Tangle Creek Corporate Presentation

Positioning the Company for Sustained Growth

April 2016

2

This presentation contains "forward-looking statements" including estimates of future production, cash flows and reserves, business plans for drilling and exploration,

the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based and related sensitivity analyses, and other expectations,

beliefs, plans, objectives, assumptions or statements about future events or performance (often, but not always, using words or phrases such as "expects" or "does not

expect", "is expected", "anticipates" or "does not anticipate", "plans", "estimated" or "intends", or stating that certain actions, events or results “may", "could", "would",

"might" or "will" be taken, occur or be achieved). In particular, this presentation contains forward-looking statements pertaining, to the following: Tangle Creek Energy

Ltd.’s (“Tangle Creek” or the “Company”) 2015 and 2016 production outlooks and cash flow forecasts; the Company’s 2016 capital budget, as well as drilling and

development plans and the timing and costs thereof; the Company's expected capital spending flexibility and ability to take advantage of available opportunities; the

ability of the Company to maintain its balance sheet strength; type well economics and performance; drilling inventory; estimated recycle ratios; the anticipated impact

of waterflood activities; the timing and cost savings associated with planned infrastructure; resource upside opportunities available to the Company; the possible upside

and the liquid expectations at the Company’s new Mannville play; and the ability of the Company to manage the current low oil price environment.

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. There are numerous

uncertainties inherent in estimating crude oil, natural gas and NGL reserves and the future cash flow attributed to such reserves. The reserve and associated cash

flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve

recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and

future operating costs, all of which may vary materially. Actual reserve values may be greater than or less than the estimates provided herein.

All forward-looking statements are based on Tangle Creek’s beliefs and assumptions based on information available at the time the assumption was made. Tangle

Creek believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to

be correct and such forward-looking statements included in this presentation should not be unduly relied upon. By their nature, such forward-looking statements are

subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated,

expressed or implied by such statements. In addition, risk factors include: financial risk of marketing reserves at an acceptable price given market conditions; volatility

in market prices for oil and natural gas; delays in business operations, pipeline restrictions, blowouts; the risk of carrying out operations with minimal environmental

impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are

interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at a reasonable cost;

uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things,

capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of

acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance;

fluctuations in foreign exchange and interest rates; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions;

uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk;

and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry. These risks and uncertainties could cause

actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements. The impact of any one risk, uncertainty or

factor on a particular forward-looking statement is not determinable with certainty as these are interdependent.

Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion

method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Tangle Creek assumes no obligation to update forward-

looking statements should circumstances or management's estimates or opinions change. Certain information contained herein have been prepared by third-party

sources. The information provided herein has not been independently audited or verified by the Company.

Forward Looking Statements

“If you are going through hell….

…Be sure not to stop…”

Winston Churchill

3

Tangle

Creek

Team

Building

The

Business

Founding Team of 7 Experienced Business Builders 12 full-time + 5 part-time & consultants + 10 field

Technical team - experienced with emerging technologies

5 years building Tangle Creek

Tangle Creek Energy Ltd. incorporated November 2010 - initial

equity raise completed March 2011

Equity invested of $185 million – 22 shareholders

ARC Financial & Camcor – longest standing energy PE firms in

Canada

Tangle Creek Corporate Profile

Business

Plan

Light tight oil & liquids rich gas

Candidates for emerging tight rock technologies

High margin – low risk – development opportunities

Operatorship, high working interests

Concentrated assets, material land positions & drilling inventory

Growth through combination of acquisitions & drilling

4

5

Board of Directors

Jim Pasieka Glenn Gradeen

CEO

Camcor Partners Inc.

Cam McVeigh

Tangle Creek Energy

Lauchlan Currie

ARC Financial Corp.

Chairman

Dan Botterill

P.Eng.

Independent Director

Larry M Jones

Independent Director

McCarthy Tétrault

6

Executive Team

Glenn Gradeen

Greg Kondro

Alison Essery Cam Virginillo

John Pantazopoulos

Berkana, Rosetta, Ocelot

Rosetta, Ocelot

Conoco-Burlington, Shell PetroBakken, Berens

Enerplus

EnCana, Berens, Skywest

Chief Executive

Officer

Vice President

Production

Vice President

Exploration

Vice President

Engineering &

Chief Operating Officer

Chief Financial

Officer

Steve Holyoake

Vice President,

Drilling & Completions

Petro-Reef, Terra

Mike McGeough

Berens, MarkWest

Vice President

Land

In November 2014, with the onset of weakening commodity prices, we established a

corporate strategy that presumed longer term weakness in oil & gas prices and the

opportunity to position the company for the future.

