating 2 to 5 BCF per location
Kaybob Dunvegan
TCE Dunvegan Lands – 450 mmbbls OIP
111 (69 net) sections
Company Interest 2P Reserves @ July 31, 2015
= 22 mmboe
~3,800 boe/d in 2015
~90 wells
Windfall Mannville
TCE Lands – 67 (66 net) sections
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Well established oil
project – initial proof of
concept and
development by Tangle
Creek in 2011
High margin, high quality
project – close to
services and
infrastructure in
Whitecourt, Fox Creek,
Edmonton and Grand
Prairie
Tangle Creek Dunvegan
wells have often been
reported as among the
top oil wells in Alberta (Industry Research by Scotia
Capital, AltaCorp, National
Bank and others)
Kaybob Dunvegan – Light Sweet Crude Oil
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Tangle Creek – Dominant Dunvegan Light Oil Position
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TCE Internal Locations (195 Gross)
8 Tier 1 – High Type Curve
48 Tier 2 – Base Type Curve
139 – Tier 3 & 4 Low Base and
Gassy Type Curve
Existing Dunvegan Hz Wells
64 (55.9 net) Operated Wells
28 (7.8 net) non-Operated
Tier 1 Tier 2 Tier 3 Tier 4 TTL
Gross 8 48 126 13 195
Total Net 8.0 38.2 76.0 6.6 128.8
Total Locations 128.8
Already in SAL Dec 31 Report 24.6
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Dunvegan Stratigraphy – Kaybob South
Dunvegan
Carbonates
Dunvegan vertical depth is 1,600 to 1,800 m at Kaybob Total hole length is typically 3,000 m to 3,400 m
Drill times are 9 to 11 days
Adapted from Canadian Discovery Digest
0
1,000
2,000
3,000
4,000
5,000
6,000
2011 - DRILLED & NONOP WELLS 2011 - ACQUIRED WELLS 2012 - DRILLED WELLS 2012 - ACQUIRED WELLS
NIPISI 2013 - DRILLED WELLS 2013 - ACQUIRED WELLS 2014 - DRILLED WELLS
2014 - OTHER 2015 - DRILLED WELLS 2015 - ACQUIRED WELLS
Dunvegan Drilling Vintages – Wells with 2 to 3 years History are down to ~20% declines
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2014 Drilling
2013 Drilling 2012 Drilling
2011 Drilling
3rd Party
Solution Gas
Processing
Restriction
Solution Gas
Take-away
Restriction 2015
Acquisition
0
50
100
150
200
250
300
350
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Bb
ls/d
Month
Tier 1 Dunvegan Type Curve Tier 2 Dunvegan Type Curve
Dunvegan Type Curves - Half Cycle Economics (capex $2.5mm/well)
Note: Y Axis is oil – for boe/d add 25%
US$70 Oil, C$3.00 gas Strip Flat US$50 / C$2.50
Oil
(mbbls) Total
(mboe) NPV 10 IRR NPV 10 IRR NPV 10 IRR
Tier 1 225 300 $5.0mm 162% $4.1mm 90% $2.9mm 68%
Tier 2 175 230 $3.2mm 65% $2.6mm 42% $1.6mm 31%
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EUR
Type
Curve
boe/d Oil Gas
IP30 IP365 mboe mbbls mmscf
Tier 1 400 180 300 225 400
Tier 2 200 110 230 175 300
$0
$1,000,000
$2,000,000
$3,000,000
$4,000,000
$5,000,000
$6,000,000
$7,000,000
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Continuous Improvement of Operations - Decreasing Per Well Capital Costs
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Avg. Capital Cost / Well 1st Five Operated Wells $4,769,293
H2 2015 Operated Wells (8) (excluding SWF) $2,762,000 Most Recent Five Operated Wells (excluding SWF) $2,512,000
Completion
and lease
issues (3)
SWF wells
(5)
2. New Mannville Liquids Rich Development Opportunity
67 (66 net) sections of land acquired through land sales and transactions with industry
participants
As in the Dunvegan, rock work has been key. Area has had hundreds of vertical
penetrations to deeper targets over 50 years of industry activity
Dozens of cores analyzed and hundreds of cutting samples inspected from previously drilled
wells prior to land capture to ensure high-grading of opportunity
Main targets are Lower Mannville braided fluvial systems and tidal sands (calibrated to core
interpretation)
Expect liquids - rich gas based on older vertical production in the region – initial locations
offset vertical wells that produced or tested oil
Multi-zone Potential
Secondary zones in Gething , Notikewin, Viking, Ostracod and Rock Creek
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Brackish Bay
Fluvial
Braidplain
Tidal Bar
Stacked Reservoirs 5-20m of 6-20% porosity, 1-15md
tighter conventional deep basin
reservoirs
Gas in Place 7-12 BCF/sec (based on
7m @ 12% porosity & 14m @ 9%)
Main Lower Mannville Targets Chert-rich (low resistivity) Braidplain
(Yellow) deposited as a sheet over
area of interest
Tidal Bars (Orange) tidal bars in
brackish bay
Secondary Mannville Targets Gething channels (Brown). Good
reservoir quality with limited
distribution.
