Tangle Creek Corporate Overview
December 2016
Tangle Creek Overview
Company Summary
 Tangle Creek Energy Ltd. is a fully integrated, private energy company differentiated by high margin, light,
tight oil & liquids rich natural gas development in central Alberta
 Tangle raised its initial capital in late 2010 & early 2011 and commenced operations in 2011
 A total of $185mm of equity capital was raised at prices from $0.70 to $1.25/share
 Growth from 0 to 4,000 boe/d and 19 mmboe of reserves was primarily through the drill bit & acquisition of
partner interests after de-risking
 The Company acquired Beringer Energy in August 2016 adding 1,500 boe/d, 12 MMboe of reserves &120 net
sections of undeveloped land
 The Company is backed by top-tier sponsors including ARC Financial and Camcor
Board of Directors
Capitalization and Operating Summary
Capitalization
As of Sept 30, 2016
Basic Shares Outstanding
MM
226
Current Net Debt
$MM
$60
Oct Strip
Operating Metrics
2014
2015
2016E
2017F
Production (Oil & NGL)
bbls/d
2,923
2,582
2,632
3,177
Nat Gas
Mcf/d
6,050
6,527
10,252
16,554
Total Production
boe/d
3,931
3,670
4,163
5,936
Cash Flow
$MM
$67
$34
$26
$39
CAPEX
$MM
$62
$71
$25
$40
Period End Debt
$MM
$43
$60
$69
$61
CFPS
$/sh
$0.40
$0.20
$0.13
$0.17
Field Netback
$/boe
$50.95
$26.11
$18.16
$23.55
Corporate Netback
$/boe
$46.73
$30.13
$22.47
$22.11
2
Executive Team - Introductions
Chief Executive
Officer
Vice President
Exploration
Vice President
Engineering &
Chief Operating Officer
Chief Financial
Officer
Glenn Gradeen
Alison Essery
Cam Virginillo
John Pantazopoulos
Berkana, Rosetta, Ocelot
Conoco-Burlington, Shell
Vice President
Production
Greg Kondro
Rosetta, Ocelot
PetroBakken, Berens
Home Oil
Vice President
Land
Mike McGeough
Berens, MarkWest
Petro-Reef, Terra
Vice President,
Drilling & Completions
Steve Holyoake
EnCana, Berens, Skywest
3
Corporate Operating Snapshot
 Production (Q4 2016)
5,000 boe/d (53% liquids)
 Cash Flow (Q4 2016 Annualized – US$46 oil Post Pembina/Alliance)
$26 million

Forecast 2017
 Net Debt (Sept 30, 2016)

Forecast to Dec 31, 2016
($0.13/sh)
• $35 - $40mm
$60 million
(2) (2.2x CF)
• est. $69mm (1.7x 2017 CF)
 Bank Line
$100 million
 P + P Reserves (Jan 1 2016 – combined SAL & GLJ)
31 mmboe (60% light oil & ngls)

Est Dec 31, 2016 (see Appendix)
 Total Land

• est. 29 – 32 mmboe
346 (265 net) sections
Undeveloped Land
257 (204 net) sections
 Net Drilling Locations – economic at current strip
90+
 2016 Capital Program
$25 million

