bellatrix corporate presentation nov 2012

CORPORATE PRESENTATION NOVEMBER 15, 2012

TSX: BXE NYSE MKT: BXE

2 Bellatrix Corporate Presentation

TOP TIER PERFORMANCE

APPLYING INNOVATION & TECHNOLOGY TO CREATE VALUE

155% Production Growth (2009-2011)

257% Liquids Production Growth (2009-2011)

191% Reserve Growth per Share (2009 – 2011)

133% Cash Flow Growth per Share (2009-2011)

40+ yrs Years of high ROR Drilling Inventory

REAL GROWTH WITH THE DRILL BIT


CORPORATE SNAPSHOT

Liquidity (past 6 months) 675,000 shares/d

Production guidance (2012e) 16,500 – 17,000 boe/d

Exit rate guidance (2012e) 19,000 – 19,500 boe/d

Oil / liquids weighting 35 %

Capital structure

Common shares - basic 107.6 mm

Common shares - diluted 117.1 mm

Convertible debentures outstanding $55.0 mm (4.75% Coupon $5.60 Strike)

Insider ownership (fully diluted) 13.3%

Tax pools (approximate as of Sept 30, 2012) $560 mm


OPERATIONS AT A GLANCE

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


o Enhance shareholder value with a focused exploitation program supported with targeted acquisitions

o Cardium and Notikewin focused core areas continue to drive growth through horizontal drilling and multi-stage hydraulic fracturing

o Large land base with significant inventory of low risk high rate of return drilling opportunities drive a substantial upside

o Prudent financial management in volatile times through commodity hedges and debt to cash flow maintenance

BELLATRIX STRATEGY

DRILLING ORGANIC OPPORTUNITIES ADDS VALUE


BELLATRIX’S FINANCIAL FORECASTS

Oil ($CDN/bbl) $88.50 $90.00

AECO ($CDN/GJ) $2.00 $3.00

Exchange rate ($CDN/$US) $1.00 $1.00

2012E 2011 Year over

Year

2013E 2012 Year over

Year

Cash from operations $115 - $120 +24% $155 - $165 +35% Cash per share $1.07 - $1.12 +20% $1.45 - $1.55 +36% Avg annual production (boe/d) 16,500 - 17,000 +40% 20,000 – 21,000 +22% Exit Rate (boe/d) 19,000 – 19,500 +16% 21,500 - 22,500 +13%

Capital expenditures ($mm) $160 - $170 $175 - $185 Debt (including Convertible Debenture) Total credit capacity*

$170 - $180 $255

$190 - $200 $255

* Includes $55 million subordinated convertible debenture issued April 15, 2010 and credit facility $200 million through to May 31, 2013


GROWING BELLATRIX

77%

20%

1.5%

1.5%

2013 ESTIMATED CAPITAL BUDGET

+/- $175 - $185 Million

Drilling and Completions

Facilities

Maintenance

Land and Seismic


TRACK RECORD OF PER SHARE GROWTH

PRODUCTION UP 155% LIQUIDS UP 257%

Prod

uctio

n pe

r mm

Sha

res

Oil and liquids Natural gas Production per share

0

20

40

60

80

100

120

140

160

180

-2500

2500

7500

12500

17500

22500

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

6,572

25%

7,248

7,617

9,119

10,000

10,084

11,643

11,837

14,209

15,900

16,569

26% 27% 26% 38% 39%

38% 37%

37%

34%

15,503

19,000

39% 35%

34%


OPERATING EXPENSES AND NETBACKS

CORPORATE NETBACK ($ NETBACK)IIII TOTAL OPERATING EXPENSE ($/BOE)

Before Risk Management

After Risk Management 0

2

4

6

8

10

12

14

16

18

20

$/boe

Date

56%

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00


0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

55,000

60,000

65,000

70,000

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

2009 2010 2011

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

2009 2010 2011

RESERVES / SHARE (boe/share)

RESERVES GROWTH

RESERVES (Mboe)

