Corporate Presentation April 2019 Forward-Looking Statement This - - PowerPoint PPT Presentation

Corporate Presentation

April 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

• r 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

2

Tangle Creek Overview

• Private company founded in 2010
• Owners include ARC Financial, Wells Fargo and

Camcor

• 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

3

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

30 miles

Production (boe/d) 2018 Production % Liquids 7,869 53% Reserves (mmboe)1 PDP Proved Proved + Probable 13.5 27.2 51.1

Hwy 43 Hwy 32 Hwy 16

Waskahigan Kaybob

Windfall

Carrot Creek

Tangle Creek Field Office

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 Currie

Chairman

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 Gradeen

Berkana, Rosetta, Ocelot

Vice President, Exploration

Alison Essery

Conoco-Burlington, Shell

Vice President, Engineering

Ben Makar

Cenovus, Encana

Vice President, Production

Greg Kondro

Rosetta, Ocelot

Director, Business Development

Robyn Lore

Berkana, Rosetta, Kallisto

Vice President, Land

Jim Junker

Nordegg, Burmis, Wascana, Shell

CFO

J.P. Buyze

Trident, UBS Securities

Strong leadership from highly experienced management team and board of directors

4

The Vision – Create a High-Quality, High-Growth Business

Focused on high-margin, high-growth business with significant running room

5

 Focus on top-tier, high margin, light-tight oil plays  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  Maintain low financial leverage

• Capital program scalable depending on market conditions (pricing and differentials)
• Capital and growth is funded by internally generated cash flow

 Maintain high Environmental, Social and Governance standards  Liquidity for investors within 24 to 36 months

Key Strengths

6

1. Large Inventory of Highly Economic Drilling Locations

 More than 300 oil-weighted locations (10+ years)  Potential to double production by 2022 at current strip prices  Light oil wells have demonstrated to be amongst the 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

6. Maintain Strong Financial Position

 Crucial in volatile commodity pricing environment  Syndicated credit facility of $130.0 million

Tangle Creek Operating Areas

22% 51% 27%

PDP

44% 33% 23%

P+P

22% 44% 34%

2018E

70% 23% 7%

2023E2

7

Production Profile1 Reserve Split by Area Production Split by Area Kaybob Waskahigan Other Legend

13.8 mmboe 51.4 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 Production (boe/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%

8 2017 drilling program (9 wells) 2018 drilling program (4 wells)

Maintaining production ~ 3,000 boe/d

Track Record of Well Performance Improvements…

Kaybob Dunvegan Annual Drilling Programs Historical DC&T Costs

9

Historical Days Drilling

Cumulative Production - boe

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 9 259 2016 4 204 2015 1 133 2014 18 173 2013 13 131 2011 - 2012 27 115 Total 76

New Completion Design Target Well Cost

… And Strong Well Economics

10

Dunvegan Well Inputs Dunvegan Well Economics1 Kaybob Dunvegan Type Curves

TC129 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)

3,300

10,800

3,300

10,800

Stage Count 25 25 Frac Intensity (T/m)

(lbs/ft)

0.4

270

0.4

270

TC129 TC155 NPV-10 ($MM) 1.8 2.6 P/I Ratio 1.7x 2.0x IRR% 46% 73% Payout (Months) 23 16 F&D ($/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 75% IRRs and payouts of 1 to 2 years

1. Assumes natural gas prices, net of transportation, of C$2.00/mcf and FX of $0.75.

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 $ $2.25MM 51% 97% 166% $2.25MM $1.7 $2.8 $3.8 $2.25MM 21 13 9 $2.50MM 39% 73% 122% $2.50MM $1.5 $2.6 $3.6 $2.50MM 26 16 11 $2.75MM 30% 56% 93% $2.75MM $1.2 $2.3 $3.3 $2.75MM 32 19 13 40.00 $ 50.00 $ 60.00 $ 40.00 $ 50.00 $ 60.00 $ 40.00 $ 50.00 $ 60.00 $ $2.25MM 31% 61% 102% $2.25MM $1.0 $2.0 $2.9 $2.25MM 31 19 13 $2.50MM 24% 46% 77% $2.50MM $0.8 $1.8 $2.6 $2.50MM 39 23 15 $2.75MM 18% 36% 59% $2.75MM $0.5 $1.5 $2.4 $2.75MM 49 28 18

