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Bellatrix Exploration April 2012 Corporate Presentation
 

Bellatrix Exploration April 2012 Corporate Presentation

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    Bellatrix Exploration April 2012 Corporate Presentation Bellatrix Exploration April 2012 Corporate Presentation Presentation Transcript

    • Corporate Presentation April 11, 20121 1
    • Corporate Snapshot Capital structure Common shares - basic 107.4 mm Common shares - diluted 115.3 mm Convertible debentures outstanding $55.0 mm (4.75% Coupon $5.60 Strike) Insider ownership (fully diluted) 13.3% Production guidance (2012e) 16,500 – 17,000 boe/d Exit rate guidance (2012e) 19,000 – 19,500 boe/d Oil / liquids weighting (As of December, 2011) 40% Tax pools (approximate) (As of December 31, 2011) $514 mm2 2
    • Corporate Snapshot Reserves (P&P) (December 31, 2011 after dispositions)* 67.6 mmboe Net undeveloped acres (December 31, 2011) 224,559 acres Net drilling locations 900 December 31, 2011(P&P) FD&A costs (including FDC) $9.29/boe Reserve life index (P&P) (as at December 31, 2011) 10 years December 31, 2011 Recycle ratio (excluding FDC, P&P) 4.16x 1 December 31, 2011 Recycle ratio (excluding FDC, proved) 3.01x * The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effectives of aggregation3 3
    • Directors and Officers Executive Most Recent Position Raymond G. Smith, P.Eng. President, CEO & Chairman, Meridian Energy Corp. President, Chief Executive Officer & Director Edward J. Brown, CA Vice President, Finance & CFO, Petrofund Energy Trust Vice President, Finance & CFO Ving Y. Woo, P.Eng. Vice President, Engineering, Meridian Energy Corp. Vice President & COO Russell G. Oicle, P. Geol. Supervisor, Exploration, Penn West Energy Trust Vice President, Exploration Tim A. Blair Vice President, Land, Terra Energy Corp. Vice President Land Garrett K. Ulmer, P. Eng. Manager of Exploitation, Bellatrix Exploration Ltd. Vice President, Engineering Director Experience W.C. (Mickey) Dunn Past Director, Precision Drilling Inc. Chairman Doug Baker, FCA Director, ATB, Winstar, RMP Energy Murray L. Cobbe Executive Chairman, Trican Well Service Ltd. John H. Cuthbertson, QC Partner, Burnet, Duckworth & Palmer LLP Melvin M. Hawkrigg, BA, FCA, LLD (Hon.) Chairman, Orlick Industries Limited Robert A. Johnson, P. Geol. Former Executive Vice President, Grey Wolf Exploration Inc. Keith Macdonald, CA Director, Surge Energy, Madalena Ventures Murray B. Todd, B.Sc., P. Eng. President, Canada Hibernia Holding Corporation4 4
    • Bellatrix Strategy • Enhance shareholder value with a focused exploitation program supported with targeted acquisitions • Cardium and Notikewin focused core areas will continue to drive growth through horizontal drilling and multi-stage hydraulic fracturing • Large land base with significant inventory of low risk drilling opportunities drive a large upside opportunity • Continue to deliver on an increased oil and liquids weighting while maintaining low F&D costs • Prudent financial management in volatile times through commodity hedges and debt to cash flow maintenance5 5
    • Bellatrix’s Financial Forecasts 2010A 2011A % Increase 2012E % Increase Oil ($CDN/bbl) $76.25 $92.51 $95 - $100 AECO ($CDN/GJ) $3.81 $3.43 $2.50 - $3.50 Exchange rate ($CDN/$US) $0.97 $1.01 $1.00 Cash from operations $53 $94 +77% $145 - $165 54% - 76% Cash per share $0.57 $0.91 +60% $1.35 – 1.53 48% - 68% Average annual production (boe/d) 8,519 11,954 +40% 16,500 - 17,000 +40% Exit Rate (boe/d) 10,500 16,141 +54% 19,000 – 19,500 +21% Capital expenditures ($mm) $107 $175 +64% $180 +3% Debt (including Convertible Debenture) $87 $119 $160 - $140 Total credit capacity* $225 $225 * Includes $55 million subordinated convertible debenture issued April 15, 2010 and credit facility $170 million as of November 25, 2011.6 6
