AGM PresentationJune 10, 2019

This presentation contains forward-looking statements. More particularly, this presentation contains statements concerning anticipated: business strategies, plans and objectives; potential development opportunities and drilling locations, expectations and assumptions concerning the success of future drilling and development activities, the performance of existing wells, the performance of new wells, decline rates, recovery factors, the successful application of technology and the geological characteristics of our properties; cash flow; oil & natural gas production growth and mix; reserves; debt and bank facilities; amounts and timing of capital expenditures; hedging results; primary and secondary recovery potentials and implementation thereof; and drilling, completion and operating costs.

Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Actual reserve values may be greater than or less than the estimates provided in this presentation.

The forward-looking statements are based on certain key expectations and assumptions made by Tangle Creek, including expectations and assumptions concerning the performance of existing wells and success obtained in drilling new wells, anticipated expenses, cash flow and capital expenditures and the application of regulatory and royalty regimes. Although Tangle Creek believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Tangle Creek can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures.

Readers are cautioned that the foregoing list of risk factors is not exhaustive. Furthermore, new risk factors emerge from time to time, and it is not possible for Tangle Creek to predict all of such factors and to assess in advance the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. The above summary of assumptions and risks related to forward-looking statements in this presentation has been provided in order to provide potential investors with a more complete perspective of our current and future operations and as such information may be not appropriate for other purposes. The forward-looking statements contained in this presentation are made as of the date hereof and Tangle Creek undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Forward-Looking Statement

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Board of Directors

Management Team

Management and Governance

Technical Management Team with extensive oil & gas experience

Experienced Board of Directors provides corporate governance and strategic guidance

Lauchlan CurrieChairman

ARC Financial Corp.

Jeff Prentice

ARC Financial Corp.

Dan Botterill

Independent Director

Jim Pasieka

McCarthy Tetrault.

Ian Fergusson

Camcor Partners Inc..

Glenn Gradeen

Tangle Creek Energy Ltd.

Larry Jones

Independent Director

CEO

Glenn GradeenBerkana, Rosetta, Ocelot

Vice President,Exploration

Alison EsseryConoco-Burlington, Shell

Vice President,Engineering

Ben MakarCenovus, Encana

Vice President,Production

Greg KondroRosetta, Ocelot

Director, Business Development

Robyn LoreBerkana, Rosetta, Kallisto

Vice President, Land

Jim JunkerNordegg, Burmis, Wascana,

Shell

CFO

J.P. BuyzeTrident, UBS Securities

Strong leadership from highly experienced management team and board of directors

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http://www.shell.ca/http://www.shell.ca/

The Vision – Create a High-Quality, High-Growth BusinessFocused on high-margin, high-growth business with significant running room

4

Focus on top-tier, high margin, light-tight oil plays Maintain high Environmental, Social and Governance standards Deliver 10-20% per year production and CFPS growth Sustainable Growth – 10+ years of light oil drilling inventory Demonstrable well design efficiency gains using modern drilling and

completion techniques High working interest ownership in infrastructure enables low operating

costs, control of pace and development strategies Low financial leverage

• Capital program scalable depending on market conditions (pricing and differentials)

• Capital and growth is funded by internally generated cash flow

Liquidity for investors within 24 to 36 months

Who should be the supplier of choice for the world’s100-million-barrel-a-day oil needs? Should there be a merit order ascribed to producers?Canada’s oil and gas industry, the world’s fifth largest, ranks highly on many performance dimensions, including corporate governance, transparency, environmental stringency, and innovation.

Thankfully, some credible institutions take time to evaluate countries by their virtues, or lack thereof. For example, every year Berlin-based Transparency International (TI) scores and ranks countries by perceived levels of public-sector corruption.

TI gives Canada top marks for low corruption.

Among 28 oil-producing countries that fill 90% of the world’s oil tanks, Canada ranks number 2 (yellow end of spectrum on figure). The only supplier that ranks slightly cleaner is Norway which has a state owned industry.It will take time for consumers to kick the 100-million-barrell-a-day habit. Until such time…

…the world needs more – not less – from transparent, accountable Canada

Canada – Responsible Production and TransparencyWhy are we filling our tanks with foreign sourced oil? Canada is ranked as one of the top jurisdictions in the world having transparent and responsible regulations and production.

