Tangle Creek Corporate Presentation

Transcription

1 Positioning the Company for Sustained Growth Tangle Creek Corporate Presentation April 2016

2 Forward Looking Statements This presentation contains "forward-looking statements" including estimates of future production, cash flows and reserves, business plans for drilling and exploration, the estimated amounts and timing of capital expenditures, the assumptions upon which estimates are based and related sensitivity analyses, and other expectations, beliefs, plans, objectives, assumptions or statements about future events or performance (often, but not always, using words or phrases such as "expects" or "does not expect", "is expected", "anticipates" or "does not anticipate", "plans", "estimated" or "intends", or stating that certain actions, events or results may", "could", "would", "might" or "will" be taken, occur or be achieved). In particular, this presentation contains forward-looking statements pertaining, to the following: Tangle Creek Energy Ltd. s ( Tangle Creek or the Company ) 2015 and 2016 production outlooks and cash flow forecasts; the Company s 2016 capital budget, as well as drilling and development plans and the timing and costs thereof; the Company's expected capital spending flexibility and ability to take advantage of available opportunities; the ability of the Company to maintain its balance sheet strength; type well economics and performance; drilling inventory; estimated recycle ratios; the anticipated impact of waterflood activities; the timing and cost savings associated with planned infrastructure; resource upside opportunities available to the Company; the possible upside and the liquid expectations at the Company s new Mannville play; and the ability of the Company to manage the current low oil price environment. Statements relating to "reserves" are deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. There are numerous uncertainties inherent in estimating crude oil, natural gas and NGL reserves and the future cash flow attributed to such reserves. The reserve and associated cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. Actual reserve values may be greater than or less than the estimates provided herein. All forward-looking statements are based on Tangle Creek s beliefs and assumptions based on information available at the time the assumption was made. Tangle Creek believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this presentation should not be unduly relied upon. By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements. In addition, risk factors include: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas; delays in business operations, pipeline restrictions, blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value of acquisitions and exploration and development programs; unexpected geological, technical, drilling, construction and processing problems; availability of insurance; fluctuations in foreign exchange and interest rates; failure to realize the anticipated benefits of acquisitions; general economic, market and business conditions; uncertainties associated with regulatory approvals; uncertainty of government policy changes; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry. These risks and uncertainties could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent. Barrels of oil equivalent ( boe ) may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Tangle Creek assumes no obligation to update forwardlooking statements should circumstances or management's estimates or opinions change. Certain information contained herein have been prepared by third-party sources. The information provided herein has not been independently audited or verified by the Company. 2

3 If you are going through hell. Be sure not to stop Winston Churchill 3

4 Tangle Creek Corporate Profile Business Plan Light tight oil & liquids rich gas Candidates for emerging tight rock technologies High margin low risk development opportunities Operatorship, high working interests Concentrated assets, material land positions & drilling inventory Growth through combination of acquisitions & drilling Tangle Creek Team Founding Team of 7 Experienced Business Builders 12 full-time + 5 part-time & consultants + 10 field Technical team - experienced with emerging technologies 5 years building Tangle Creek Building The Business Tangle Creek Energy Ltd. incorporated November initial equity raise completed March 2011 Equity invested of $185 million 22 shareholders ARC Financial & Camcor longest standing energy PE firms in Canada 4

5 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 5

6 Executive Team Chief Executive Officer Vice President Exploration Vice President Engineering & Chief Operating Officer Vice President Land Glenn Gradeen Berkana, Rosetta, Ocelot Alison Essery Conoco-Burlington, Shell Cam Virginillo PetroBakken, Berens Enerplus Mike McGeough Berens, MarkWest Vice President Production Greg Kondro Rosetta, Ocelot Chief Financial Officer John Pantazopoulos Petro-Reef, Terra Vice President, Drilling & Completions Steve Holyoake EnCana, Berens, Skywest 6