Oil and liquids Natural gas

29%

40% 37%

38%

28% 38% 29%

28%

38%

40% 37%

38%

265% 191% Oil and liquids Natural gas


REVENUE AND CASH FLOW PER SHARE

REVENUE ($MM’S) CASH FLOW / SHAREIAA

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

69% Liquids

0

50

100

150

200

250

300

2009 2010 2011E 2012E**

Natural GasOil and Liquids

48% 52%

Liquids

69% Liquids

78% Liquids

$109 $118

$202

$225

$0.39

$0.57

$0.91

$1.08

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

2009 2010 2011 2012E

Oil and Liquids

177% 106%


FORMULA FOR GROWTH

o Inventory of low risk development locations − 1,027 net locations (Cardium & Notikewin) − 1,554 net locations total

o Extensive undeveloped land base of 197,428 net acres

o Stacked Hydrocarbon Bearing Reservoirs in WCA:

Belly River +/- 1,300 m

Cardium +/- 2,100 m

Second White Specs +/- 2,200 m

Viking +/- 2,300 m

Notikewin +/- 2,400 m

Falher +/- 2,500 m

Rock Creek +/- 2,600 m

Duvernay +/- 3,400 m


BALANCED RESOURCE PLAY INVENTORY

Net Remaining Inventory

Cost per well ($ mm) Net Remaining Investment ($mm)

Belly River (HZ) 23 $2.5 58

Second White Specks (Vrt) 200 $0.25 5

Cardium (HZ) 669 $3.6 2,408

Notikewin/Falher (HZ) 358 $4.6 1,647

Viking, Mannville, Rock Creek (HZ)

58 $4.6 267

Duvernay (HZ) 246 $11.0 2,706

1,554 $7,091

Based upon internal estimates


CARDIUM LIGHT OIL RESOURCE PLAY

o Approximately 20,000 square miles

o Approximately 1.3 Billion bbls produced to date

o Currently producing 57,000 bbl/d

o LOE < $8.00/boe

o F&D $12.87

o 1,000 Gross, 669 net locations

o Regional facilities & infrastructure control

CANADA’S LARGEST ACCUMULATION OF LIGHT OIL IN THE WESTERN CANADIAN SEDIMENTARY BASIN

BELLATRIX WEST CENTRAL ALBERTA

Pembina

West Pembina

Brazeau

Ferrier

Willesden Green

Norbuck


APPENDIX BUCK CREEK 12-25 OFFSET TO 15-25


CARDIUM OIL TYPE CURVE

0

10

20

30

40

50

60

0

100

200

300

400

500

0 4 8 12 16 20 24 28 32 36 40 44 48 52 56 60 64 68 72 76 80 84 88 92 96 100 104

Con

tribu

ting

Wel

ls

Wee

kly

Aver

age

Prod

uctio

n (b

oed)

Producing Months

BXE Production Oil Well Count

HORIZONTAL CARDIUM OIL WELL PRODUCTION

2 1 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26


BRAZEAU / FERRIER

Brazeau (45-11W5) Cardium Oil Production

Well Payout

Cum

ulat

ive

Pro

duct

ion,

mbb

l

Months from Rig Release

Conoco O’ Chiese 75 mmcf/d capacity BXE 9.88% W.I. Conoco Alder Flats 75 mmcf/d capacity BXE 20% W.I. Keyera MBL 160 mmcf/d capacity

Keyera Nordegg 40 mmcf/d capacity

Keyera Strachan 230 mmcf/d capacity

Keyera West Pembina 140 mmcf/d capacity

BXE Land Sections 69 Gross 59 Net

BXE Wells Drilled 20 Gross 18 Net

BXE Drilling Inventory 451 Gross 400 Net


WEST PEMBINA

0

10

20

30

40

50

60

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

BELLATRIX (4 wells) INDUSTRY (2 Companies, 26 wells)

Well Payout

Cum

ulat

ive

Pro

duct

ion,

mbb

l


West Pembina (48-11W5) Cardium Oil Production, 2011-12 Drills

Keyera Brazeau North 50 mmcf/d capacity

Blaze West Pembina 150 mmcf/d capacity





0

10

20

30

40

50

60

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

BELLATRIX (14 wells) INDUSTRY (2 Companies, 11 wells)

CENTRAL PEMBINA

Central Pembina (48-08W5) Cardium Oil Production, 2010-12 Drills

Cum

ulat

ive

Pro

duct

ion,

mbb

l

Conoco Lodgepole 45 mmcf/d capacity

Arc Pembalta 6 mmcf/d capacity BXE 0.8% W.I.