2017 Capital Forecast
 Corporate FD&A (Tangle + Beringer basis Dec 31, 2015 reserves)


2016 Operating Netback (prior to hedging – realized & strip)
2016 Corporate Netback (realized, strip & current hedges)
(capex<cash flow)
• $35-$40 million (capex=cash flow)
$17/boe (includes FDC)
$18/boe
$22/boe
(1) Date of strip pricing, Dec 13, 2016, 2016
(2) Excludes ELOC available of $9.7mm
4
Tangle Creek – Corporate Milestones
Technical, focused team
Dec 2010 – Formation
of Tangle Creek
 Track record of building successful energy businesses
2011
 Special expertise in tight rock reservoirs – recognize that
rock & geology matter
 Focused on profitability – building a “bullet-proof” business
Q4 2011 – Initial
Kaybob test well
2012
• Expertise in growing production volumes, top decile operating
2012 – Proof of
concept and Kaybob
development
margins and maintaining strong balance sheet
 Kaybob Dunvegan –
• Initial hunt for tight oil candidates for horizontal multi-stage
•
•
•
•
technologies
Extensive rock work, petrophysical work & interpretation of
depositional environments - Kaybob Dunvegan was top candidate
Several 5-15 year old vertical completions confirmed oil potential
21 section TLM farm-in and first test well at 12-16-60-17w5 resulted
in 1,000 bopd test rates and confirmation of economics
Concurrently with initial drill program - sourced and undertook over
20 additional land deals to “own the play”
 “Best in Class” operator – a complete full service team
• 1st
• 1st
•
•
to drill multistage horizontal on Dunvegan Oil Play
approval for Dunvegan water flood
st
1 approval to increase well density – up to eight wells per section
1st Dunvegan slick-water completion
 Large land base & proven oil property – in a desirable area
 In 2016 expanded into Windfall – Mannville LRG play and
acquired Beringer Energy Inc.
Q1 2011 – Initial
Capitalization @
$1/share
2013
2013 – New equity @
$1.25/share and
acquisition of TLM
Dunvegan assets
2015 – New equity @
$1.25/share and
acquisition of Trilogy
Dunvegan assets.
Drilling of Windfall test
wells
2014
2014 – Organic
Production Growth to
5,000 boe/d
2015
2016
2016 – Operational
Improvements
including completions
and waterflood –
initial development at
Windfall
2016 – Corporate
acquisition of
Beringer Energy
&
New ELOC negotiated
for ~$10mm
2016 – 2017
Positioning with
merger or major
acquisition
5
Operating Area – West Central Alberta
130 net sections at
Kaybob / Windfall
Kaybob
Ft. McMurray
Windfall
Grande Prairie
Edmonton
Calgary
6
 Operating area –
Between Highway 43
& Hwy 16 between
Edmonton & Grande
Prairie
Windfall
Carrot Creek
120 net sections
at Carrot Creek
6
Single Well Economics – Play Ranking 180+ Locations (90+ economic)
Locations
20+ (net)
Plant Gate Nat Gas
(C$ / mcf)
$20.00
Gas Plant
construction
(Windfall) and slick
water facing on Tier
3 wells (Kaybob) to
generate 50%-60%
returns
5.6%
18.0%
29.3%
