Tangle Creek Corporate Overview - RBC Private Company Conference. January 18, 2017

Transcription

1 Tangle Creek Corporate Overview - RBC Private Company Conference January 18, 2017

2 FORWARD-LOOKING STATEMENTS 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. 2

3 Tangle Creek Overview Who Are We? Company Summary 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 Q Organic growth to Beringer Energy, acquired in Aug first corporate acquisition expansion outside of Dunvegan Backed by top-tier sponsors including ARC Financial, Camcor, Northleaf and GE Board of Directors Leadership Team 3

4 Our History - Corporate Milestones Track record building successful energy businesses Dec 2010 Formation of Tangle Creek 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 1 st to drill multistage horizontal on Dunvegan Oil Play 1 st approval for Dunvegan water flood 1 st approval to increase well density up to eight wells per section 1 st Dunvegan slick-water completion Q Initial Kaybob test well 2013 New $1.25/share and acquisition of TLM Dunvegan assets 2015 New $1.25/share and acquisition of Trilogy Dunvegan assets. Drilling of Windfall test wells 2016 Corporate acquisition of Beringer Energy & New ELOC ~$10mm Q Initial $1/share 2012 Proof of concept and Kaybob development 2014 Organic Production Growth to 5,000 boe/d 2016 Operational Improvements including completions and waterflood initial development at Windfall In 2016 expanded into Windfall Mannville LRG play and acquired Beringer Energy Inc Positioning with merger or major acquisition 4

5 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) mmboe (60% light oil) Total Land Undeveloped Land 346 (265 net) sections 257 (204 net) sections Net Drilling Locations economic at current strip Capital Program (7 wells + land + facilities) 2017 Capital Forecast (10-12 wells + land + facilities) 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) $25 million (capex<cash flow) $40 million (capex=cash flow) $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

6 Operating Fairway West Central Alberta Operating Fairway Kaybob 130 net sections at Kaybob / Windfall Ft. McMurray Windfall Grande Prairie Edmonton Operating Fairway Defined in Yellow Windfall Calgary Carrot Creek net sections at Carrot Creek 6

7 Plant Gate Nat Gas (C$ / mcf) Plant Gate Nat Gas (C$ / mcf) Plant Gate Nat Gas (C$ / mcf) Plant Gate Nat Gas (C$ / mcf) Plant Gate Nat Gas (C$ / mcf) Plant Gate Nat Gas (C$ / mcf) Plant Gate Nat Gas (C$ / mcf) Plant Gate Nat Gas (C$ / mcf) Single Well Economics Three Plays/Six Types Moving Locations into Economic Category Cost reductions have led to significant improvement in well economics Average prospect - 50% to 60% of these improved through newer drilling and completion practices & 1 mi vs ½ mi laterals Gas Plant construction (Windfall) and slick water fracing on Tier 3 wells (Kaybob) to generate 50%-60% returns MRF - Tier 1 Dunvegan ($2.1mm capex) MRF - Tier 2 / 4 Dunvegan ($2.1mmcapex) Locations IRR Locations IRR 6+ (net) US$ / bbl 47+ (net) 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 $ % 115.4% 182.8% 304.3% 396.7% 487.4% $ % 54.8% 93.5% 120.8% 149.1% $ % 120.0% 188.9% 312.8% 406.8% 499.2% $ % 56.6% 95.9% 123.6% 152.3% $ % 124.7% 195.0% 321.4% 417.1% 511.1% $ % 58.4% 98.2% 126.4% 155.5% $ % 61.5% 129.4% 201.2% 330.0% 427.5% 523.2% $ % 60.2% 100.7% 129.2% 158.7% $ % 64.6% 134.1% 207.4% 338.5% 437.7% 534.9% $ % 37.9% 62.0% 103.1% 132.0% 161.9% $ % 67.9% 138.9% 213.7% 347.2% 448.0% 546.8% $ % 39.3% 63.9% 105.5% 134.9% 165.1% $ % 71.2% 143.7% 220.0% 355.9% 458.4% 558.8% $ % 40.8% 65.7% 108.0% 137.7% 168.4% MRF - Windfall Mannville - TCE Gas Plant MRF - Carrot Gething Locations Locations IRR IRR 20+ (net) 20 (net) 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 $ % 19.4% 29.9% 40.0% 47.5% $ % 14.3% 22.8% 33.9% 45.9% 54.9% $ % 22.0% 31.6% 42.9% 54.4% 61.8% $ % 19.3% 28.5% 40.6% 53.6% 63.3% $ % 21.1% 34.3% 44.8% 57.5% 70.0% 78.8% $ % 13.5% 24.7% 34.8% 47.8% 61.8% 72.2% $ % 33.3% 47.8% 59.4% 73.2% 86.5% 95.6% $ % 18.3% 30.5% 41.5% 55.5% 70.5% 81.5% $ % 45.9% 61.6% 74.4% 89.1% 104.0% 113.5% $ % 23.3% 36.6% 48.4% 63.5% 79.4% 91.0% $ % 59.7% 77.1% 90.4% 106.7% 122.6% 134.8% $ % 28.7% 43.1% 55.9% 71.9% 88.8% 101.1% $ % 74.4% 93.1% 107.8% 125.2% 141.8% 154.8% $ % 34.6% 50.1% 63.7% 80.8% 98.6% 111.5% Locations MRF - Carrot Rock Creek Oil Locations MRF - Pembina Rock Creek Oil 8 (net) IRR 8 (net) 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 $ % 29.7% 40.7% 48.8% $ % 24.4% 34.3% 41.9% $ % 22.3% 33.2% 44.7% 53.7% $ % 27.0% 37.4% 45.2% $ % 25.5% 37.0% 49.4% 58.1% $ % 29.7% 40.6% 48.6% $ % 28.9% 40.9% 53.7% 62.5% $ % 32.5% 43.6% 52.1% $ % 22.4% 32.4% 44.7% 57.7% 67.5% $ % 15.5% 24.4% 35.2% 46.8% 55.5% $ % 25.5% 35.7% 48.6% 61.8% 71.8% $ % 17.8% 26.8% 38.2% 50.0% 58.9% $ % 28.7% 39.3% 52.5% 66.7% 75.8% $ % 20.1% 29.4% 41.2% 53.3% 62.4% Locations MRF - Windfall Mannville - No Gas Plant Locations MRF - Dunvegan Tier 3 ($2.1mm capex) 20+ (net) IRR 72 (net) IRR US$ / 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 $ % $ % 16.5% 27.2% 34.9% $ % 17.0% $ % 17.3% 28.0% 35.9% $ % 14.6% 23.5% 29.5% $ % 18.1% 28.9% 36.8% $ % 16.9% 26.7% 36.0% 43.2% $ % 18.9% 29.8% 37.8% $ % 19.2% 28.0% 38.3% 48.8% 56.7% $ % 19.7% 30.7% 38.8% $ % 17.9% 30.4% 39.7% 51.3% 62.6% 71.3% $ % 9.8% 20.5% 31.6% 39.8% $ % 28.6% 42.0% 52.4% 64.9% 76.9% 86.2% $ % 10.5% 21.3% 32.5% 40.7% Meets Hurdle rate Doesn t Meet Hurdle rate 7

