11

Corporate PresentationApril 11, 2012

22

Corporate Snapshot

Capital structureCommon shares - basic 107.4 mmCommon shares - diluted 115.3 mmConvertible 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/dExit rate guidance (2012e) 19,000 – 19,500 boe/dOil / liquids weighting (As of December, 2011) 40%Tax pools (approximate) (As of December 31, 2011) $514 mm

33

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

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

1

44

Directors and OfficersExecutive Most Recent PositionRaymond G. Smith, P.Eng.President, Chief Executive Officer & Director President, CEO & Chairman, Meridian Energy Corp.

Edward J. Brown, CAVice President, Finance & CFO Vice President, Finance & CFO, Petrofund Energy Trust

Ving Y. Woo, P.Eng.Vice President & COO Vice President, Engineering, Meridian Energy Corp.

Russell G. Oicle, P. Geol.Vice President, Exploration Supervisor, Exploration, Penn West Energy Trust

Tim A. BlairVice President Land Vice President, Land, Terra Energy Corp.

Garrett K. Ulmer, P. Eng.Vice President, Engineering Manager of Exploitation, Bellatrix Exploration Ltd.

Director ExperienceW.C. (Mickey) DunnChairman

Past Director, Precision Drilling Inc.

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

55

Bellatrix Strategy

• Enhance shareholder value with a focused exploitation program supportedwith targeted acquisitions

• Cardium and Notikewin focused core areas will continue to drive growththrough horizontal drilling and multi-stage hydraulic fracturing

• Large land base with significant inventory of low risk drilling opportunitiesdrive a large upside opportunity

• Continue to deliver on an increased oil and liquids weighting whilemaintaining low F&D costs

• Prudent financial management in volatile times through commodity hedgesand debt to cash flow maintenance

66

Bellatrix’s Financial Forecasts

* Includes $55 million subordinated convertible debenture issued April 15, 2010 and credit facility $170 million as of November 25, 2011.

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)

Total credit capacity*

$87 $119

$225

$160 - $140

$225

77

Commodity Risk

Crude Oil and Natural Gas Production Hedges

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

Jan 1 – Dec 31, 2012 3,000 bopd $92.30 CDN/bblApr 1 – Apr 30, 2012 27.3 mmcfd $4.51 CDN/mcfMay 1 – Oct 31, 2012 36.4 mmcfd $3.87 CDN/mcf

Oil

*Gas

88

Forecast Capital Expenditures

85%11%2% 2%

Drilling and CompletionFacilitiesLand and SeismicMaintenance

+/- $180 Million

2011 Capital Budget 2012 Capital Budget

81.6%7.2%9.4% 1.8%

Drilling and CompletionFacilitiesLand and SeismicMaintenance

+/- $170 Million

99

Production per mm Shares

Oil and liquids

Natural gas

Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012e

Production (boe/d)

Q4 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Q4 2011 Q1 2012e

Proven Track Record of Per Share Growth

6,57225%

7,24826%

7,67127%

9,11926%

10,00038%

10,08439%

11,64338%

11,83737%

83.4 78.4 82.9 93.8 102.6 103.5 108.4 110.2

14,20937%

15,50040%

130.4144.3

1010

14,625 16,500 16,500 16,500

8,700

17,750

27,5005,896

11,725

11,725

$0

$10,000

$20,000

$30,000

$40,000

$50,000

$60,000

Dry Gas 35 bbl/mmcf (Notikewin) 70 bbl/mmcf (Cardium) 90 bbl/mmcf (Duvernay)

NGL's

Condensate

Dry Gas

INCREASING LIQUIDS RATIO

Assumes 5 mmcfd$3.00/GJ

$100/bbl condensate$67/bbl NGL’s

Comparative Revenue Streams

RealizedPrice

$2.93/mcfe $6.22/mcfe $9.15/mcfe $11.15/mcfe

Value of Liquids $0/mcf $3.22/mcf $6.15/mcf $8.15/mcf

1111

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Proved P+P Proved P+P Proved P+P

