Tangle Creek Corporate Overview - PowerPoint Presentation

Slide1

Tangle Creek Corporate Overview

December 2016Slide2

Tangle Creek Overview

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

by

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

Tangle raised its initial capital in late 2010 & early 2011 and commenced operations in 2011

A total of $185mm of equity capital was raised at prices from $0.70 to $1.25/shareGrowth from 0 to 4,000 boe/d and 19 mmboe of reserves was primarily through the drill bit & acquisition of partner interests after de-risking The Company acquired Beringer Energy in August 2016 adding 1,500 boe/d, 12 MMboe of reserves &120 net sections of undeveloped landThe Company is backed by top-tier sponsors including ARC Financial and Camcor

Capitalization and Operating Summary

Capitalization   As of Sept 30, 2016Basic Shares OutstandingMM 226  Current Net Debt$MM  $60  Oct StripOperating Metrics 201420152016E2017FProduction (Oil & NGL)bbls/d2,9232,5822,6323,177Nat Gas Mcf/d6,0506,52710,25216,554Total Productionboe/d3,9313,6704,1635,936Cash Flow$MM$67$34$26$39CAPEX$MM$62$71$25$40Period End Debt$MM$43$60$69$61CFPS$/sh$0.40$0.20$0.13$0.17Field Netback$/boe$50.95$26.11$18.16$23.55Corporate Netback$/boe$46.73$30.13$22.47$22.11

Board of Directors

Company Summary

2Slide3

Executive Team - Introductions

Glenn Gradeen

Greg Kondro

Alison

EsseryCam Virginillo

John Pantazopoulos Berkana, Rosetta, Ocelot Rosetta, Ocelot Conoco-Burlington, Shell PetroBakken, Berens Home OilEnCana, Berens, SkywestChief ExecutiveOfficerVice PresidentProductionVice PresidentExplorationVice PresidentEngineering & Chief Operating OfficerChief FinancialOfficerSteve HolyoakeVice President, Drilling & Completions

Petro-Reef, Terra

Mike McGeoughBerens, MarkWest Vice PresidentLand3Slide4

Corporate Operating Snapshot

Production

(Q4 2016)

5,000 boe/d

(53% liquids)Cash Flow (Q4 2016 Annualized – US$46 oil Post Pembina/Alliance)Forecast 2017$26 million ($0.13/sh)$35 - $40mmNet Debt (Sept 30, 2016)Forecast to Dec 31, 2016$60 million (2) (2.2x CF)est. $69mm (1.7x 2017 CF)

Bank Line

$100 million P + P Reserves (Jan 1 2016 – combined SAL & GLJ)Est Dec 31, 2016 (see Appendix)31 mmboe (60% light oil & ngls)est. 29 – 32 mmboeTotal LandUndeveloped Land346 (265 net) sections257 (204 net) sectionsNet Drilling Locations – economic at current strip90+2016 Capital Program2017 Capital Forecast$25 million (capex<cash flow)$35-$40 million (capex=cash flow)Corporate FD&A (Tangle + Beringer basis Dec 31, 2015 reserves)2016 Operating Netback (prior to hedging – realized & strip)2016 Corporate Netback (realized, strip & current hedges)$17/boe (includes FDC)$18/boe$22/boeDate of strip pricing, Dec 13, 2016, 2016Excludes ELOC available of $9.7mm4Slide5

Tangle Creek – Corporate Milestones

Technical, focused team

Track record of building successful energy businesses

Special expertise in tight rock reservoirs – recognize that rock & geology matter

