Peyto Exploration & Development Corp. · TSX:PEY
Peyto Exploration & Development — First Energy Conference 2010
44 slides from Peyto Exploration & Development's conference presentation, Dec 2, 2010
Slide 1: First Energy Conference, December 2, 2010
TSX: PEY.UN December 2, 2010 130 million units outstanding www.Peyto.com
Slide 2: Peyto Version 3.0
Peyto Version 3.0 Di id d paying Dividend i corporation ti $40 $35 Peyto 1.0 10 Peyto 2.0 20 Peyto 3.0 30 $30 Great $25 Recession $20 $15 $10 $5 >$1 Billion in Distributions $‐ unit price w/dist unit price 2
Slide 3: We Invest In Ourselves
We Invest In Ourselves P d ti per U Production Unit it or Sh Share $40 00 $40.00 /d per million) m distribution) 300 Record Production/unit Aug/05 of 241 boe/d/mm $35.00 250 $30.00 Production per Unitt or Share (boe/ nd without cum Converted C t d 200 to a Trust $25.00 $20.00 150 Uniit price (with a
Slide 4: Production Growth Per Unit (share) Industry Comparison
Production Growth Per Unit(share) I d t Comparison Industry C i 30% 20% 10% 0% -10% -20% -30% 4 Q3 2010 over Q3 2009 production per trust unit or share 12/6/2010
Slide 5: Improved Capital Efficiency
Improved Capital Efficiency R Record dAAnnuall P Production d ti W Wedge d $60,000 2010F ~ $16 500/boe/d $16,500/boe/d 2009 - $17,300/boe/d 2008 - $33,100/boe/d 2007 - $26,500/boe/d $50,000 2006 - $50,300/boe/d Annual Produciton Wedge 2005 - $42,100/boe/d 2004 - $22,200/boe/d $22 200/b /d al Efficie
Slide 6: Tight Gas Resource Plays
Tight Gas Resource Plays M lti l V Multiple Vertical ti l /H /Horizontal i t lTTargets t Sundance Area Reservoirs 12 6 12/6/2010
Slide 7: Concentrated Asset Base
Concentrated Asset Base G hi ll F Geographically dC Focused Core A Areas • 240,000 net acres R10 R8 R6 R4 R2W6 R27 R25 • 5 R23 operated R21 gas R19 plants R17 R15 R13W5 T64 ---(245 mmcf/d capacity) T64 • 900 km pipelines C G F F CF F C F F F F GG Cutbank • 700+ producing zones F C F W C FC T62 T62 •
Slide 8: Tight Gas Resource Plays: Horizontal MSF Pilot Projects
Tight Gas Resource Plays H i t l MSF Pil Horizontal Pilott P j t Projects 8 12/6/2010
Slide 9: Cardium Resource Play
Cardium Resource Play H i Horizontal t l MSF Pil Pilott #1 C di Cardium Gas G Fairway F i Pilot Project #1 Sundance Cardium • >4,000 sq miles • up to 65 TCF Gas in Place1 • ~ 2-3 TCF developed to date E Peyto Cardium Rights • >400 sq miles (gross) • 1.0 TCF developed to date (vertical wells only)2 D
Slide 10: Cardium Resource Play: Type Log and Reserves
Cardium Resource Play C di Cardium T Type L Log and dRReserves Volumetric Reserves AREA(Ha)= 256 (1 section) 23m Gross thickness H(m)= 15 15m Net Pay (using POROSITY(%)= 9 6% porosity cutoff) SW(%)= 18 TEMP.(Deg.C)= 80 PRES.(kPa)= 19000 Z= 0.8 Recovery Factor(%)= 85 Surface Loss(%)= 7 OGIP(BCF)= 19.