Figure 1: World Oil Producers Ranked by Corruption and Volume

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Environmental, Social & Governance Performance

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Tangle Creek – Committed to reducing emissions intensity

Environmental, Social & Governance Performance

US Average

US Average

Tangle Creek in relation to Energy Industry

Tangle Creek production emissions rank well below the average for crude oil consumed in the United States in 2014 (the most recent baseline). Innovations & Programs include: Vapor recovery units (VRU’s) installed and

operational on all major facilities – ongoing program to add VRU’s to smaller facilities

Fugitive emissions and leak detection processes – ongoing program of detection and repair and replace

Ongoing program to reduce producing site visits through technology applications

Ongoing program to electrify multi-well pads Program to reduce field gathering system

pressures in conjunction with VRU’s Integrate and upgrade new assets Continuous improvement and upgrading of

emissions detection technology

Tangle Creek was one of the first producers to use up to 100% produced (versus fresh) water in its completions systems.

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Tangle Creek-26%

Tangle Creek-71%

Greenhouse Gas Emissions Intensity – OilTangle Creek vs Global Crudes- Production Emissions Only

Greenhouse Gas Emissions Intensity – Natural GasExtraction, Field Transportation and Processing

Tangle Creek2018

Tangle Creek Overview

Private company founded in 2010 Owners include ARC Financial, Camcor, Wells

Fargo, Northleaf, Boden/Alta and GE Pension Focused on light-tight oil; demonstrated experience

with tight, unconventional reservoirs Concentrated assets – strategically positioned in

West Central Alberta Two high margin light oil properties:

Montney at Waskahigan Dunvegan at Kaybob

Strong organic growth profile Light oil drilling inventory of over 300 locations

Significant infrastructure in place: Owned and operated facilities with low operating

costs

Private growth-oriented oil producer with concentrated land position in West Central Alberta

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1. From December 31, 2018 Sproule year-end reserves evaluation.

30 miles

Production (boe/d)

2019 Q1 Production% Liquids

6,63853%

Reserves (mmboe)1

PDPProvedProved + Probable

13.527.251.1

Hwy 43

Hwy 32

Hwy 16

Waskahigan

Kaybob

Windfall

Carrot Creek

Tangle Creek Field Office

Key Strengths

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1. Large Inventory of Highly Economic Drilling Locations More than 300 oil-weighted locations (10+ years) Light oil wells have demonstrated to be amongst the highest margin, best returns in Canada Shallower well depths of less than 2,500 m provide lower drilling capital costs

2. Strong Technical Expertise Developing and Operating Unconventional Reservoirs Track record of driving down drilling and completion costs while improving well performance Successful application of new technologies to optimize drilling and completion techniques

3. High working interest ownership in infrastructure Existing infrastructure ready to accommodate growth in production Provides low operating costs and accommodates future development

4. Egress Oil – 100% firm service on Pembina Natural gas – 55% of gas to Chicago via Alliance, 25% of gas to ATP and 20% to AECO via TCPL

5. Active Hedging Program Significant hedging to protect cash flows, capital programs and balance sheet Target up to 65% of gross “blowdown” production hedged over next 12 months, up to 40% hedged over 12-24 months

Benchmark Pricing Q1 2018 Q2 2018 Q3 2018 Q4 2018 FY 2018 Q1 2019WTI (US$/bbl) 62.87 67.88 69.50 58.83 64.78 54.90 Edmonton Par (C$/bbl) 72.15 80.58 81.92 43.00 69.56 66.38 AECO 5A (C$/mcf) 2.05 1.23 1.21 1.61 1.52 2.45 Chicago City Gate (US$/mmbtu) 3.24 2.58 2.75 3.63 3.05 3.10 FX 1.265 1.291 1.307 1.322 1.296 1.328

Production Q1 2018 Q2 2018 Q3 2018 Q4 2018 FY 2018 Q1 2019Oil (bbl/d) 3,932 3,786 3,422 3,149 3,570 3,000 Gas (mcf/d) 23,041 22,922 22,077 20,165 22,043 18,712 NGL (bbl/d) 622 659 637 583 625 519 Total (boe/d) 8,394 8,265 7,738 7,093 7,869 6,638