41.5%
54.5%
Plant Gate Nat Gas
(C$ / mcf)
MRF - Carrot Rock Creek Oil
IRR
US$ / bbl
$20.00 $30.00 $40.00 $50.00
$60.00
$1.00
19.1%
29.7%
$1.50
13.3%
22.3%
33.2%
$2.00
16.3%
25.5%
37.0%
$2.50
19.3%
28.9%
40.9%
$3.00
10.1% 22.4%
32.4%
44.7%
$3.50
13.0% 25.5%
35.7%
48.6%
$4.00
15.8% 28.7%
39.3%
52.5%
Locations
20+ (net)
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
MRF - Tier 2 / 4 Dunvegan ($2.1mmcapex)
IRR
US$ / bbl
$20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $80.00
32.1% 54.8% 93.5% 120.8% 149.1%
33.5% 56.6% 95.9% 123.6% 152.3%
34.9% 58.4% 98.2% 126.4% 155.5%
36.4% 60.2% 100.7% 129.2% 158.7%
12.6% 37.9% 62.0% 103.1% 132.0% 161.9%
13.8% 39.3% 63.9% 105.5% 134.9% 165.1%
15.0% 40.8% 65.7% 108.0% 137.7% 168.4%
Locations
20 (net)
$80.00
47.5%
61.8%
78.8%
95.6%
113.5%
134.8%
154.8%
Locations
8 (net)
Plant Gate Nat Gas
(C$ / mcf)
Average prospect 50% to 60% of
these improved
through newer
drilling and
completion
practices & 1 mi vs
½ mi laterals
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
MRF - Windfall Mannville - TCE Gas Plant
IRR
US$ / bbl
$30.00 $40.00 $50.00
$60.00
$70.00
10.1%
19.4%
29.9%
40.0%
9.1% 22.0%
31.6%
42.9%
54.4%
21.1% 34.3%
44.8%
57.5%
70.0%
33.3% 47.8%
59.4%
73.2%
86.5%
45.9% 61.6%
74.4%
89.1%
104.0%
59.7% 77.1%
90.4%
106.7%
122.6%
74.4% 93.1% 107.8%
125.2%
141.8%
Plant Gate Nat Gas
(C$ / mcf)
12.9%
15.3%
17.7%
20.0%
$80.00
487.4%
499.2%
511.1%
523.2%
534.9%
546.8%
558.8%
Plant Gate Nat Gas
(C$ / mcf)
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
Locations
47+ (net)
$20.00 $30.00
$1.00
4.6%
$1.50
8.9%
$2.00 3.0% 13.5%
$2.50 7.4% 18.3%
$3.00 11.6% 23.3%
$3.50 16.1% 28.7%
$4.00 20.8% 34.6%
MRF - Carrot Gething
IRR
US$ / bbl
$40.00 $50.00 $60.00
14.3% 22.8% 33.9%
19.3% 28.5% 40.6%
24.7% 34.8% 47.8%
30.5% 41.5% 55.5%
36.6% 48.4% 63.5%
43.1% 55.9% 71.9%
50.1% 63.7% 80.8%
$70.00
45.9%
53.6%
61.8%
70.5%
79.4%
88.8%
98.6%
$80.00
54.9%
63.3%
72.2%
81.5%
91.0%
101.1%
111.5%
MRF - Pembina Rock Creek Oil
IRR
US$ / bbl
$20.00 $30.00 $40.00 $50.00 $60.00 $70.00
$1.00
14.7% 24.4% 34.3%
$1.50
17.1% 27.0% 37.4%
$2.00
19.4% 29.7% 40.6%
$2.50
21.9% 32.5% 43.6%
$3.00
3.7% 15.5% 24.4% 35.2% 46.8%
$3.50
6.1% 17.8% 26.8% 38.2% 50.0%
$4.00
8.4% 20.1% 29.4% 41.2% 53.3%
$80.00
41.9%
45.2%
48.6%
52.1%
55.5%
58.9%
62.4%
Locations
8 (net)
$70.00 $80.00
40.7% 48.8%
44.7% 53.7%
49.4% 58.1%
53.7% 62.5%
57.7% 67.5%
61.8% 71.8%
66.7% 75.8%
MRF - Windfall Mannville - No Gas Plant
IRR
US$ / bbl
$20.00 $30.00 $40.00 $50.00
$60.00
$70.00 $80.00
3.2%
11.1% 17.0%
4.2%
14.6%
23.5% 29.5%
8.1%
16.9%
26.7%
36.0% 43.2%
6.7% 19.2%
28.0%
38.3%
48.8% 56.7%
0.1% 17.9% 30.4%
39.7%
51.3%
62.6% 71.3%
13.5% 28.6% 42.0%
52.4%
64.9%
76.9% 86.2%
Plant Gate Nat Gas
(C$ / mcf)
$20.00
Plant Gate Nat Gas
(C$ / mcf)
Cost
reductions
have led to
significant
improvement
in well
economics
MRF - Tier 1 Dunvegan ($2.1mm capex)
IRR
US$ / bbl
$30.00 $40.00 $50.00