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

CAPEX / Well CAPEX / Well CAPEX / Well IRR PV-10 ($MM) Payout (mo) Dunvegan P90 Risked Type Curve - 1.0 Mile Wells - TC129 mbbl / 162mboe EUR

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

CAPEX / Well CAPEX / Well CAPEX / Well IRR PV-10 ($MM) Payout (mo) Dunvegan P50 Type Curve - 1.0 Mile Wells - TC155 mbbl / 194mboe EUR

Waskahigan Property Acquisition (Acquired October 2017)

Tangle Creek acquired RMP’s Waskahigan Montney light oil Assets for C$80 million in October 2017

• Established new growth engine and core area
• Light oil production – API gravity 36˚ to 38˚
• Acquisition primarily funded through equity financing

Rationale for Montney Oil Acquisition

• Over 500 million barrels Original Oil In Place
• Clear opportunity to implement new completion methods and

technologies to extract greater value (validated through 2018/19 program results) Acquisition Included Infrastructure Control

• 100% working interest ownership of key facilities and

infrastructure to support future growth Development Plan

• Seeking to more than double corporate production through

Waskahigan Montney oil development

• Initial 6 Montney wells drilled by H1 2019 with enhanced

completion practices 11

Recent ECA and POU Montney drills Active Duvernay Fairway

Initial 6 Tangle Creek wells have already increased field production by ~ 150 %

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%

Tangle Creek’s 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
• pportunities identified
• Over 12 pad sites have being surveyed and readied

with produced water and infrastructure strategy 12

Remaining Recoverable Locations EUR (mmboe) Sproule PPDP 76 3.8 2018 YE Sproule PPUD 59 18.4 Unbooked locations 122 38.0

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

Infrastructure in Place Supports Growth Plan

13

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

Significant Upside Relative to Current Reserve Bookings

14

• Growth is achieved by expanding play out in the West and

“filling in” / infilling within the previously under-stimulated Montney to the East

• Evolving area strategy unlocks significantly more value:

1. Increased capital efficiencies through 1.5 mile wells 2. Ability to implement modern, higher frac intensity completion techniques (increased proppant intensity, increased pumping rates, reduced stage spacing, etc.) 3. OOIP supports densifying development beyond its original 4 well per section design – increased inventory and ultimate recovery at 5 wells per section 4. Significant infrastructure now in place to more efficiently execute the growth plan:

• Produced water piped to pads for frac’ing
• perations – no fresh water use or hauling costs
• Growth capacity in place for emulsion treating, gas

compression, and water disposal

• Large inventory of future locations enables continuous reserve

growth: Unbooked Areas Tighter Well Spacing = 20% More Locations = Increased RF

Higher Completion Intensity Enhances Productivity

15

Waskahigan Montney Hz Results By Completion Generation (Rate-Time)

___________________________________________________ S

• urce: geoS

COUT, Frac Dat abase.

Waskahigan Montney Hz Results By Completion Generation (Rate-Cum)

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

Demonstrating Enhanced Completions on Montney Oil

16

• Predecessor Company’s Completion

Practices:

• Initially oil based fracs and low proppant

intensity (<20T)

• Evolved to cross-linked gels

(reduced near well-bore perms)

• Wide frac spacing, 1 mile laterals
• Enhanced Frac Spacing:
• Historically: 70-120 m

(<30 stages)

• Tangle Creek: ~35-45 m

(50-65 stages)

• Enhanced Proppant Intensity:
• Historically: 0.2T to 0.6 T/m (133 – 400

lb/ft) with oil or cross-linked gels

• Tangle Creek: 0.9 - 1.1 T/meter with

slickwater (667 lb/ft)