7 Tangle Creek Energy Ltd. Dealing with Uncertainty In November 2014, with the onset of weakening commodity prices, we established a corporate strategy that presumed longer term weakness in oil & gas prices and the opportunity to position the company for the future. Our focus since the beginning of 2015 Protect the balance sheet & keep debt to cash flow at 2x or less even in the face of weak pricing Maintain financial strength and flexibility Production pause on continued growth Develop and strengthen relationships with equity providers No drilling until Q preserve high value, high quality Dunvegan drilling inventory Shut in high margin/low royalty/high performing wells wait for improved prices Focus on preserving & improving operating margins through reductions in costs especially structural changes: e.g. trucking, sales pipelines, improved processing, improved technologies, better efficiencies and third party processing & handling Maintain flexibility to acquire assets in a prolonged weak price environment opportunities happen Develop and strengthen relationships with equity providers Position the company for future growth Add new grassroots opportunities 7

8 Tangle Creek Corporate Strategic Positioning Efficient and Effective Light Oil Producer Best in class FD&A and Recycle Ratios Capital costs driven down 50% BEFORE 2015 price adjustments by service companies Proven Organic Growth Capacity 1 st to identify & implement Kaybob Dunvegan horizontal technologies including new drilling and completions applications and EOR Kaybob grown from 0 to 4,000 boe/d in 3 years 75% light sweet crude with over 450 mmbbls OIP on Tangle Lands Most active, experienced Dunvegan oil operator Grassroots Liquids Rich Opportunity Identified & Captured 66 net sections acquired with material liquids rich gas potential estimating 30 to 60 bbls/mmcf 150+ potential net locations identified Opportunistic Acquirer With Strong Balance Sheet Since inception, completed $130mm in acquisitions while keeping debt / cash flow under control Over $50mm in 2015 including undeveloped land 69 net light oil sections in Kaybob acquired through 30 separate transactions Counter cyclically acquired 80 net sections on two plays in

9 Tangle Creek Energy Ltd. Operations Snapshot Production 2016 Forecast ~ 3,800 boe/d (70% light oil) Production Margins (Field Netbacks - before hedging, G&A, E&E, interest) 2014 Operating netback of $53/boe 2015 Operating netback ~ $24/boe (forecast before hedging) 90%+ operated production 2016 Cash Flow forecast ~ $25mm (strip) - $0.13/share Reserves - 18mmboe (Jan 2016) 75% light sweet crude (36 API) Land 135 net sections Corporate historic FD&A - $20/boe (includes July 2015 acquisition & FDC) 2016 CAPEX ~$17mm Maintain production of 3,800 4,000 boe/d Delever balance sheet to < $50mm of debt (target 2.0x debt / cash flow) Strategic use of hedges to support capital expenditures 1,300 bbls/d Fiscal / bbl (60% of production) 5.25 mmcf/d Fiscal C$3.00 / mcf (60% of production) 9

10 C$mm Tangle Creek Energy Ltd. Cash Flow Secured to Pursue CAPEX Program Tangle Creek Energy Ltd. Forecasted Cash Flow $35.0 $30.0 $ CAPEX $20.0 $15.0 $10.0 $5.0 $0.0 $10.00 $15.00 $20.00 $25.00 $30.00 $35.00 $40.00 $45.00 $50.00 $ $5.0 -$10.0 US$ / bbl Hedging Gain Non Hedging Cash Flow 10

11 Cash Flow ($mm) boe/d P+P Reserves (mmboe) Tangle Creek Historic Performance Production Reserves 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, ,931 3,800 2,772 1, E Sustained production growth 17% CAGR on a production / debt adjusted share basis 27% annual cash flow growth (Strip pricing) ~40% of 2016 crude oil hedged at > C$70 / bbl 2015 CF $34mm CF - $67mm Q debt - $60mm ($100mm credit line) $80 $70 $60 $50 $40 $30 $20 $10 $0 Cash Flow $67 $38 $34 $ E 11