Slide 11: Cardium Pilot Project #1 – Sundance Cardium
Cardium Resource Play Pilot Project #1 – Sundance Cardium R23 R22 R21 R20 R19W5 W FFUUF F A U F U FL FU Peyto 16-32-55-21-W5 G CG F F G G C W F F C F FF F F F F D24 F U F U 21 F F C F 24 G F 19 U F F W E 24 L G G G UV 20 21 F 22 23 GV F F F F FC 21 UF UF G A 19 20 22 23 22 23 24 19 20 21 22 23 A 20
Slide 12: Cardium Economic Comparison – Vertical vs. Horizontal
Cardium Resource Play E Economic i CComparison i – Vertical V ti l vs. H Horizontal i t l Ave Cardium Vertical ‐ last 5 yrs (00/13‐20‐055‐22W5/0) 7,000 Well 1 Well 2 Well 3 Well 4 6,000 Well 5 Well 6 High Hz Well 7 5,000 Well 7 Ave Vertical Daily Gas Producction (mcfe/d) Ave Vertical Well 8 Ave Hz (
Slide 13: Cardium Horizontal Development Potential Locations
Cardium Horizontal Development P t ti l L Potential Locations ti R9 R7 R5 R3 R1W6 R26 R24 R22 R20 R18 R16W5 F CF F FFF G CE G JF G FC ED F AEF AF C F G FF FCF KKGF CIK CGFCF CF D CL GC G FGFA G E G G G G CG L GF CG ECF F GF CI EF CJ CE EEE L S I E G J EEG EE F LLLG G GG G ILK LF F C FF G GG G EG K F
Slide 14: Notikewin Resource Play
Notikewin Resource Play H i Horizontal t l MSF Pil Pilott #2 Peyto Notikewin Mineral Rights 14 12/6/2010
Slide 15: Notikewin Type Log and Reserves
Notikewin Resource Play T Type L 1 Log 1-20-54-22W5 20 54 22W5 28m Gross Pay Volumetric Reserves 19m Net Pay AREA(Ha)= 256 (1 section) H(m)= 19 23m Gross Pay POROSITY(%)= 8 16m Net Pay SW(%)= 35 TEMP.(Deg.C)= 96 PRES.(kPa)= 32000 Z= 1.02 Recovery Factor(%)= 85 Surface Loss(%)= 4.5 OGIP(BCF)= 22 RGIP
Slide 16: Notikewin Pilot Project #2 – Greater Sundance
Notikewin Resource Play Pilot Project #2 – Greater Sundance Notikewin R23 R22 R21 R20 R19W5 U WF FDV U U F C G F F F W G E Peyto Pine Ck 14-7-56-17W5 L GG FG IC F F FF FF F U F F C G UV F G F F FVU F F F UG F F G F FF F UF UF F I EU G E G U C F F C C FF E F F C V F F U FU F CU F C F FU F F FC CU C F
Slide 17: Notikewin Economic Comparison – Vertical vs. Horizontal
Notikewin Resource Play E Economic i CComparison i – Vertical V ti l vs. H Horizontal i t l Average Vertical Notikewin 00/08‐03‐056‐21W5/0 10,000 Well 2 Well 1 Hi h Hz High H Well 4 Well 3 8,000 Well 5 Well 6 Ave Vertical 08‐03‐56‐21W5 High Hz Ave Horizontal Low Hz on (mcfe/d) Well 7 Ave Hz Extrap A
Slide 18: Wilrich Resource Play
Wilrich Resource Play H i Horizontal t l MSF Pil Pilott #3 Nosehill Project Area Peyto Wilrich Mineral Rights 18 12/6/2010
Slide 19: Wilrich Type Log and Reserves
Wilrich Resource Play T Type L 7 Log 7-5-56-20W5 5 56 20W5 Volumetric Reserves AREA(Ha)= 256 (1 section) JET 2825 H(m)= 16 FRAC 23m Gross Pay (-1578.4) POROSITY(%)= 8 16m Net Pay SW(%)= 35 TEMP.(Deg.C)= 98 PRES.(kPa)= 24000 Z= 0.92 Recovery Factor(%)= 85 Surface Loss(%)= 4.5 OGIP(BCF)= 15 RGIP RAW(B
Slide 20: Wilrich Pilot Project #3 – Nosehill
Wilrich Resource Play Pilot Project #3 – Nosehill Wilrich R21 R20 R19W5 F G 25 F U 29 28 27 F 26 30 29 F28 K 27 26 25 30 29 28 27 26 F F C Peyto 14-05-56-20W5 F G J I EE E F F G F F G G C E Wilrich Horizontal F F CG E IC W LGG F G 20 F F C 21 UF 22 23 24 19 20 21 22 23 24 GGUV 19 20 21 22 23 On Prod
Slide 21: Wilrich Economic Comparison – Vertical vs. Horizontal
Wilrich Resource Play E Economic i CComparison i – Vertical V ti l vs. H Horizontal i t l Average Wilrich Vertical 00/02‐26‐055‐20W5/0 Well 1 10,000 Well 2 Well 3 Well 4 9,000 Well 5 Well 6 Well 7 8,000 Well 8 Ave Vertical High Hz Ave Horizontal Low Hz Well 9 Well 10 Ave. Costs $2,000 $5,120 $5,120
Slide 22: Other Resource Plays: Horizontal MSF Pilot #4, 5 and on
Other Resource Plays H i Horizontal t l MSF Pil Pilott #4 #4,5 5 and d on 22 12/6/2010
Slide 23: Peyto's Full-Cycle Gas Supply Cost