8 Operational Performance 5 Years History - Predictable Type Curves Solid Economics Tier 1 IP 365 = 222 boe/d (35 wells) Tier 2 IP 365 =117 boe/d (23 wells) All Wells Tier 3 IP 365 = 65 boe/d (16 wells) Type Curve Economics - MRF Tier 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 $ $4.1 $ $9,930 $55 $ $5.6 $ $9,930 $65 $ $6.9 $ $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 $ $1.3 $ $17,115 $55 $ $2.2 $ $17,115 $65 $ $3.1 $ $17,115 8

9 Cost Improvements - A Game-Changer Reductions in costs are largely structural i.e. improved technologies & efficiencies Includes 1-time costs associated with Beringer acquisition 9

10 OPEX Top Decile Among Liquid Peers OPEX / Transportation / BOE - Liquids Producers Fiscal 2016 (NBF Research) $30.00 $25.00 includes $2.00 Transportation Costs $20.00 $15.00 $11.25 $10.00 $5.00 $0.00 VII TCE RRX TVE SKX BTE MQL PGF RE TOO PWT MEI SPE AEI ZAR SOG

11 Cash Flow Margins are Top Decile Among Peers CF / BOE - All Producers Fiscal 2016 (NBF Research) $35.00 $30.00 $25.00 $20.00 $18.84 $15.00 $10.00 $5.00 $0.00 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

12 Value Creation Through Cost Initiatives Efficiency gains combined with recovering commodity prices pushing recycles back north of 2x 12

13 Another Game-Changer - Hybrid Slickwater Application Improving Performance w5 On-stream Feb 22, 2016 Tier 3 to Tier 2 + Tier 1 Type Curve Tier 2 Type Curve w5 On-stream Mar 15, Tier 3 to Tier 2 Tier 3 Type Curve 13

14 Hybrid Slickwater Application Improving Performance/Adding to Inventory Hybrid Slickwater Frac Older Foam Frac Technology 14

15 Field Development Plan Tiers 1, 2 & 4 Economic at Strip Recent drilling and interpretation - upgrading Tier 3 wells to Tier 2 Two Tier 1 wells drilled in November reduces inventory from 8 to 6 Q drilling two tier 3 wells Hybrid Slick Water Frac technology - potential to add 2-4 Tier 2 PUDs 15