Financial Information Q1 2018 Q2 2018 Q3 2018 Q4 2018 FY 2018 Q1 2019 Q1 2018 Q2 2018 Q3 2018 Q4 2018 FY 2018 Q1 2019Oil 70.27 79.13 79.48 37.84 67.63 63.71 24,867 27,264 25,025 10,962 88,118 17,201 Gas 2.99 3.05 2.94 4.24 3.28 3.79 6,200 6,370 5,971 7,867 26,408 6,391 NGL 42.61 49.93 47.72 41.47 45.58 39.05 2,387 2,994 2,796 2,226 10,403 1,824 Revenue 44.28 48.70 47.47 32.27 43.50 42.55 33,454 36,628 33,792 21,055 124,929 25,416 Royalties (4.60) (4.75) (4.52) (2.52) (4.15) (2.61) (3,471) (3,572) (3,220) (1,647) (11,910) (1,561) Operating (12.17) (9.90) (9.01) (10.11) (10.32) (11.28) (9,192) (7,448) (6,413) (6,598) (29,651) (6,741) Transportation (4.92) (6.53) (6.22) (6.38) (5.99) (6.57) (3,717) (4,914) (4,425) (4,162) (17,218) (3,923) Operating Cashflow 22.59 27.52 27.72 13.26 23.04 22.09 17,074 20,694 19,734 8,648 66,150 13,191 Realized Hedging (3.86) (5.86) (8.12) (3.95) (5.46) (4.25) (2,913) (4,405) (5,778) (2,576) (15,672) (2,542) Operating Cashflow (after hedging) 18.73 21.66 19.60 9.31 17.58 17.84 14,161 16,289 13,956 6,072 50,478 10,649 G&A (2.06) (2.45) (2.37) (2.66) (2.37) (3.06) (1,550) (1,844) (1,693) (1,736) (6,823) (1,828) Transaction - - (0.19) - (0.05) - - - (137) - (137) - E&E - - - - - - - - - - - - Interest (1.10) (1.28) (1.21) (1.43) (1.25) (1.78) (834) (966) (865) (931) (3,596) (1,061) Total Cashflow 15.57 17.93 15.83 5.22 13.91 13.00 11,777 13,479 11,261 3,405 39,922 7,760

($/boe) ($000s)

Income Statement Review

2018 cash flow negatively impacted by: Weak Q4 Edmonton pricing Less drilling due to higher than expected capital costs Poor 4-23 well results Regulatory delays impacting drilling timing Transportation costs - demand charge obligations

Q1 19 cash flow negatively impacted by: Lower YoY production driven by restricted new well

drilling, natural declines, disposition of Pembina, and production outages due to extreme cold

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2018 impacted by weak Q4 Edmonton Par crude oil pricing while Q1 19 impacted by lower production.

Observations

Sheet1

Benchmark PricingQ1 2018Q2 2018Q3 2018Q4 2018FY 2018Q1 2019

WTI (US$/bbl)62.8767.8869.5058.8364.7854.90

Edmonton Par (C$/bbl)72.1580.5881.9243.0069.5666.38

AECO 5A (C$/mcf)2.051.231.211.611.522.45

Chicago City Gate (US$/mmbtu)3.242.582.753.633.053.10

FX1.2651.2911.3071.3221.2961.328

ProductionQ1 2018Q2 2018Q3 2018Q4 2018FY 2018Q1 2019

Oil (bbl/d)3,9323,7863,4223,1493,5703,000

Gas (mcf/d)23,04122,92222,07720,16522,04318,712

NGL (bbl/d)622659637583625519

Total (boe/d)8,3948,2657,7387,0937,8696,638

($/boe)($000s)

Financial InformationQ1 2018Q2 2018Q3 2018Q4 2018FY 2018Q1 2019Q1 2018Q2 2018Q3 2018Q4 2018FY 2018Q1 2019

Oil70.2779.1379.4837.8467.6363.7124,86727,26425,02510,96288,11817,201- 0

Gas2.993.052.944.243.283.796,2006,3705,9717,86726,4086,391- 0

NGL42.6149.9347.7241.4745.5839.052,3872,9942,7962,22610,4031,824- 0

Revenue44.2848.7047.4732.2743.5042.5533,45436,62833,79221,055124,92925,416- 0

Royalties(4.60)(4.75)(4.52)(2.52)(4.15)(2.61)(3,471)(3,572)(3,220)(1,647)(11,910)(1,561)- 0

Operating(12.17)(9.90)(9.01)(10.11)(10.32)(11.28)(9,192)(7,448)(6,413)(6,598)(29,651)(6,741)- 0

Transportation(4.92)(6.53)(6.22)(6.38)(5.99)(6.57)(3,717)(4,914)(4,425)(4,162)(17,218)(3,923)- 0