• Other Enhancement Initiatives:
• Evolved to 1.5 mile or longer laterals
• Opportunity for infilling or EOR in

legacy under-stimulated areas

Generation 1: Oil based fracs, 12-20 stages, 10-15 T/stage, 70-120 m inter-frac spacing Generation 2 & 3: Hybrid Slickwater fracs, 17-30 stages, 50 T/stage, 80 m inter-frac spacing Tangle Creek: Slickwater fracs, 50 stages, 50T+/stage, 40-50 m inter-frac spacing. Default to 1.5 mile long wells Generation 2: Continued use of gelling agents, short laterals, and low frac-intensity 2018 – 2019 Tangle Creek Design Target Tangle Creek Type Curve (220 mbbl) Generation 1 Generation 3: Generally slickwater, 50 T/stage but low stage count Generation 4 Generation 4

P25 P50 P75 P10

TCE Waskahigan Relative to Other AB Montney Oil

17

Year On Stream Cumulative 3-month initial well production (bbl/d) 285 bbl/d type curve = 26,000 bbl/d first 3 months

• Tangle Creek is getting significantly higher initial production performance than what RMP accomplished
• Waskahigan TC180 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 a paramount objective

• TCE wells rank very high amongst top

Montney oil wells drilled in last several years

1. Cum IP90 for 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.

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

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)
• ptimization- 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

18

• Continue 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

1 2

$5.8 MM

3

Highly Attractive Well Economics (1.5 mile wells)

19

Waskahigan Montney Well Inputs Waskahigan Montney Well Economics1 Waskahigan Montney Type Curves

TC195 TC220 DCET Capital ($MM) 5.0 5.0 EUR (Oil) (mbbl) 195 220 EUR (mboe) 378 425 IP90 (bbl/d) 315 354 Measured Depth (m)

(feet)

4,700

15,400

4,700

15,400

Stage Count 50 - 65 50 - 65 Frac Intensity (T/m)

(lbs/ft)

~1.0

700

~1.0

700

TC195 TC220 NPV-10 ($MM) 2.0 2.9 P/I Ratio 1.6x 1.8x IRR% 54 75 Payout (months) 17 13 F&D ($/boe) 13.22 11.76 3 mo Capital Efficiency ($/boe/d) 15,873 13,227 Netback ($/boe) 25.66 25.98

Economic Sensitivity Tables1 At US$50 Edmonton pricing, type curves generate 50% to 75% IRR with payouts less than 1.5 years

1. Assumes natural gas prices, net of transportation, of C$2.00/mcf and FX of $0.75.

40.00 $ 50.00 $ 60.00 $ 40.00 $ 50.00 $ 60.00 $ 40.00 $ 50.00 $ 60.00 $ $4.5MM 54% 101% 160% $4.5MM $2.8 $4.5 $6.0 $4.5MM 17 11 9 $5.0MM 40% 75% 120% $5.0MM $2.3 $4.0 $5.5 $5.0MM 21 13 10 $5.5MM 29% 57% 92% $5.5MM $1.8 $3.5 $5.0 $5.5MM 27 16 12 40.00 $ 50.00 $ 60.00 $ 40.00 $ 50.00 $ 60.00 $ 40.00 $ 50.00 $ 60.00 $ $4.5MM 38% 73% 119% $4.5MM $1.9 $3.5 $4.9 $4.5MM 22 14 10 $5.0MM 27% 54% 89% $5.0MM $1.4 $3.0 $4.4 $5.0MM 29 17 12 $5.5MM 19% 40% 67% $5.5MM $0.9 $2.5 $3.9 $5.5MM 38 21 14

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

CAPEX / Well CAPEX / Well CAPEX / Well IRR PV-10 ($MM) Payout (mo) Waskahigan P50 Type Curve - 1.5 Mile Wells - TC220mbbl / 425mboe (IP90= 354bbl/d flat) CAPEX / Well CAPEX / Well CAPEX / Well

