Yangarra Resources Ltd. · TSX:YGR
Yangarra Resources — Investor Presentation (May 2014)
35 slides from Yangarra Resources's investor presentation, May 2014
Slide 1: Corporate Presentation May 2014
Yangarra was recognized as a TSX Venture 50® company in 2014. TSX Venture 50 is a trade-mark of TSX Inc. and is used under license Corporate Presentation May 2014 TSX-V: YGR
Slide 2: Forward-looking statements
Statements in this presentation may contain forward-looking information including expectations of future production and components of cash flow and earnings. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and unce
Slide 3: Boe conversion and reserve definitions
Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value eq
Slide 4: Corporate values and full cycle IRR focus
• Our job is to create shareholder value • Integrity and ethical behavior are essential to success • Sound ethics and shareholders interests are compatible • It is okay to be wrong: own it, accept it, learn from it • Embrace adversity, it is a difficult business • Diversity of skill-sets within the
Slide 5: Publicly listed junior oil and gas company
Publicly listed junior oil and gas company TSX-V: YGR Shares Outstanding Basic 173 million Options/Warrants (weighted average $0.63) 15 million Fully Diluted 188 million Insider Ownership Basic 15% Fully Diluted 22% Market Capitalization (at $1.15/share) $200 million Current Net Debt Estimate ($90 m
Slide 6: First Quarter 2014 Production and netbacks
First Quarter 2014 Production 2,764 boe /d Liquid Content 53% Sales Price $ 62.37 /boe Royalty income 1.25 / boe Royalty expense (3.73) /boe Production costs (6.42) boe Transportation costs (1.32)/ boe Field Operating netback $ 52.07 / boe Commodity contract settlement (6.85)/ boe Operating netback
Slide 7: Management Team and Board of Directors
Management Team Jim Evaskevich, President & CEO Randall Faminow, VP, Land • 30+ years extensive executive experience with strong • 30+ years of experience in all aspects of oil and gas land work, operations background including negotiation, acquisitions and divestments, contracts and mergers Lorne S
Slide 8: Cashflow and reserves per share growth
30,000,000 20,000 25,000,000 15,000 (Cashflow) 20,000,000 (mboe) 15,000,000 10,000 10,000,000 5,000 5,000,000 0 0 2010 2011 2012 2013 Cashflow Reserves Cashflow per share growth Reserves per share growth 2011 278% 2011 13% 2012 0% 2012 38% 2013 45% 2013 15% 8
Slide 9: 41% reduction in average drilling costs since 2011
6000 25 41% reduction in Drilling Represents 70% average drilling costs of Corporate Costs since 2011 5000 Staff count is down and 473 20 performance is up 4000 498 1,807 373 15 Equip Complete 3000 1,792 1,376 273 Drill 10 Staff Count 2000 1,134 2,832 5 1000 2,088 2,134 1,563 0 0 9 2010 2011 2012 20
Slide 10: Drilling cost per meter and completion cost per stage
Drilling cost per meter Completion cost per stage 800 250,000 700 200,000 600 500 150,000 400 Cost per meter 300 100,000 Cost per 200 stage 50,000 100 0 0 2010 2011 2012 2013 2010 2011 2012 2013 10
Slide 11: Half Cycle and Full Cycle IRR
Half Cycle IRR (1) Full Cycle IRR (2) 80% 70% 60% 50% IRR 40% 67% 65% 30% 20% 41% 34% 31% 10% 24% 26% 12% 0% 2010 2011 2012 2013 1. Half cycle IRR is based on actual drilling and completion costs, production to date and P+P reserves. 2. Full cycle IRR allocates all other capital costs to the wells (
Slide 12: P+P reserves and reserve value growth
P+P Reserves (mboe) Reserve Value PV10 ($ millions) 20,000 300 18,000 250 16,000 14,000 200 12,000 Oil Oil 10,000 150 NGL's NGL's 8,000 Natural gas Natural gas 100 6,000 4,000 50 2,000 0 0 2010 2011 2012 2013 2010 2011 2012 2013 • 298% increase in reserves since 2010 (86% per share) • Replaced 2013