Focused on profitability – building a “bullet-proof” businessExpertise in growing production volumes, top decile operating margins and maintaining strong balance sheetKaybob Dunvegan – Initial hunt for tight oil candidates for horizontal multi-stage technologiesExtensive rock work, petrophysical work & interpretation of depositional environments - Kaybob Dunvegan was top candidateSeveral 5-15 year old vertical completions confirmed oil potential21 section TLM farm-in and first test well at 12-16-60-17w5 resulted in 1,000 bopd test rates and confirmation of economicsConcurrently with initial drill program - sourced and undertook over 20 additional land deals to “own the play”“Best in Class” operator – a complete full service team1st 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 section1st Dunvegan slick-water completionLarge land base & proven oil property – in a desirable areaIn 2016 expanded into Windfall – Mannville LRG play and acquired Beringer Energy Inc.201120122013201420152016Dec 2010 – Formation of Tangle CreekQ1 2011 – Initial Capitalization @ $1/share2013 – New equity @ $1.25/share and acquisition of TLM Dunvegan assets2014 – Organic Production Growth to 5,000 boe/d2016 – 2017 Positioning with merger or major acquisitionQ4 2011 – Initial Kaybob test well 2012 – Proof of concept and Kaybob development2015 – New equity @ $1.25/share and acquisition of Trilogy Dunvegan assets. Drilling of Windfall test wells2016 – Corporate acquisition of Beringer Energy&New ELOC negotiated for ~$10mm2016 – Operational Improvements including completions and waterflood – initial development at Windfall5Slide6

Operating Area – West Central Alberta6

Operating area – Between Highway 43 & Hwy 16 between Edmonton & Grande Prairie

Calgary

Edmonton

Ft. McMurray

Grande Prairie130 net sections at Kaybob / WindfallKaybobWindfallWindfallCarrot Creek

120 net sections at Carrot Creek

6Slide7

Single Well Economics – Play Ranking 180+ Locations (90+ economic)

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 ($2.1mm

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$80.00Plant Gate Nat Gas (C$ / mcf)$1.00 52.1%115.4%182.8%304.3%396.7%487.4%Plant Gate Nat Gas (C$ / mcf)$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 Gething

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$80.00Plant Gate Nat Gas (C$ / mcf)$1.00 10.1%19.4%29.9%40.0%47.5%Plant Gate Nat Gas (C$ / mcf)$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%$2.005.6%21.1%34.3%44.8%57.5%70.0%78.8%$2.003.0%13.5%24.7%34.8%47.8%61.8%72.2%$2.5018.0%33.3%47.8%59.4%73.2%86.5%95.6%$2.507.4%18.3%30.5%41.5%55.5%70.5%81.5%$3.0029.3%45.9%61.6%74.4%89.1%104.0%113.5%$3.0011.6%23.3%36.6%48.4%63.5%79.4%91.0%$3.5041.5%59.7%77.1%90.4%106.7%122.6%134.8%$3.5016.1%28.7%43.1%55.9%71.9%88.8%101.1%$4.0054.5%74.4%93.1%107.8%125.2%141.8%154.8%$4.0020.8%34.6%50.1%63.7%80.8%98.6%111.5%  MRF - Carrot Rock Creek Oil  MRF - Pembina Rock Creek Oil  IRR  IRR US$ / 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$80.00Plant Gate Nat Gas (C$ / mcf)$1.00 19.1%29.7%40.7%48.8%Plant Gate Nat Gas (C$ / mcf)$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$80.00Plant Gate Nat Gas (C$ / mcf)$1.00  3.2%Plant Gate Nat Gas (C$ / mcf)$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%$3.500.1%17.9%30.4%39.7%51.3%62.6%71.3%$3.50 0.2%9.8%20.5%31.6%39.8%$4.0013.5%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 facing on Tier 3 wells (Kaybob) to generate 50%-60% returns

Locations6+ (net)

Locations47+ (net)

Locations20+ (net)

Locations20+ (net)

Locations20 (net)

Locations72 (net)

Locations8 (net)

Locations8 (net)

Cost reductions have led to significant improvement in well economicsSlide8

Production Adds & Drilling Vintages – Production is leveling

2014 Drilling

2013 Drilling

2012 Drilling

2011 Drilling

3rd Party Solution Gas Processing RestrictionSolution Gas Take-away Restriction2015Trilogy Acquisition

TCPL Curtailment

8Wells with 4+ years history are down to 15% declines or lessCorporate decline is 25% to 30%35%15%25%12%WindfallShut-inBeringerAcquisitionPrior 12 monthDecline2016 DrillingSlide9

Kaybob Asset – Operational Improvements have Enhanced Economics & drilling inventory9