12 Concentrated High Interest Asset Base Two Projects Balanced Asset Base Single operating area on Hwy 43 between Edmonton & Grand Prairie Excellent access & infrastructure Balanced between solid cash flow base & undeveloped lands 1. Kaybob Dunvegan Light sweet crude oil 36 API 3,500 3,700 boe/d 90% operated 69 net sections 90 net wells Ownership of key infrastructure 120 to 200 net locations at 4 to 6 wells/section 450+ mmboe OOIP on Tangle Lands Waterflood project commenced Q Preliminary results encouraging 2. Windfall Mannville Multi-zone liquids rich 66 net sections 2 wells drilled 2-4 follow-up locations in H net locations identified Estimating 2 to 5 BCF per location Windfall Mannville TCE Lands 67 (66 net) sections Kaybob Dunvegan TCE Dunvegan Lands 450 mmbbls OIP 111 (69 net) sections Company Interest 2P July 31, 2015 = 22 mmboe ~3,800 boe/d in 2015 ~90 wells 12

13 Kaybob Dunvegan Light Sweet Crude Oil Well established oil project initial proof of concept and development by Tangle Creek in 2011 High margin, high quality project close to services and infrastructure in Whitecourt, Fox Creek, Edmonton and Grand Prairie Tangle Creek Dunvegan wells have often been reported as among the top oil wells in Alberta (Industry Research by Scotia Capital, AltaCorp, National Bank and others) 13

14 Tangle Creek Dominant Dunvegan Light Oil Position TCE Internal Locations (195 Gross) 8 Tier 1 High Type Curve 48 Tier 2 Base Type Curve 139 Tier 3 & 4 Low Base and Gassy Type Curve Existing Dunvegan Hz Wells 64 (55.9 net) Operated Wells 28 (7.8 net) non-operated Tier 1 Tier 2 Tier 3 Tier 4 TTL Gross Total Net Total Locations Already in SAL Dec 31 Report

15 Dunvegan Stratigraphy Kaybob South Dunvegan vertical depth is 1,600 to 1,800 m at Kaybob Total hole length is typically 3,000 m to 3,400 m Drill times are 9 to 11 days Dunvegan Carbonates Adapted from Canadian Discovery Digest 15

16 Dunvegan Drilling Vintages Wells with 2 to 3 years History are down to ~20% declines 6,000 5,000 4,000 3 rd Party Solution Gas Processing Restriction Solution Gas Take-away Restriction 2015 Acquisition 3, Drilling 2, Drilling 2013 Drilling 1, Drilling DRILLED & NONOP WELLS ACQUIRED WELLS DRILLED WELLS ACQUIRED WELLS NIPISI DRILLED WELLS ACQUIRED WELLS DRILLED WELLS OTHER DRILLED WELLS ACQUIRED WELLS 16

17 Bbls/d Dunvegan Type Curves - Half Cycle Economics (capex $2.5mm/well) 350 Oil (mbbls) US$70 Oil, C$3.00 gas Strip Flat US$50 / C$2.50 Total (mboe) NPV 10 IRR NPV 10 IRR NPV 10 IRR Tier $5.0mm 162% $4.1mm 90% $2.9mm 68% Tier $3.2mm 65% $2.6mm 42% $1.6mm 31% 200 Type Curve EUR boe/d Oil Gas IP30 IP365 mboe mbbls mmscf 150 Tier Tier Month Note: Y Axis is oil for boe/d add 25% Tier 1 Dunvegan Type Curve Tier 2 Dunvegan Type Curve 17

18 Operated Well #1 Operated Well #3 Operated Well #5 Operated Well #7 Operated Well #9 Operated Well #11 Operated Well #13 Operated Well #15 Operated Well #17 Operated Well #19 Operated Well #21 Operated Well #23 Operated Well #25 Operated Well #27 Operated Well #29 Operated Well #31 Operated Well #33 Operated Well #35 Operated Well #37 Operated Well #39 Operated Well #41 Operated Well #43 Operated Well #45 Operated Well #47 Operated Well #49 Operated Well #51 Operated Well #53 Operated Well #55 Operated Well #57 Operated Well #59 Continuous Improvement of Operations - Decreasing Per Well Capital Costs $7,000,000 $6,000,000 Avg. Capital Cost / Well 1st Five Operated Wells $4,769,293 H Operated Wells (8) (excluding SWF) $2,762,000 Most Recent Five Operated Wells (excluding SWF) $2,512,000 $5,000,000 SWF wells (5) $4,000,000 Completion and lease issues (3) $3,000,000 $2,000,000 $1,000,000 $0 18

