Tangle Creek Corporate Overview December 2016 Tangle Creek

Tangle Creek Corporate Overview December 2016

Tangle Creek Overview Company Summary Ø 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 Ø Tangle raised its initial capital in late 2010 & early 2011 and commenced operations in 2011 Ø A total of $185 mm of equity capital was raised at prices from $0. 70 to $1. 25/share Ø 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 Ø The Company acquired Beringer Energy in August 2016 adding 1, 500 boe/d, 12 MMboe of reserves &120 net sections of undeveloped land Ø The Company is backed by top-tier sponsors including ARC Financial and Camcor Board of Directors Capitalization and Operating Summary Capitalization Basic Shares Outstanding MM As of Sept 30, 2016 226 Current Net Debt $MM $60 Operating Metrics 2014 2015 2016 E 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 Oct Strip 2017 F 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 Petro. Bakken, Berens Home Oil Vice President Land Mike Mc. Geough Berens, Mark. West Petro-Reef, Terra Vice President, Drilling & Completions Steve Holyoake En. Cana, Berens, Skywest 3

Corporate Operating Snapshot § Production (Q 4 2016) 5, 000 boe/d (53% liquids) § Cash Flow (Q 4 2016 Annualized – US$46 oil Post Pembina/Alliance) $26 million ($0. 13/sh) § Forecast 2017 § Net Debt (Sept 30, 2016) § Forecast to Dec 31, 2016 • $35 - $40 mm $60 million (2) (2. 2 x CF) • est. $69 mm (1. 7 x 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 Ø • 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 (capex<cash flow) Ø 2017 Capital Forecast § Corporate FD&A (Tangle + Beringer basis Dec 31, 2015 reserves) Ø Ø 2016 Operating Netback (prior to hedging – realized & strip) 2016 Corporate Netback (realized, strip & current hedges) • $35 -$40 million (capex=cash flow) $17/boe (includes FDC) $18/boe $22/boe (1) Date of strip pricing, Dec 13, 2016 (2) Excludes ELOC available of $9. 7 mm 4

Tangle Creek – Corporate Milestones Technical, focused team Dec 2010 – Formation of Tangle Creek Ø Track record of building successful energy businesses 2011 Ø Special expertise in tight rock reservoirs – recognize that rock & geology matter Ø Focused on profitability – building a “bullet-proof” business Q 4 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 Ø 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 -17 w 5 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” Ø “Best in Class” operator – a complete full service team • 1 st to drill multistage horizontal on Dunvegan Oil Play • 1 st approval for Dunvegan water flood • • 1 st approval to increase well density – up to eight wells per section 1 st Dunvegan slick-water completion Ø Large land base & proven oil property – in a desirable area Ø In 2016 expanded into Windfall – Mannville LRG play and acquired Beringer Energy Inc. Q 1 2011 – Initial Capitalization @ $1/share 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 – Organic Production Growth to 5, 000 boe/d 2015 2016 – Operational Improvements including completions and waterflood – initial development at Windfall 2016 – Corporate acquisition of Beringer Energy & New ELOC negotiated for ~$10 mm 2016 – 2017 Positioning with merger or major acquisition 5