Kaybob Dunvegan represents the bulk of Tangle’s asset value, production & cash flow. Focus has been on improving economics to establish a top tier asset with significant running room:Capital cost reductions have been a game-changer – last two wells drilled were $2.1mm each – all in. Four years ago cost was $4.8mm per well, better technologies, mono-bore designs, internally designed drill equipment have all come together to reduce capital costs over and above the economic climate. For example drill times have been reduced from 15-17 days to 8-9 days. These are real structural changes

Opex has been reduced by 40% by consolidating batteries, boring the Athabasca River, re-negotiation trucking and third party charges and bringing field staff on the payroll

Declines are better understood, with steep initial

and long term declines down to 15% to 20% on wells older than 30 months. Corporately we are at 30% or less including BeringerWhile Tier 1 wells were always highly economic (200%+ IRR at US$50 oil), the reduced costs combined with better completions result in Tier 2 single well economics of 60% IRR or better – moving these ~50 locations into top tier vis-à-vis industry

Improving the drilling inventory. Improved hybrid slick water fracturing has opened up new regions for moving some of the 75 Tier 3 locations into Tier 2 or better.Further economic enhancements are being planned with successful response on the pilot water-floodThis is a significant, top tier asset with considerable growth potential yetSlide10

10OPEX – Top Decile Among Liquid Peers

includes $2.00 Transportation CostsSlide11

11Cash Flow - Top Decile Among PeersSlide12

Ongoing Continuous Improvement #1 -

Cost Improvements - A Game-Changer

12

Year over year reductions in costs and improved economics driven by improved efficiencies

45% reduction in drill times

55% reduction in total capex/well55% reduction in Drilling costsOpex - 40% DecreaseSlide13

Operational Performance

– 4+ Years History - Cost reductions = Improving economics

Type Curve Economics - MRF

Tier 1 Type Curve - $2.1mm Capex, EUR 280

mbbls

oil 375 mboe CapitalPayoutIRRNPV10F&DRecycle Ratio1st Yr CapitalWTI

($MM)(yrs)

(%)($MM)($/boe)(times)Efficiency ($/boe/d)$45$2.10.8161$4.1$5.754.9$9,930$55$2.10.6285$5.6$5.676.2$9,930$65$2.10.5460$6.9$5.627.5$9,930Tier 2 Type Curve - $2.1mm Capex, EUR 150 mbbls oil 195 mboe CapitalPayoutIRRNPV10F&DRecycle Ratio1st Yr CapitalWTI($MM)(yrs)(%)($MM)($/boe)(times)Efficiency ($/boe/d)$45$2.12.238$1.3$11.312.5$17,115$55$2.11.467$2.2$10.993.3$17,115$65$2.11.0103$3.1$10.814.0$17,115Tier 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 Wells13Slide14

Recent drilling and interpretation has led to the upgrading of multiple Tier 3 wells to Tier 2

14

Field Development Plan – Tiers 1, 2 & 4 Economic at Strip – 55 Locations (March 31, 2016)

Two Tier 1 wells drilled in November – reduces inventory

from 8 to 6Slide15

Slickwater Application –

Expanding the Sweet Spots

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 2Tier 2 Type CurveTier 1 Type CurveTier 3 Type Curve15Slide16

16Tangle Dunvegan Slickwater Application

14-04-60-17 Foam Frac

15-04-60-17 Slickwater FracSlide17

Ongoing Continuous Improvement #2 - Slickwater Application – Improving Inventory

Green = Proved Undeveloped

Red = Probable UndevelopedOrange = Uneconomic PUDBlack = Q1 2016 Drills

4-30-60-18w5 – On-stream

Feb 22, 2016

15-04-60-17w5 – On-stream Mar 15, 201617

9 Gross (8.9 Net) PUDs

Assume Type 2 @ 195 mboe = 1.73 mmboeSlide18

Continuous Improvement #3 - Dunvegan Waterflood - EOR under MRF should be a game-changer

13

18 sections with 175

mmbbls

OOIP

Secondary Recovery – 10-15 mmbblsReserves increase could reach 50% to 90%Reserve Additions at $2.50/bbl10-18 Injector Conversion1/2 section pilotGood Response after 8 monthsGOR DecreasingOil Rate IncreasingNo Water Breakthrough from Hz InjectorSlide19