    • Commodity Risk Crude Oil and Natural Gas Production Hedges Oil Jan 1 – Dec 31, 2012 3,000 bopd $92.30 CDN/bbl *Gas Apr 1 – Apr 30, 2012 27.3 mmcfd $4.51 CDN/mcf May 1 – Oct 31, 2012 36.4 mmcfd $3.87 CDN/mcf 58 percent of Q2 & Q3 production hedged in 2012 based on Q1 actual * Placed a call on 3,000 bbl/d at $US110/bbl for the year 2013 Assumes $US/$CDN currency conversion of 1 to 1 and a 39 Mj/m3 average heat content7 7
    • Forecast Capital Expenditures 2011 Capital Budget 2012 Capital Budget 9.4% 1.8% 2% 2% 81.6% 11% 85% 7.2% +/- $170 Million +/- $180 Million Drilling and Completion Drilling and Completion Facilities Facilities Land and Seismic Land and Seismic Maintenance Maintenance8 8
    • Proven Track Record of Per Share Growth Production (boe/d) Oil and liquids Natural gas 15,500 14,209 40% 11,643 11,837 37% 10,000 10,084 38% 37% 9,119 7,248 7,671 38% 39% 6,572 26% 26% 27% 25% Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012e Production per mm Shares 144.3 130.4 103.5 108.4 110.2 102.6 93.8 83.4 78.4 82.99 Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012e 9
    • Comparative Revenue Streams $60,000 INCREASING LIQUIDS RATIO NGLs Condensate $50,000 11,725 Dry Gas Assumes 5 mmcfd $40,000 11,725 $3.00/GJ $100/bbl condensate $67/bbl NGL’s $30,000 27,500 5,896 17,750 $20,000 8,700 $10,000 14,625 16,500 16,500 16,500 $0 Dry Gas 35 bbl/mmcf (Notikewin) 70 bbl/mmcf (Cardium) 90 bbl/mmcf (Duvernay) Realized $2.93/mcfe $6.22/mcfe $9.15/mcfe $11.15/mcfe Price10 Value of Liquids $0/mcf $3.22/mcf $6.15/mcf $8.15/mcf 10
    • Reserves Growth Reserves 70,000 67,550 Oil and liquids 38% Natural Gas 60,000 265% 50,000 42,442 41,818 mboe 40,000 40% 37% 30,000 25,750 24,842 28% 38% 20,000 16,492 29% 10,000 0 Proved P+P Proved P+P Proved P+P11 2009 2010 2011 11
    • Reserves Growth Reserves / Share 0.7 Oil and liquids 0.63 0.6 Natural Gas 38% 191% 0.5 0.44 40% 0.39 0.4 boe / share 37% 0.33 0.3 28% 0.25 38% 0.21 0.2 29% 0.1 0.0 Proved P+P Proved P+P Proved P+P12 2009 2010 2011 12
    • Revenue and Cash Flow Per Share Revenue ($mm’s) Cash Flow / Share Natural Gas 350 $1.60 Oil and Liquids Oil and Liquids $310 $1.40 300 79% Liquids $1.37 $1.20 250 $202 $1.00 200 69% 69% Liquids $0.80 $0.91 Liquids 150 $118 $0.60 $109 52% 100 48% Liquids $0.40 $0.47 Liquids $0.39 50 $0.20 0 $0.00 2009 2010 2011E 2012E** 2009 2010 2011 2012E ** Assumes avg 17000 boe/d 40% liquids, Edmonton Par $100/bbl, AECO $2.50/GJ13 13
    • Formula for Growth • Inventory of low risk development locations Northern Alberta / BC (1,000 boe/d) – 900 net locations – Over 10 years of drilling inventory • Extensive undeveloped land base of 224,559 net acres • Large geophysical Edmonton database West Central Alberta • Concentrated operations base in (16,000 boe/d) WCA • Stacked Reservoirs in WCA: – Cardium +/- 2,200 m South East Central Alberta / – Notikewin +/- 2,600 m South West Saskatchewan Calgary (600 boe/d) – Duvernay +/- 3,400 m14 14
    • Pembina – Cardium Oil • Inventory of 377 net horizontal drilling locations – 175 gross sections – 110 net sections West Pembina • Superior results obtained by understanding variability and Lodgepole applying technology • Emerging technology horizontal oil well incentive of 30 months or 70 mboe volume at a maximum 5% Brazeau royalty rate equivalent to $1.9 mm in the first year of production for Crown wells • 2011 Ferrier Willesden – 37 gross wells (27 net) Green • 2012 – 38 gross wells (32 net)15 15