Our focus since the beginning of 2015… Protect the balance sheet & keep debt to cash flow at 2x or less – even in the face of weak pricing

Maintain financial strength and flexibility

Production – “pause” on continued growth Develop and strengthen relationships with equity providers

No drilling until Q4 2015 – preserve high value, high quality Dunvegan drilling inventory

Shut in high margin/low royalty/high performing wells – wait for improved prices

Focus on preserving & improving operating margins through reductions in costs – especially “structural”

changes: e.g. trucking, sales pipelines, improved processing, improved technologies, better efficiencies

and third party processing & handling

Maintain flexibility to acquire assets – in a prolonged weak price environment opportunities happen

Develop and strengthen relationships with equity providers

Position the company for future growth

Add new grassroots opportunities

7

Tangle Creek Energy Ltd. – Dealing with Uncertainty

8

Tangle Creek – Corporate Strategic Positioning

Efficient and Effective Light Oil Producer Best in class FD&A and Recycle Ratios

Capital costs driven down 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

Kaybob grown from 0 to 4,000 boe/d in 3 years – 75% light sweet crude with over 450 mmbbls OIP on

Tangle Lands

Most active, experienced Dunvegan oil operator

Grassroots Liquids Rich Opportunity Identified & Captured 66 net sections acquired with material liquids rich gas potential – estimating 30 to 60 bbls/mmcf

150+ potential net locations identified

Opportunistic Acquirer With Strong Balance Sheet Since inception, completed $130mm in acquisitions while keeping debt / cash flow under control

Over $50mm 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

Production – 2016 Forecast ~ 3,800 boe/d (70% light oil)

• Production Margins (Field Netbacks - before hedging, G&A, E&E, interest)

2014 Operating netback of $53/boe

2015 Operating netback ~ $24/boe (forecast before hedging)

• 90%+ operated production

2016 Cash Flow forecast ~ $25mm (strip) - $0.13/share

Reserves - 18mmboe (Jan 2016) – 75% light sweet crude (36°API)

Land – 135 net sections

Corporate historic FD&A - $20/boe (includes July 2015 acquisition & FDC)

2016 CAPEX ~$17mm • Maintain production of 3,800 – 4,000 boe/d

• Delever balance sheet to < $50mm of debt (target – 2.0x debt / cash flow)

Strategic use of hedges to support capital expenditures • 1,300 bbls/d Fiscal 2016 @C$72 / bbl (60% of production)

• 5.25 mmcf/d Fiscal 2016 @ C$3.00 / mcf (60% of production)

9

Tangle Creek Energy Ltd. – Operations Snapshot

10

Tangle Creek Energy Ltd. – Cash Flow Secured to Pursue CAPEX Program

-$10.0

-$5.0

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

$10.00 $15.00 $20.00 $25.00 $30.00 $35.00 $40.00 $45.00 $50.00 $55.00

C$

mm

US$ / bbl

Tangle Creek Energy Ltd. Forecasted Cash Flow

Hedging Gain Non Hedging Cash Flow

2016 CAPEX

Sustained production growth

17% CAGR on a production / debt adjusted share basis

27% annual cash flow growth (Strip pricing)

~40% of 2016 crude oil hedged at > C$70 / bbl

2015 CF $34mm - 2014 CF - $67mm

Q4 2015 debt - $60mm ($100mm credit line)

11

Tangle Creek – Historic Performance

1,245

2,772

3,931 3,800

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

2012 2013 2014 2015E

bo

e/d

Production

9

18 18 18

0

2

4

6

8

10

12

14

16

18

20

2012 2013 2014 2015

P+P

Res

erve

s (m

mb

oe)

Reserves

$15

$38

$67

$34

$0

$10

$20

$30

$40

$50

$60

$70

$80

2012 2013 2014 2015E

Cas

h F

low

($

mm

)