Notikewin channels. Existing
horizontal production.
Windfall Mannville – Stacked Reservoir Opportunity
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Lwr Mann_2
Lwr Mann_1
Mannville Economic Detail at Strip Pricing
Two test wells drilled in Q4 – 2015 -
followed up by 4 or more wells in 2016
Liquids yields on both wells exceeded type
curve estimates
Single well economics of play
satisfactory - drilling & completions
refinements to drive down CAPEX / well
and delineation will identify sweet spots Economics assume 3rd party processing
and improve with construction of gas plant
Dunvegan capital costs / well reduced 48%
in 3 years – expect Mannville to be $3 to
$3.5mm in time
Dunvegan initial economics based on IP30
= 200 and IP 365 = 110 boe/d – 85% of
Dunvegan development has IP30 = 465 and
IP365 = 192
Scope and position for future
development
TCE Mannville Low Liquids Type Curve
TCE Mannville "High Liquids"
Type Curve
Capital Cost ($mm) $3.5 $3.5
Reserves
Oil and NGLs (mbbls) 85 115 Nat Gas (mmcf) 2,500 1,700 Total (mboe) 500 400
% Oil and NGLs 17% 29%
NPV - 10% - $mm $0.6 $1.0 P/I - 10% Discount 1.1x 1.3x
Rate of Return 17% 29%
IP 30 (boe/d) 593 474 IP 365 (boe/d) 375 300
F&D Cost / $ / BOE $6.96 $8.72
F&D Cost / $/BOE/D $9,333 $11,667
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Mannville Type Curves – Current Environment Half Cycle Economics (capex $3.5mm/well)
-
100
200
300
400
500
600
700
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
BO
E/D
Month
High (60 bbl/mmcf) Mannville Type Curve Low (30 bbl/mmcf) Mannville Type Curve
US$70 Oil, C$3.00 gas Strip Pricing US$50 / C$2.50 gas
Liquids (mbbls)
Total (mboe) NPV 10 IRR NPV 10 IRR NPV 10 IRR
Liquids Rich (60bbls/mmcf) 115 400 $1.6mm 36% $1.0mm 29% $0.0mm 10%
Low Liquids (30bbls/mmcf) 85 500 $1.1mm 27% $0.6mm 17% $0.0mm 4%
EUR - 400 mboe 1.7BCF & 115 mbbls
EUR - 500 mboe 2.5BCF & 85 mbbls
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Mannville Low Liquids Type Curve – Price Sensitivities with Improved Capex ( $3mm/well)
0% 5%
11%
17% 24%
30%
36%
43%
51%
55%
66%
75%
84%
94%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
$40 $45 $50 $55 $60 $65 $70 $75
Rat
e o
f R
etu
rn
US$ / bbl WTI
Rate of Return - $3mm per Well CAPEX
C$2.00 / mcf Nat Gas C$3.00 / mcf Nat Gas C$4.00 / mcf Nat Gas
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2016 Operating and CAPEX Budget – Maintain Reserves and Balance Sheet
Modest 2016 CAPEX budget to maintain production while deleveraging balance sheet
70% of Cash flow spent on CAPEX – 10% Increase in production YoY (US$37.50 / bbl)
24 24
Proforma Analysis
Fiscal 2015 Q1 - 2016 Q2 - 2016 Q3 - 2016 Q4 - 2016 Fiscal 2016
Production (Boe/d) 3,529 3,834 3,840 3,858 3,850 3,845
% Liquids 59.9% 64.0% 63.7% 61.9% 61.0% 62.6%
Liquids (bbls/d) 2,115 2,456 2,445 2,388 2,348 2,409
Revenue (Before Hedging) $57,311,000 $10,107,645 $10,400,290 $10,295,848 $10,167,735 $40,971,518
