1. Tangle Creek Corporate Overview
December 2016

2. 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
$67
$34
$26
$39
CAPEX
$62
$71
$25
$40
Period End Debt
$43
$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
$46.73
$30.13
$22.47
$22.11

3. 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
PetroBakken, Berens Home Oil
Petro-Reef, Terra
Vice President, Drilling & Completions
Vice President
Production
Vice President
Land
Greg Kondro
Steve Holyoake
Mike McGeough
Rosetta, Ocelot
EnCana, Berens, Skywest
Berens, MarkWest

4. Corporate Operating Snapshot Production (Q4 2016)
5,000 boe/d (53% liquids)
Cash Flow (Q Annualized – US$46 oil Post Pembina/Alliance)
Forecast 2017
$26 million ($0.13/sh)
$35 - $40mm
Net Debt (Sept 30, 2016)
Forecast to Dec 31, 2016
$60 million (2) (2.2x CF)
est. $69mm (1.7x 2017 CF)
Bank Line
$100 million
P + P Reserves (Jan – combined SAL & GLJ)
Est Dec 31, 2016 (see Appendix)
31 mmboe (60% light oil & ngls)
est. 29 – 32 mmboe
Total Land
Undeveloped Land
346 (265 net) sections
257 (204 net) sections
Net Drilling Locations – economic at current strip
90+
2016 Capital Program
2017 Capital Forecast
$25 million (capex<cash flow)
$35-$40 million (capex=cash flow)
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)
$17/boe (includes FDC)
$18/boe
$22/boe
Date of strip pricing, Dec 13, 2016, 2016
Excludes ELOC available of $9.7mm

5. Tangle Creek – Corporate Milestones
Technical, focused team
Track record of building successful energy businesses
Special expertise in tight rock reservoirs – recognize that rock & geology matter
Focused on profitability – building a “bullet-proof” business
Expertise in growing production volumes, top decile operating 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 w5 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 to drill multistage horizontal on Dunvegan Oil Play
1st approval for Dunvegan water flood
1st 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.
Dec 2010 – Formation of Tangle Creek
2011
2012
2013
2014
2015
2016
Q – Initial $1/share
Q – Initial Kaybob test well
2012 – Proof of concept and Kaybob development
2013 – New $1.25/share and acquisition of TLM Dunvegan assets
2014 – Organic Production Growth to 5,000 boe/d
2015 – New $1.25/share and acquisition of Trilogy Dunvegan assets. Drilling of Windfall test wells
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

6. Operating Area – West Central Alberta
130 net sections at Kaybob / Windfall
Kaybob
Windfall
Calgary
Edmonton
Ft. McMurray
Grande Prairie
Windfall
Carrot Creek
Operating area – Between Highway 43 & Hwy 16 between Edmonton & Grande Prairie
120 net sections at Carrot Creek

