tangle creek corporate overview - rbc private company … · 2017-01-18 · corporate fd&a...

Tangle Creek Corporate Overview - RBC – Private Company Conference

January 18, 2017

FORWARD-LOOKING STATEMENTS

2

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; timing and amount of

future dividend payments; 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.

Tangle Creek Overview – Who Are We?

Tangle Creek Energy Ltd. - a fully integrated, private energy company differentiated by

high margin, light oil & liquids rich natural gas development & production in Alberta

Total equity capital of $185mm – initial equity commitment Q1 2011

Organic growth to 2016 - Beringer Energy, acquired in Aug 2016 - first corporate

acquisition expansion outside of Dunvegan

Backed by top-tier sponsors including ARC Financial, Camcor, Northleaf and GE

Leadership TeamBoard of Directors

Company Summary

3

Our History - Corporate Milestones

Track record building successful energy businesses

Special expertise in tight rock reservoirs –rock & geology matter

Focused on profitability – building a “bullet-proof” business

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

• Initial test wells confirmed economics

• Concurrently with initial drill program - sourced and undertook over

20 land deals to “own the play”

“Best in Class” operator – a complete 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

In 2016 expanded into Windfall – Mannville LRG play and acquired Beringer Energy Inc.

2011

2012

2013

2014

2015

2016

Dec 2010 – Formation

of Tangle Creek

Q1 2011 – Initial

Capitalization @

$1/share

2013 – New equity @

$1.25/share and

acquisition of TLM

Dunvegan assets

2014 – Organic

Production Growth to

5,000 boe/d

2017 Positioning with

merger or major

acquisition

Q4 2011 – Initial

Kaybob test well

2012 – Proof of

concept and Kaybob

development

2015 – New equity @

$1.25/share and

acquisition of Trilogy

Dunvegan assets.

Drilling of Windfall test

wells

2016 – Corporate

acquisition of

Beringer Energy

&

New ELOC ~$10mm

2016 – Operational

Improvements

including completions

and waterflood –

initial development at

Windfall

4

A Snapshot Today

Production (Q1 2017) 6,000 boe/d (60% oil & NGLs)

Cash Flow - Forecast 2017(1) $41 million ($0.18/sh)

Net Debt (Sept 30, 2016)

Estimate Dec 31, 2016

$60 million (2) (2.2x 2016 CF)

• $69mm (1.7x 2017 CF)

Bank Line $100 million

P + P Reserves (Est Dec 31, 2016) 28-30 mmboe (60% light oil)

Total Land Undeveloped Land

346 (265 net) sections257 (204 net) sections

Net Drilling Locations – economic at current strip 90+

2016 Capital Program (7 wells + land + facilities)

2017 Capital Forecast (10-12 wells + land + facilities)

$25 million (capex<cash flow)

$40 million (capex=cash flow)

Corporate FD&A (Tangle + Beringer basis Dec 31, 2015 reserves)

2016 Operating Netback (prior to hedging – realized)

2016 Corporate Netback (realized, strip & current hedges)

2017 Operating Netback (prior to hedging – Jan 4 strip)

$17/boe (includes FDC)

$18.50/boe

$17.75/boe

$25.00/boe

(1) Date of strip pricing, January 4, 2017

(2) Excludes ELOC available of $9.7mm

5

Operating Fairway – West Central Alberta

6

Operating Fairway

Defined in Yellow

Calgary

Edmonton

Ft. McMurray

Grande Prairie

130 net sections at

Kaybob / WindfallKaybob

Windfall

Windfall

Carrot Creek

120 net sections

at Carrot Creek

6

Operating

Fairway

Single Well Economics – Three Plays/Six Types – Moving Locations into Economic Category

Average prospect -

50% to 60% of

these improved

through newer

drilling and

completion

practices & 1 mi vs

½ mi laterals

7

MRF - Tier 1 Dunvegan ($2.1mm capex) MRF - Tier 2 / 4 Dunvegan ($2.1mmcapex)IRR IRR

US$ / bbl US$ / bbl$20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $80.00 $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $80.00

Pla

nt

Gat

e N

at G

as

(C$

/ m

cf)

$1.00 52.1% 115.4% 182.8% 304.3% 396.7% 487.4%

Pla

nt

Gat

e N

at G

as

(C$

/ m

cf)