Operating Cashflow22.5927.5227.7213.2623.0422.0917,07420,69419,7348,64866,15013,191- 0

Realized Hedging(3.86)(5.86)(8.12)(3.95)(5.46)(4.25)(2,913)(4,405)(5,778)(2,576)(15,672)(2,542)- 0

Operating Cashflow (after hedging)18.7321.6619.609.3117.5817.8414,16116,28913,9566,07250,47810,649- 0

G&A(2.06)(2.45)(2.37)(2.66)(2.37)(3.06)(1,550)(1,844)(1,693)(1,736)(6,823)(1,828)- 0

Transaction- 0- 0(0.19)- 0(0.05)- 0- 0- 0(137)- 0(137)- 0- 0

E&E- 0- 0- 0- 0- 0- 0- 0- 0- 0- 0- 0- 0- 0

Interest(1.10)(1.28)(1.21)(1.43)(1.25)(1.78)(834)(966)(865)(931)(3,596)(1,061)- 0

Total Cashflow15.5717.9315.835.2213.9113.0011,77713,47911,2613,40539,9227,760- 0

Balance Sheet Review

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Revolving credit facility Syndicated facility set to $120.0MM plus $10.0MM accordion effective June

2019 Modifications to reporting requirements on decommissioning obligations Additional negative covenants related to LMR and acquisitions /

dispositions D/CF: 3.2x as at March 31, 2019 (vs. 2.4x at December 31, 2018)

Higher than our targets – working to bring this back in line

($000's)

Working Capital 2018 Q1 2019Cash - 1,690 Accounts receivable 5,808 10,860 Prepaid expenses and deposits 753 656 Accounts payable and accrued liabilities (16,568) (18,143)

(10,007) (4,937)

Revolving credit facility (87,226) (94,000)

Net Debt (97,233) (98,937)

Weak Q4 2018 cash flows resulted in increased net debt levels for year-end 2018 and Q1 2019.

Tangle Creek Operating Areas

22%

52%

26%

PDP 44%

34%

22%

P+P

22%

44%

34%2018

70%

23%

7%

2023E2

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Production Profile1

Reserve Split by Area Production Split by Area

Kaybob

Waskahigan

Other

Legend

13.5 mmboe 51.1 mmboe 7,869 boe/d

1. Production for ‘Other’ has been adjusted for the Pembina property disposition closed August 2018.2. Based on management forecast assuming strip pricing and capital expenditures equal to cash flow.

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2012 2013 2014 2015 2016 2017 2018

Prod

uctio

n (b

oe/d

)

Core Operating Area – Kaybob Dunvegan

Key Statistics

2018 Production 3,450 boe/d 2018YE Reserves

PPDP 9.6 mmboe PPUD 7.5 mmboe (44 wells)

2018 NOI % ~60% of Total 2018 Netback ~$33/boe 106.5 (66.5 net) sections with Dunvegan rights Total Inventory of ~120 net locations Light oil – API Gravity 36°

Low risk, free cash flow generating light oil asset which funds corporate growth

Key Characteristics

Shallow depth wells (1,600 m / 5,250 ft); high chance of success

Low operating costs, high netbacks Established infrastructure – new drilling off existing pads Drilling inventory in place to maintain flat production for ~7

years while generating significant free cash flow Demonstrated improvement in type curves from evolving

completion techniques Waterflood proving effective in increasing recovery and value OOIP = 460 mmbbl. 99 net horizontal wells drilled since 2011 PPDP Ultimate Recovery Factor only 4%

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2017 drilling program (9 wells) 2018 drilling program (4 wells)

Maintaining production

~ 3,000 boe/d

3 – 5 well winter program

Track Record of Well Performance Improvements…

Kaybob Dunvegan Annual Drilling Programs

Historical DC&T Costs

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Historical Days Drilling

Cum

ulat

ive

Prod

uctio

n -b

oe

Days on Production

Advancing completion techniques have improved IP365s and EURs beyond type curve expectations

Continuous improvement of

drilling and completions

Lower DC&T costs Improved recoveries and reserves Faster payout times Better IRRs

2017 9 2592016 4 2042015 1 1332014 18 1732013 13 131

2011 - 2012 27 115Total 76

New Completion DesignTarget Well Cost

… And Strong Well Economics

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Dunvegan Well Inputs

Dunvegan Well Economics1

Kaybob Dunvegan Type CurvesTC129 TC155

DCET Capital ($MM) 2.5 2.5

EUR (Oil) (mbbl) 129 155

EUR (mboe) 162 194

IP90 (bbl/d) 163 195

Measured Depth (m)(feet)