19 2. New Mannville Liquids Rich Development Opportunity 67 (66 net) sections of land acquired through land sales and transactions with industry participants As in the Dunvegan, rock work has been key. Area has had hundreds of vertical penetrations to deeper targets over 50 years of industry activity Dozens of cores analyzed and hundreds of cutting samples inspected from previously drilled wells prior to land capture to ensure high-grading of opportunity Main targets are Lower Mannville braided fluvial systems and tidal sands (calibrated to core interpretation) Expect liquids - rich gas based on older vertical production in the region initial locations offset vertical wells that produced or tested oil Multi-zone Potential Secondary zones in Gething, Notikewin, Viking, Ostracod and Rock Creek 19

20 Windfall Mannville Stacked Reservoir Opportunity Stacked Reservoirs 5-20m of 6-20% porosity, 1-15md tighter conventional deep basin reservoirs Gas in Place 7-12 BCF/sec (based on 12% porosity & 9%) Main Lower Mannville Targets Chert-rich (low resistivity) Braidplain (Yellow) deposited as a sheet over area of interest Tidal Bars (Orange) tidal bars in brackish bay Secondary Mannville Targets Gething channels (Brown). Good reservoir quality with limited distribution. Notikewin channels. Existing horizontal production. Lwr Mann_2 Lwr Mann_1 Brackish Bay Fluvial Braidplain Tidal Bar 20

21 Mannville Economic Detail at Strip Pricing Two test wells drilled in Q followed up by 4 or more wells in 2016 Liquids yields on both wells exceeded type curve estimates Single well economics of play satisfactory - drilling & completions refinements to drive down CAPEX / well and delineation will identify sweet spots Economics assume 3 rd party processing and improve with construction of gas plant Dunvegan capital costs / well reduced 48% in 3 years expect Mannville to be $3 to $3.5mm in time Dunvegan initial economics based on IP30 = 200 and IP 365 = 110 boe/d 85% of Dunvegan development has IP30 = 465 and IP365 = 192 Scope and position for future development TCE Mannville Low Liquids Type Curve TCE Mannville "High Liquids" Type Curve Capital Cost ($mm) $3.5 $3.5 Reserves Oil and NGLs (mbbls) Nat Gas (mmcf) 2,500 1,700 Total (mboe) % Oil and NGLs 17% 29% NPV - 10% - $mm $0.6 $1.0 P/I - 10% Discount 1.1x 1.3x Rate of Return 17% 29% IP 30 (boe/d) IP 365 (boe/d) F&D Cost / $ / BOE $6.96 $8.72 F&D Cost / $/BOE/D $9,333 $11,667 21

22 BOE/D Mannville Type Curves Current Environment Half Cycle Economics (capex $3.5mm/well) Liquids (mbbls) US$70 Oil, C$3.00 gas Strip Pricing US$50 / C$2.50 gas Total (mboe) NPV 10 IRR NPV 10 IRR NPV 10 IRR Liquids Rich (60bbls/mmcf) $1.6mm 36% $1.0mm 29% $0.0mm 10% Low Liquids (30bbls/mmcf) $1.1mm 27% $0.6mm 17% $0.0mm 4% EUR mboe 2.5BCF & 85 mbbls 100 EUR mboe 1.7BCF & 115 mbbls Month High (60 bbl/mmcf) Mannville Type Curve Low (30 bbl/mmcf) Mannville Type Curve 22