Low Cost Producer P t ’ Full-Cycle Peyto’s F ll C l G Gas S Supply l CCostt $10 $10 hedged Realiized Price ($//mcfe) cfe) $8 41% $8 as Price ($/GJ J) s Price ($/mc Average Profit $6 $6 $/mcf Bonus Cnd$ Realized Gas O Monthly Ga $4 $4 PDP FD&A G&A, Interest $2 $2 Peyto R AECO Peyto Unh Royalties Op C
Slide 24: The New Margins (how to make $3 gas work)
Low Cost Producer Th New The N M Margins i (h(how tto make k $3 gas work) k) Total Peyto Revenue 84.8% Gas 15 2% Liquids 15.2% TWP (new drilling) Peyto 9mo 2010 Unhedged Cardium Hztl Wilrich/Notikewin Hztl $3.92/GJ (Ave AECO daily) $3/GJ $4.57/mcf $ / ((16.5% up p Peyto y realized)) $3.50/mcf $ / ((
Slide 25: Margins Matter
Low Cost Producer M i M Margins Matter tt 100% 90% 80% enue 70% Margin as % of Reve 74% Operating 60% Margin 50% 40% 30% 56% Profit Margin 20% 10% 0% 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Earnings Cashflow Field Netback 25 12/6/2010
Slide 26: Peyto's Industry Leading Op Costs
Low Cost Producer P t ’ IIndustry Peyto’s d t L Leading di O Op C Costs t $16 Quarterly Operating C osts ($/boe) 12%/yr $14 $12 $ $10 $8 $6 $4 1.6%/yr $2 $0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Year Peyto Bonavista Baytex ARC Enerplus Crescent Point Vermilion PMT 26 BOE factor
Slide 27: Low Op Cost = Long Reserve Life
Low Cost Producer L Low O Op Cost C t = Long L R Reserve Lif Life 2009 Year End Proven Producing Reserve Life 15 10 35 Years PDP 5 30 29 TP - 25 25 P+P 21 22 RLI ((yrs) 20 18 16 15 14 14 11 10 10 10 6 5 0 YE 2009 4 times Op Cost 10% inflation 4 times Op PLA Feb 201 Reserve Report (Dec 31, 2009) Cost
Slide 28: Deep Gas Drilling Royalty Incentives
Low Cost Producer D Deep G Gas Drilling D illi R Royalty lt IIncentives ti 3,500-4,000 m MD Trigger depth for Natural Gas Deep Drilling Program 2,200 m TVD reduced from 2,500m TVD to 2,000m TVD 3,700-4,000 m MD 2,650-2,850 m TVD 4,200 m MD 2,750-2,900 m TVD *3,700m 3,700m Cardium Horizontal Well wou
Slide 29: Who's Profitable
Low Cost Producer Wh ’ Profitable Who’s P fit bl Peyto Ave Profit 2002-2009 = $2.92/mcfe Ultra Pet. Ave Profit 2002-2009 = $2.79/mcfe $10 $10 $10 $10 Price ($/mcf) ce ($/mcfe) $8 41% $8 $8 $8 Peyto Realized Gas Price ($/mcfe) $/mcfe) Average ECO Monthly Gas Price ($/GJ) Profit Ultra Realized Gas Pri
Slide 30: Horizontal Well Payout
Horizontal Well Payout C t off Capital Cost C it l Ad Advantage t 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 00/13-35-055-20W5/0 00/12-34-055-20W5/2 Life (in months) Wilrich 00/16-35-055-20W5/0 % Paid Out 00/04-05-056-20W5/0 00/16-33-055-20W5/0 00/14-05-056-20W5/0 00/12-05-056-20W5/0 00/13-25-055-2
Slide 31: The Peyto Strategy: High Returns on Capital and Equity
The Peyto Strategy Hi hR High t Returns on C it l and Capital dE it Equity 60% $250 50% 41% $200 Ave ROE 40% $150 30% 21% Ave $100 ROCE 20% $50 10% 0% $0 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Return On Capital Employed (%) Return On Equity (%) Earnings ($M) Return on Equity (ROE) is
Slide 32: 2010 Activity To Date
2010 Activity To Date Continue Active Development Pace • Capital Expenditures ($225-$250 million before DRC) • ~ 48 net wells pprojected j to YE 2010 ((38 drilled to date)) • 85% are Horizontal MSF • Plant expansion at Nosehill, compressor upgrades at Oldman and Wildhay increase Peyto’s raw gas proc
Slide 33: 2011 Outlook
2011 Outlook More Of The Same • Capital Expenditures ($250-$275 million before DRC) • Drill and Re-enter New Gas Locations ((90% Hz)) • Expand Gas Gathering & Processing Capacity • Expand Undeveloped Land Base • Expand Seismic Database • Acquire Additional Opportunities and Partner Interests 33 12/6
Slide 34: 2011 Outlook: 2010 All Over Again?