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

Waskahigan P90 Risked Type Curve - 1.5 Mile Wells - TC195mbbl / 378mboe (IP90= 315bbl/d flat) IRR PV-10 ($MM) Payout (mo)

03/11-15-064-23W5 Drill Feb – On stream March 18, 2019

Benchmarking North American Resource Plays

0% 25% 50% 75% 100% 125% 150% Top Quart ile Delaware VII Nest 2 Top Quart ile Midland TCE 220 Mbbl Oil Chevron Duvernay 250 bbl/ MMcf ECA Pipest one Very Rich Gas STAC K Average Midland TCE 190 Mbbl Oil Eagle Ford NVA Pipest one VRG NVA Bilbo ECA Pipest one Rich Gas Average Delaware Chevron Duvernay 150 bbl/ MMcf NVA Pipest one SCOOP POU Smoky Duvernay VII Nest 3 VII Nest 1 ECA Duvernay Sout h POU Kaybob Duvernay NVA Gold Creek POU Karr ECA Duvernay Nort h NVA Elmwort h Chevron Duvernay 50 bbl/ MMcf

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 Montney U.S. Oil Price $1.75 $3.00 Montney U.S. Gas Price

Top U.S. Plays Select Canadian Plays Tangle Creek Tangle Creek @ US$10/bbl Edmonton 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

20 Tangle Creek – Montney Economic Range of Results

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 Low Corruption

Why 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 21

Environmental, Social & Governance Performance

Tangle Creek 2017

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

• perational 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.

22

Environmental, Social & Governance Performance

23

Tangle Creek – Committed to reducing emissions intensity

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
• Strong financial position

 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

24

Contact Information

Tangle Creek Energy Ltd. 2100, 715 – 5th Avenue SW Calgary, Alberta T2P 2X6 Main: +1 (403) 648-4900 www.tanglecreekenergy.com Glenn Gradeen President & CEO d: +1 (403) 648-4901 m: +1(403) 618-0434 ggradeen@tanglecreekenergy.com Jean-Pierre (J.P.) Buyze Chief Financial Officer d: +1 (403) 648-4903 m: +1 (403) 991-2442 jpbuyze@tanglecreekenergy.com Ben Makar Vice President Engineering d: +1 (403) 648-4905 m: +1(403) 614-7311 bmakar@tanglecreekenergy.com

25

Additional Corporate Information

Appendix 1

26

• ARC-backed private company started late 2010
• Management team – technical, experienced and

driven to quality

• Two high margin light-tight oil plays – Montney and

Dunvegan

• Industry leader – light-tight oil
• 1st to drill multistage horizontal – 1st ball drop system – 1st cemented liner

system

• 1st approval for Dunvegan water flood
• 1st Dunvegan slick-water completion
• Motivated management team (30+ deals to “own our plays”)
• 35% compound annual production growth from 2012-2017+
• Scalable, high value, light-tight oil producer via

strategic acquisition and innovation

• Waskahigan Montney oil acquisition – October 2017

 Financed with 88% new equity ½ of which came from existing

shareholders.

 New equity investor support from Wells Fargo

• Positioning – consolidator of Montney oil play
• Development inventory through mid-2020s
• Focused operations on high margin light sweet oil
• Infrastructure in place to double production without facilities capital
• Follow-on acquisitions identified and negotiated

Dec 2010 – Formation, Q1 2011 initial capital raised at $1/sh 2013 – Acquisition of Talisman Dunvegan assets, equity raise at $1.25/share; enables 2014 organic growth to 5,000 boe/d Q4 2011 – Initial Kaybob test well leading to 2012 concept development 2015 – Acquisition of Trilogy Dunvegan assets, equity raise at $1.25/sh; Windfall well 2016 – Beringer acquisition to capture Rock Creek oil and Mannville liq. rich gas, Dunvegan waterflood implementation