3,30010,800

3,30010,800

Stage Count 25 25

Frac Intensity (T/m)(lbs/ft)

0.4270

0.4270

TC129 TC155

NPV-10 ($MM) 1.7 2.5

P/I Ratio 1.7x 2.0x

IRR% 46% 72%

Payout (Months) 23 16

F&D ($/boe) 15.43 12.89

3mo Capital Efficiency ($/boe/d) 12,438 10,373

Netback ($/boe) 33.41 33.92

Economic Sensitivity Tables1

At US$50 Edmonton pricing, type curves generate 45% to 70% IRRs and payouts of ~ 18 to 24 months

Optimization efforts have aligned 2018 program with current Dunvegan type curves

40.00$ 50.00$ 60.00$ 40.00$ 50.00$ 60.00$ 40.00$ 50.00$ 60.00$ $2.25 $11.60 50% 96% 164% $2.25 $1.7 $2.8 $3.8 $2.25 22 13 10$2.50 $12.89 38% 72% 120% $2.50 $1.5 $2.5 $3.5 $2.50 27 16 11$2.75 $14.18 30% 56% 91% $2.75 $1.2 $2.3 $3.3 $2.75 33 19 13

40.00$ 50.00$ 60.00$ 40.00$ 50.00$ 60.00$ 40.00$ 50.00$ 60.00$ $2.25 $13.89 31% 61% 101% $2.25 $1.0 $2.0 $2.9 $2.25 32 19 13$2.50 $15.43 23% 46% 76% $2.50 $0.8 $1.7 $2.6 $2.50 40 23 16$2.75 $16.98 17% 36% 58% $2.75 $0.5 $1.5 $2.4 $2.75 50 28 18

CAPEX / Well ($MM)

CAPEX / Well ($MM)

Edmonton (US$) Edmonton (US$) Edmonton (US$)

CAPEX / Well ($MM)

CAPEX / Well ($MM)

CAPEX / Well ($MM)

IRR PV-10 ($MM) Payout (mo)

Edmonton (US$) Edmonton (US$) Edmonton (US$)

IRR PV-10 ($MM) Payout (mo)

Dunvegan P50 Type Curve - 1.0 Mile Wells - TC155 mbbl / 194mboe EUR

Dunvegan P90 Risked Type Curve - 1.0 Mile Wells - TC129 mbbl / 162mboe EUR

CAPEX / Well

Well F&D ($/boe)

Well F&D ($/boe)

1 economic analysis assumes Fx = 0.75, CDN$3.75/bbl adjustment for quality & transport, realized gas price of CDN$1.75/mcf

Kaybob Dunvegan High-graded 5 year Inventory (59 Locations)Dunvegan Waterflood Advancement2015 Primary prodn rate: 50 bbl/d2019 W/F prodn rate: 90 bbl/d

100/15-18-060-17W5: oil well offsetting first horizontal injector

3 hz producer / 3 hz injector overall flood performance: 70% recovery increase expected

• 2015-2017 waterflood implementation• 3 producers, 3 HZ injectors, 2 vertical injectors).

• AER applications prepared for anticipated 2020 waterflood expansion in 60-17 and pilot in 60-18

Highgraded floodable area metrics:• 18 sections – 175 mmbbls OOIP• Enhanced Oil Recovery adds 10-15mmbbl• Oil Reserves increase – 50% to 100%• Reserve Additions at $2.50/bbl

Core Operating Area – Waskahigan Montney

Key Statistics 2018 Production 1,731 boe/d 2018YE Reserves

PPDP 3.8 mmboe PPUD 18.4 mmboe (59 wells)

2018 NOI % ~30% of Total 2018 Operating Netback ~$26/boe 80.0 gross/net core Montney sections (100% WI) Inventory of ~ 200 locations OOIP = 565 mmbbl 65 net horizontal wells drilled. PPDP Ultimate Recovery Factor only 1%

Growth engine with significant drilling inventory

Upside Characteristics

Existing infrastructure can manage near-term growth with minimal additional capital investment required

Opportunity to materially reduce operating costs

Higher intensity fracturing to unlock additional reserves; Sproule bookings based on oil technology

Full field development plan built and cost savings opportunities identified

Over 12 pad sites have being surveyed and readied with produced water and infrastructure strategy