$60.00
$70.00
52.1% 115.4% 182.8%
304.3%
396.7%
55.2% 120.0% 188.9%
312.8%
406.8%
58.3% 124.7% 195.0%
321.4%
417.1%
61.5% 129.4% 201.2%
330.0%
427.5%
64.6% 134.1% 207.4%
338.5%
437.7%
67.9% 138.9% 213.7%
347.2%
448.0%
71.2% 143.7% 220.0%
355.9%
458.4%
Locations
72 (net)
Plant Gate Nat Gas
(C$ / mcf)
Locations
6+ (net)
MRF - Dunvegan Tier 3 ($2.1mm capex)
IRR
US$ / bbl
$20.00 $30.00 $40.00 $50.00 $60.00 $70.00
$1.00
5.9% 16.5% 27.2%
$1.50
6.7% 17.3% 28.0%
$2.00
7.5% 18.1% 28.9%
$2.50
8.2% 18.9% 29.8%
$3.00
9.0% 19.7% 30.7%
$3.50
0.2% 9.8% 20.5% 31.6%
$4.00
1.0% 10.5% 21.3% 32.5%
$80.00
34.9%
35.9%
36.8%
37.8%
38.8%
39.8%
40.7%
7
Production Adds & Drilling Vintages – Production is leveling
 Wells with 4+ years history are down to 15% declines or less
 Corporate decline is 25% to 30%
Beringer
Acquisition
3rd Party
Solution
Gas
Processing
Restriction
Solution
Gas
Takeaway
Restricti
on
2014
Drilling
2012
Drilling
2015
2016
Trilogy
Drilling
Acquisition
TCPL
Curtailment
Windfall
Shut-in
2013
Drilling
35%
Prior
12
month
25% Decline
15%
12%
2011
Drilling
8
Kaybob Asset – Operational Improvements have Enhanced Economics & drilling inventory
Kaybob Dunvegan represents the bulk of Tangle’s asset value, production & cash
flow. Focus has been on improving economics to establish a top tier asset with
significant running room:
 Capital cost reductions have been a game-changer – last two wells drilled were $2.1mm
each – all in. Four years ago cost was $4.8mm per well, better technologies, mono-bore designs,
internally designed drill equipment have all come together to reduce capital costs over and above
the economic climate. For example drill times have been reduced from 15-17 days to 8-9 days.
These are real structural changes
 Opex has been reduced by 40% by consolidating batteries, boring the Athabasca River, renegotiation trucking and third party charges and bringing field staff on the payroll
 Declines are better understood, with steep initial and long term declines down to 15% to 20%
on wells older than 30 months. Corporately we are at 30% or less including Beringer
 While Tier 1 wells were always highly economic (200%+ IRR at US$50 oil), the reduced costs
combined with better completions result in Tier 2 single well economics of 60% IRR or better
– moving these ~50 locations into top tier vis-à-vis industry
 Improving the drilling inventory. Improved hybrid slick water fracturing has opened up new
regions for moving some of the 75 Tier 3 locations into Tier 2 or better.
 Further economic enhancements are being planned with successful response on the pilot
water-flood
 This is a significant, top tier asset with considerable growth potential yet
9
OPEX – Top Decile Among Liquid Peers
OPEX / Transportation / BOE - Liquids Producers
Fiscal 2016 (NBF Research)
$30.00
$25.00
includes $2.00 Transportation Costs
$20.00
$15.00
$11.25
$10.00
$5.00
$0.00