$1.00 32.1% 54.8% 93.5% 120.8% 149.1%$1.50 55.2% 120.0% 188.9% 312.8% 406.8% 499.2% $1.50 33.5% 56.6% 95.9% 123.6% 152.3%$2.00 58.3% 124.7% 195.0% 321.4% 417.1% 511.1% $2.00 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% $2.50 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% $3.00 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% $3.50 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% $4.00 15.0% 40.8% 65.7% 108.0% 137.7% 168.4%

MRF - Windfall Mannville - TCE Gas Plant MRF - Carrot GethingIRR IRR

US$ / bbl US$ / bbl$20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $80.00 $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $80.00

Pla

nt

Gat

e N

at G

as

(C$

/ m

cf)

$1.00 10.1% 19.4% 29.9% 40.0% 47.5%

Pla

nt

Gat

e N

at G

as

(C$

/ m

cf)

$1.00 4.6% 14.3% 22.8% 33.9% 45.9% 54.9%$1.50 9.1% 22.0% 31.6% 42.9% 54.4% 61.8% $1.50 8.9% 19.3% 28.5% 40.6% 53.6% 63.3%$2.00 5.6% 21.1% 34.3% 44.8% 57.5% 70.0% 78.8% $2.00 3.0% 13.5% 24.7% 34.8% 47.8% 61.8% 72.2%$2.50 18.0% 33.3% 47.8% 59.4% 73.2% 86.5% 95.6% $2.50 7.4% 18.3% 30.5% 41.5% 55.5% 70.5% 81.5%$3.00 29.3% 45.9% 61.6% 74.4% 89.1% 104.0% 113.5% $3.00 11.6% 23.3% 36.6% 48.4% 63.5% 79.4% 91.0%$3.50 41.5% 59.7% 77.1% 90.4% 106.7% 122.6% 134.8% $3.50 16.1% 28.7% 43.1% 55.9% 71.9% 88.8% 101.1%$4.00 54.5% 74.4% 93.1% 107.8% 125.2% 141.8% 154.8% $4.00 20.8% 34.6% 50.1% 63.7% 80.8% 98.6% 111.5%

MRF - Carrot Rock Creek Oil MRF - Pembina Rock Creek OilIRR IRR

US$ / bbl US$ / bbl$20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $80.00 $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $80.00

Pla

nt

Gat

e N

at G

as

(C$

/ m

cf)

$1.00 19.1% 29.7% 40.7% 48.8%

Pla

nt

Gat

e N

at G

as

(C$

/ m

cf)

$1.00 14.7% 24.4% 34.3% 41.9%$1.50 13.3% 22.3% 33.2% 44.7% 53.7% $1.50 17.1% 27.0% 37.4% 45.2%$2.00 16.3% 25.5% 37.0% 49.4% 58.1% $2.00 19.4% 29.7% 40.6% 48.6%$2.50 19.3% 28.9% 40.9% 53.7% 62.5% $2.50 21.9% 32.5% 43.6% 52.1%$3.00 10.1% 22.4% 32.4% 44.7% 57.7% 67.5% $3.00 3.7% 15.5% 24.4% 35.2% 46.8% 55.5%$3.50 13.0% 25.5% 35.7% 48.6% 61.8% 71.8% $3.50 6.1% 17.8% 26.8% 38.2% 50.0% 58.9%$4.00 15.8% 28.7% 39.3% 52.5% 66.7% 75.8% $4.00 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)IRR IRR

US$ / bbl US$ / bbl$20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $80.00 $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $80.00

Pla

nt

Gat

e N

at G

as

(C$

/ m

cf)

$1.00 3.2%

Pla

nt

Gat

e N

at G

as

(C$

/ m

cf)

$1.00 5.9% 16.5% 27.2% 34.9%$1.50 11.1% 17.0% $1.50 6.7% 17.3% 28.0% 35.9%$2.00 4.2% 14.6% 23.5% 29.5% $2.00 7.5% 18.1% 28.9% 36.8%$2.50 8.1% 16.9% 26.7% 36.0% 43.2% $2.50 8.2% 18.9% 29.8% 37.8%$3.00 6.7% 19.2% 28.0% 38.3% 48.8% 56.7% $3.00 9.0% 19.7% 30.7% 38.8%$3.50 0.1% 17.9% 30.4% 39.7% 51.3% 62.6% 71.3% $3.50 0.2% 9.8% 20.5% 31.6% 39.8%$4.00 13.5% 28.6% 42.0% 52.4% 64.9% 76.9% 86.2% $4.00 1.0% 10.5% 21.3% 32.5% 40.7%