16 Dunvegan EOR Changing the Game Again Doubles Reserves 1/2 section pilot Good Response after 8 months GOR Decreasing Oil Rate Increasing No Water Breakthrough from Hz Injector Injector Conversion 18 sections mmbbls OOIP Enhanced Oil Recovery adds mmbbls Oil Reserves increase 50% to 100% Reserve Additions at $2.50/bbl 13

17 Windfall & Carrot Creek/Pembina Expanding Scope to Oily & LRG Mannville/Jurassic 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 Lower Mannville is 2,000 to 2,300 m deep; typical 1 mile horizontal well legs 17

18 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 MRF Strip ( ) MBOE Gas IRR NPV 10 P/I P/O (%) (%) (M$C) 10% (Years) 3 rd Party Processing Single Well Gas Plant Single Well , Well/Gas Plant Project 6, , Total Field NPV10 Ex Capital 70,719 Notes 1. Capex = 3.5 M$C/well 2. Gas Plant = $10.125M$C (including Water Disposal) 3. Total Capital Cost ($m) = $ 45, Does not include and 9-14 wells 4. Using modernized royalty regime 18

19 A Look Into 2017 Return to Growth! Solid Margins 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 19

20 Fiscal Return to Growth! After 2 years of Protecting Value and Consolidating Assets Growth (US$80 US$100) Growth (US$50 US$60) Consolidation (US$80 US$27) 20

21 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 % of Prod. Hedged Q Q Q Q Q Q Q Q % of Total - Crude Oil 58% 53% 63% 63% 48% 48% 40% 40% % of Total - Nat Gas 55% 49% 53% 47% 21% 16% 10% 10% 21

22 Nat Gas Price ($ / mcf) 2017 TCE Cash Flow Sensitivity 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 $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 $

23 Create a sizable, high margin, self sustaining, oil weighted producer: Transforming Tangle Creek Next Stage of Development 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 E 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 o locations - Tangle brings new technologies & both lateral and vertical infill horizontal drilling Duvernay high impact play currently being delineated and de-risked by industry 23

24 What are we Targeting? Today 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 Required CAD $200 million new equity, targeted acquisition and organic growth Target 2 to 4 years 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 24

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 1 st 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 25

26 Contact: Tangle Creek Energy Ltd Glenn Gradeen President and CEO d: +1 (403) m: +1(403) John Pantazopoulos VP Finance and CFO d: +1 (403) m: +1(403) , th Ave S.W. Calgary, AB T2P 2X6 TANGLE CREEK ENERGY January 2017 Logo Placement

27 Appendix 27

28 28 Production Adds & Drilling Vintages Production is leveling Wells with 4+ years history are down to 15% declines or less Corporate decline is 25% to 30% Beringer Acquisition 3 rd Party Solution Gas Processing Restriction 2014 Drilling Solution Gas Takeaway Restricti on 2015 Trilogy 2016 Acquisition Drilling TCPL Curtailment Windfall Shut-in 2012 Drilling 2013 Drilling 35% 25% Prior 12 month Decline 2011 Drilling 15% 12%

29 Kaybob Dunvegan Attributes Vertical depths 1,600 to 1,800 meters MD ~3,200m 9-11 drilling days Q 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

30 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

31 Kaybob Dunvegan E1 MMBOIP - Sept

32 West Windfall Development 10+ Section Oily Area New well w5 (completed Nov 2016 initial clean-up flow similar to 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 Alliance Nova Drilled Q On Production Q mmcfd sales bbl/d oil and NGL s Nova and 3 rd party lines Section 8 acquired Oct locations Proposed gas plant site 32

33 2016 / 2017 TCE Cash Flow Back to Growth! 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 Q Fiscal 2016 Q Q Q Q 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 $86,201,858 Field 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, ,524, ,574, ,885, ,508, ,508, ,119,116 Annualized CPFS $0.121 $0.131 $0.180 $0.199 $0.161 $0.167 $

34 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

35 Value Creation Organic Growth Delivers Best Returns Assumes new equity of $200 million, targeted acquisition and organic growth 35

36 Growth Opportunities Currently Under Review Entity 2017 Production boed 2P Reserve mmboe Tangle Creek 6,000 55% Transformational Acquisitions - leading to Organic Growth % Oil & NGL Estimated Cost $mm Five Targets under review 6,700 30% 50 $270 Total TCE + Large Targets 12,700 42% 80 $ Strategic Acquisitions - Enhancing existing operations Four Targets under review 2,300 50% 17 $87 Total TCE+Large+Strategic 15,000 44% 97 $ Internal Projects - Waterflood + Windfall + Maintenance Four internal projects 2,800 45% 6 $45 Total Unrisked Potential 17,800 45% 103 $402 36