Operating Area – West Central Alberta 130 net sections at Kaybob / Windfall Kaybob Ft. Mc. Murray Windfall Grande Prairie Edmonton Calgary 6 Ø 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) Gas Plant construction (Windfall) and slick water facing on Tier 3 wells (Kaybob) to generate 50%-60% returns $20. 00 $1. 00 $1. 50 $2. 00 $2. 50 $3. 00 $3. 50 $4. 00 5. 6% 18. 0% 29. 3% 41. 5% 54. 5% Locations 8 (net) $20. 00 $30. 00 Plant Gate Nat Gas (C$ / mcf) 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% $1. 00 $1. 50 $2. 00 $2. 50 $3. 00 $3. 50 $4. 00 Locations 20+ (net) 10. 1% 13. 0% 15. 8% MRF - Carrot Rock Creek Oil IRR US$ / bbl $40. 00 $50. 00 $60. 00 19. 1% 29. 7% 13. 3% 22. 3% 33. 2% 16. 3% 25. 5% 37. 0% 19. 3% 28. 9% 40. 9% 22. 4% 32. 4% 44. 7% 25. 5% 35. 7% 48. 6% 28. 7% 39. 3% 52. 5% $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 $1. 00 3. 2% $1. 50 11. 1% 17. 0% $2. 00 4. 2% 14. 6% 23. 5% 29. 5% $2. 50 8. 1% 16. 9% 26. 7% 36. 0% 43. 2% $3. 00 6. 7% 19. 2% 28. 0% 38. 3% 48. 8% 56. 7% $3. 50 0. 1% 17. 9% 30. 4% 39. 7% 51. 3% 62. 6% 71. 3% $4. 00 13. 5% 28. 6% 42. 0% 52. 4% 64. 9% 76. 9% 86. 2% Plant Gate Nat Gas (C$ / mcf) $80. 00 47. 5% 61. 8% 78. 8% 95. 6% 113. 5% 134. 8% 154. 8% Locations 20 (net) $20. 00 $1. 50 $2. 00 3. 0% $2. 50 7. 4% $3. 00 11. 6% $3. 50 16. 1% $4. 00 20. 8% Plant Gate Nat Gas (C$ / mcf) Locations 20+ (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 12. 9% 15. 3% 17. 7% 20. 0% $80. 00 487. 4% 499. 2% 511. 1% 523. 2% 534. 9% 546. 8% 558. 8% MRF - Tier 2 / 4 Dunvegan ($2. 1 mmcapex) Locations IRR 47+ (net) US$ / bbl $20. 00 $30. 00 $40. 00 $50. 00 $60. 00 $70. 00 $80. 00 $1. 00 32. 1% 54. 8% 93. 5% 120. 8% 149. 1% $1. 50 33. 5% 56. 6% 95. 9% 123. 6% 152. 3% $2. 00 34. 9% 58. 4% 98. 2% 126. 4% 155. 5% $2. 50 36. 4% 60. 2% 100. 7% 129. 2% 158. 7% $3. 00 12. 6% 37. 9% 62. 0% 103. 1% 132. 0% 161. 9% $3. 50 13. 8% 39. 3% 63. 9% 105. 5% 134. 9% 165. 1% $4. 00 15. 0% 40. 8% 65. 7% 108. 0% 137. 7% 168. 4% $30. 00 4. 6% 8. 9% 13. 5% 18. 3% 23. 3% 28. 7% 34. 6% MRF - Carrot Gething IRR US$ / 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% $70. 00 45. 9% 53. 6% 61. 8% 70. 5% 79. 4% 88. 8% 98. 6% Locations MRF - Pembina Rock Creek Oil IRR 8 (net) US$ / 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% Locations MRF - Dunvegan Tier 3 ($2. 1 mm capex) 72 (net) IRR US$ / 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% $80. 00 54. 9% 63. 3% 72. 2% 81. 5% 91. 0% 101. 1% 111. 5% Plant Gate Nat Gas (C$ / mcf) $20. 00 $1. 50 $2. 00 $2. 50 $3. 00 $3. 50 $4. 00 Plant Gate Nat Gas (C$ / mcf) MRF - Tier 1 Dunvegan ($2. 1 mm capex) IRR US$ / 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% $80. 00 41. 9% 45. 2% 48. 6% 52. 1% 55. 5% 58. 9% 62. 4% Plant Gate Nat Gas (C$ / mcf) Locations 6+ (net) Plant Gate Nat Gas (C$ / mcf) Cost reductions have led to significant improvement in well economics $80. 00 34. 9% 35. 9% 36. 8% 37. 8% 38. 8% 39. 8% 40. 7% 7

Production Adds & Drilling Vintages – Production is leveling Ø Wells with 4+ years history are down to 15% declines or less Ø Corporate decline is 25% to 30% Beringer Acquisition 3 rd Party Solution Gas Processing Restriction Solution Gas Take -away Restricti on 2014 Drilling 2012 Drilling 2015 2016 Trilogy Drilling Acquisition TCPL Curtailment Windfall Shut-in 2013 Drilling 35% Prior 12 month Decline 25% 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: ü Capital cost reductions have been a game-changer – last two wells drilled were $2. 1 mm each – all in. Four years ago cost was $4. 8 mm 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 ü 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 ü Declines are better understood, with steep initial and long term declines down to 15% to 20% and long term declines down to 15% to 20 on wells older than 30 months. Corporately we are at 30% or less including Beringer ü 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 ü 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. ü Further economic enhancements are being planned with successful response on the pilot water-flood ü 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 SOG 10