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Remaining Recoverable Locations EUR (mmboe)

Sproule PPDP 76 3.8

2018 YE Sproule PPUD 59 18.4

Unbooked locations 122 38.0

3 well summer program

100% WI ownership in infrastructure provides low operating costs and competitive advantage area

Infrastructure in Place Supports Growth Plan

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12-07-064-23W5 Battery Volumes

Capacity Q1 – 2019E Throughput

Current % Utilization

Oil Treating (bbl/d) 3,500 1,061 30%

Water Handling (bbl/d) 9,000 2,007 22%

Compression (mmcf/d) 17.0 9.01 53%

Refridge (mmcf/d) 20.0 9.01 45%

Oil Storage (bbl/d) 6,000 N/A

Water Storage (bbl/d) 6,000 N/A

1. Includes sales gas and volumes utilized for fuel gas and gas lift.

12-07-64-23W5 Battery

Higher Completion Intensity Enhances Productivity

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Waskahigan Montney Hz ResultsBy Completion Generation (Rate-Cum)

___________________________________________________Source: geoSCOUT, Frac Database.

Waskahigan Montney Hz ResultsBy Completion Generation (Rate-Time)

Dramatic increase in performance as the play moved to higher intensity water

based fracs and longer wells

Higher intensity fracs will extend the life of Generation 4 wells. An infill opportunity exists in

the under-exploited Generation 1 area

Generation 1 2 3 4 Forward Plan

Years 2011-2014 2014-2016 2014-2017 2014-2018 2019 +

# of Wells 50 8 4 6

Average Lateral Length (m) 1,442 1,851 1,462 2,293 2,300

Average # of Stages Per Well 18 20 19 30 - 50 50 – 65

Average Stage Spacing (m) 80 94 74 45 - 75 35 - 45

Average Proppant Intensity (T/m) (lb/ft) 0.20 (133) 0.52 (347) 0.71 (473) 0.63 – 1.1 (576) 0.90 - 1.1 (667)

Average Fluid Intensity (m3/m) 0.52 2.31 3.02 4.20 4.50 - 5.50

2018 and 2019-Q1 New Well Performance

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2018 and 2019-Q1 New Well Performance

• 2019-H2 Summer program will utilize the refined drill & complete strategy developed in 2018/2019-Q1.• Monobore drill• 65 stage NCS cemented liner system, 35T/stage (>1T/m frac intensity)

• Refined usage of N2 and resin at heel of well• All three wells will utilize 100% produced water recycle for fracs

• Bi-fuel initiative:• Have utilized bi-fuel on completions where service company can provide that capability• Have selected bi-fuel drilling rig (utilizing natural gas at padsite instead of diesel)

• Environmental & cost benefits

103/11-15-064-23W5:• 74 days of production cum of 50mbbl• Of all Alberta Montney oil wells drilled since 2011 (~1200 wells),

103/11-15 is within top 5% in terms of IP90

100/10-15-064-23W5:Well has recently increased from ~40 to ~80 bbl/d - increase due to lower line pressure (added compression)

16-17 Pad: with optimization complete (oil boost pump and blowcase install), oil production at 16-17 has increased ~200bbl/d (300boe/d) in the last week

16-17 Pad: with surface facilities optimization complete, oil production at 16-17 pad has increased by ~200 bbl/d (300 boe/d) in the last week

21

P25 P50 P75P10

TCE Waskahigan Relative to Other AB Montney Oil

22

Year On Stream

Cum

ulat

ive

3-m

onth

initi

al w

ell p

rodu

ctio

n (b

bl)

285 bbl/d type curve = 26,000 bbl/d first 3 months

Tangle Creek is getting significantly higher initial production performance than what previous operators accomplished in the area Waskahigan TC180 risked type curve (285 bbl/d IP90) is equivalent to a P25 well amongst all Montney hz oil wells drilled in

Alberta since 2011 (~1,200 wells)

• Key for Tangle Creek is to keep refining completions design with optimal execution and cost reduction as paramount objectives

• TCE wells rank very high amongst top Montney oil wells drilled in last several years

1. Cum IP90 for 100/10-15 was 26,000 bbl over 1,102 hrs, much less than typical 1,700 – 1,800 hrs over the first 3 months of production. 10-15 production was pro-rated up to 1,700 hrs to better represent this well’s IP.

