“Building a High Quality, High Margin Energy Business” Tangle Creek Energy Corporate Presentation October 2014 Tangle Creek – Corporate Snapshot Concentrated, high margin energy business built in 3 ½ years: Production –2014 average - 3,900 boe/d - forecast Q4 2014 ~5,000 boe/d • • • • 75% light sweet crude (36°API) High Margin – Operating netbacks of $50/boe to $60/boe in 2014 90%+ operated production Organic growth with low risk acquisitions Reserves –18.1mmboe (Sproule June 30, 2014) – 13+ year Reserve Life Index Land – 52 net sections at Kaybob Corporate 2013 FD&A - $17.89/boe (includes FDC) • Significant drilling inventory • Total land inventory in three areas is 80 net sections • Since inception FD&A - $18.39/boe • Recycle ratio of 2.7x to 3.3x …while maintaining financial discipline: 2014 forecast cash flow $67million million (CFPS $0.49) (CFPS $0.41) – annualized Q4 cash flow $80 2014 capital program of $66 million $37 million net debt at June 30, 2014 - bank lines of $80 million Debt to 2014 cash flow of 0.7:1 2 Tangle Creek Corporate Profile Business Plan Tangle Creek Team Building The Business Light tight oil 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 Founding Team of 7 Experienced Business Builders 12 full-time + 7 part-time & consultants + 6 field Technical team - experienced with emerging technologies 3 ½ years building Tangle Creek Tangle Creek Energy Ltd. incorporated November 2010 - initial equity raise completed March 2011 Equity invested of $165 million – 22 shareholders ARC Financial and Camcor – oldest PE firms in Calgary 3 Board of Directors Chairman CEO Lauchlan Currie Glenn Gradeen Jim Pasieka Cam McVeigh ARC Financial Corp. Tangle Creek Energy McCarthy Tétrault Camcor Partners Inc. Dan Botterill P.Eng. Larry M Jones Independent Director Independent Director 4 Executive Team Chief Executive Officer Vice President Exploration Vice President Engineering & Chief Operating Officer Vice President Land Glenn Gradeen Alison Essery Cam Virginillo Mike McGeough Berkana, Rosetta, Ocelot Conoco-Burlington, Shell PetroBakken, Berens Enerplus Berens, MarkWest Vice President Production Chief Financial Officer Vice President, Drilling & Completions Greg Kondro John Pantazopoulos Steve Holyoake Rosetta, Ocelot EnCana, Berens, Skywest Petro-Reef, Terra 5 Horizontal Drilling and Completion Technology – Impact on Oil Production Multistage Fracturing System Modified http://www.loganinternationalinc.com/lcs/PDF/LCS_MS-Brochure_R1_web.pdf 6 Growing Conventional Oil Production – New Technologies Source: ARC Energy Charts – June 2014 7 Tangle Creek – Kaybob Property Tangle Creek Energy – First utilization of horizontal multistage technology on the Kaybob Dunvegan Play early mover application of new technology completions detailed technical review - unearthing high potential oil opportunities The largest and most prospective land position on the play – with a significant drilling inventory, year-round access and extensive infrastructure most active and experienced operator Current corporate focus on acquisition opportunities & expanding Kaybob production & cash flows: Improving capital & operating cost efficiencies Advancing technologies - applications already implemented – improved ball drop (metallic, composite, soluble); monobore well design, internally designed drill bits, multi-well pads Initiatives being tested in 2014 include: – 3 & 4 well pads, waterflood pilot, drill/ream system, slickwater completions, inter-well spacing 8 Dunvegan Stratigraphy Dunvegan 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 Dunvegan Carbonates Adapted from Canadian Discovery Digest 9 Kaybob Area Dunvegan Activity Source: CIBC – March 2014 Dunvegan Drilling Dunvegan horizontals (green) Dunvegan horizontals (green) 10 10 Tangle Creek – Kaybob Existing Wells & 2014 Drilling Program 2014 Q3Q4 Drilling Program 13 (11.5 net) Operated Wells Location TBD - 1 net non-Op Well Q1 2014 Dunvegan Hz Wells 5 (4.9 net) Operated Wells 2 (0.3 net) non-Operated 2012/13 Dunvegan Hz Wells 41(33.2 net) Operated Wells 22 (4.2 net) non-Operated 2013-12-31 Owned Gross 90.75 Net 51.17 Farmin Lands Gross Farmin Net before Net After Lands Total Gross Earning Earning 2.00 92.75 2.00 1.50 11 11 Growing Light Oil Production Forecast 6,000 Actual ~5,000 boe/d 75% Liquids 5,000 4,250 boe/d 74% Liquids 3,551 boe/d 4,000 72% Liquids 2,770 boe/d 3,000 70% Liquids 2,000 1,245 boe/d 67% Liquids 1,000 53 boe/d 76% Liquids 0 2011 2011 2012 2012 2013 2013 H1 2014 2014 H2 2014 2014 Exit Q4 2014 12 Value Creation - Growing Cash Flows $85 $0.60 $75 $0.49 $0.50 $0.41 $80 $65 $0.40 $67 $0.30 $0.27 $45 CFPS Cash Flow ($mm) $55 $35 $0.17 $0.20 $38 $25 $0.10 $15 $15 $0.00 $5 -$5 -$0.07 2011 2012 2013 Cash Flow ($mm) 2014 (Forecast) CFPS Annualized Q4 - 2014 -$0.10 13 Growing Reserves – Total Proved Plus Probable 20 0.115 18.1 18 0.110 0.110 16 0.105 14 12 10 8 0.100 9.3 0.096 P+P boe reserves / Share mmbe (P+P Reserves) 0.105 0.095 6 4 0.090 2 1.5 0 0.085 12/31/2011 12/31/2012 Total Reserves (mmboe) 6/30/2014 Reserves / Share 14 Current Status - Operational Confidence – Well Performance is Predicable Average Well Well Count 15 Dunvegan Type Curves - Four Tiers & Half Cycle Economics (capex $2.8mm/well) Tier 1 High Tier 2 Type Tier 3 Low Tier 4 Gassy Oil (kbbls) Total (kBoe) 225 305 175 233 120 157 100 304 $85 oil, $4.00 gas NPV10 PI $5,344 2.9 $4,644 2.33 $3,687 2.3 $2,987 1.86 $1,798 1.6 $1,098 1.31 $2,840 2.0 $2,140 1.61 Sproule Sproule 201406Pricing Pricing NPV10 $7,316 $5,747 $5,290 $3,915 $2,949 $1,771 $4,409 $3,099 PI → Profitability Index (NPV10/Capex) Note: Y Axis is oil – for boe/d add 25% (50% for Tier 4) PI 3.6 2.65 2.9 2.12 2.1 1.51 2.6 1.89 Improving Well Performance - IP 90 by Quarter Drilled IP 90 by Quarter 500 20 19 446 450 18 400 16 350 14 13 308 315 12 boe/d 260 250 200 244 10 9 7 181 197 190 150 Well Count 300 8 6 5 4 4 100 4 2 50 2 - Q4 - 2011 Q1 - 2012 Q3 - 2012 Q4 - 2012 Number of Wells Q1 - 2013 IP 90 - By Year Q3 - 2013 Q4 - 2013 Q1 - 2014 NB: Excludes west farm-in test well 17 $3,000,000 Operated Well #1 Operated Well #2 Operated Well #3 Operated Well #4 Operated Well #5 Operated Well #6 Operated Well #7 Operated Well #8 Operated Well #9 Operated Well #10 Operated Well #11 Operated Well #12 Operated Well #13 Operated Well #14 Operated Well #15 Operated Well #16 Operated Well #17 Operated Well #18 Operated Well #19 Operated Well #20 Operated Well #21 Operated Well #22 