23 Rate of Return Mannville Low Liquids Type Curve Price Sensitivities with Improved Capex ( $3mm/well) Rate of Return - $3mm per Well CAPEX 100% 94% 90% 84% 80% 75% 70% 66% 60% 55% 50% 51% 40% 43% 30% 36% 20% 24% 30% 17% 11% 10% 5% 0% 0% $40 $45 $50 $55 $60 $65 $70 $75 US$ / bbl WTI C$2.00 / mcf Nat Gas C$3.00 / mcf Nat Gas C$4.00 / mcf Nat Gas 23

24 2016 Operating and CAPEX Budget Maintain Reserves and Balance Sheet Modest 2016 CAPEX budget to maintain production while deleveraging balance sheet 70% of Cash flow spent on CAPEX 10% Increase in production YoY (US$37.50 / bbl) Proforma Analysis Fiscal 2015 Q Q Q Q Fiscal 2016 Production (Boe/d) 3,529 3,834 3,840 3,858 3,850 3,845 % Liquids 59.9% 64.0% 63.7% 61.9% 61.0% 62.6% Liquids (bbls/d) 2,115 2,456 2,445 2,388 2,348 2,409 Revenue (Before Hedging) $57,311,000 $10,107,645 $10,400,290 $10,295,848 $10,167,735 $40,971,518 Revenue (After Hedging) $62,086,890 $13,270,908 $13,125,327 $12,979,198 $12,851,085 $52,226,519 Field NOI $34,962,712 $4,946,005 $5,232,841 $5,076,440 $4,994,130 $20,249,416 CF From Ops $32,975,388 $6,312,439 $5,976,941 $5,933,274 $5,952,212 $24,174,866 CAPEX $70,747,001 $8,250,000 $0 $3,000,000 $5,500,000 $16,750,000 CAPEX (excluding acquisitions) $25,697,001 $8,250,000 $0 $3,000,000 $5,500,000 $16,750,000 Quarter End Debt (exc MTM) $59,795,384 $61,732,946 $55,756,005 $52,822,730 $52,370,518 $52,370,518 Quarter End Debt / Annualized CF 1.81x 2.44x 2.33x 2.23x 2.20x 2.17x Share Count / Equity Drawn 172,737, ,474, ,474, ,474, ,474, ,474,672 Annualized CPFS $0.191 $0.140 $0.132 $0.132 $0.132 $

25 Fiscal 2016 CF (C$mm) 2016 Cash Flow Forecast Hedging Gains Hedges provide certainty to 2016 cash flows which support continued capital program during period of commodity price weakness $35.0 $30.0 $ CAPEX $20.0 $15.0 $10.0 $5.0 $0.0 $20.00 $25.00 $30.00 $35.00 $40.00 $45.00 $50.00 $55.00 $60.00 US$ / bbl Hedging Gain Non Hedging Cash Flow 25

26 OPEX Top Decile Among Liquid Peers OPEX / BOE - Liquids Producers Fiscal 2016 (NBF Research) $30.00 $25.00 $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 26

27 Cash Flow - 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 27

28 The Vision A Look Into 2016 / 2017 Solid Margins - at 2016 strip pricing - annual CF stable at $25mm Low cost structure ensures sustainable cash costs ~C$16.50 / boe Shipper on Alliance (firm service) and firm on Pembina (liquids) unique among juniors Disciplined - CAPEX less than cash flow demonstrate growth at strip pricing but debt / cash flow remains ~2.0x through end 2016 Production Growth Modest production growth in 2016 while CAPEX < cash flow as declines begin to approach 20% / annum IRR / NPV Positive Drilling Drilling inventory economic at today s prices Upside Exposure & Optionality an increase in WTI to US$50 / bbl increases cash flow to $30mm ($0.17 / share) with Debt / CF of <1.7x by Q Opportunity to accelerate drilling, increase production, add to reserves and grow cash flow Continued Positioning combination of organic growth and opportunistic acquisitions positions the company for the future while delivering value creation in a tough environment 28

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