Revenue (After Hedging) $62,086,890 $13,270,908 $13,125,327 $12,979,198 $12,851,085 $52,226,519
Field NOI $34,962,712 $4,946,005 $5,232,841 $5,076,440 $4,994,130 $20,249,416
CF From Ops $32,975,388 $6,312,439 $5,976,941 $5,933,274 $5,952,212 $24,174,866
CAPEX $70,747,001 $8,250,000 $0 $3,000,000 $5,500,000 $16,750,000
CAPEX (excluding acquisitions) $25,697,001 $8,250,000 $0 $3,000,000 $5,500,000 $16,750,000
Quarter End Debt (exc MTM) $59,795,384 $61,732,946 $55,756,005 $52,822,730 $52,370,518 $52,370,518
Quarter End Debt / Annualized CF 1.81x 2.44x 2.33x 2.23x 2.20x 2.17x
Share Count / Equity Drawn 172,737,336 180,474,672 180,474,672 180,474,672 180,474,672 180,474,672
Annualized CPFS $0.191 $0.140 $0.132 $0.132 $0.132 $0.134
2016 Cash Flow Forecast – Hedging Gains
Hedges provide “certainty” to 2016 cash flows which support continued capital program
during period of commodity price weakness
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$0.0
$5.0
$10.0
$15.0
$20.0
$25.0
$30.0
$35.0
$20.00 $25.00 $30.00 $35.00 $40.00 $45.00 $50.00 $55.00 $60.00
Fisc
al 2
01
6 C
F (C
$m
m)
US$ / bbl
Hedging Gain Non Hedging Cash Flow
2016 CAPEX
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OPEX – Top Decile Among Liquid Peers
$11.25
$0.00
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
VII TCE RRX TVE SKX BTE MQL PGF RE TOO PWT MEI SPE AEI ZAR SOG
OPEX / BOE - Liquids Producers Fiscal 2016 (NBF Research)
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Cash Flow - Top Decile Among Peers
$18.84
$0.00
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
SOG PMT MEI CKE ZAR PNE PWT PGF CQE BBI MQL TOO BXE POU CR AEI PPY KEL SRX TET DEE BTE NVA BIR RE AAV VII TVE SKX RMP LXE TCE SPE RRX
CF / BOE - All Producers Fiscal 2016 (NBF Research)
Solid Margins - at 2016 strip pricing - annual CF stable at $25mm
Low cost structure ensures sustainable – cash costs ~C$16.50 / boe
Shipper on Alliance (firm service) and firm on Pembina (liquids) – unique among juniors
Disciplined - CAPEX less than cash flow – demonstrate growth at strip pricing but debt /
cash flow remains ~2.0x through end 2016
Production Growth – Modest production growth in 2016 while CAPEX < cash flow as
declines begin to approach 20% / annum
IRR / NPV Positive Drilling – Drilling inventory economic at today’s prices
Upside Exposure & Optionality – an increase in WTI to US$50 / bbl increases cash
flow to $30mm ($0.17 / share) with Debt / CF of <1.7x by Q4 – 2016
Opportunity to accelerate drilling, increase production, add to reserves and grow cash flow
Continued Positioning – combination of organic growth and opportunistic
acquisitions positions the company for the future while delivering value creation in a
tough environment
The Vision – A Look Into 2016 / 2017
28
Logo
Placement
TANGLE CREEK ENERGY
Contact:
Tangle Creek Energy Ltd Glenn Gradeen
CEO d: +1 (403) 648-4901
m: +1(403) 618-0434
1400, 715 – 5th Ave S.W.
Calgary, AB T2P 2X6
John Pantazopoulos
CFO d: +1 (403) 648-4903
m: +1(403) 828-8084