Operated Well #23 Operated Well #24 Operated Well #25 Operated Well #26 Operated Well #27 Operated Well #28 Operated Well #29 Operated Well #30 Operated Well #31 Operated Well #32 Operated Well #33 Operated Well #34 Operated Well #35 Operated Well #36 Operated Well #37 Operated Well #38 Operated Well #39 Operated Well #40 Operated Well #41 Operated Well #42 Operated Well #43 Operated Well #44 Operated Well #45 Operated Well #46 Operated Well #47 Operated Well #48 Operated Well #49 Value Creation – Decreasing Per Well Capital Costs $7,000,000 1st Five Operated Wells Most Recent 5 Operated Wells Avg. Capital Cost / Well $4,769,293 $2,850,000 $6,000,000 $5,000,000 $4,000,000 Estimate $2,000,000 $1,000,000 $0 18 Continuous Improvement of Operating Costs OPEX ($ / boe) $18.00 $16.04 $16.00 $14.56 $14.23 $13.69 $14.00 $13.63 Estimate $12.80 $11.95 $12.00 $12.18 $11.75 $11.64 $11.50 $10.83 $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 Q4 - 2011 Q1 - 2012 Q2 - 2012 Q3 - 2012 Q4 - 2012 Q1 - 2013 Q2 - 2013 Q3 - 2013 Q4 - 2013 Q1- 2014 Q2- 2014 Q3 - 2014 High Margin – High Netback Production NOI ($ / boe) $70.00 $58.85 $60.00 $59.88 $57.96 Estimate $53.63 $50.00 $44.01 $41.89 $38.91 $40.00 $45.14 $43.79 $41.44 $39.17 $32.50 $30.00 $20.00 $10.00 $0.00 Q4 - 2011 Q1 - 2012 Q2 - 2012 Q3 - 2012 Q4 - 2012 Q1 - 2013 Q2 - 2013 Q3 - 2013 Q4 - 2013 Q1- 2014 Q2- 2014 Q3 - 2014 20 Value Creation – Operating Margins & Competitive FDA Yield Strong Economic Performance $70.00 8.0x 7.1x $59.37 $60.00 7.0x 6.0x $50.00 5.0x $38.38 $ / BOE $40.00 4.0x 3.1x 4.1x $30.00 3.0x 2.5x $21.38 $20.00 2.1x $18.17 $17.89 $14.41 $14.37 2.0x 1.8x $8.40 $10.00 1.0x $0.00 0.0x 2012 2013 Half Cycle F&D - Includes earning (Left Axis) Full Cycle FD&A (Left Axis) Recycle Ratio - Half Cycle (Right Axis) Recycle Ratio - Full Cycle (Right Axis) H1 - 2014 Net Operating Income (Left Axis) Recycle Ratio (NOI / F&D) $44.82 Construction of Three Multi-well Batteries Treating for over 6,000 bbls/d of pipeline spec oil Tangle Creek’s 2,000 bbl/d battery & compressor station at 01-20-60-17w5 on-stream October 2012 22 Comparison of Dunvegan, Cardium, Montney, Viking Marine Sandstone Parameters Water Saturation (Sw) Similar marine oil plays have similar reservoir characteristics & benefit from new technology applications Dunvegan benefits from longer development times on Cardium, Montney & Viking Modified after Macquarie Research, April 2010 Kaybob 2014 Drilling Program & New Initiatives – 22+ Wells (net 17.6 budgeted) 7 (5.2 net) 8+ (6.5 net) 7+ (6.0 net) Oil Pipeline Tie-in ? H2_2013 Drills - Black Sec 20-60-19 -– New Tier 2 Area Q1 2015 Locations Centralization River Bore Sec 20&29-60-18– Expanded Tier 1 Area Approved 8 Well per Section Slickwater Frac New Farm-in’s Approved Waterflood Pilot Area Kaybob Drilling Inventory – Various Prices, Capital and Well Densities Drilling Inventory # of Net Drilling Locations Capable of Achieving a 30% IRR 250 223.8 223.8 200 # of Net Drilling Locations 167.9 167.9 150 118.8 100 111.9 111.9 111.9 111.9 89.1 59.4 52.3 50 0 US$70 / bbl US$85 / bbl 4 Wells / Section - $3.0mm / Well (C$3.00 / mcf) 4 Wells / Section - $3.0mm / Well (C$4.00 / mcf) 6 Wells / Section - $3.0mm / Well (C$4.00 / mcf) 8 