7. Single Well Economics – Play Ranking 180+ Locations (90+ economic)
6+ (net)
MRF - Tier 1 Dunvegan ($2.1mm capex)
MRF - Tier 2 / 4 Dunvegan ($2.1mmcapex)
IRR
US$ / bbl
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
Plant Gate Nat Gas (C$ / mcf)
$1.00
52.1%
115.4%
182.8%
304.3%
396.7%
487.4%
32.1%
54.8%
93.5%
120.8%
149.1%
$1.50
55.2%
120.0%
188.9%
312.8%
406.8%
499.2%
33.5%
56.6%
95.9%
123.6%
152.3%
$2.00
58.3%
124.7%
195.0%
321.4%
417.1%
511.1%
34.9%
58.4%
98.2%
126.4%
155.5%
$2.50
12.9%
61.5%
129.4%
201.2%
330.0%
427.5%
523.2%
36.4%
60.2%
100.7%
129.2%
158.7%
$3.00
15.3%
64.6%
134.1%
207.4%
338.5%
437.7%
534.9%
12.6%
37.9%
62.0%
103.1%
132.0%
161.9%
$3.50
17.7%
67.9%
138.9%
213.7%
347.2%
448.0%
546.8%
13.8%
39.3%
63.9%
105.5%
134.9%
165.1%
$4.00
20.0%
71.2%
143.7%
220.0%
355.9%
458.4%
558.8%
15.0%
40.8%
65.7%
108.0%
137.7%
168.4%
MRF - Windfall Mannville - TCE Gas Plant
MRF - Carrot Gething
10.1%
19.4%
29.9%
40.0%
47.5%
4.6%
14.3%
22.8%
33.9%
45.9%
54.9%
9.1%
22.0%
31.6%
42.9%
54.4%
61.8%
8.9%
19.3%
28.5%
40.6%
53.6%
63.3%
5.6%
21.1%
34.3%
44.8%
57.5%
70.0%
78.8%
3.0%
13.5%
24.7%
34.8%
47.8%
72.2%
18.0%
33.3%
59.4%
73.2%
86.5%
95.6%
7.4%
18.3%
30.5%
41.5%
55.5%
70.5%
81.5%
29.3%
61.6%
74.4%
89.1%
104.0%
113.5%
11.6%
23.3%
36.6%
48.4%
63.5%
79.4%
91.0%
59.7%
77.1%
90.4%
106.7%
122.6%
134.8%
16.1%
28.7%
43.1%
55.9%
71.9%
88.8%
101.1%
54.5%
93.1%
107.8%
125.2%
141.8%
154.8%
20.8%
34.6%
50.1%
63.7%
80.8%
98.6%
111.5%
MRF - Carrot Rock Creek Oil
MRF - Pembina Rock Creek Oil
19.1%
29.7%
40.7%
48.8%
14.7%
24.4%
41.9%
13.3%
22.3%
33.2%
44.7%
53.7%
17.1%
27.0%
37.4%
45.2%
16.3%
25.5%
37.0%
49.4%
58.1%
48.6%
28.9%
40.9%
62.5%
21.9%
32.5%
43.6%
22.4%
32.4%
57.7%
67.5%
3.7%
15.5%
35.2%
46.8%
13.0%
35.7%
71.8%
6.1%
17.8%
26.8%
38.2%
50.0%
58.9%
15.8%
52.5%
66.7%
75.8%
8.4%
20.1%
29.4%
41.2%
53.3%
62.4%
MRF - Windfall Mannville - No Gas Plant
MRF - Dunvegan Tier 3 ($2.1mm capex)
3.2%
5.9%
16.5%
27.2%
11.1%
17.0%
6.7%
17.3%
28.0%
35.9%
4.2%
14.6%
23.5%
29.5%
7.5%
18.1%
36.8%
8.1%
16.9%
26.7%
36.0%
43.2%
8.2%
18.9%
29.8%
37.8%
19.2%
38.3%
56.7%
9.0%
19.7%
30.7%
38.8%
0.1%
17.9%
30.4%
39.7%
51.3%
62.6%
71.3%
0.2%
9.8%
20.5%
39.8%
28.6%
42.0%
52.4%
64.9%
76.9%
86.2%
1.0%
10.5%
21.3%
Locations
47+ (net)
Cost reductions have led to significant improvement in well economics
Locations
20+ (net)
Locations
20 (net)
Locations
8 (net)
Locations
8 (net)
Average prospect - 50% to 60% of these improved through newer drilling and completion practices & 1 mi vs ½ mi laterals
Locations
20+ (net)
Locations
72 (net)
Gas Plant construction (Windfall) and slick water facing on Tier 3 wells (Kaybob) to generate 50%-60% returns

8. 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 Take-away Restriction
2015
Trilogy Acquisition
2016 Drilling
TCPL Curtailment
Windfall
Shut-in
2014 Drilling
2012 Drilling
2013 Drilling
Prior 12 month
Decline
35%
15%
25%
12%
2011 Drilling

9. 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 days to 8-9 days. These are real structural changes
Opex has been reduced by 40% by consolidating batteries, boring the Athabasca River, re- negotiation 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