Well Payout



WILLESDEN GREEN

Willesden Green (42-8W5) Cardium Oil Production

Cum

ulat

ive

Pro

duct

ion,

mbb

l

Conoco Alder Flats 75 mmcf/d capacity BXE 20% W.I. Keyera MBL 125 mmcf/d capacity




0

10

20

30

40

50

60

70

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24BELLATRIX (11 wells) INDUSTRY (3 Companies, 14 wells)

Well Payout


PennWest Gas Plant 60 mmcf/d capacity


CARDIUM TYPE CURVES

0

100

200

300

400

500

600

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

Cardium Rich Gas, 31% liquids Cardium High GOR, 60% liquids Cardium Low GOR 87% liquids

Internal estimates based upon January 1, 2012 Sproule Evaluation Based upon internal IRR $90 CDN/bbl and $3.00 CDN/mmBTU gas


CARDIUM ECONOMICS & INVENTORY

Net Inventory Sections Wells Drilled To Date

Remaining Inventory Remaining Investment ($mm)

Brazeau/Ferrier 59 18 400 1,440

West Pembina 13 12 39 140

Central Pembina 16 19 90 324

Willesden Green 30 9 114 410

Total (inc. other) 111 58 669 2,408

Low GOR Cardium (Main Pembina Pool)

High GOR Cardium (Willesden Grn/Brazeau/Ferrier) Rich Gas Cardium (Ferrier)

Locations (net) 143 425 76

Drill, case, complete & tie-in $3.6M $3.6M $3.6M

Initial Production, IP30 381 boed 585 boed 1427 boed

EUR/well 229 mboe 352 mboe 674 mboe

% liquids 86% 60% 31%

NPVBT @ 10% $5.9M $6.9M $8.8M

Rate of Return 131% 140% 283%

Payout 9 months 9 months 5 months

Based upon internal calculated IRR using $90 CDN/bbl and $3.00 CDN/mmBTU gas


CARDIUM PAD DRILLING EVOLUTION

o 8 well Pads are capital efficient for down-spacing:

o 8 wells will fully develop a section

o 8 single laterals required to achieve the same well density

o Approximate cost savings of $0.3mm per well or $2.4mm/Pad

DEVELOPMENT OF PAD HORIZONTAL WELL DRILLING


NOTIKEWIN/FALHER LIQUIDS RICH GAS

o Regional Stacked Mannville Channel Trend

o 29 BXE and industry Notikewin/Falher gas wells > 10 MMcfd test

o 13 gross wells (5.6 net) wells in 2011

o 5 gross wells (4 net) planned for 2012

o Regional facilities & infrastructure control

West Pembina

Brazeau

Ferrier

Willesden Green

Pembina

BXE Land Sections 184 Gross 96 Net BXE Drilling Inventory 697 Gross 358 Net

Keyera Strachan 230 mmcf/d capacity

Conoco O’ Chiese Conoco Alder Flats Keyera MBL


NOTIKEWIN/FALHER LIQUIDS RICH GAS

DELIVERABILITY PROFILES

NPV 10% BIT = $11.6 mm IRR = 188% Payout 0.8 Years @ $3.00/mmBTU gas & $90 CDN/bbl

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

NPV 10% BIT = $8.2 mm IRR = 101% Payout 1.2 years @ $2.00/mmBTU gas & $95 CDN/bbl

* Population 14 Wells

0

100

200

300

400

500

600

700

0

1000

2000

3000

4000

5000

6000

7000

0 2 4 6 8 10 12 14 16 18 20 22 24

Mon

thly

Ave

rage

Liq

uid

Prod

uctio

n (b

pd)

Mon

thly

Ave

rage

Gas

Pro

duct

ion

(mcf

/d)

Producing Months

Bellatrix Horizontal Notikewin Production *

Gas Liquids


DUVERNAY SHALE

o Industry has licensed 96 wells on Duvernay trend

o 12 industry wells drilled at Ferrier

o BXE 9-24 gas well produced 435 mmcf over 5 months, average 2.9 mmcf/d

o 42 Gross, 41 Net sections held in liquids rich gas fairway

o BHP 63.6 MPa, Over pressured 19.1 KPa/M

o Thickness 33 m, TOC 4-5%, Adsorbed gas 8–10%; porosity 8-10%

Liquid Rich Gas

Dry Gas

Oil Window


$10.54 $11.77

$13.15 $14.29 $14.45 $14.48

$16.94

$22.08

$28.53

$35.23 $35.95

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00

Bel

latri

xE

xplo

ratio

nLt

d.