VII
TCE
RRX
TVE
SKX
BTE
MQL
PGF
RE
TOO
PWT
MEI
SPE
AEI
ZAR
SOG10
Cash Flow - Top Decile Among Peers
CF / BOE - All Producers
Fiscal 2016 (NBF Research)
$35.00
$30.00
$25.00
$20.00
$18.84
$15.00
$10.00
$5.00
$0.00
SOG PMT MEI CKE ZAR PNE PWT PGF CQE BBI MQL TOO BXE POU CR AEI PPY KEL SRX TET DEE BTE NVA BIR RE AAV VII TVE SKX RMP LXE TCE SPE RRX
11
Ongoing Continuous Improvement #1 - Cost Improvements - A Game-Changer
 Year over year reductions in costs and improved economics driven by improved efficiencies
OPEX / Transportation ($ / boe)
$18.00
$16.04
$16.00
$14.56
45% reduction in
drill times
$14.00
$14.23
$13.69
Q4 - $1.00 / boe increase
due to Alliance Gas
Transportation
$13.63
$12.80
$12.00
$11.95
$12.18
$11.75
$11.64
$10.83
$10.51
$10.92
$11.34
$11.27
$10.79
$10.29
$10.00
$8.00
$6.00
$4.00
$2.00
$0.00
Q4 - 2011 Q1 - 2012 Q2 - 2012 Q3 - 2012 Q4 - 2012 Q1 - 2013 Q2 - 2013 Q3 - 2013 Q4 - 2013 Q1 - 2014 Q2 - 2014 Q3 - 2014 Q4 - 2014 Q1 - 2015 Q2 - 2015 Q3 - 2015 Q4 - 2015
55% reduction in
total capex/well
55% reduction in
Drilling costs
12
Operational Performance – 4+ Years History - Cost reductions = Improving economics
Tier 1 – IP 365 = 222 boe/d
(35 wells)
Tier 2 – IP 365 =117 boe/d
(23 wells)
All Wells
Tier 3 – IP 365 = 65 boe/d
(16 wells)
Type Curve Economics - MRF
Tier 1 Type Curve - $2.1mm Capex, EUR 280 mbbls oil 375 mboe
WTI
$45
$55
$65
Capital
($MM)
$2.1
$2.1
$2.1
Payout
(yrs)
0.8
0.6
0.5
IRR
(%)
161
285
460
NPV10
($MM)
$4.1
$5.6
$6.9
F&D
($/boe)
$5.75
$5.67
$5.62
Recycle Ratio
(times)
4.9
6.2
7.5
1st Yr Capital
Efficiency ($/boe/d)
$9,930
$9,930
$9,930
Recycle Ratio
(times)
2.5
3.3
4.0
1st Yr Capital
Efficiency ($/boe/d)
$17,115
$17,115
$17,115
Tier 2 Type Curve - $2.1mm Capex, EUR 150 mbbls oil 195 mboe
WTI
$45
$55
$65
Capital
($MM)
$2.1
$2.1
$2.1
Payout
(yrs)
2.2
1.4
1.0
IRR
(%)
38
67
103
NPV10
($MM)
$1.3
$2.2
$3.1
F&D
($/boe)
$11.31
$10.99
$10.81
13
Field Development Plan – Tiers 1, 2 & 4 Economic at Strip – 55 Locations (March 31, 2016)
Recent drilling and interpretation has led to the
upgrading of multiple Tier 3 wells to Tier 2
Two Tier 1 wells
drilled in
November –
reduces
inventory from 8
to 6
14
Slickwater Application – Expanding the Sweet Spots
04-30-60-18w5 – On-stream Feb
22, 2016 – Tier 3 to Tier 2 +
Tier 1 Type Curve
Tier 2 Type Curve
15-04-60-17w5 – On-stream Mar
15, 2016 - Tier 3 to Tier 2
Tier 3 Type Curve
15
Tangle Dunvegan Slickwater Application
15-04-60-17 Slickwater Frac
14-04-60-17 Foam Frac
16
Ongoing Continuous Improvement #2 - Slickwater Application – Improving Inventory
Green = Proved Undeveloped
Red = Probable Undeveloped
Orange = Uneconomic PUD
Black = Q1 2016 Drills
9 Gross (8.9 Net) PUDs
Assume Type 2 @ 195
mboe = 1.73 mmboe
4-30-60-18w5 – On-stream Feb 22, 2016
15-04-60-17w5 – On-stream Mar 15, 2016
17
Continuous Improvement #3 - Dunvegan Waterflood - EOR under MRF should be a game-changer