2011 Outlook 2010 All O Over A Again? i ? $60,000 2011F ~ $16,500/boe/d $16 500/boe/d 2010F ~ $16,500/boe/d 2009 ‐ $17,300/boe/d 2008 ‐ $33,100/boe/d $50,000 2007 ‐ $26,500/boe/d 2006 ‐ $50,300/boe/d 2005 ‐ $42,100/boe/d $42 100/boe/d 2004 ‐ $22,200/boe/d 2003 ‐ $25,300/boe/d $40,000 2002 ‐ $22,400/
Slide 35: Canada vs USA
Canada vs USA We’re We re losing market share 20 80 19 70 18 17 60 Cnd Gas (bcf/d) US Gas (bcf/d) 16 15 50 14 U C 40 13 12 30 11 10 20 2007 2008 2009 2010 Western Canadian Gas Supply (Bcf/d) U S Dry U.S. D N t lG Natural Gas P d ti (MM Production f) (MMcf)
Slide 36: Appendix
Appendix • Quarterly Track Record • Industry Comparisons • Distribution Historyy • Payout Ratio • Gas Marketing • Hedging Strategy • Reserves data – volumes, values 36 12/6/2010
Slide 37: Quarterly Track Record
Quarterly Track Record 2010 2009 Q3 Q2 Q1 Total Q4 Q3 Q2 Q1 Total Q4 Operations Production Oil & NGLs (bbl/d) 3,322 3,465 3,330 3,028 3,222 2,916 2,950 3,022 3,265 3,207 Natural gas (mcf/d) 122,717 112,422 103,934 92,718 95,467 89,259 90,191 95,998 100,384 101,907 Barrels of oil equivalent 23,775 22
Slide 38: Distribution History
Distribution History Monthly Distribution $0.20 $0.15 $0.10 $0.05 $0.00 Monthly Distribution 38 Historical Per Unit and Units Outstanding numbers have been adjusted to reflect the May 27, 2005 2:1 stock split 12/6/2010 BOE factor - 6 mcf = 1 bbl of oil equivalent
Slide 39: Payout Ratio History
Payout Ratio History Maximum 91% Historical Payout Ratio 100% Minimum Converted 42% % to a Trust 80% at 57% 60% 40% 20% 0% Quarter Cash Payout Ratio Total Payout Ratio Historical Per Unit and Units Outstanding numbers have been adjusted to reflect the May 27, 2005 2:1 stock split Total Payout Ratio
Slide 40: Gas Marketing
Gas Marketing F t Future Sales S l Financial Hedges - Gas 2009 2010 2011 2012 Pricing 0-Jan-00 GJ/d ($/GJ) A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O N D J F M A M J J A S O From To 1-Apr-09 31-Oct-09 5000 $7.850 ● ● ● ● ● ● ● 1-Nov-08 31-Mar-09 5000 $9.700 1-Apr-09 31-Oct-09 5000
Slide 41: Successful Hedging Strategy
Successful Hedging Strategy Peyto Realized Price History 2003 2004 2005 2006 2007 2008 2009 $16.00 Peyto $7.51/mcf Peyto $7.38/mcf Peyto $8.78/mcf Peyto $8.46/mcf Peyto $8.42/mcf Peyto $8.64/mcf Peyto $6.44/mcf AECO Mo AECO Mo AECO Mo AECO Mo AECO Mo AECO Mo AECO Mo $7.43/mcf $7.53/mcf $9.41/mcf $7.
Slide 42: Peyto's Reserves: Volumes
Peyto’s Reserves V l Volumes Natural Gas Sales Gas Liquids & Oil Category (BCF) (Mstb) BOE's(Mstb) Proven Producing 497 15,801 98,573 Proven Non-Producing 15 374 2,913 Proven Undeveloped 242 7,116 47,372 Total Proven 753 23,291 148,858 Probable Additional 260 7,693 51,033 Proved + Probable 1,013 30,
Slide 43: Peyto's Reserves: Net Present Value
Peyto’s Reserves N t Present Net P t Value V l Variable Price Economics NPV (millions of CDN dollars) Category 0% 5% 8% 10% Proven Producing $ 4,655 4 655 $ 2,389 2 389 $1,825 1 825 $ 1,578 1 578 Proven Non-Producing $ 140 $ 68 $ 49 $ 41 Proven Undeveloped $ 1,855 $ 888 $ 626 $ 508 Total Proven $ 6,
Slide 44: Advisory Regarding Forward-Looking Statements
Advisory R Regarding di F Forward-Looking d L ki St Statements t t This presentation contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing
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