Gas Plant

construction

(Windfall) and slick

water fracing on

Tier 3 wells

(Kaybob) to

generate 50%-60%

returns

Locations

6+ (net)Locations

47+ (net)

Locations

20+ (net)

Locations

20+ (net)

Locations

20 (net)

Locations

72 (net)

Locations

8 (net)Locations

8 (net)

Cost

reductions

have led to

significant

improvement

in well

economics

Meets

Hurdle

rate

Doesn’t

Meet

Hurdle

rate

Operational Performance – 5 Years History - Predictable Type Curves – Solid Economics

Type Curve Economics - MRFTier 1 Type Curve - $2.1mm Capex, EUR 280 mbbls oil 375 mmboe (6 locations)

Capital Payout IRR NPV10 F&D Recycle Ratio 1st Yr Capital

WTI ($MM) (yrs) (%) ($MM) ($/boe) (times) Efficiency ($/boe/d)

$45 $2.1 0.8 161 $4.1 $5.75 4.9 $9,930

$55 $2.1 0.6 285 $5.6 $5.67 6.2 $9,930

$65 $2.1 0.5 460 $6.9 $5.62 7.5 $9,930

Tier 2 Type Curve - $2.1mm Capex, EUR 150 mbbls oil 195 mmboe (47 locations)Capital Payout IRR NPV10 F&D Recycle Ratio 1st Yr Capital

WTI ($MM) (yrs) (%) ($MM) ($/boe) (times) Efficiency ($/boe/d)

$45 $2.1 2.2 38 $1.3 $11.31 2.5 $17,115

$55 $2.1 1.4 67 $2.2 $10.99 3.3 $17,115

$65 $2.1 1.0 103 $3.1 $10.81 4.0 $17,115

Tier 1 – IP 365 = 222 boe/d

(35 wells)Tier 2 – IP 365 =117 boe/d

(23 wells)

Tier 3 – IP 365 = 65 boe/d

(16 wells)

All Wells

8

Cost Improvements - A Game-Changer

9

Reductions in costs are largely

structural – i.e. improved

technologies & efficiencies

Includes 1-time

costs associated

with Beringer

acquisition

10

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 / Transportation / BOE - Liquids ProducersFiscal 2016 (NBF Research)

includes $2.00 Transportation Costs

11

Cash Flow Margins are 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 ProducersFiscal 2016 (NBF Research)

Value Creation Through Cost Initiatives

12

Efficiency gains combined with recovering commodity prices pushing recycles back north of 2x

Another Game-Changer - Hybrid Slickwater Application – Improving Performance

04-30-60-18w5 – On-stream Feb

22, 2016 – Tier 3 to Tier 2 +

15-04-60-17w5 – On-stream Mar

15, 2016 - Tier 3 to Tier 2

Tier 2 Type Curve

Tier 1 Type Curve

Tier 3 Type Curve

13

14

Hybrid Slickwater Application – Improving Performance/Adding to Inventory

14-04-60-17 Older Foam Frac Technology

15-04-60-17 Hybrid Slickwater Frac

Recent drilling and interpretation

- upgrading Tier 3 wells to Tier 2

15

Field Development Plan – Tiers 1, 2 & 4 Economic at Strip

Two Tier 1 wells

drilled in

November –

reduces

inventory from 8

to 6

Q1 2017 drilling two

tier 3 wells – Hybrid

Slick Water Frac

technology -

potential to add 2-4

Tier 2 PUDs

Dunvegan EOR – Changing the Game Again – Doubles Reserves

13

18 sections - 175 mmbbls OOIP

Enhanced Oil Recovery adds 10-15 mmbbls

Oil Reserves increase – 50% to 100%

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

Lower Mannville is 2,000 to 2,300 m deep;

typical 1 mile horizontal well legs

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, 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

Windfall & Carrot Creek/Pembina – Expanding Scope to Oily & LRG Mannville/Jurassic

17

MRF Strip (17-08-2016)