18 sections with 175 mmbbls OOIP
Secondary Recovery – 10-15 mmbbls
Reserves increase could reach 50% to 90%
Reserve Additions at $2.50/bbl
10-18 Injector
Conversion
 1/2 section pilot
 Good Response after 8 months
• GOR Decreasing
• Oil Rate Increasing
• No Water Breakthrough from Hz Injector
13
Windfall & Carrot Creek/Pembina – Expanding Scope to Oily & LRG Mannville/Jurassic
 Stacked Deep Basin Lower Mannville targets & upper Jurassic targets
 Oil & gas pools (‘Ostracod’, ‘Ellerslie’, Rock Creek) and secondary dry gas (Spirit
River, Bluesky, Gething)
 Detailed technical review - uncovering high potential oily opportunities
 Active drilling by Velvet and Vermillion, year-round access and good
infrastructure
 65 net sections at Windfall, 120 net sections at Carrot Creek/Pembina
 Current focus on expanding scale & scope of the plays, improving
technology applications & on cost efficiencies
Lower Mannville is 2,000 to 2,300 m deep;
typical 1 mile horizontal well legs
19
Windfall Development – 10+ Section Oily Area – 14-32 Basis
 Third well drilled at 45-58-17w5 (October
2016 – completed
Nov 2016 – initial
clean-up flow similar
to 14-32 – currently
on build-up)
 2017 plan is for two
additional scoping
wells – then a
development
including gas plant
 Drilling program and
gas plant currently
under review
 Proposed gas plant
site provides access
to either Nova or
Alliance
First well - 9-14-58-17 produces 11.5 mmcf/d of natural gas with
~200 bbl/mmcf of water
Nova and 3rd party lines
Alliance
Section 8 acquired Oct 2016
2017 locations
Nova
Third well - 4-5-58-17
Q4 2016
Proposed gas plant site
Second well -14-3257-17
2.5mmcfd sales +
180 bbl/d oil and
NGL’s
20
Windfall Development – Single Well Economics and 3 year - 10 Well Program
 3 Year development program Includes 10 wells, 10 mmcfd gas plant & infrastructure
 Current data indicates 11 low risk sections (22 wells) & additional 8 moderate risk
 Total 20 out of 65 net sections – 30% of lands currently considered prospective
MRF
SemCams Single Well
Gas Plant Single Well
10 Well/Gas Plant Project
Total Field NPV10 Ex
Capital
Strip (17-08-2016)
IRR
NPV 10
(%)
(M$C)
MBOE
Gas
(%)
605
74
12
628
6,255
74
74
68
33
High (29-08-2016)
IRR
NPV 10
(%)
(M$C)
P/I
10%
P/O
(Years)
MBOE
% Gas
(%)
148
1.0
4.9
615
74
33
4,117
25,090
2.2
1.6
1.5
3.4
631
6,298
74
74
99
50
70,719
P/I
10%
P/O
(Years)
1,839
1.5
2.4
5,819
41,652
2.7
2.0
1.2
2.8
87,281
Notes
1. Capex = 3.5 M$C/well
2. Gas Plant = $10.125M$C (including Water Disposal)
$ 45,629
3. Total Capital Cost ($m) =
3. Does not include 14-32 and 9-14 wells
4. Using modernized royalty regime
21
Carrot Creek – Acquired August 2016
 120 net sections in corporate acquisition
 Extensive owned infrastructure makes gassier asset attractive – however – focused on
oilier areas
 27.5 net locations and 11.4 net contingent locations in Lower Mannville/Jurassic
fluvial and tidal sandstones and Jurassic Rock Creek/Niton shoreface
sandstones
 Petrophysical review of Lower Mannville complete - cores and cutting samples from
area wells interpreted to ensure high-grading of locations
 Expect Lower Mannville to be liquids - rich gas based on older vertical production
in the region – initial locations offset vertical wells that produced or tested oil.
 Rock Creek will generally be oily with ½ mile laterals
 Two wells planned for Q4 2016 – three wells planned in 2017 with some contingencies
 Further Multi-zone Potential
 Secondary zones in Viking, Notikewin, Gething , Ostracod
22
Carrot Creek – Land Base / Infrastructure
Carrot Creek Land Base:
120 Net Sections
Average WI – 84%
Carrot Creek Infrastructure:
02-26-52-12 Gas Plant – 73%
10-29-53-10 Gas Plant – 100%
15 mmcf/d net capacity (40%
utilized)
Firm Service – 7.1 mmcf/d
rises to 11.5 mmcf/d in 2018
9-12-52-12
Q4 2016
23
Carrot/South-Pembina – Locations (Mannville purple; Rock Creek green). Contingent (grey)
Land Rights
Bullhead to Fernie
Rock Creek
13-16-49-11
Drilling Q4
2016
Rock
Creek
Production
Proactive Hedging Plan
 Tangle Creek maintains a proactive hedging program – 50% - 60% of 2017
physical total developed oil volumes (net of royalties) & ~65% of net gas volumes
are currently hedged through a combination of swaps and collars
 Plan to continue as production volumes increase - unhedged volumes will be
protected through regular program of layering contracts every quarter. Target is
60% to 70% of physical production
 Following table shows % of base production (current production declined)
hedged – gross – before deduction of royalties (add 5% to 10% for volumes net
of royalties)
% of Production
Hedged Q4 - 2016 Q1 – 2017 Q2 - 2017
% of Total - Crude Oil
66%
53%
49%
% of Total - Nat Gas
51%
55%
49%
Q3 - 2017
58%
49%
Q4 - 2017
58%
45%
Q1 - 2018
38%
24%
Q2 - 2018
39%
18%
Q3 - 2018
30%
12%
Q4 - 2018
30%
12%
25
A Look Into 2017
 Solid Margins - 2017 CF stable at $35 to $40mm with free cash flow above
maintenance CAPEX to grow production >10% per year

