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 $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

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

Corporate Operating Snapshot Production (Q4 2016) 5,000 boe/d (53% liquids) Cash Flow (Q4 2016 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 1 2016 – 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

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 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 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 Q1 2011 – Initial Capitalization @ $1/share Q4 2011 – Initial Kaybob test well 2012 – Proof of concept and Kaybob development 2013 – New equity @ $1.25/share and acquisition of TLM Dunvegan assets 2014 – Organic Production Growth to 5,000 boe/d 2015 – New equity @ $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

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

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

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

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, 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

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

Cash Flow - Top Decile Among Peers

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

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

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

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

Tangle Dunvegan Slickwater Application 15-04-60-17 Slickwater Frac 14-04-60-17 Foam Frac

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

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 – 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

Windfall Development – 10+ Section Oily Area – 14-32 Basis Proposed gas plant site Nova and 3rd party lines Nova Alliance Second well -14-32-57-17 2.5mmcfd sales + 180 bbl/d oil and NGL’s Third well - 4-5-58-17 Q4 2016 2017 locations Section 8 acquired Oct 2016 Third well drilled at 4- 5-58-17w5 (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 1-1.5 mmcf/d of natural gas with ~200 bbl/mmcf of water 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 Strip (17-08-2016) High (29-08-2016) 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 14-32 and 9-14 wells 4. Using modernized royalty regime 21

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 Q4 2016 – three wells planned in 2017 with some contingencies Further Multi-zone Potential Secondary zones in Viking, Notikewin, Gething , Ostracod

Carrot Creek – Land Base / Infrastructure 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) 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 Q3 - 2017 Q4 - 2017 Q1 - 2018 Q2 - 2018 Q3 - 2018 Q4 - 2018 % of Total - Crude Oil 66% 53% 49% 58% 38% 39% 30% % of Total - Nat Gas 51% 55% 45% 24% 18% 12%

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

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 Fiscal 2016 Q1 - 2017 Q2 - 2017 Q3 - 2017 Q4 - 2017 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

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 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

2017 Production Summary Annual Average 5,938boe/d Total BOE/D   Total BOE/D % of Total Base 2016 Wedge 4,500 75.6% Q4 - 2016 Wells 775 13.0% Q1 - 2017 Wells 350 5.9% Q3 - 2017 Wells 300 5.0% Q4 - 2017 Wells 25 0.4%

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

Acquisition Opportunities Currently Under Review

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

Tangle Creek Energy Ltd Contact: Tangle Creek Energy Ltd Glenn Gradeen CEO d: +1 (403) 648-4901 m: +1(403) 618-0434 ggradeen@tanglecreekenergy.com 1400, 715 – 5th Ave S.W. Calgary, AB T2P 2X6 John Pantazopoulos CFO d: +1 (403) 648-4903 m: +1(403) 828-8084 jpantazopoulos@tanglecreekenergy.com Tangle Creek Energy December 2016