MBOE Gas IRR NPV 10 P/I P/O(%) (%) (M$C) 10% (Years)

3rd Party Processing Single Well 605 74 12 148 1.0 4.9

Gas Plant Single Well 628 74 68 4,117 2.2 1.5

10 Well/Gas Plant Project 6,255 74 33 25,090 1.6 3.4Total Field NPV10 Ex Capital 70,719

Notes1. Capex = 3.5 M$C/well2. 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

Windfall Development – Single Well Economics and 3 year - 10 Well Program

3 Year development program Includes 10 wells, 10 mmcfd gas plant &

infrastructure

11 low risk sections (22 wells) & additional 8 moderate risk

Total 20 out of 65 net sections – 30% of lands currently considered prospective

18

Solid Margins - 2017 CF stable at over $40mm with free cash flow

above maintenance CAPEX to grow production >10% per year

Free cash flow – can maintain current production with ~$25mm per year CAPEX

Low cost structure – opex ~$10/boe ensures high margins and sustainablity

Firm shipper on Alliance (firm service) and firm on Pembina Peace (liquids) – unique among juniors ensures

reliable takeaway, lower costs & higher realized pricing

Disciplined – CAPEX ~ Cashflow – facilitates growing the business

Expanding Drilling Inventory – Tier 1 & Tier 2 Dunvegan drilling inventory expanding

with new technologies - economic at current strip – plus positive results at Windfall

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

Expand Dunvegan and Evaluate Windfall

Further consolidation

A Look Into 2017 – Return to Growth!

19

Fiscal 2017 - Return to Growth!

20

After 2 years of Protecting Value and Consolidating Assets

Growth

2011 - 2014(US$80 – US$100)

Consolidation

2015 – 2016(US$80 – US$27)

Growth

2017+(US$50 – US$60)

Proactive Hedging Plan – Capital / Balance Sheet Protection

Proactive & comprehensive hedging program –

60% - 65% of 2017 physical oil volumes (net of royalties)

50% of net gas volumes

combination of swaps and collars

Continue & extend as production volumes increase - unhedged volumes

protected through regular program of layering contracts every quarter.

Target is 60% to 75% of physical production – 18 to 24 months out

21

% of Prod. Hedged Q1 – 2017 Q2 - 2017 Q3 - 2017 Q4 - 2017 Q1 - 2018 Q2 - 2018 Q3 - 2018 Q4 - 2018

% of Total - Crude Oil 58% 53% 63% 63% 48% 48% 40% 40%

% of Total - Nat Gas 55% 49% 53% 47% 21% 16% 10% 10%

2017 TCE Cash Flow Sensitivity

22

Forecasted cash flows of > $40mmwith + / - US$5 / bbl change in oil price resulting in ~$5mm of CF

Assumes hedge book as of January 15, 2017

Upside to cash flow and potential for production growth exists as US$5 / bbl increase in commodity prices

supports incremental drilling

Balance sheet remains strong and capital programs can be adjusted to ensure financial strength

2017 hedges focused on wide collars – floor pricing with opportunity to capitalize on increasing prices

2017 capital program includes 7 Dunvegan, 2 Windfall and 1 Rock Creek well, $6mm for the expansion of

waterflood and $2mm towards the construction of a new natural gas plant

Fiscal 2017 Cash Flow

Price of Oil (US$ / bbl)

$41.3 $40.00 $42.50 $45.00 $47.50 $50.00 $52.50 $55.00 $57.50 $60.00 $62.50 $65.00

Nat

Gas P

rice (

$ / m

cf) $2.50 $26.2 $27.9 $29.7 $31.7 $34.5 $37.3 $40.1 $42.8 $45.6 $48.4 $51.2

$2.75 $26.8 $28.6 $30.4 $32.4 $35.2 $37.9 $40.7 $43.5 $46.3 $49.0 $51.8

$3.00 $27.5 $29.2 $31.0 $33.0 $35.8 $38.6 $41.3 $44.1 $46.9 $49.7 $52.4

$3.25 $28.1 $29.9 $31.7 $33.7 $36.4 $39.2 $42.0 $44.8 $47.5 $50.3 $53.1

$3.50 $28.7 $30.5 $32.3 $34.3 $37.1 $39.9 $42.6 $45.4 $48.2 $51.0 $53.7

$3.75 $29.4 $31.2 $32.9 $35.0 $37.7 $40.5 $43.3 $46.1 $48.8 $51.6 $54.4

Create a sizable, high margin, self sustaining, oil weighted producer:

Large oil-weighted resource in place - geographically focused - drilling inventory to

deliver sustainable growth in current commodity price environment within cash flow

Significant organic growth – free cash flow provides path to growth

sustainable growth at 15%-20% for 6 to 8 years

Downside protection - high margin sustainable production from existing assets

Increased scale - 2017E production & cash flow ~10,000+ BOE/d & over $70MM (Nov 22

strip), respectively.

Targeted investment -one fairway - three high quality oil plays & one LR gas play::

o Dunvegan – Stable, proven, high operating margins. 50+ high return locations at strip & up to

additional 75 with improving technologies. Next steps include consolidation and low risk waterflood

o Lower Mannville – Liquids rich gas currently being developed by Velvet and others –

significant existing land position

o Montney – proven, world-ranked Western Canadian play. Thick pay sections - several hundred

locations - Tangle brings new technologies & both lateral and vertical infill horizontal drilling

o Duvernay – high impact play currently being delineated and de-risked by industry

23

Transforming Tangle Creek – Next Stage of Development

What are we Targeting?

24

CAD $200 million new equity, targeted

acquisition and organic growth

Required

Target – 2 to 4 years

Today

Returns

Desirable - Publicly Listed

Acquisition(s) and material Organic Growth

20,000+ boed, 100 mmboe,50% oil

$120mm+ / annum cash flow

Debt : CF < 1x

500+ drilling inventory

10% to 20% / annum production growth

within cash flow

Private Company – 42 shareholders

Technical team of builders Difficult work and learning done

6,000 boed, 30mm boe, 60% oil

$40mm+ pa cash flow

Debt : CF ~1.5x

90 locations drilling inventory

Sustainable for 5-10 years

25

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

Logo

Placement

TANGLE CREEK ENERGY

January 2017

Contact:

Tangle Creek Energy LtdGlenn Gradeen

President and 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

VP Finance and CFO

d: +1 (403) 648-4903

m: +1(403) 828-8084

jpantazopoulos@tanglecreekenergy.com

27

Appendix

Production Adds & Drilling Vintages – Production is leveling

2014

Drilling

2013

Drilling

2012

Drilling

2011

Drilling

3rd Party

Solution

Gas

Processing

Restriction

Solution

Gas

Take-

away

Restricti

on2015

Trilogy

AcquisitionTCPL

Curtailment

28

Wells with 4+ years history are down to 15% declines or less

Corporate decline is 25% to 30%

35%

15%

25%

12%

Windfall

Shut-in

Beringer

Acquisition

Prior

12

month

Decline

2016

Drilling

Kaybob Dunvegan Attributes

Vertical depths 1,600 to 1,800 meters – MD ~3,200m – 9-11 drilling days

Q4 2016 – all in capital costs $2.1mm/well

Light gravity, sweet crude oil ~36°API

Deep Basin – no water

avg GOR of 2,500 – 4,000 scf/bbl

Original deltaic sandstones reworked by waves and tides

Very fine to fine grain size

Net pays range 5-15m, porosities range 6-20%, permeability's of 1-10s of mDs

Year round access

Good existing infrastructure and access to services

Combination of acquired lands, acquired production and farm-ins

25 land deals over 3 years to net almost 70 net sections

e.g. - Acquired Bluesky gas production to gain access to Dunvegan rights

Crown lands – royalty incentives under both ARF and MRF

Operatorship – Operate 92% of production

Other operators are active on the Dunvegan – Orlen, Apache, XTO, CNRL, etc.

29

Comparison of Dunvegan, Cardium, Montney, Viking marine sandstone parameters

These oil plays benefit from horizontal completions:

Massive increase in lower quality rock volume connected to wellbore

Modified after Macquarie Research, April 2010

30

Kaybob Dunvegan – E1 MMBOIP - Sept 2016

31

Proposed gas plant

site

Nova and 3rd party lines

Nova

Alliance

14-32-57-17

On Production Q3

2016

2mmcfd sales +

140 bbl/d oil and

NGL’s

4-5-58-17 Drilled

Q4 2016

2017

locations

Section 8 acquired Oct 2016

West Windfall Development – 10+ Section Oily Area

32

New well 4-5-58-

17w5 (completed

Nov 2016 – initial

clean-up flow similar

to 14-32 – currently

being tied-in)

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

2016 / 2017 TCE Cash Flow – Back to Growth!