10. OPEX – Top Decile Among Liquid Peers
includes $2.00 Transportation Costs

11. Cash Flow - Top Decile Among Peers

12. Ongoing Continuous Improvement #1 - Cost Improvements - A Game-Changer
Year over year reductions in costs and improved economics driven by improved efficiencies
Opex - 40% Decrease
45% reduction in drill times
55% reduction in total capex/well
55% reduction in Drilling costs

13. Type Curve Economics - MRF
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 - $2.1mm Capex, EUR 280 mbbls oil 375 mboe
Capital
Payout
IRR
NPV10
F&D
Recycle Ratio
1st Yr Capital
WTI
($MM)
(yrs)
(%)
($/boe)
(times)
Efficiency ($/boe/d)
$45
$2.1
0.8
161
$4.1
$5.75
4.9
$9,930
$55
0.6
285
$5.6
$5.67
6.2
$65
0.5
460
$6.9
$5.62
7.5
Tier 2 Type Curve - $2.1mm Capex, EUR 150 mbbls oil 195 mboe
2.2 38
$1.3
$11.31
2.5
$17,115
1.4 67
$2.2
$10.99
3.3
1.0
103
$3.1
$10.81
4.0

14. Two Tier 1 wells drilled in November – reduces inventory from 8 to 6
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

15. Slickwater Application – Expanding the Sweet Spots
w5 – On-stream Feb 22, 2016 – Tier 3 to Tier 2 +
Tier 1 Type Curve
Tier 2 Type Curve
w5 – On-stream Mar 15, Tier 3 to Tier 2
Tier 3 Type Curve

16. Tangle Dunvegan Slickwater Application
Slickwater Frac
Foam Frac

17. Ongoing Continuous Improvement #2 - Slickwater Application – Improving Inventory
Green = Proved Undeveloped
Red = Probable Undeveloped
Orange = Uneconomic PUD
Black = Q Drills
9 Gross (8.9 Net) PUDs
Assume Type 195 mboe = 1.73 mmboe
w5 – On-stream Feb 22, 2016
w5 – On-stream Mar 15, 2016

18. 18 sections with 175 mmbbls OOIP Secondary Recovery – 10-15 mmbbls
Continuous Improvement #3 - Dunvegan Waterflood - EOR under MRF should be a game-changer
18 sections with 175 mmbbls OOIP
Secondary Recovery – 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

19. 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

20. Windfall Development – 10+ Section Oily Area – 14-32 Basis
Proposed gas plant site
Nova and 3rd party lines
Nova
Alliance
Second well
2.5mmcfd sales bbl/d oil and NGL’s
Third well Q4 2016
2017 locations
Section 8 acquired Oct 2016
Third well drilled at w5 (October – completed Nov 2016 – initial clean-up flow similar to – 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 produces mmcf/d of natural gas with ~200 bbl/mmcf of water 20

21. 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
Strip ( )
High ( )
MBOE
Gas
IRR
NPV 10
P/I
P/O
% Gas
(%)
(M$C)
10%
(Years)
SemCams Single Well
605 74 12
148
1.0
4.9
615 33
1,839
1.5
2.4
Gas Plant Single Well
628 68
4,117
2.2
631 99
5,819
2.7
1.2
10 Well/Gas Plant Project
6,255
25,090
1.6
3.4
6,298 50
41,652
2.0
2.8
Total Field NPV10 Ex Capital
70,719
87,281
Notes
1. Capex = 3.5 M$C/well
2. Gas Plant = $10.125M$C (including Water Disposal)
3. Total Capital Cost ($m) =
$ 45,629
3. Does not include and 9-14 wells
4. Using modernized royalty regime 21

22. 120 net sections in corporate acquisition
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 Q – three wells planned in 2017 with some contingencies
Further Multi-zone Potential
Secondary zones in Viking, Notikewin, Gething , Ostracod