    • Cardium Oil Type Curves16 16
    • Cardium Oil Economics Locations (net) 377 Drill, case, complete & tie in $3.8m Production potential IP30 536 boed EUR / Well 270 mboe NPV BT@10% $7.3m Rate of Return 262%17 17
    • West Central Alberta – Notikewin Gas • Inventory of over 174 net horizontal drilling locations – 184 gross sections West Pembina – 96 net sections • Typical Notikewin well: Mannville Stacked Channels Brazeau – 2,300 m TVD, 1,000 m to Notikewin Gas 1,400 m hz leg Discoveries Pembina Ferrier • Crown wells qualify for the emerging technology horizontal gas well incentive of 18 months Willesden Green per 500 mmcf at 5% royalty rate as well as the natural gas drilling program incentive maintaining the 5% rate to $2.0 mm over the first 2 years of production18 18
    • West Central Alberta – Notikewin Condensate Rich Gas • Regional Stacked Mannville Channel Trend • 19 BXE Notikewin/Falher gas wells > 10 MMcfd test • Industry Drilled 9 High IP Wells > 10 MMcfd test • BXE Inventory of High Rate Drill Locations, 63 gross, 34.46 net19 19
    • West Central Alberta – Notikewin Condensate Rich Gas Deliverability Profiles • 13 gross wells (5.6 net) wells in 2011 • 4 gross wells (2.20 net) planned for 2012 LOE < $1.17/mcfe F&D (2P) $1.11/mcfe20 20
    • NTKN Economics Table Gas Price Oil Price Payout (yrs) NPV BT 10% MM$ ROR BT% $CDN/GJ $CDN/bbl 95 1.3 9.656 97.6 $1.50 100 1.3 9.719 99.7 95 1.1 10.275 120.3 $2.00 100 1.1 10.338 122.9 95 0.9 10.894 149.4 $2.50 100 0.9 10.957 152.7 95 0.8 11.513 186.5 $3.00 100 0.8 11.576 190.8 95 0.7 12.132 233.6 $3.50 100 0.7 12.195 239.0 **Internally generated estimates21 21
    • Duvernay Shale - Resource Play • 44 Gross, 43 Net sections held in liquids rich gas fairway • Thickness 33 m, TOC 4-5%, Adsorbed gas 8–10%; porosity 8-10% • Over pressured 15.6 KPa/m • Expected recoveries of 70-100 bbls liquids per mmcf • Over $1.4 B invested by industry on offset Duvernay rights • Wells qualify for emerging technologies shale gas incentive of 10% royalty rate holiday for 36 months; no volume cap22 22
    • DVRN PRELIMINARY ECONOMICS Gas Price $CDN/GJ Dry Gas 30bbl NGL / mmcf NPVBT@ NPVBT@ Pay out 10% ROR Pay out 10% ROR $ million $ million $2.50 6.7 <$0.39> 9% 1.9 $6.46 42% $3.00 4.1 $1.48 15% 1.4 $10.37 71% $4.00 2.4 $5.24 32% 1.1 $14.37 105% $5.00 1.6 $9.00 55% 0.9 $18.37 145% $6.00 1.3 $12.76 82% 0.8 $22.37 192% **Internally generated estimates23 23
    • Peer Group Comparison(1) – 2 Year Average P+P F&D Costs (incl. FDC) $40.00 $37.79 $35.00 $35.95 $32.12 $30.00 $25.00 Average $20.77 $23.52 $20.00 $17.11 $15.00 $16.12 $15.49 $13.72 $13.86 $11.77 $10.00 $11.00 $5.00 $0.00 Exploration Bellatrix Ltd. (1) Compared against selected peer group, $250mm EV to $1,500mm EV, 20% to 75% oil / liquids weighting24 24
    • Peer Group Comparison (1) Recycle Ratio [2012E CF Netback / 2 Year P+P F&D (excl. FDC)] 5.0x 4.0x 4.1x 3.8x 3.8x 3.6x 3.0x Average 2.4x 2.5x 2.0x 2.0x 1.9x 1.6x 1.6x 1.0x 0.8x 0.7x 0.0x Exploration Bellatrix Ltd. Compared against selected peer group, $250 mm EV to $1,500mm EV, 20% to 75% oil / liquids weighting.25 1) 25
    • Peer Group Comparison(1) – EV / 2012E DACF 7.0x 6.0x 6.3x 5.8x 5.0x Average 4.5x 5.0x 5.0x 4.6x 4.6x 4.0x 4.4x 4.3x 4.2x 4.1x 3.6x 3.0x 3.3x 3.2x 2.0x 1.0x 0.0x Bellatrix Exploration Ltd.26 1) Compared against selected peer group, $250 mm EV to $1,500 mm EV, 20% to 70% oil / liquids weighting. 26
    • Summary • Experienced management team with a proven track record of growing companies through the drill bit • Focus on prudent business management through per share growth, hedging and debt maintenance • Top tier asset base with a significant inventory of drill ready locations ($2.1 billion for Cardium and Notikewin) • Low cost operator with a commitment to increasing oil and liquids weighting • Near term growth catalysts with forecast 2012 exit rate of 19,000 to 19,500 boe/d27 27