33

Forecasted production of 5,900 – 6,000 boe/d with a “CAPEX = Cash Flow” in 2017 (January 4, 2017 Strip)

Oil production remains > 55%, with majority (> 85%) of liquids being light oil

56% increase in cash flow (35% increase in CFPS)

Optionality to add additional drilling to capital budget should prices rise over current strip – 2 wells would

push exit 2017 volumes to ~6,500 boe/d and help further grow cash flow to > $47mm

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

Production (Boe/d) 4,944 4,159 6,098 6,340 5,598 5,738 5,942

% Liquids 56% 60% 55% 57% 55% 55% 56%

Liquids (bbls/d) 2,791 2,494 3,370 3,621 3,091 3,147 3,306

Revenue (Before Hedging) $16,979,387 $52,745,156 $22,614,367 $24,406,223 $21,239,263 $21,573,110 $89,832,963

Revenue (After Hedging) $17,268,952 $59,070,741 $21,707,467 $23,495,625 $20,318,659 $20,680,106 $86,201,858Field Opex $4,548,840 $14,918,688 $5,213,635 $5,481,264 $4,892,522 $5,014,993 $20,602,414

Royalties 12% 10% 10% 9% 10% 9% 10%

Hedging Gain $289,565 $6,325,585 -$906,900 -$910,598 -$920,604 -$893,004 -$3,631,106

Field NOI $9,106,163 $28,177,407 $13,469,603 $14,901,059 $12,712,298 $13,014,178 $54,097,137

CF From Ops $6,865,302 $26,722,271 $10,223,890 $11,497,940 $9,641,545 $9,985,244 $41,348,618

CAPEX $15,300,000 $25,092,961 $13,650,000 $500,000 $11,200,000 $15,050,000 $40,400,000

CAPEX (excluding acquisitions) $15,300,000 $25,092,961 $13,650,000 $500,000 $11,200,000 $15,050,000 $40,400,000

Quarter End Debt (exc MTM) $69,116,074 $69,116,074 $72,542,185 $51,844,245 $53,402,700 $58,467,456 $58,467,456

Quarter End Debt / Annualized CF 2.5x 2.6x 1.8x 1.1x 1.4x 1.5x 1.4x

Share Count / Equity Drawn 226,574,672 203,524,672 226,574,672 230,885,783 239,508,005 239,508,005 234,119,116

Annualized CPFS $0.121 $0.131 $0.180 $0.199 $0.161 $0.167 $0.177

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

Positioning Tangle in highest margin plays - running room

Capitalize on history of efficiency gains – depth of team expertise

Consolidation - in core fairway with specific technical attributes = C.A.

High-grade development focusing on the highest return projects

Execute a balanced capital program to deliver on conservative growth targets Continued conservative approach to forecasting and guidance

Disciplined approach to debt – maintain top quartile debt to cash flow

Growth within cash flows

Deliver 10% to 20% per year production growth – CFPS growth at strip

Market communication & careful, consistent execution of the business plan

Shareholder value creation by delivering consistent per share growth of

production, reserves, cash flow, and net asset value

34

Value Creation – Organic Growth Delivers Best Returns

35

Assumes new equity of $200 million, targeted acquisition and organic growth

Growth Opportunities Currently Under Review

36

2017

Production

2P

Reserve

boed mmboe

Tangle Creek 6,000 55% 30

Transformational Acquisitions - leading to Organic Growth

Five Targets under review 6,700 30% 50 $270

Total TCE + Large Targets 12,700 42% 80 $270

Four Targets under review 2,300 50% 17 $87

Total TCE+Large+Strategic 15,000 44% 97 $357

Internal Projects - Waterflood + Windfall + Maintenance

Four internal projects 2,800 45% 6 $45

Total Unrisked Potential 17,800 45% 103 $402

Entity

% Oil

&

NGL

Estimated

Cost

$mm

Strategic Acquisitions - Enhancing existing operations

1.

2.

3.