Tangle Creek History, Background and Drive to Quality

TCE Corporate Events Business Strategy

Assemble experienced technical team, seek shallow oil exploration-

• riented asset base

Demonstrate Dunvegan economics Seek acquisitions to consolidate economic inventory; focus on oil- weighted assets - economic at or below strip prices; maintain geographic concentration Consolidate leading Dunvegan land position; de-risk inventory; advance well design and completion practices Slow capital investment to maintain balance sheet strength during commodity price downturn 2017 – Transformational acquisition of Montney oil assets

2011 2012 2013 2014 2015 2016 2017 2018

2018 – Organic growth and Consolidation

27

Production and Reserves History

Production Profile 2018 Reserves Summary

Liquids (mmbbl) Gas (bcfe) Total (mmboe) PV-10% (C$MM) Proved PDP PDNP PUD 7.1 0.2 7.8 38.3 1.0 32.9 13.5 0.4 13.3 $222.0 3.9 126.3 Total Proved 15.1 72.2 27.1 352.2 Probable 12.6 67.8 23.9 314.5 Total Proved + Probable 27.7 140.0 51.1 $666.7

Reserves History

28

Production Weighting

834 1,947 2,923 2,582 2,493 3,542 4,189 411 825 1,008 1,088 1,663 2,648 3,675

67% 70% 74% 70% 60% 57% 53% 0% 10% 20% 30% 40% 50% 60% 70% 80%

• 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

Oil and NGL weighting

Oil & NGL (bbl/d) Gas (boe/d) Liquids (%)

Summary of Hedging Portfolio – Crude Oil (4/15/2019)

29

Hedging Volumes Hedging Prices Nearly all of our oil is hedged at Edmonton (MSW) for 2019 but still at WTI for 2020.

0% 10% 20% 30% 40% 50% 60% 70% 80%

• 500

1,000 1,500 2,000 2,500 3,000 Q1 18 Q2 18 Q3 18 Q4 18 Q1 19 Q2 19 Q3 19 Q4 19 Q1 20 Q2 20 Q3 20 Q4 20 MSW - Swaps (bbl/d) MSW - Collars (bbl/d) WTI - Swaps (bbl/d) WTI - Collars (bbl/d) % of Blowdown $40.00 $45.00 $50.00 $55.00 $60.00 $65.00 $70.00 $75.00 $80.00 $85.00 Q1 18 Q2 18 Q3 18 Q4 18 Q1 19 Q2 19 Q3 19 Q4 19 Q1 20 Q2 20 Q3 20 Q4 20 WTI - Swaps (C$/bbl) WTI - Ceiling (C$/bbl) WTI - Floor (C$/bbl) MSW - Swaps (C$/bbl) MSW - Ceiling (C$/bbl) MSW - Floor (C$/bbl)

Summary of Hedging Portfolio – Natural Gas (4/15/2019)

30

Hedging Volumes Hedging Prices Nearly all of our hedged gas is priced at Chicago for 2019 and 2020.

Chicago Collars converted at strip F/X rates

0% 10% 20% 30% 40% 50% 60% 70% 80%

• 2,000

4,000 6,000 8,000 10,000 12,000 14,000 Q1 18 Q2 18 Q3 18 Q4 18 Q1 19 Q2 19 Q3 19 Q4 19 Q1 20 Q2 20 Q3 20 Q4 20 Chicago - Swaps (mmbtu/d) Chicago - Collars (mmbtu/d) AECO - Swaps (Gj) AECO - Collars (Gj) % of Blowdown $2.00 $2.20 $2.40 $2.60 $2.80 $3.00 $3.20 $3.40 $3.60 $3.80 $4.00 Q1 18 Q2 18 Q3 18 Q4 18 Q1 19 Q2 19 Q3 19 Q4 19 Q1 20 Q2 20 Q3 20 Q4 20 Chicago - Swaps (C$/mmbtu) Chicago - Ceiling (C$/mmbtu) Chicago - Floor (C$/mmbtu) AECO - Swaps (C$/Gj) AECO - Ceiling (C$/Gj) AECO - Floor (C$/Gj)