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 SOGPMT MEI CKE ZAR PNEPWTPGFCQE BBI MQLTOOBXE POU CR AEI PPY KEL SRX TET DEE BTE NVA BIR RE AAV VII TVE SKXRMP LXE TCE SPE RRX 11

Ongoing Continuous Improvement #1 - Cost Improvements - A Game-Changer Ø Year over year reductions in costs and improved economics driven by improved efficiencies Opex - 4 0% Decre ase 45% reduction in drill times 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 - $2. 1 mm Capex, EUR 280 mbbls oil 375 mboe Capital Payout IRR NPV 10 F&D WTI ($MM) (yrs) (%) ($MM) ($/boe) $45 $2. 1 0. 8 161 $4. 1 $5. 75 $55 $2. 1 0. 6 285 $5. 67 $65 $2. 1 0. 5 460 $6. 9 $5. 62 Recycle Ratio (times) 4. 9 6. 2 7. 5 1 st Yr Capital Efficiency ($/boe/d) $9, 930 Tier 2 Type Curve - $2. 1 mm Capex, EUR 150 mbbls oil 195 mboe Capital Payout IRR NPV 10 F&D WTI ($MM) (yrs) (%) ($MM) ($/boe) $45 $2. 1 2. 2 38 $1. 3 $11. 31 $55 $2. 1 1. 4 67 $2. 2 $10. 99 $65 $2. 1 1. 0 103 $3. 1 $10. 81 Recycle Ratio (times) 2. 5 3. 3 4. 0 1 st Yr Capital Efficiency ($/boe/d) $17, 115 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 -18 w 5 – On-stream Feb 22, 2016 – Tier 3 to Tier 2 + Tier 1 Type Curve Tier 2 Type Curve 15 -04 -60 -17 w 5 – 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 = Q 1 2016 Drills 9 Gross (8. 9 Net) PUDs Assume Type 2 @ 195 mboe = 1. 73 mmboe 4 -30 -60 -18 w 5 – On-stream Feb 22, 2016 15 -04 -60 -17 w 5 – On-stream Mar 15, 2016 17

Continuous Improvement #3 - Dunvegan Waterflood - EOR under MRF should be a game-changer Ø Ø 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 Ø 1/2 section pilot Ø 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 Ø 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 Ø Active drilling by Velvet and Vermillion, year-round access and good infrastructure - 65 net sections at Windfall, 120 net sections at Carrot Creek/Pembina Ø 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 Ø Third well drilled at 45 -58 -17 w 5 (October 2016 – completed Nov 2016 – initial clean-up flow similar to 14 -32 – currently on build-up) Ø 2017 plan is for two additional scoping wells – then a development including gas plant Ø Drilling program and gas plant currently under review Ø 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 3 rd party lines Alliance Section 8 acquired Oct 2016 2017 locations Nova Third well - 4 -5 -58 -17 Q 4 2016 Proposed gas plant site Second well -14 -3257 -17 2. 5 mmcfd sales + 180 bbl/d oil and NGL’s 20

Windfall Development – Single Well Economics and 3 year - 10 Well Program Ø 3 Year development program Includes 10 wells, 10 mmcfd gas plant & infrastructure Ø Current data indicates 11 low risk sections (22 wells) & additional 8 moderate risk 11 low risk sections (22 wells) Ø Total 20 out of 65 net sections – 30% of lands currently considered prospective MRF Sem. Cams Single Well Gas Plant Single Well 10 Well/Gas Plant Project Total Field NPV 10 Ex Capital Strip (17 -08 -2016) IRR NPV 10 (%) (M$C) MBOE Gas (%) 605 74 12 628 6, 255 74 74 68 33 Notes 1. Capex = 3. 5 M$C/well 2. Gas Plant = $10. 125 M$C (including Water Disposal) $ 45, 629 3. Total Capital Cost ($m) = 3. Does not include 14 -32 and 9 -14 wells P/I 10% P/O (Years) 148 1. 0 4. 9 4, 117 25, 090 70, 719 2. 2 1. 6 1. 5 3. 4 High (29 -08 -2016) IRR NPV 10 (%) (M$C) MBOE % Gas (%) 61 5 74 63 1 74 6, 298 74 P/I 10% P/O (Years) 33 1, 839 1. 5 2. 4 99 50 5, 819 41, 652 87, 281 2. 7 2. 0 1. 2 2. 8 4. Using modernized royalty regime 21