Cash Flow

Concentrated – High Interest Asset Base – Two Projects

Balanced Asset Base Single operating area on Hwy 43

between Edmonton & Grand Prairie

Excellent access & infrastructure

Balanced between solid cash flow

base & undeveloped lands

1. Kaybob Dunvegan

Light sweet crude oil – 36°API

3,500 – 3,700 boe/d – 90% operated

69 net sections – 90 net wells

Ownership of key infrastructure

120 to 200 net locations at 4 to 6

wells/section

450+ mmboe OOIP on Tangle Lands

Waterflood project commenced Q1

2015 – Preliminary results

encouraging

2. Windfall Mannville

Multi-zone liquids rich

66 net sections

2 wells drilled – 2-4 follow-up

locations in H2 - 2016

150 net locations identified

Estimating 2 to 5 BCF per location

Kaybob Dunvegan

TCE Dunvegan Lands – 450 mmbbls OIP

111 (69 net) sections

Company Interest 2P Reserves @ July 31, 2015

= 22 mmboe

~3,800 boe/d in 2015

~90 wells

Windfall Mannville

TCE Lands – 67 (66 net) sections

12

Well established oil

project – initial proof of

concept and

development by Tangle

Creek in 2011

High margin, high quality

project – close to

services and

infrastructure in

Whitecourt, Fox Creek,

Edmonton and Grand

Prairie

Tangle Creek Dunvegan

wells have often been

reported as among the

top oil wells in Alberta (Industry Research by Scotia

Capital, AltaCorp, National

Bank and others)

Kaybob Dunvegan – Light Sweet Crude Oil

13

Tangle Creek – Dominant Dunvegan Light Oil Position

14

TCE Internal Locations (195 Gross)

8 Tier 1 – High Type Curve

48 Tier 2 – Base Type Curve

139 – Tier 3 & 4 Low Base and

Gassy Type Curve

Existing Dunvegan Hz Wells

64 (55.9 net) Operated Wells

28 (7.8 net) non-Operated

Tier 1 Tier 2 Tier 3 Tier 4 TTL

Gross 8 48 126 13 195

Total Net 8.0 38.2 76.0 6.6 128.8

Total Locations 128.8

Already in SAL Dec 31 Report 24.6

15

Dunvegan Stratigraphy – Kaybob South

Dunvegan

Carbonates

Dunvegan vertical depth is 1,600 to 1,800 m at Kaybob Total hole length is typically 3,000 m to 3,400 m

Drill times are 9 to 11 days

Adapted from Canadian Discovery Digest

0

1,000

2,000

3,000

4,000

5,000

6,000

2011 - DRILLED & NONOP WELLS 2011 - ACQUIRED WELLS 2012 - DRILLED WELLS 2012 - ACQUIRED WELLS

NIPISI 2013 - DRILLED WELLS 2013 - ACQUIRED WELLS 2014 - DRILLED WELLS

2014 - OTHER 2015 - DRILLED WELLS 2015 - ACQUIRED WELLS

Dunvegan Drilling Vintages – Wells with 2 to 3 years History are down to ~20% declines

16

2014 Drilling

2013 Drilling 2012 Drilling

2011 Drilling

3rd Party

Solution Gas

Processing

Restriction

Solution Gas

Take-away

Restriction 2015

Acquisition

0

50

100

150

200

250

300

350

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Bb

ls/d

Month

Tier 1 Dunvegan Type Curve Tier 2 Dunvegan Type Curve

Dunvegan Type Curves - Half Cycle Economics (capex $2.5mm/well)

Note: Y Axis is oil – for boe/d add 25%

US$70 Oil, C$3.00 gas Strip Flat US$50 / C$2.50

Oil

(mbbls) Total

(mboe) NPV 10 IRR NPV 10 IRR NPV 10 IRR

Tier 1 225 300 $5.0mm 162% $4.1mm 90% $2.9mm 68%

Tier 2 175 230 $3.2mm 65% $2.6mm 42% $1.6mm 31%

17

EUR

Type

Curve

boe/d Oil Gas

IP30 IP365 mboe mbbls mmscf

Tier 1 400 180 300 225 400

Tier 2 200 110 230 175 300

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

$7,000,000

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Continuous Improvement of Operations - Decreasing Per Well Capital Costs