Free cash flow – can maintain current production with ~$20mm per year CAPEX

Low cost structure – (opex ~$10/boe) ensures sustainable – total cash costs ~C$17 / boe (includes opex,
transportation, G&A, E&E, interest)

Shipper on Alliance (firm service) and firm on Pembina Peace (liquids) – unique among juniors ensures lower costs,
higher realized pricing and minimal downtime due to pipeline constraints
 Disciplined - CAPEX ~ Cashflow improves liquidity & dry powder for acquisitions
 Production Maintenance – In 2016 while CAPEX ~ cash flow as declines further
reduce to 20% - 30% / annum – maintain production while not depleting inventory
 IRR / NPV Positive Drilling – Tier 1 and Tier 2 Dunvegan drilling inventory expanding
with new technologies - economic at current strip
 Hedging program – crucial to protecting cash flows and capital programs

Hedging gains funded 33% of 2016 CAPEX program allowing for modest deleveraging and growth
 Upside Exposure & Optionality – WTI price increase to US$60 / bbl increases cash
flow to $47mm with debt / CF of <1.0x by Q3 – 2017


Opportunity to accelerate drilling, increase production, add to reserves and grow cash flow
Expand Dunvegan and Evaluate Windfall
26
2016 / 2017 TCE Cash Flow – Back to Growth!
 Forecasted production of 5,900 boe/d with a “Cash flow ~ CAPEX” budget in fiscal 2017
 Liquids production remains > 50%, with majority (> 85%) of liquids being light oil
 Forecasted 47% increase in cash flow (27% increase in CFPS), with debt reducing to $61mm due to equity
draw end of Q2 - 2017
 Ability to add additional 2-3 wells (500 boe/d / annum) to capital budget should prices rise to US$60 / bbl,
which would push exit 2017 volumes to ~7,000 boe/d and grow cash flow to > $46mm
Q4 - 2016
5,000
53.1%
2,632
Fiscal 2016
4,100
59.0%
2,454
Q1 - 2017
5,900
54.1%
3,218
Q2 - 2017
6,100
55.6%
3,434
Q3 - 2017
5,500
54.2%
2,978
Q4 - 2017
6,100
50.2%
3,082
Fiscal 2017
5,900
53.5%
3,177
Revenue (Before Hedging)
Revenue (After Hedging)
Hedging Gain
Field NOI
CF From Ops
$16,346,090
$16,717,662
$371,572
$8,602,227
$6,443,418
$52,111,859
$58,519,451
$6,407,592
$27,673,471
$26,300,387
$21,375,300
$20,611,750
-$763,550
$12,614,456
$9,503,717
$22,927,530
$22,142,055
-$785,476
$13,839,203
$10,552,400
$20,236,424
$19,442,317
-$794,107
$12,023,618
$9,059,070
$21,404,682
$20,628,974
-$775,707
$12,553,223
$9,611,214
$85,943,936
$82,825,096
-$3,118,840
$51,030,499
$38,726,401
CAPEX
CAPEX (excluding acquisitions)
$15,300,000
$15,300,000
$25,092,961
$25,092,961
$12,700,000
$12,700,000
$800,000
$800,000
$11,650,000
$11,650,000
$14,850,000
$14,850,000
$40,000,000
$40,000,000
Quarter End Debt (exc MTM)
Quarter End Debt / Annualized CF
$69,537,959
2.70x
$69,537,959
2.64x
$72,734,242
1.91x
$53,281,841
1.26x
$55,872,771
1.54x
$61,111,557
1.59x
$61,111,557
1.58x
Share Count / Equity Drawn
226,574,672
203,524,672
226,574,672
230,885,783
239,508,005
239,508,005
234,119,116
$0.114
$0.129
$0.168
$0.183
$0.151
$0.161
$0.165
Production (Boe/d)
% Liquids
Liquids (bbls/d)
Annualized CPFS
27
2017 TCE Cash Flow Sensitivity Analysis
 Forecasted cash flows of > $39mm with + / - US$5 / bbl change in oil price resulting in ~$5mm of CF
 Upside to cash flow and potential for production growth exists as US$5 / bbl increase in commodity prices
potentially supporting the drilling of 2 incremental wells (300 - 400 boe/d incremental production)
 Balance sheet remains strong and capital programs can be adjusted to ensure financial strength
2017 hedges focused on wide collars providing opportunity if prices rise above strip