Lower

Mannville

is 2,000 to 2,300

m deep;typical 1 mile horizontal well legsStacked Deep Basin Lower Mannville targets & upper Jurassic targetsOil & gas pools (‘Ostracod’, ‘Ellerslie’, Rock Creek) and secondary dry gas (Spirit River, Bluesky, Gething)

Detailed technical review - uncovering high potential oily opportunities

Active drilling by Velvet and Vermillion, year-round access and good infrastructure65 net sections at Windfall, 120 net sections at Carrot Creek/PembinaCurrent focus on expanding scale & scope of the plays, improving technology applications & on cost efficiencies Windfall & Carrot Creek/Pembina – Expanding Scope to Oily & LRG Mannville/Jurassic19Slide20

Proposed

gas plant site

Nova and 3

rd

party linesNovaAllianceSecond well -14-32-57-17 2.5mmcfd sales + 180 bbl/d oil and NGL’sThird well - 4-5-58-17 Q4 2016

2017 locations

Section 8 acquired Oct 2016Windfall Development – 10+ Section Oily Area – 14-32 Basis20Third well drilled at 4-5-58-17w5 (October 2016 – completed Nov 2016 – initial clean-up flow similar to 14-32 – currently on build-up)2017 plan is for two additional scoping wells – then a development including gas plant Drilling program and gas plant currently under reviewProposed gas plant site provides access to either Nova or AllianceFirst well - 9-14-58-17 produces 1-1.5 mmcf/d of natural gas with ~200 bbl/mmcf of water Slide21

21

MRF

Strip (17-08-2016)

High (29-08-2016)

MBOE

GasIRR NPV 10 P/IP/O

MBOE

% GasIRR NPV 10 P/IP/O (%)(%) (M$C) 10%(Years) (%)(%) (M$C) 10%(Years)SemCams Single Well605 7412148 1.04.9 615 74331,839 1.52.4Gas Plant Single Well 628 74684,117 2.21.5 631 74995,819 2.71.210 Well/Gas Plant Project6,255 743325,090 1.63.4 6,298 745041,652 2.02.8Total Field NPV10 Ex Capital   70,719      87,281   Notes

1. Capex = 3.5 M$C/well

2. Gas Plant = $10.125M$C (including Water Disposal)

3. Total Capital Cost ($m) =

$ 45,629

3. Does not include 14-32 and 9-14 wells

4. Using modernized royalty regime

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

3 Year development program Includes

10 wells, 10

mmcfd

gas plant & infrastructure

Current data indicates

11 low risk sections (22 wells)

& additional 8 moderate risk

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

21Slide22

Carrot Creek – Acquired August 2016

22

120 net sections

in corporate acquisition

Extensive owned infrastructure

makes gassier asset attractive – however – focused on oilier areas27.5 net locations and 11.4 net contingent locations in Lower Mannville/Jurassic fluvial and tidal sandstones and Jurassic Rock Creek/Niton shoreface sandstonesPetrophysical review of Lower Mannville complete - cores and cutting samples from area wells interpreted to ensure high-grading of locationsExpect Lower Mannville to be liquids - rich gas based on older vertical production in the region – initial locations offset vertical wells that produced or tested oil. Rock Creek will generally be oily with ½ mile lateralsTwo wells planned for Q4 2016 – three wells planned in 2017 with some contingenciesFurther Multi-zone PotentialSecondary zones in Viking, Notikewin, Gething , OstracodSlide23

Carrot Creek – Land Base / Infrastructure

Carrot Creek Infrastructure:

02-26-52-12 Gas Plant – 73%

10-29-53-10 Gas Plant – 100%

15

mmcf/d net capacity (40% utilized)Firm Service – 7.1 mmcf/d rises to 11.5 mmcf/d in 2018Carrot Creek Land Base:120 Net SectionsAverage WI – 84%239-12-52-12 Q4 2016Slide24

Carrot/South-Pembina – Locations (Mannville purple; Rock Creek green). Contingent (grey) Rock Creek

Production

Bullhead to Fernie

Rock Creek

Land Rights

13-16-49-11 Drilling Q4 2016Slide25

Proactive Hedging Plan

Tangle Creek maintains a proactive hedging program – 50% - 60% of 2017 physical total developed oil volumes (net of royalties) & ~65% of net gas volumes are currently hedged through a combination of swaps and collars