18

Avg. Capital Cost / Well 1st Five Operated Wells $4,769,293

H2 2015 Operated Wells (8) (excluding SWF) $2,762,000 Most Recent Five Operated Wells (excluding SWF) $2,512,000

Completion

and lease

issues (3)

SWF wells

(5)

2. New Mannville Liquids Rich Development Opportunity

67 (66 net) sections of land acquired through land sales and transactions with industry

participants

As in the Dunvegan, rock work has been key. Area has had hundreds of vertical

penetrations to deeper targets over 50 years of industry activity

Dozens of cores analyzed and hundreds of cutting samples inspected from previously drilled

wells prior to land capture to ensure high-grading of opportunity

Main targets are Lower Mannville braided fluvial systems and tidal sands (calibrated to core

interpretation)

Expect liquids - rich gas based on older vertical production in the region – initial locations

offset vertical wells that produced or tested oil

Multi-zone Potential

Secondary zones in Gething , Notikewin, Viking, Ostracod and Rock Creek

19

Brackish Bay

Fluvial

Braidplain

Tidal Bar

Stacked Reservoirs 5-20m of 6-20% porosity, 1-15md

tighter conventional deep basin

reservoirs

Gas in Place 7-12 BCF/sec (based on

7m @ 12% porosity & 14m @ 9%)

Main Lower Mannville Targets Chert-rich (low resistivity) Braidplain

(Yellow) deposited as a sheet over

area of interest

Tidal Bars (Orange) tidal bars in

brackish bay

Secondary Mannville Targets Gething channels (Brown). Good

reservoir quality with limited

distribution.

Notikewin channels. Existing

horizontal production.

Windfall Mannville – Stacked Reservoir Opportunity

20

Lwr Mann_2

Lwr Mann_1

Mannville Economic Detail at Strip Pricing

Two test wells drilled in Q4 – 2015 -

followed up by 4 or more wells in 2016

Liquids yields on both wells exceeded type

curve estimates

Single well economics of play

satisfactory - drilling & completions

refinements to drive down CAPEX / well

and delineation will identify sweet spots Economics assume 3rd party processing

and improve with construction of gas plant

Dunvegan capital costs / well reduced 48%

in 3 years – expect Mannville to be $3 to

$3.5mm in time

Dunvegan initial economics based on IP30

= 200 and IP 365 = 110 boe/d – 85% of

Dunvegan development has IP30 = 465 and

IP365 = 192

Scope and position for future

development

TCE Mannville Low Liquids Type Curve

TCE Mannville "High Liquids"

Type Curve

Capital Cost ($mm) $3.5 $3.5

Reserves

Oil and NGLs (mbbls) 85 115 Nat Gas (mmcf) 2,500 1,700 Total (mboe) 500 400

% Oil and NGLs 17% 29%

NPV - 10% - $mm $0.6 $1.0 P/I - 10% Discount 1.1x 1.3x

Rate of Return 17% 29%

IP 30 (boe/d) 593 474 IP 365 (boe/d) 375 300

F&D Cost / $ / BOE $6.96 $8.72

F&D Cost / $/BOE/D $9,333 $11,667

21

Mannville Type Curves – Current Environment Half Cycle Economics (capex $3.5mm/well)

-

100

200

300

400

500

600

700

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

BO

E/D

Month

High (60 bbl/mmcf) Mannville Type Curve Low (30 bbl/mmcf) Mannville Type Curve

US$70 Oil, C$3.00 gas Strip Pricing US$50 / C$2.50 gas

Liquids (mbbls)

Total (mboe) NPV 10 IRR NPV 10 IRR NPV 10 IRR

Liquids Rich (60bbls/mmcf) 115 400 $1.6mm 36% $1.0mm 29% $0.0mm 10%

Low Liquids (30bbls/mmcf) 85 500 $1.1mm 27% $0.6mm 17% $0.0mm 4%

EUR - 400 mboe 1.7BCF & 115 mbbls

EUR - 500 mboe 2.5BCF & 85 mbbls

22

Mannville Low Liquids Type Curve – Price Sensitivities with Improved Capex ( $3mm/well)