2. Cum IP90 for 103/11-15 is a field estimate thru May 31, 2019. First production was March 14, 2019.

Cum IP90 for 100/04-23 (2,191 hrs)

Three of the first 6 Tangle Creek Waskahigan drills are top decile wells within Alberta Montney Oil plays

Roadmap to Reduce Per Well Capital

Phase 1 : Recipe Development ($6.8 to $5.8 MM) Frac Optimization ($650 K)

Frac Program Design / Pricing Utilization of produced water and setup of central

infrastructure 5.5” Monobore Drilling ($600 K)

Based on 102/11-15 Drill Cost Phase 2 : Recipe Refinement ($5.8 to $5.1 MM) Additional infrastructure development – water ($100 K)

optimization- compression – water disposal Pad construction Optimization ($100 K) Flow back Optimization ($300 K)

Reduction in cleanouts, swabbing, drillouts Using Resin sand and N2 on fracs

Phase 3 : Recipe Fine Tuning ($5.1 to $4.5 MM)• Logistics optimization – seasonal – pad selection – multi

pad drilling - water optimization ($200 K)• Existing infrastructure utilization ($100 K)• Economies of Scale – Program drilling ($200 K)• On Stream Time initiatives; reduced from 3 to 1.5

months Optimize inline flow back – equipping with

Blowcase, Pump, Gas Lift Pipeline prior to completion/drill

Continued completion optimization 2019-H2 plan is 65 stages (1.5mi laterals) and 35T fracs

Frac intensity: >1.0 T/m

$6.8 MM

$4.5 MM$5.1 MM

12$5.8 MM

3

1. F&Ds shown are based on our expected type curve of 220mbbl (425mboe)

F&D1: $16.00/boe $13.64/boe $12.00/boe $10.59/boe

23

Waskahigan Single Well Economics

40.00$ 50.00$ 60.00$ 40.00$ 50.00$ 60.00$ 40.00$ 50.00$ 60.00$ $4.5 $10.59 51% 96% 155% $4.5 $2.6 $4.3 $5.8 $4.5 18 12 9$5.0 $11.76 37% 72% 116% $5.0 $2.1 $3.8 $5.3 $5.0 22 14 10$5.5 $12.94 27% 54% 89% $5.5 $1.6 $3.3 $4.8 $5.5 28 17 12

40.00$ 50.00$ 60.00$ 40.00$ 50.00$ 60.00$ 40.00$ 50.00$ 60.00$ $4.5 $11.90 36% 70% 115% $4.5 $1.8 $3.4 $4.8 $4.5 23 14 10$5.0 $13.23 25% 52% 86% $5.0 $1.3 $2.9 $4.3 $5.0 30 17 12$5.5 $14.55 17% 38% 65% $5.5 $0.8 $2.4 $3.8 $5.5 40 21 14

40.00$ 50.00$ 60.00$ 40.00$ 50.00$ 60.00$ 40.00$ 50.00$ 60.00$ $4.5 $15.79 26% 55% 91% $4.5 $1.2 $2.8 $4.1 $4.5 29 17 12$5.0 $17.54 18% 40% 67% $5.0 $0.7 $2.3 $3.6 $5.0 39 21 14$5.5 $19.30 12% 29% 50% $5.5 $0.2 $1.8 $3.1 $5.5 55 27 17

CAPEX / Well ($MM)

CAPEX / Well ($MM)

CAPEX / Well ($MM)

PV-10 ($MM) Payout (mo)

Edmonton (US$) Edmonton (US$) Edmonton (US$)

Edmonton (US$) Edmonton (US$) Edmonton (US$)CAPEX / Well ($MM)

CAPEX / Well ($MM)

Edmonton (US$) Edmonton (US$) Edmonton (US$)

Waskahigan Risked Type Curve - 1.5 Mile Wells - TC195mbbl / 378mboe (IP90= 315bbl/d flat)

IRR PV-10 ($MM) Payout (mo)

CAPEX / Well ($MM)

CAPEX / Well ($MM)

Waskahigan Base Case Type Curve - 1.5 Mile Wells - TC180 / 344mboe (IP90= 285bbl/d flat)

Waskahigan Internal Case Type Curve - 1.5 Mile Wells - TC220mbbl / 425mboe (IP90= 354bbl/d flat)

Well F&D ($/boe)

Well F&D ($/boe)

Well F&D ($/boe)

CAPEX / Well ($MM)

IRR PV-10 ($MM) Payout (mo)

CAPEX / Well ($MM)