23. Carrot Creek – Land Base / Infrastructure
120 Net Sections
Average WI – 84%
Carrot Creek Infrastructure:
Gas Plant – 73%
Gas Plant – 100%
15 mmcf/d net capacity (40% utilized)
Firm Service – 7.1 mmcf/d rises to 11.5 mmcf/d in 2018
Q4 2016 23

24. Carrot/South-Pembina – Locations (Mannville purple; Rock Creek green)
Carrot/South-Pembina – Locations (Mannville purple; Rock Creek green). Contingent (grey)
Land Rights
Bullhead to Fernie
Rock Creek
Drilling Q4 2016
Rock Creek
Production

25. Proactive Hedging Plan
Tangle Creek maintains a proactive hedging program – 50% - 60% of 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 Q
Q1 – 2017 Q Q Q Q Q Q Q
% of Total - Crude Oil
66%
53%
49%
58%
38%
39%
30%
% of Total - Nat Gas
51%
55%
45%
24%
18%
12%

26. A Look Into 2017
Solid Margins 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

27. 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 Q
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 Q
Fiscal 2016 Q Q Q Q
Fiscal 2017
Production (Boe/d)
5,000
4,100
5,900
6,100
5,500
% Liquids
53.1%
59.0%
54.1%
55.6%
54.2%
50.2%
53.5%
Liquids (bbls/d)
2,632
2,454
3,218
3,434
2,978
3,082
3,177
Revenue (Before Hedging)
$16,346,090
$52,111,859
$21,375,300
$22,927,530
$20,236,424
$21,404,682
$85,943,936
Revenue (After Hedging)
$16,717,662
$58,519,451
$20,611,750
$22,142,055
$19,442,317
$20,628,974
$82,825,096
Hedging Gain
$371,572
$6,407,592
-$763,550
-$785,476
-$794,107
-$775,707
-$3,118,840
Field NOI
$8,602,227
$27,673,471
$12,614,456
$13,839,203
$12,023,618
$12,553,223
$51,030,499
CF From Ops
$6,443,418
$26,300,387
$9,503,717
$10,552,400
$9,059,070
$9,611,214
$38,726,401
CAPEX
$15,300,000
$25,092,961
$12,700,000
$800,000
$11,650,000
$14,850,000
$40,000,000
CAPEX (excluding acquisitions)
Quarter End Debt (exc MTM)
$69,537,959
$72,734,242
$53,281,841
$55,872,771
$61,111,557
Quarter End Debt / Annualized CF
2.70x
2.64x
1.91x
1.26x
1.54x
1.59x
1.58x
Share Count / Equity Drawn
226,574,672
203,524,672
230,885,783
239,508,005
234,119,116
Annualized CPFS
$0.114
$0.129
$0.168
$0.183
$0.151
$0.161
$0.165

28. 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 ( 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
2017 capital program includes 4 Dunvegan, 3 Windfall, 2 Carrot Creek and 1 Gething wells, $6mm for the expansion of our waterflood project and $2mm towards the construction of a new natural gas plant
Fiscal 2017 Cash Flow
Price of Oil (US$ / bbl)
$38.7
$40.00
$42.50
$45.00
$47.50
$50.00
$52.50
$55.00
$57.50
$60.00
$62.50
$65.00
Nat Gas Price ($ / mcf)
$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
$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

29. 2017 Production Summary Annual Average 5,938boe/d Total BOE/D
Total BOE/D
% of Total
Base 2016 Wedge
4,500
75.6%
Q Wells
775
13.0%
Q Wells
350
5.9%
Q Wells
300
5.0%
Q Wells 25
0.4%

30. 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

31. Acquisition Opportunities Currently Under Review

32. 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

33. Tangle Creek Energy Ltd
Contact:
Tangle Creek Energy Ltd
Glenn Gradeen
CEO
d: +1 (403)
m: +1(403)
1400, 715 – 5th Ave S.W.
Calgary, AB T2P 2X6
John Pantazopoulos
CFO
d: +1 (403)
m: +1(403)
Tangle Creek Energy
December 2016