Carrot Creek – Acquired August 2016 Ø 120 net sections in corporate acquisition 120 net sections Ø Extensive owned infrastructure makes gassier asset attractive – however – focused on Extensive owned infrastructure oilier areas Ø 27. 5 net locations and 11. 4 net contingent locations in Lower Mannville/Jurassic 27. 5 net locations and 11. 4 net contingent locations fluvial and tidal sandstones and Jurassic Rock Creek/Niton shoreface sandstones Ø Petrophysical review of Lower Mannville complete - Petrophysical review of Lower Mannville complete cores and cutting samples from area wells interpreted to ensure high-grading of locations Ø Expect Lower Mannville to be liquids - rich gas based on older vertical production Lower Mannville to be liquids - rich gas in the region – initial locations offset vertical wells that produced or tested oil. Ø Rock Creek will generally be oily with ½ mile laterals Rock Creek will generally be oily Ø Two wells planned for Q 4 2016 – three wells planned in 2017 with some contingencies Ø Further Multi-zone Potential Ø 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 Q 4 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 Q 4 2016 Rock Creek Production

Proactive Hedging Plan Ø 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 Ø 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 Ø 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 4 - 2016 Q 1 – 2017 Q 2 - 2017 % of Total - Crude Oil 66% 53% 49% % of Total - Nat Gas 51% 55% 49% Q 3 - 2017 58% 49% Q 4 - 2017 58% 45% Q 1 - 2018 38% 24% Q 2 - 2018 39% 18% Q 3 - 2018 30% 12% Q 4 - 2018 30% 12% 25

A Look Into 2017 Ø Solid Margins - 2017 CF stable at $35 to $40 mm with free cash flow above maintenance CAPEX to grow production >10% per year Ø Free cash flow – can maintain current production with ~$20 mm per year CAPEX Ø Low cost structure – (opex ~$10/boe) ensures sustainable – total cash costs ~C$17 / boe (includes opex, transportation, G&A, E&E, interest) Ø 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 Ø Disciplined - CAPEX ~ Cashflow improves liquidity & dry powder for acquisitions Ø Production Maintenance – In 2016 while CAPEX ~ cash flow as declines further reduce to 20% - 30% / annum – maintain production while not depleting inventory Ø IRR / NPV Positive Drilling – Tier 1 and Tier 2 Dunvegan drilling inventory expanding – with new technologies - economic at current strip Ø Hedging program – crucial to protecting cash flows and capital programs Ø Hedging gains funded 33% of 2016 CAPEX program allowing for modest deleveraging and growth Ø Upside Exposure & Optionality – WTI price increase to US$60 / bbl increases cash flow to $47 mm with debt / CF of <1. 0 x by Q 3 – 2017 Ø Ø 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! Ø Forecasted production of 5, 900 boe/d with a “Cash flow ~ CAPEX” budget in fiscal 2017 Ø Liquids production remains > 50%, with majority (> 85%) of liquids being light oil Ø Forecasted 47% increase in cash flow (27% increase in CFPS), with debt reducing to $61 mm due to equity draw end of Q 2 - 2017 Ø Ability to 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 > $46 mm Production (Boe/d) % Liquids (bbls/d) Revenue (Before Hedging) Revenue (After Hedging) Hedging Gain Field NOI CF From Ops CAPEX (excluding acquisitions) Q 4 - 2016 5, 000 53. 1% 2, 632 Fiscal 2016 4, 100 59. 0% 2, 454 Q 1 - 2017 5, 900 54. 1% 3, 218 Q 2 - 2017 6, 100 55. 6% 3, 434 Q 3 - 2017 5, 500 54. 2% 2, 978 Q 4 - 2017 6, 100 50. 2% 3, 082 $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 $15, 300, 000 $25, 092, 961 $12, 700, 000 $800, 000 $11, 650, 000 $14, 850, 000 $40, 000, 000 Quarter End Debt (exc MTM) Quarter End Debt / Annualized CF $69, 537, 959 2. 70 x $69, 537, 959 2. 64 x $72, 734, 242 1. 91 x $53, 281, 841 1. 26 x $55, 872, 771 1. 54 x $61, 111, 557 1. 59 x $61, 111, 557 1. 58 x Share Count / Equity Drawn 226, 574, 672 203, 524, 672 226, 574, 672 230, 885, 783 239, 508, 005 $16, 346, 090 $16, 717, 662 $371, 572 $8, 602, 227 $6, 443, 418 Annualized CPFS Fiscal 2017 5, 900 53. 5% 3, 177 $85, 943, 936 $82, 825, 096 -$3, 118, 840 $51, 030, 499 $38, 726, 401 $0. 114 234, 119, 116 $0. 129 $0. 168 $0. 183 $0. 151 $0. 165 27