Wells / Section - $3.0mm / Well (C$4.00 / mcf) US$100 / bbl 25 PDP Production PUD - 2014 PUD 2015 PUD 2016 PUD 2017 PUD 2018 PUD 2019 PUD 2020 Nov-20 Sep-20 Jul-20 May-20 Mar-20 Jan-20 Nov-19 Sep-19 Jul-19 May-19 Mar-19 Jan-19 Nov-18 Sep-18 Jul-18 May-18 Mar-18 Jan-18 Nov-17 Sep-17 Jul-17 May-17 Mar-17 Jan-17 Nov-16 Sep-16 Jul-16 May-16 Mar-16 Jan-16 Nov-15 Sep-15 Jul-15 May-15 Mar-15 Jan-15 Nov-14 Sep-14 Jul-14 May-14 Mar-14 Jan-14 Analyzing Value Creation – One Possible Future Scenario Under Review Production Forecast Maintenance of 5,000 boe/d 6,000 5,000 4,000 3,000 2,000 1,000 0 26 Slave Point Production and TCE lands Nipisi Slave Point & Gilwood 1,700 - 1,900 m TVD Slave Point – Production from older verticals and recent horizontals, total 18 MMBO Slave Point D pool with significant horizontal drilling, cum 1.3 MMBO since 2010 Gilwood pools range from <10,000 bbls/well to >400,000 bbls/well, discrete structural closures A D Positioning Tangle Creek for the Future 1. Second Core Operating Area – Test well(s) at Nipisi 2. Acquisitions – Oil & liquids rich gas opportunities under review in 3 separate areas. Land purchases, asset & corporate acquisitions Over $400 million of potential acquisitions currently under review 3. Capital Resources – $40+mm in un-utilized bank debt facilities plus new asset value Free cash flow of approximately $40mm pa New equity – existing & new shareholders 4. Corporate Metrics (cash flow multiples, value per flowing boe , $/boe reserves, etc.) are aligning & the potential for attractive market valuations may be compelling over the coming year Free cash flow provides options for dividend or growth Future liquidity for PE shareholders is a consideration “Peer” Group Comparison (Public Company Information) –Recycle Ratios 3.0x 3.x Tangle Creek Energy = 2.8x 2.8x 2.6x 2.5x 2.5x 2.4x 2.3x 2.3x 2.4x 2.3x 2.2x Average Recycle = 1.9x 2.x 2.0x 1.9x 2.x 2.x 1.9x 1.8x 1.7x 1.5x 1.5x 1.3x 1.2x 1.3x 1.2x 1.1x 1.0x .8x 0.5x 0.0x Based on 2013 FD&A and National Bank 2014 Forecast Pricing & Netbacks 29 Tangle Creek Energy – Conclusions Tangle Creek – Competitive Advantages Technical, focused team “Best in Class” operator – a complete “full service” team 1st to drill multistage horizontal on Dunvegan Oil Play 1st approval for Dunvegan waterflood 1st approval to increase well density – up to eight wells per section 1st to plan slick-water completion – implement later this year Special expertise in tight rock reservoirs – recognize rock & geology matter History of building concentrated – highly desirable assets Large land base and proven core property – in a desirable area Focused on margins – building a “bullet-proof” business Track record of building successful energy businesses Substantial capital resources to develop current & future opportunities Reviewing several significant acquisition targets with view to development, growth, yield and liquidity 30 Contact: Tangle Creek Energy Ltd Glenn Gradeen CEO d: +1 (403) 648-4901 m: +1(403) 618-0434 [email protected] John Pantazopoulos CFO d: +1 (403) 648-4903 m: +1(403) 828-8084 [email protected] 1400, 715 – 5th Ave S.W. Calgary, AB T2P 2X6 TANGLE CREEK ENERGY October 2014 Logo Placement 31
© Copyright 2025 ExpyDoc