IRR

At US$50 Edmonton pricing, type curves generate 40% to 70% IRRs and payouts of ~ 12 to 20 months 2019 average asset operating netback of $27/boe with a range of $21 - $37/boe 1

1 operating netback before hedging, interest, and Corporate G&A2 economic analysis assumes Fx = 0.75, CDN$6.50/bbl adjustment for PSO/WADF, quality & transport,

realized gas price of CDN$1.75/mcf 24

Benchmarking North American Resource Plays

0%

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Half Cycle IRR’s (US$60 WTI / US$3 NYMEX)1

Source: TPH, Company Disclosure.1. WTI of US$60/bbl. Ed. Par differential of US$8.00/bbl. NYMEX of US$3.00/mmbtu.

AECO differential of US$1.25/mmbtu. USD/CAD of 1.30x.

First 24 Month Royalty

5%

18%

8%

28%

0%

5%

10%

15%

20%

25%

30%

Montney U.S. Plays

On average, Crown royalties for new

Montney wells are 5% while freehold

royalties for most U.S. plays average

18% to 28%

Benchmark Prices (US$)

$52 $

60

Mon

tney

U.S

.

Oil Price

$1.7

5

$3.0

0

Mon

tney

U.S

.

Gas Price

Top U.S. Plays

Select Canadian Plays

Tangle Creek

Tangle Creek @ US$10/bblEdmonton Par Differential

DCET(US$MM) $7.7 $8.5 $6.8 $3.9 $7.7 $7.2 $3.9 $6.1 $3.9 $7.2 $5.2 $7.2 $7.2 $7.9 $7.7 $7.2 $8.6 $9.0 $8.5 $7.3 $9.7 $9.0 $8.3 $9.8 $9.7 $6.5 $7.7

Raw IP30(boe/d) 1,922 2,001 1,800 819 1,198 1,843 355 1,024 694 1,566 1,450 1,566 1,511 1,603 851 1,511 546 1,871 1,988 1,122 1,477 2,049 1,634 1,799 1,101 1,635 504

Sales EUR

(Mboe)1,464 1,725 1,200 422 1,479 1,143 582 924 358 1,021 1,159 1,021 1,273 1,092 1,118 1,246 1,260 827 1,892 894 1,199 1,121 1,166 1,368 851 1,263 758

25

Tangle Creek –Montney Economic Range of Results

Tangle Creek – Summary

High Quality – High Margin Assets – Light oil focus with running room• Material drilling inventory to drive long-term growth• Top tier returns• Strong technical expertise• Own and control the infrastructure• Egress secured

Consolidation Opportunities – further expand light oil drilling inventory• Waskahigan is considered non-core to other players in the area• Seeking opportunistic acquisitions – taking advantage of the depressed

Canadian energy sector

Strong shareholder returns – targeting liquidity event in 24-36 months• Further multiple expansion through consolidation and growth

26

Contact Information

Tangle Creek Energy Ltd.2100, 715 – 5th Avenue SWCalgary, Alberta T2P 2X6Main: +1 (403) 648-4900www.tanglecreekenergy.com

Glenn GradeenPresident & CEOd: +1 (403) 648-4901m: +1(403) 618-0434ggradeen@tanglecreekenergy.com

Jean-Pierre (J.P.) BuyzeChief Financial Officerd: +1 (403) 648-4903m: +1 (403) 991-2442jpbuyze@tanglecreekenergy.com

Ben MakarVice President Engineeringd: +1 (403) 648-4905m: +1(403) 614-7311bmakar@tanglecreekenergy.com

27

AGM Presentation�Forward-Looking StatementManagement and GovernanceThe Vision – Create a High-Quality, High-Growth Business� Slide Number 5Environmental, Social & Governance PerformanceEnvironmental, Social & Governance PerformanceTangle Creek OverviewKey StrengthsIncome Statement ReviewBalance Sheet Review Tangle Creek Operating AreasCore Operating Area – Kaybob DunveganTrack Record of Well Performance Improvements…… And Strong Well EconomicsSlide Number 16Core Operating Area – Waskahigan MontneyInfrastructure in Place Supports Growth PlanHigher Completion Intensity Enhances Productivity2018 and 2019-Q1 New Well Performance2018 and 2019-Q1 New Well PerformanceTCE Waskahigan Relative to Other AB Montney OilRoadmap to Reduce Per Well CapitalWaskahigan Single Well EconomicsBenchmarking North American Resource PlaysTangle Creek – SummaryContact Information