Oil and liquidsNatural Gas

Reserves Growth

Reserves

2009 20112010

29%

28% 38%

40% 37%

38%

16,492

25,750 24,842

42,442 41,818

67,550

mbo

e

265%

1212

Reserves / Share

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

Proved P+P Proved P+P Proved P+P

boe /

shar

e

Oil and liquids

Natural Gas

2009 2010

29%

28%

38%

40%37%

38%

0.21

0.33

0.25

0.440.39

0.63

2011

Reserves Growth

191%

1313

Revenue and Cash Flow Per Share

Revenue ($mm’s) Cash Flow / Share

** Assumes avg 17000 boe/d 40% liquids, Edmonton Par $100/bbl, AECO $2.50/GJ

69%Liquids

0

50

100

150

200

250

300

350

2009 2010 2011E 2012E**

Natural Gas

Oil and Liquids

48% Liquids

52% Liquids

69% Liquids

79% Liquids

$109 $118

$202

$310

$0.39$0.47

$0.91

$1.37

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

2009 2010 2011 2012E

Oil and Liquids

1414

Formula for Growth

• Inventory of low risk development locations

– 900 net locations– Over 10 years of drilling

inventory• Extensive undeveloped

land base of 224,559 net acres• Large geophysical

database• Concentrated operations base in

WCA• Stacked Reservoirs in WCA:

– Cardium +/- 2,200 m– Notikewin +/- 2,600 m – Duvernay +/- 3,400 m

Northern Alberta / BC(1,000 boe/d)

West Central Alberta(16,000 boe/d)

South East Central Alberta / South West Saskatchewan

(600 boe/d)

Edmonton

Calgary

1515

Pembina – Cardium Oil

• Inventory of 377 net horizontal drilling locations

– 175 gross sections– 110 net sections

• Superior results obtained by understanding variability and applying technology

• Emerging technology horizontal oil well incentive of 30 months or 70 mboe volume at a maximum 5% royalty rate equivalent to $1.9 mm in the first year of production for Crown wells

• 2011– 37 gross wells (27 net)

• 2012– 38 gross wells (32 net)

West Pembina Lodgepole

Willesden Green

Ferrier

Brazeau

1616

Cardium Oil Type Curves

1717

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%

1818

West Central Alberta – Notikewin Gas

• Inventory of over 174 net horizontal drilling locations

– 184 gross sections– 96 net sections

• Typical Notikewin well:– 2,300 m TVD, 1,000 m to

1,400 m hz leg

• Crown wells qualify for the emerging technology horizontal gas well incentive of 18 months 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

Pembina

Brazeau

Ferrier

Willesden Green

West Pembina

Notikewin Gas Discoveries

Mannville Stacked Channels

1919

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

2020

West Central Alberta – Notikewin Condensate Rich Gas

• 13 gross wells (5.6 net) wells in 2011

• 4 gross wells (2.20 net) planned for 2012

Deliverability Profiles

LOE < $1.17/mcfe F&D (2P) $1.11/mcfe

2121

NTKN Economics Table

Gas Price $CDN/GJ

Oil Price$CDN/bbl

Payout (yrs) NPV BT 10% MM$ ROR BT%

$1.5095 1.3 9.656 97.6

100 1.3 9.719 99.7

$2.0095 1.1 10.275 120.3

100 1.1 10.338 122.9

$2.5095 0.9 10.894 149.4

100 0.9 10.957 152.7

$3.0095 0.8 11.513 186.5

100 0.8 11.576 190.8

$3.5095 0.7 12.132 233.6

100 0.7 12.195 239.0

**Internally generated estimates

2222

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

2323

DVRN PRELIMINARY ECONOMICS

Gas Price $CDN/GJ Dry Gas 30bbl NGL / mmcf

Pay outNPVBT@

10%$ million

ROR Pay outNPVBT@

10%$ million

ROR

$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 estimates

2424

Peer Group Comparison(1) – 2 Year Average P+P F&D Costs (incl. FDC)

(1) Compared against selected peer group, $250mm EV to $1,500mm EV, 20% to 75% oil / liquids weighting

$11.00$11.77

$13.72 $13.86

$15.49$16.12

$17.11

$23.52

$32.12

$35.95

$37.79

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00Be

llatr

ixEx

plor

atio

nLt

d.

Average $20.77

2525

Peer Group Comparison (1) Recycle Ratio[2012E CF Netback / 2 Year P+P F&D (excl. FDC)]

1) Compared against selected peer group, $250 mm EV to $1,500mm EV, 20% to 75% oil / liquids weighting.

4.1x

3.8x 3.8x

3.6x

2.5x

2.0x 1.9x

1.6x1.6x

0.8x0.7x

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

Bella

trix

Expl

orat

ion

Ltd.

Average 2.4x

2626

Peer Group Comparison(1) – EV / 2012E DACF

1) Compared against selected peer group, $250 mm EV to $1,500 mm EV, 20% to 70% oil / liquids weighting.