2017 TCE Cash Flow Sensitivity Analysis Ø Forecasted cash flows of > $39 mm with + / - US$5 / bbl change in oil price resulting in ~$5 mm of CF Ø 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) Ø 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 ü Ø 2017 capital program includes 4 Dunvegan, 3 Windfall, 2 Carrot Creek and 1 Gething wells, $6 mm for the expansion of our waterflood project and $2 mm 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 $51. 1 Nat Gas Price ($ / mcf) $57. 50 $60. 00 $62. 50 $65. 00 28

2017 Production Summary Annual Average 5, 938 boe/d Base 2016 Wedge Q 4 - 2016 Wells Q 1 - 2017 Wells Q 3 - 2017 Wells Q 4 - 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 Ø Position the company with a best in class balance sheet to exploit both existing and new opportunities that create long-term shareholder value ü Disciplined approach to debt – maintain top quartile debt to cash flow Ø Disciplined consolidation strategy for assets in a core fairway with specific technical attributes Ø Methodically develop the asset base with a focus on the highest return projects Ø Execute a balanced capital program to deliver on conservative growth targets ü Continued conservative approach to forecasting and guidance ü Growth within cash flows Ø Deliver 10% to 20% per year production growth – i. e. steady CFPS growth at strip Ø Continuously improve market following & cost of capital through communication and careful, consistent execution of the business plan Ø 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 31

Tangle Creek – Corporate Summary Efficient and Effective Light Oil & Gas Producer ü Best in class revenues, operating costs & netbacks, combined with low FD&A and Recycle Ratios ü Capital costs reduced 50% BEFORE 2015 price adjustments by service companies Proven Organic Growth Capacity ü 1 st to identify & implement Kaybob Dunvegan horizontal technologies – including new drilling and completions applications and EOR ü Organic growth over 3 years from 0 to 4, 000 boe/d (Q 4 2014) ü 75% light sweet crude with over 460 mmbbls OIP on Tangle Kaybob Lands ü Most active, experienced Dunvegan oil operator Opportunistic Acquirer With Strong Balance Sheet ü ü Focus on quality, operating margins, economics and running room Sinception, completed $130 mm in acquisitions while keeping debt / cash flow under 2 x ü Over $50 mm of acquisitions in 2015 including undeveloped land ü 69 net light oil sections in Kaybob acquired through 30 separate transactions ü Counter cyclically acquired 80 net sections on two plays in 2015 (Kaybob and Windfall) ü 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 d: +1 (403) 648 -4901 m: +1(403) 618 -0434 ggradeen@tanglecreekenergy. com John Pantazopoulos CFO d: +1 (403) 648 -4903 m: +1(403) 828 -8084 jpantazopoulos@tanglecreekenergy. com 1400, 715 – 5 th Ave S. W. Calgary, AB T 2 P 2 X 6 TANGLE CREEK ENERGY December 2016 Logo Placement