Nat Gas Price ($ / mcf)
 2017 capital program includes 4 Dunvegan, 3 Windfall, 2 Carrot Creek and 1 Gething wells, $6mm for the
expansion of our waterflood project and $2mm towards the construction of a new natural gas plant
$38.7
$40.00
$42.50
$45.00
Fiscal 2017 Cash Flow
Price of Oil (US$ / bbl)
$47.50
$50.00 $52.50 $55.00
$2.50
$25.0
$26.6
$28.1
$29.7
$32.2
$34.8
$37.3
$39.9
$42.4
$45.0
$47.6
$2.75
$25.7
$27.3
$28.9
$30.4
$32.9
$35.5
$38.0
$40.6
$43.1
$45.7
$48.3
$3.00
$26.4
$28.0
$29.6
$31.1
$33.6
$36.2
$38.7
$41.3
$43.8
$46.4
$49.0
$3.25
$27.1
$28.7
$30.3
$31.9
$34.3
$36.9
$39.4
$42.0
$44.6
$47.1
$49.7
$3.50
$27.8
$29.4
$31.0
$32.6
$35.0
$37.6
$40.1
$42.7
$45.3
$47.8
$50.4
$3.75
$28.5
$30.1
$31.7
$33.3
$35.7
$38.3
$40.8
$43.4
$46.0
$48.5
$51.1
$57.50
$60.00
$62.50
$65.00
28
2017 Production Summary
Annual Average 5,938boe/d
Base 2016 Wedge
Q4 - 2016 Wells
Q1 - 2017 Wells
Q3 - 2017 Wells
Q4 - 2017 Wells
Total BOE/D % of Total
4,500
75.6%
775
13.0%
350
5.9%
300
5.0%
25
0.4%
29
The Vision
To create a “must own” growth producer with the capital, cash flow, balance
sheet and assets to create long-term shareholder value & multiple expansion
 Position the company with a best in class balance sheet to exploit both existing
and new opportunities that create long-term shareholder value
 Disciplined approach to debt – maintain top quartile debt to cash flow
 Disciplined consolidation strategy for assets in a core fairway with specific
technical attributes
 Methodically develop the asset base with a focus on the highest return projects
 Execute a balanced capital program to deliver on conservative growth targets
 Continued conservative approach to forecasting and guidance
 Growth within cash flows
 Deliver 10% to 20% per year production growth – i.e. steady CFPS growth at strip
 Continuously improve market following & cost of capital through communication
and careful, consistent execution of the business plan
 Provide investors with significant potential returns by delivering consistent per
share growth of production, reserves, cash flow, and net asset value
30
Acquisition Opportunities Currently Under Review
Entity
2P
2017 % Oil
Reserve
Production
&
boed NGL mmboe
Estimated
Cost
$mm
6,000
55%
30
6,700
30%
50
$270
12,700 42%
80
$270
50%
20
$97
15,500 44%
100
$367
Tangle Creek
Large Target Acquisitions - Moving toward PubCo
Two Targets under review
Total TCE + Large Targets
Strategic Acquisitions - Enhancing existing operations
Five Targets under review
Total TCE+Large+Strategic
2,800
Internal Projects - Waterflood + Windfall + Maintenance
2,800
Four internal projects
18,300
Total Unrisked Potential
45%
45%
6
106
$45
$412
31
Tangle Creek – Corporate Summary
Efficient and Effective Light Oil & Gas Producer

Best in class revenues, operating costs & netbacks, combined with low FD&A and Recycle Ratios

Capital costs reduced 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

Organic growth over 3 years from 0 to 4,000 boe/d (Q4 2014)

75% light sweet crude with over 460 mmbbls OIP on Tangle Kaybob Lands

Most active, experienced Dunvegan oil operator
Opportunistic Acquirer With Strong Balance Sheet


Focus on quality, operating margins, economics and running room
Since inception, completed $130mm in acquisitions while keeping debt / cash flow under 2x

Over $50mm of acquisitions 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 (Kaybob and Windfall)

Acquired Beringer Corporate (120 net sections) in August 2016 – adding 1,500 boed and supplementing Windfall play
On the hunt for material acquisitions - move into next tier
of production & development
32
Contact:
Tangle Creek Energy Ltd
Glenn Gradeen
CEO
John Pantazopoulos
CFO
d: +1 (403) 648-4901
m: +1(403) 618-0434
d: +1 (403) 648-4903
m: +1(403) 828-8084
[email protected]
[email protected]
1400, 715 – 5th Ave S.W.
Calgary, AB T2P 2X6
TANGLE CREEK ENERGY
December 2016
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