PEER GROUP COMPARISON

Compared against selected peer group, $250mm EV to $1,500mm EV, 20% to 75% oil / liquids weighting Where 3 years of data is insufficient/non-meaningful, 2 year average P+P F&D costs are applied

Average $19.77/P+P

3 YEAR AVERAGE P+P F&D COSTS (INCL. FDC & EXC. ACQUISITIONS)


3.6x

3.3x 3.2x

2.5x 2.4x 2.2x

1.9x

1.1x 1.0x

0.7x 0.6x

0.0x

1.0x

2.0x

3.0x

4.0xBe

llatr

ixEx

plor

atio

nLt

d.

PEER GROUP COMPARISON

Compared against selected peer group, $250 mm EV to $1,500mm EV, 20% to 75% oil / liquids weighting. Where 3 years of data is insufficient/non-meaningful, 2 year average P+P F&D costs are applied

RECYCLE RATIO [2012E CF NETBACK / 3 YEAR P+P F&D (EXCL. FDC)]

Average 2.1x


PROVIDING PER SHARE VALUE TO INVESTORS THROUGH DRILLING AND DEVELOPMENT

SUMMARY

o Knowledgeable management team with a long term proven track record of growing companies through the drill bit

o Prudent business management focused on per share growth, hedging and debt maintenance

o Top tier asset base with a significant high IRR inventory of drill ready locations ($7.0 billion)

o Low cost operator, low cost finder

o Near term growth catalysts with forecast 2012 exit rate of 19,000 to 19,500 boe/d


CORPORATE INFORMATION

BOARD OF DIRECTORS W.C. (Mickey) Dunn Chairman Doug N. Baker, FCA Murray L. Cobbe John H. Cuthbertson, QC Melvin M. Hawkrigg, BA, FCA, LLD (Hon.) Robert A. Johnson, P.Geol. Keith E. Macdonald, CA Raymond G. Smith, P. Eng. Murray B. Todd, B.Sc., P. Eng.

OFFICERS Raymond G. Smith, P.Eng.

President & CEO

Edward J. Brown, CA Vice President, Finance & CFO

Brent A. Eshleman, P.Eng. Executive Vice President

Ving Y. Woo, P.Eng.

Vice President & COO

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

Tim A. Blair

Vice President, Land

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

Duncan A. Chisholm, B.Sc

Vice President, Production & Business Development

BANKERS National Bank of Canada

Alberta Treasury Branches HSBC Bank Canada

EVALUATION ENGINEERS

Sproule Associates Limited

REGISTRAR & TRANSFER AGENT Computershare Trust Company of Canada

LEGAL COUNSEL

Burnet, Duckworth & Palmer LLP

AUDITORS KPMG LLP

EXCHANGE LISTING

The Toronto Stock Exchange - BXE NYSE MKT - BXE


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

ANALYST COVERAGE


ADVISORY FORWARD LOOKING STATEMENTS: In the interest of providing Bellatrix’s shareholders and potential investors with information regarding Bellatrix, including management’s assessment of Bellatrix’s future plans and operations, certain statements made by the presenter and contained in these presentation materials (collectively, this “presentation”) are “forward looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995 and “forward-looking statements”. The forward-looking statements contained in this presentation speak only as of the date of this presentation and are expressly qualified by this cautionary statement. 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 and 2013 average production and exit rate, estimates of commodity prices and exchange rates, estimated 2012 and 2013 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 and 2013 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 the U.S. Securities Exchange Commission, may be accessed through the SEDAR website (www.sedar.com) the SEC’s website (www.sec.gov) or at Bellatrix's website (www.bellatrixexploration.com). Estimated 2012 and 2013 cash from operations, cash per share and 2012 and 2013 year end debt levels may constitute financial outlooks under applicable securities laws and were approved by management on October 31, 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. Cash from operations per share is calculated using the weighted average number of shares for the period.


ADVISORY

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. INITIAL PRODUCTION RATES: Initial Production rates discloses herein may not be indicative of long-term performance or ultimate recovery. 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 December 31, 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 December 31, 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.

