2. 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 mm
2 2
3. 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 aggregation
3 3
4. 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 Corporation
4 4
5. 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 maintenance
5 5
6. 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
7. 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 content
7 7
8. 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 Maintenance
8 8
14. 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 m
14 14
15. 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
17. 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
18. 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 production
18 18
19. 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 net
19 19
20. 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/mcfe
20 20
22. 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 cap
22 22
24. 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 weighting
24 24
25. 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
26. 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
27. 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/d
27 27
28. 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
BXE
28 28
29. 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 Capital
29 29
30. Legal Disclaimer
FORWARD LOOKING STATEMENTS: Certain information contained herein may contain forward looking statements including management's 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 Bellatrix's 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 Bellatrix's 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 Bellatrix's 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 Company's 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
Company's 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
Company's Management's 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 period
30 30
31. 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 management's 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