Slide 13: 2014 CAPEX budget and guidance
CAPEX budget for 2014 $75.0 million • Budget focused on Central Alberta • Includes one Duvernay vertical test well • Funded with cash flow and the existing credit facilities 2014 Guidance Production (boe/d) Annual Average 3,500 boe/d Cash flow from operations $50 million Annual debt to cash flow 0.9
Slide 14: Central Alberta
Central Alberta • Interest in 140 sections of land • 70 total horizontal wells drilled since 2010 • Focus • Cardium and Glauc plays Pembina Edmonton Willesden Green • Light oil Ferrier Rocky Mountain House • High netback Red Deer • Quick payouts Calgary 14
Slide 15: Vertical production exists in all zones
Colorado Group Cardium 650m thick 5m Second White Specks • Vertical production 30m exists in all zones Viking 5m • All zones meet the criteria for horizontal drilling Glauconitic 20m Ellerslie 10m Rock Creek 15m Duvernay 15
Slide 16: 5+ years of drilling inventory
Gross Net Net Booked in Locations Locations 2013 reserve Inventory Type report Cardium Light Oil (includes 105 78 35 farm-in) Glauconite Liquids Rich 40 26 11 Total 145 104 46 • 5+ years of drilling inventory in Cardium and Glauconite • Significant un-booked upside • Additional locations in the SWS
Slide 17: Cardium horizontal wells
• Drilled or participated in 38 gross (24.6 net) HZ Cardium wells (32 operated) • Reservoir is characterized by 60-85% oil and liquid weighting • Currently being developed with four wells per section • Yangarra owns a 15 % override on 11 sections • Map indicates extent of prospective lower permeabil
Slide 18: Willesden Green Cardium farm-in
• 47 gross (29 net) sections in the Willesden Green area that offset existing Yangarra land holdings • 61 gross (37 net) Cardium locations indentified • Pay 100% to earn 75%, earn one section per earning well • 7 net earning wells over a two year period • Rolling option until December 2016 • Drillin
Slide 19: Hoadley Glauconite Barrier Island Complex
Hoadley Glauconite Barrier Island Complex: • Development of our Glauconite lands commenced in March 2010 with the drilling of our first horizontal (“HZ”) well • Drilled or participated in 22 gross HZ (13.3 net) wells to date into the formation (12 operated) • Accumulated 45 gross (24.0 net) sections
Slide 20: Second White Specks (SWS) lands
• Significant amounts of oil have been produced over the past 30 years from vertical wells • 10 to 20 million barrels of Original Oil in Place (OOIP) per section • Accumulated 45 gross (35 net) sections • Yangarra has 3 horizontal wells and 2 vertical wells in the SWS formation Yangarra Land 20
Slide 21: Duvernay land
• Yangarra owns 61 Gross North Block (61 net) sections of Duvernay land South Block Yangarra Land 21
Slide 22: Let industry de-risk the Duvernay play
• Let industry de-risk the play • Continue land-base to 2020 with three vertical strat test wells • Larger players are migrating to the Duvernay which may provide opportunities in plays like the Cardium and Glauc in Central Alberta • Our first vertical strat test well is planned for late 2014 • The
Slide 23: Hedges and interest rate swaps
Oil Hedges 2014: 1,200 bbl/d hedged at $95.02/bbl 2015: 1,300 bbl/d hedged at $93.65/bbl Natural Gas Hedges 2014: 5,000 GJ/d hedged at $3.39/GJ or $4.20/mcf* Interest Rate Swaps 4.70% Fixed rate on $10 million (June 2014-June 2018) 4.85% Fixed rate on $10 million (June 2014-June 2018) 23 * Assumes Y
Slide 24: Peer comparison table
YGR PEY BNP BXE WCP DTX TVE BNE TOU RMP Production 2,796 72,208 74,015 35,049 26,508 9,372 4,182 12,006 102,564 9,229 Gas Weighting 47% 90% 65% 65% 29% 22% 44% 31% 85% 40% Netback $45.23 $23.58 $30.24 $33.46 $53.96 47.21 $40.52 $44.94 $31.03 49.23 Op Costs $7.81 $3.14 $10.51 $9.72 $12.11 $11.87 $16.