    • Corporate Information BOARD OF DIRECTORS OFFICERS BANKERS W.C. (Mickey) Dunn Raymond G. Smith, P.Eng. National Bank of Canada Chairman President & CEO Alberta Treasury Branches HSBC Bank Canada Doug Baker, FCA Edward J. Brown, CA Vice President, Finance & CFO EVALUATION ENGINEERS Murray L. Cobbe Ving Y. Woo, P.Eng. GLJ Petroleum Consultants John H. Cuthbertson, QC Sproule Associates Limited Vice President & COO Melvin M. Hawkrigg, BA, FCA, LLD (Hon.) Russell G. Oicle, P.Geol. REGISTRAR & TRANSFER AGENT Robert A. Johnson, P.Geol. Computershare Trust Company Vice President, Exploration Keith Macdonald, CA of Canada Tim A. Blair Raymond G. Smith, P. Eng. LEGAL COUNSEL Vice President, Land Murray B. Todd, B.Sc., P. Eng. Burnet, Duckworth & Palmer LLP Garrett K. Ulmer, P.Eng. Vice President, Engineering AUDITORS KPMG LLP EXCHANGE LISTING The Toronto Stock Exchange BXE28 28
    • Analyst Coverage Analyst Firm Jeremy McCrea AltaCorp Capital Omid Ameri Byron Securities Brian Kristjansen Canaccord Genuity Kevin Shaw Casimir Capital Arthur Grayfer CIBC Chris Bolton Fraser Mackenzie Geoff Ready Haywood Securities Christina Lopez Macquarie Capital Dan Payne National Bank Financial Ken Lin Paradigm Capital Paul Lee Scotia Capital29 29
    • Legal Disclaimer FORWARD LOOKING STATEMENTS: Certain information contained herein may contain forward looking statements including managements assessment of future plans and operations, drilling plans and the timing thereof, commodity price risk management strategies, expected 2012 average production and exit rate, estimates of commodity prices and exchange rates, estimated 2012 cash from operations, estimated recovery from wells to be drilled in 2012 capital expenditures and the nature of capital expenditures and cash from operations per share and estimated 2012 year end debt levels, may constitute forward- looking statements under applicable securities laws and necessarily involve risks including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, actual results from wells to be drilled may not be similar to the results from previous wells drilled, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources. The recovery and estimates of Bellatrixs reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Bellatrix. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could effect Bellatrixs operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), at Bellatrixs website (www.bellatrixexploration.com). Estimated 2012 cash from operations, cash per share and 2012 year end debt levels may constitute financial outlooks under applicable securities laws and were approved by management on January 23, 2012. The foregoing are included to provide readers with information as to the expected impact results on the cash from operations of the Corporation during the periods indicated and the ability of the Company to fund its ongoing operations and capital expenditures and the resulting debt and may not be appropriate for other purposes. The forward-looking statements contained herein are made as at the date hereof and Bellatrix does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. NON-GAAP MEASURES: This presentation contains the term "cash from operations" which should not be considered an alternative to, or more meaningful than "cash flow from operating activities" as determined in accordance with Canadian GAAP as an indicator of the Companys performance. Therefore reference to cash from