Plan to continue as production volumes increase - unhedged volumes will be protected through regular program of layering contracts every quarter. Target is 60% to 70% of physical production

Following table shows % of base production (current production declined) hedged – gross – before deduction of royalties (add 5% to 10% for volumes net of royalties)

% of Production Hedged

Q4 - 2016Q1 – 2017Q2 - 2017Q3 - 2017Q4 - 2017Q1 - 2018Q2 - 2018Q3 - 2018

Q4 - 2018

% of Total - Crude Oil66%53%49%58%58%38%39%30%30%% of Total - Nat Gas51%55%49%49%45%24%18%12%12%25Slide26

Solid Margins

-

2017 CF stable at $35 to $40mm with free cash flow above maintenance CAPEX to grow production >10% per year

Free cash flow

– can maintain current production with ~$20mm per year CAPEXLow cost structure – (opex ~$10/boe) ensures sustainable – total cash costs ~C$17 / boe

(includes opex, transportation, G&A, E&E, interest)Shipper on Alliance (firm service) and firm on Pembina Peace (liquids) – unique among juniors ensures lower costs, higher realized pricing and minimal downtime due to pipeline constraintsDisciplined - CAPEX ~ Cashflow improves liquidity & dry powder for acquisitionsProduction Maintenance – In 2016 while CAPEX ~ cash flow as declines further reduce to 20% - 30% / annum – maintain production while not depleting inventoryIRR / NPV Positive Drilling – Tier 1 and Tier 2 Dunvegan drilling inventory expanding with new technologies - economic at current stripHedging program – crucial to protecting cash flows and capital programsHedging gains funded 33% of 2016 CAPEX program allowing for modest deleveraging and growthUpside Exposure & Optionality – WTI price increase to US$60 / bbl increases cash flow to $47mm with debt / CF of <1.0x by Q3 – 2017Opportunity to accelerate drilling, increase production, add to reserves and grow cash flowExpand Dunvegan and Evaluate WindfallA Look Into 201726Slide27

2016 / 2017 TCE Cash Flow – Back to Growth!

27

Forecasted production of 5,900 boe/d with a “Cash flow ~ CAPEX” budget in fiscal 2017

Liquids production remains > 50%, with majority (> 85%) of liquids being light oil

Forecasted 47% increase in cash flow (27% increase in CFPS), with debt reducing to $61mm due to equity draw end of Q2 - 2017

Ability to add additional 2-3 wells (500 boe/d / annum) to capital budget should prices rise to US$60 / bbl, which would push exit 2017 volumes to ~7,000 boe/d and grow cash flow to > $46mm      

  Q4 - 2016Fiscal 2016Q1 - 2017Q2 - 2017Q3 - 2017Q4 - 2017Fiscal 2017Production (Boe/d)5,0004,1005,9006,1005,5006,1005,900% Liquids53.1%59.0%54.1%55.6%54.2%50.2%53.5%Liquids (bbls/d)2,6322,4543,2183,4342,9783,0823,177   Revenue (Before Hedging)$16,346,090$52,111,859$21,375,300$22,927,530$20,236,424$21,404,682$85,943,936Revenue (After Hedging)$16,717,662$58,519,451$20,611,750$22,142,055$19,442,317$20,628,974$82,825,096Hedging Gain$371,572$6,407,592-$763,550-$785,476-$794,107-$775,707-$3,118,840Field NOI$8,602,227$27,673,471$12,614,456$13,839,203$12,023,618$12,553,223$51,030,499CF From Ops$6,443,418$26,300,387$9,503,717$10,552,400$9,059,070$9,611,214$38,726,401   CAPEX$15,300,000$25,092,961$12,700,000

$800,000$11,650,000

$14,850,000

$40,000,000

CAPEX (excluding acquisitions)$15,300,000

$25,092,961$12,700,000

$800,000$11,650,000$14,850,000

$40,000,000

Quarter End Debt (exc MTM)