Slide 25: Operating costs and G&A per boe vs peers
Q1 2014 Operating costs/boe Q1 2014 G&A/boe 35.00 10.00 30.00 8.00 25.00 20.00 Average $17.94 6.00 Average $4.36 15.00 4.00 10.00 2.00 5.00 0.00 0.00 YGR YGR • Management team with strong operations background • Maintain low operating costs through operational presence and control over infrastructur
Slide 26: Debt to cash flow and debt/equity vs peers
Q1 2014 Debt to Cash Flow Q1 2014 Debt/Equity 10.00 1.60 9.00 1.40 8.00 1.20 7.00 6.00 1.00 5.00 0.80 4.00 0.60 3.00 0.40 2.00 1.00 0.20 0.00 0.00 YGR YGR • Focus on reducing costs and maximizing profit • Risk management program protects against a drop in oil prices 26 Tables based on internal analy
Slide 27: NAV per share
$1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $- 2010 2011 2012 2013 2014 27
Slide 28: Corporate transition point summary
• Proven operational track record, on a per share basis • Production per share growth of 134% since 2010 • Reserve per share growth of 86% since 2010 • Focus on improving economics and accelerating capital • CAPEX / well down 41% since 2011 drilling program • 2013 wells with IRRs of 65% half-cycle a
Slide 29: Appendix
Appendix 29
Slide 30: Detailed hedge positions
2014 (1,200 bbl/d hedged) 2014 Natural Gas (5,000 GJ/d hedged) • 100 bbl/d @ $98.30 WTI/CAD for 2014 • 1,000 GJ/d at $3.11/GJ for Jan – Dec 2014 • 100 bbl/d @ $100.00 WTI/CAD for 2014 • 1,000 GJ/d at $3.05/GJ for Jan – Dec 2014 • 100 bbl/d @ $91.40 WTI/CAD for 2014 • 1,000 GJ/d at $3.54/GJ for Jan –
Slide 31: Cash flow sustainability ratio vs debt/cash flow
Cash Flow Sustainability Ratio (2013) vs. Debt / Cash Flow >$500 EV Liquids 225% >$500 EV Gas PPY <$500 EV Liquids TOG YO NVA 200% <$500 EV Gas PXX RE TOL Cash Flow Sustainability ((CAPEX + Divs )/ CashFlow 175% CQE PGF RTK SOG LPR ARX DEE MQL 150% ZAR DTX BTE NGL CPG CTA PXL MEI PBN RRX SGY PWT RMP
Slide 32: Leverage to Duvernay play in enterprise value
• Yangarra is highly leveraged to the Duvernay play in terms of acres to Enterprise Value 32
Slide 33: Texas Water Demand
Texas Water Demand Irrigation 55.9% Municipal 26.9% Manufacturing 9.6% Steam Electric 4.1% Livestock 1.8% Mining (including oil and gas) 1.6% “The amount of water required to drill all 2916 of the Marcellus wells permitted in Pennsylvania in the first 11 months of 2010 would equal the amount of drin
Slide 34: North American cost of new gas supply
A North "ATCEiCan ‘Cést ‘OF iNew. w Gas) Supply ~ 2012 Market Deliverability Dry gas development is required to offset annual production declines Gas production required to offset Supply Cost* $/MMBtu decline from December 2011 >$6.00 | | q $5.50 -6.00 | $5.00 -5.50 | I $4.50 -5.00 | | $4.00 -4.50 |
Slide 35: Yangarra Resources Ltd.
Yangarra Resources Ltd. 1530, 715 – 5 Ave. SW Calgary, Alberta T2P 2X6 403-262-9558 35
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