CURRENCY: All dollar amounts in this presentation are Canadian dollars unless otherwise identified.


APPENDIX COMMODITY RISK

Jan 1 – Dec 31, 2012 3,000 bopd $92.30 CDN/bbl

Jan 1 – Dec 31, 2013 1,500 bopd $94.50 CDN/bbl

May 1 – Oct 31, 2012 36.4 mmcfd $3.87 CDN/mcf

Oil

Oil

Gas*

o 58 percent of Q2 & Q3 production hedged in 2012 based on Q1 actual

o * Placed a call on 3,000 bbl/d at $US110/bbl for the year 2013

o Assumes $US/$CDN currency conversion of 1 to 1 and a 39 Mj/m3 average heat content


• Special Care and Attention to Rock Composition, Depositional History, Post Depositional Alteration and Structure

• Define the “Sweet Spot” • Petrographic Support Provides a Competitive Advantage

• Detailed evaluations of potential reservoirs for porosity , permeability: grainsize, composition, cements, clay fraction, fracturing.

• Facies determination using ichnofacies evaluation using trace fossils in core and drill cuttings

• Fracture identification in Cardium and Duvernay • High grading of play inventory via ranking of reservoir character

• Geophysical Support in both Structural and Stratigraphic

APPENDIX BXE DRILLING SUCCESS AT 100%


• Falher “Sweet Spot” identified • 25 Highly Productive Falher Liquids

Rich Gaswells drilled • The BXE Edge: Petrology, 3D

seismic and aeromagnetics “Define the Sweet Spot”

• Thick coarse grained, silica rich channels

• Underlying structure influenced deposition and post depositional fracturing

• Recent modified completion at 13-1, along valley margin, 40T slick water

• New Technique enhances Inventory

APPENDIX FERRIER – FALHER “SWEET SPOT”


Increased grainsize, porosity and silica rich. Wells test at >10 MMcfd. 25 High Rate Wells Drilled

APPENDIX FERRIER – MAIN FALHER CHANNEL


Bellatrix drilled the 13-1 Falher Hzl on an expiring section along the western edge of the main channel. A 40T slick water completion yielded IP7 of 11.5 MMcfd in tighter reservoir.

APPENDIX FERRIER 13-1 SLICK WATER COMPLETION


• Q1 Results at 100%; 12 wells Drilled

• At Buck Creek, we increased the OOIP potential; 2 wells tested the Mid-Lwr Cardium oil section, 300-400 Boed IP7

• West Pembina: completed the Cardium with slick water, approx 600 Boed IP7

• At Brazeau, completed the latest cardium drill at 4-2 with 40T Slick water, >1100 Boed, IP5

• At Ferrier, BXE drilled three liquids rich Cardium gas wells on seismic defined structures, 70 Bbls/MMcf liquids yield. 6-10 MMcfd IP7

• Seismic and aeromag support enhanced fracturing; calcite lined fractures identified in drill cuttings.

APPENDIX BELLATRIX CARDIUM ADVANCEMENTS


• Existing core and log data support increased potential for Cardium OOIP stratigraphically below the earlier developed reservoir layer.

• BXE drilled two successful Hzl oilwells into the Mid-Lwr Shoreface.

• Excellent IP7 production rates of 300 Bopd ( 400 Boed)

• Lower water cuts of approximately 30% vs 95% from the upper Cardium vertical producers.

APPENDIX BUCK CREEK CARDIUM HORIZONTAL PLAN


APPENDIX BUCK CREEK 12-25 OFFSET TO 15-25


APPENDIX BXE BUCK CREEK CARDIUM


BELLATRIX 4-2 CARDIUM HZL FLOW TEST – 40T SLICK WATER, 17 STAGE COMPLETION; AVERAGE APPROX 1100 BOED

APPENDIX BRAZEAU 4-2 FLOW TEST


2300, 530 – 8th Avenue SW Calgary, Alberta Canada T2P 3S8 Tel: (403) 266-8670 Fax: (403) 264-8163 www.bellatrixexploration.com

bellatrix corporate presentation nov 2012

Documents

corporate snapshotliquidity

bellatrix strategyo

liquids production growth

boe corporate netback

cash flow growth

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boedoil liquids weighting35