operations or cash from operations per share may not be comparable with the calculation of similar measures for other entities. Management uses cash from operations to analyze operating performance and leverage and considers cash from operations to be a key measure as it demonstrates the Companys ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between cash flow from operating activities and funds flow from operations (the Company calculates funds flow from operations in the same manner as cash from operations) can be found in the Companys Managements Discussion and Analysis which is available through the SEDAR website (www.sedar.com). Cash from operations per share is calculated using the weighted average number of shares for the period30 30
    • Legal Disclaimer . FD&A COSTS: This presentation includes calculations of finding, development and acquisition ("FD&A") costs for the year ended December 31, 2011. National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") requires that written disclosure of finding and development costs to be calculated in accordance with Section 5.15 of NI 51-101 which does not include the reserves additions associated with acquisitions or the costs of acquisitions in the calculation. The calculations of FD&A in this presentation include the reserves additions associated with acquisitions and the costs of acquisitions as the Company believes that including the effect of acquisitions provides useful information to investors. FD&A costs for the year ended December 31, 2011 and 2010 are $9.29/boe and $12.89/ proved plus probable boe respectively and the average FD&A for the last three completed years is $13.69/ proved plus probable boe. The finding and developments costs calculated in accordance with Section 5.15 of NI 51-101 for the years ended December 31, 2011 and 2010 are $13.00/proved boe ($9.29/proved plus probable boe) and $8.37/proved boe ($6.06/proved plus probable boe) and the average finding and development costs for the last three completed years is $10.59/proved boe ($13.69/proved plus probable boe). The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. BOE PRESENTATION: In this presentation, production is stated in barrels of oil equivalent (“BOE”) using a six to one conversion basis when converting thousands of cubic feet of natural gas to barrels of oil and a one to one conversion basis for natural gas liquids. Such conversion may be misleading, particularly if used in isolation. A 6:1 conversion ratio is based on energy equivalence between natural gas and oil at the burner tip and does not represent economic equivalence at the wellhead or point of sale. ESTIMATED ULTIMATE RECOVERY (EUR): In this presentation, estimated ultimate recovery for Cardium oil wells is a representative value within the range of estimates of proved plus probable reserves per well as evaluated by Sproule Associates Limited effective June 30, 2011 based on forecast prices and costs. Estimated ultimate recovery for Notikewin wells is a representative value within the range of estimates of proved plus probable reserves per well as evaluated by Sproule Associates Limited effective June 30, 2011 based on forecast prices and costs. Estimated ultimate recovery for Duvernay wells does not represent an estimate of resources but has been provided to show managements assumptions used for its internal projections and plans. There is no certainty that any resources will be discovered for such Duvernay wells. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.31 31
    • 2300, 530 – 8th Avenue SW Calgary, Alberta Canada T2P 3S8 Tel: (403) 266-8670 Fax: (403) 264-8163 www.bellatrixexploration.com32 32