6.3x5.8x

5.0x 5.0x 4.6x 4.6x4.4x 4.3x 4.2x 4.1x

3.6x3.3x 3.2x

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

7.0x

Bella

trix

Exp

lora

tion

Ltd

.

Average 4.5x

2727

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

2828

Corporate Information

BOARD OF DIRECTORSW.C. (Mickey) DunnChairman

Doug Baker, FCA

Murray L. Cobbe

John H. Cuthbertson, QC

Melvin M. Hawkrigg, BA, FCA, LLD (Hon.)

Robert A. Johnson, P.Geol.

Keith Macdonald, CA

Raymond G. Smith, P. Eng.

Murray B. Todd, B.Sc., P. Eng.

OFFICERSRaymond G. Smith, P.Eng.President & CEO

Edward J. Brown, CAVice President, Finance & CFO

Ving Y. Woo, P.Eng.Vice President & COO

Russell G. Oicle, P.Geol.Vice President, Exploration

Tim A. BlairVice President, Land

Garrett K. Ulmer, P.Eng.Vice President, Engineering

EXCHANGE LISTINGThe Toronto Stock ExchangeBXE

BANKERSNational Bank of CanadaAlberta Treasury BranchesHSBC Bank Canada

EVALUATION ENGINEERSGLJ Petroleum ConsultantsSproule Associates Limited

REGISTRAR & TRANSFER AGENTComputershare Trust Company of Canada

LEGAL COUNSELBurnet, Duckworth & Palmer LLP

AUDITORSKPMG LLP

2929

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

3030

Legal Disclaimer

FORWARD LOOKING STATEMENTS: Certain information contained herein may contain forward looking statements including management's assessment offuture 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 capitalexpenditures 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 reserveestimates, actual results from wells to be drilled may not be similar to the results from previous wells drilled, environmental risks, competition from otherproducers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits ofacquisitions, 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 unknownrisks, uncertainties, and other factors, many of which are beyond the control of Bellatrix. Readers are cautioned that the foregoing list is not exhaustive of allfactors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-lookingstatements. Additional information on these and other factors that could effect Bellatrix's operations and financial results are included in reports on file withCanadian 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 underapplicable securities laws and were approved by management on January 23, 2012. The foregoing are included to provide readers with information as to theexpected impact results on the cash from operations of the Corporation during the periods indicated and the ability of the Company to fund its ongoingoperations and capital expenditures and the resulting debt and may not be appropriate for other purposes. The forward-looking statements contained herein aremade 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 tocash from operations or cash from operations per share may not be comparable with the calculation of similar measures for other entities. Management usescash from operations to analyze operating performance and leverage and considers cash from operations to be a key measure as it demonstrates theCompany's ability to generate the cash necessary to fund future capital investments and to repay debt. The reconciliation between cash flow from operatingactivities and funds flow from operations (the Company calculates funds flow from operations in the same manner as cash from operations) can be found in theCompany's Management's Discussion and Analysis which is available through the SEDAR website (www.sedar.com). Cash from operations per share iscalculated using the weighted average number of shares for the period

3131

Legal Disclaimer

.

FD&A COSTS: This presentation includes calculations of finding, development and acquisition ("FD&A") costs for the year ended December 31, 2011. NationalInstrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101") requires that written disclosure of finding and development costs to becalculated 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 inthe calculation. The calculations of FD&A in this presentation include the reserves additions associated with acquisitions and the costs of acquisitions as theCompany believes that including the effect of acquisitions provides useful information to investors. FD&A costs for the year ended December 31, 2011 and 2010are $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 forthe 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 themost recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costsrelated 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 convertingthousands 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 ifused 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 economicequivalence 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 ofestimates of proved plus probable reserves per well as evaluated by Sproule Associates Limited effective June 30, 2011 based on forecast prices andcosts. Estimated ultimate recovery for Notikewin wells is a representative value within the range of estimates of proved plus probable reserves per well asevaluated by Sproule Associates Limited effective June 30, 2011 based on forecast prices and costs. Estimated ultimate recovery for Duvernay wells does notrepresent an estimate of resources but has been provided to show management's assumptions used for its internal projections and plans. There is no certaintythat 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 theresources.

3232

2300, 530 – 8th Avenue SWCalgary, Alberta Canada T2P 3S8

Tel: (403) 266-8670 Fax: (403) 264-8163

www.bellatrixexploration.com