0% 5%

11%

17% 24%

30%

36%

43%

51%

55%

66%

75%

84%

94%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

$40 $45 $50 $55 $60 $65 $70 $75

Rat

e o

f R

etu

rn

US$ / bbl WTI

Rate of Return - $3mm per Well CAPEX

C$2.00 / mcf Nat Gas C$3.00 / mcf Nat Gas C$4.00 / mcf Nat Gas

23

2016 Operating and CAPEX Budget – Maintain Reserves and Balance Sheet

Modest 2016 CAPEX budget to maintain production while deleveraging balance sheet

70% of Cash flow spent on CAPEX – 10% Increase in production YoY (US$37.50 / bbl)

24 24

Proforma Analysis

Fiscal 2015 Q1 - 2016 Q2 - 2016 Q3 - 2016 Q4 - 2016 Fiscal 2016

Production (Boe/d) 3,529 3,834 3,840 3,858 3,850 3,845

% Liquids 59.9% 64.0% 63.7% 61.9% 61.0% 62.6%

Liquids (bbls/d) 2,115 2,456 2,445 2,388 2,348 2,409

Revenue (Before Hedging) $57,311,000 $10,107,645 $10,400,290 $10,295,848 $10,167,735 $40,971,518

Revenue (After Hedging) $62,086,890 $13,270,908 $13,125,327 $12,979,198 $12,851,085 $52,226,519

Field NOI $34,962,712 $4,946,005 $5,232,841 $5,076,440 $4,994,130 $20,249,416

CF From Ops $32,975,388 $6,312,439 $5,976,941 $5,933,274 $5,952,212 $24,174,866

CAPEX $70,747,001 $8,250,000 $0 $3,000,000 $5,500,000 $16,750,000

CAPEX (excluding acquisitions) $25,697,001 $8,250,000 $0 $3,000,000 $5,500,000 $16,750,000

Quarter End Debt (exc MTM) $59,795,384 $61,732,946 $55,756,005 $52,822,730 $52,370,518 $52,370,518

Quarter End Debt / Annualized CF 1.81x 2.44x 2.33x 2.23x 2.20x 2.17x

Share Count / Equity Drawn 172,737,336 180,474,672 180,474,672 180,474,672 180,474,672 180,474,672

Annualized CPFS $0.191 $0.140 $0.132 $0.132 $0.132 $0.134

2016 Cash Flow Forecast – Hedging Gains

Hedges provide “certainty” to 2016 cash flows which support continued capital program

during period of commodity price weakness

25

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

$20.00 $25.00 $30.00 $35.00 $40.00 $45.00 $50.00 $55.00 $60.00

Fisc

al 2

01

6 C

F (C

$m

m)

US$ / bbl

Hedging Gain Non Hedging Cash Flow

2016 CAPEX

26

OPEX – Top Decile Among Liquid Peers

$11.25

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

VII TCE RRX TVE SKX BTE MQL PGF RE TOO PWT MEI SPE AEI ZAR SOG

OPEX / BOE - Liquids Producers Fiscal 2016 (NBF Research)

27

Cash Flow - Top Decile Among Peers

$18.84

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

SOG PMT MEI CKE ZAR PNE PWT PGF CQE BBI MQL TOO BXE POU CR AEI PPY KEL SRX TET DEE BTE NVA BIR RE AAV VII TVE SKX RMP LXE TCE SPE RRX

CF / BOE - All Producers Fiscal 2016 (NBF Research)

Solid Margins - at 2016 strip pricing - annual CF stable at $25mm

Low cost structure ensures sustainable – cash costs ~C$16.50 / boe

Shipper on Alliance (firm service) and firm on Pembina (liquids) – unique among juniors

Disciplined - CAPEX less than cash flow – demonstrate growth at strip pricing but debt /

cash flow remains ~2.0x through end 2016

Production Growth – Modest production growth in 2016 while CAPEX < cash flow as

declines begin to approach 20% / annum

IRR / NPV Positive Drilling – Drilling inventory economic at today’s prices

Upside Exposure & Optionality – an increase in WTI to US$50 / bbl increases cash

flow to $30mm ($0.17 / share) with Debt / CF of <1.7x by Q4 – 2016

Opportunity to accelerate drilling, increase production, add to reserves and grow cash flow

Continued Positioning – combination of organic growth and opportunistic

acquisitions positions the company for the future while delivering value creation in a

tough environment

The Vision – A Look Into 2016 / 2017

28

Logo

Placement

TANGLE CREEK ENERGY

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