$69,537,959

$69,537,959

$72,734,242

$53,281,841

$55,872,771

$61,111,557

$61,111,557

Quarter End Debt / Annualized CF

2.70x

2.64x

1.91x

1.26x

1.54x

1.59x

1.58x

Share Count / Equity Drawn

226,574,672

203,524,672

226,574,672

230,885,783

239,508,005

239,508,005

234,119,116

Annualized CPFS

$0.114

$0.129

$0.168

$0.183

$0.151

$0.161

$0.165Slide28

2017 TCE Cash Flow Sensitivity Analysis

28

Forecasted cash flows of > $39mm with + / - US$5 / bbl change in oil price resulting in ~$5mm of CF

Upside to cash flow and potential for production growth exists as US$5 / bbl increase in commodity prices potentially supporting the drilling of 2 incremental wells (300 - 400 boe/d incremental production)

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

2017 hedges focused on wide collars providing opportunity if prices rise above strip2017 capital program includes 4 Dunvegan, 3 Windfall, 2 Carrot Creek and 1 Gething wells, $6mm for the expansion of our waterflood project and $2mm towards the construction of a new natural gas plantFiscal 2017 Cash Flow 

Price of Oil (US$ / bbl) $38.7$40.00$42.50$45.00$47.50$50.00$52.50$55.00$57.50$60.00$62.50$65.00Nat Gas Price ($ / mcf)$2.50$25.0$26.6$28.1$29.7$32.2$34.8$37.3$39.9$42.4$45.0$47.6$2.75$25.7$27.3$28.9$30.4$32.9$35.5$38.0$40.6$43.1$45.7$48.3$3.00$26.4$28.0$29.6$31.1$33.6$36.2$38.7$41.3$43.8$46.4$49.0$3.25$27.1$28.7$30.3$31.9$34.3$36.9$39.4$42.0$44.6$47.1$49.7$3.50$27.8$29.4$31.0$32.6$35.0$37.6$40.1$42.7$45.3$47.8$50.4$3.75$28.5$30.1$31.7$33.3$35.7$38.3$40.8$43.4$46.0$48.5$51.1Slide29

2017 Production Summary

29

Annual Average 5,938boe/d

Total BOE/D

% of Total Base 2016 Wedge 4,50075.6% Q4 - 2016 Wells 77513.0% Q1 - 2017 Wells 3505.9%

Q3 - 2017 Wells

3005.0% Q4 - 2017 Wells 250.4%Slide30

The Vision To create a “must own” growth producer with the capital, cash flow, balance sheet and assets to create long-term shareholder value & multiple expansion

Position the company with a best in class balance sheet to exploit both existing and new opportunities that create long-term shareholder valueDisciplined approach to debt – maintain top quartile debt to cash flowDisciplined consolidation strategy for assets in a core fairway with specific technical attributes

Methodically develop the asset base with a focus on the highest return projectsExecute a balanced capital program to deliver on conservative growth targets

Continued conservative approach to forecasting and guidance

Growth within cash flowsDeliver 10% to 20% per year production growth – i.e. steady CFPS growth at strip Continuously improve market following & cost of capital through communication and careful, consistent execution of the business planProvide investors with significant potential returns by delivering consistent per share growth of production, reserves, cash flow, and net asset value

30Slide31

Acquisition Opportunities Currently Under Review

31Slide32

32Tangle Creek – Corporate Summary

Efficient and Effective Light Oil & Gas ProducerBest in class revenues, operating costs & netbacks, combined with low FD&A and Recycle RatiosCapital costs reduced 50% BEFORE 2015 price adjustments by service companies

Proven Organic Growth Capacity1st

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 LandsMost active, experienced Dunvegan oil operatorOpportunistic Acquirer With Strong Balance SheetFocus on quality, operating margins, economics and running room

Since inception, completed $130mm in acquisitions while keeping debt / cash flow under 2xOver $50mm of acquisitions in 2015 including undeveloped land69 net light oil sections in Kaybob acquired through 30 separate transactionsCounter 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 playOn the hunt for material acquisitions - move into next tier of production & developmentSlide33

Tangle Creek EnergyDecember 2016Contact:

Tangle Creek Energy LtdGlenn GradeenCEOd: +1 (403) 648-4901m: +1(403) 618-0434

ggradeen@tanglecreekenergy.com1400, 715 – 5th Ave S.W.

Calgary, AB T2P 2X6

John PantazopoulosCFOd: +1 (403) 648-4903m: +1(403) 828-8084jpantazopoulos@tanglecreekenergy.com