SUSTAINABLE LONG TERM VALUE CREATION Corporate Presentation – March 2017

Advisories

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 contained in these presentation materials (collectively, this “presentation”) are forward looking statements or information within the meaning of applicable securities legislation, collectively referred to herein as “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. Forward looking statements in this presentation include, but are not limited to: statements regarding the quality of the Company’s assets and acreage, the Company’s infrastructure and firm transportation capacity, the Company’s growth plans and forecasted capital efficiencies and investment returns, the Company’s balance sheet and available liquidity, future production estimates, future drilling locations, 2017 guidance relating to production, production mix, net capital expenditures and production expense, the Company’s net asset value, the Company’s acreage position, the nature and profitability of the Company’s Spirit River acreage, well results, the sustainability of cost reductions, drilling times and capital efficiencies, development metrics, future drilling inventory, the Company’s land position, and the sufficiency and performance of the Company’s infrastructure. To the extent that any forward-looking information contained herein constitute a financial outlook, they were approved by management on March 14, 2017 and are included herein to provide readers with an understanding of the anticipated funds available to Bellatrix to fund its operations and readers are cautioned that the information may not be appropriate for other purposes. Forward looking statements 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, 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, actions taken by the Company's lenders that reduce the Company's available credit and ability to access sufficient capital from internal and external sources. 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. In addition, forward looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect and which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on Bellatrix’s future operations. Such information may prove to be incorrect and readers are cautioned that the information may not be appropriate for other purposes. Although the Company believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market its oil and natural gas products. 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 affect Bellatrix’s operations and financial results are included in reports on file with Canadian and United States securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), through the SEC website (www.sec.gov), and at Bellatrix’s website (www.bellatrixexploration.com). Furthermore, 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 Throughout this presentation, the Company uses terms that are commonly used in the oil and natural gas industry, but do not have a standardized meaning presented by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable to the calculations of similar measures for other entities. Management believes that the presentation of these non-GAAP measures provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis. CAPITAL PERFORMANCE MEASURES In addition to the non-GAAP measures described above, there are also terms that have been reconciled in the Company’s financial statements to the most comparable IFRS measures. These terms do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculations of similar measures for other entities. These terms are used by management to analyze operating performance on a comparable basis with prior periods and to analyze the liquidity of the Company. This presentation contains the term “total net debt” which is not recognized measures under GAAP. Therefore reference to total net debt may not be comparable with the calculation of a similar measure for other entities. The Company’s calculation of total net debt excludes other deferred liabilities, deferred capital obligations, long-term risk management contract liabilities, decommissioning liabilities, and deferred tax liabilities. Total net debt includes the working capital deficiency, long term loans receivable, convertible debentures (liability component), current bank debt and long term bank debt. DRILLING LOCATIONS In this presentation, the Company has disclosed certain drilling locations associated with Bellatrix's interest in the Spirit River and Cardium plays. Of the 393 net Spirit River drilling locations identified herein, 86 are proved locations, 30 are probable locations and 277 are unbooked locations. Of the 239 net Cardium drilling locations identified herein, 107 are proved locations, 37 are probable locations, and 95 are unbooked locations. Proved locations and probable locations are derived from Bellatrix’s independent reserve report prepared by InSite Petroleum Consultants Ltd. as at December 31,2016 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations as disclosed herein have been identified by management as an estimation of the Company's multi-year drilling activities using information including applicable geologic, seismic, engineering, production, pricing assumptions and reserves information. There is no certainty that Bellatrix will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which Bellatrix actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While the majority of Bellatrix's unbooked locations are extensions or infills of the drilling patterns already recognized by the Company's independent qualified reserves evaluator, other unbooked drilling locations are farther away from existing wells where management may have less information about the characteristics of the reservoir and therefore there may be more uncertainty whether wells will be drilled in such locations and if drilled there may be more uncertainty that such wells will result in additional oil and gas reserves, resources or production. INITIAL RATES OF PRODUCTION References in this presentation to initial production rates associated with certain wells are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. The Company cautions that such production rates should be considered to be preliminary. BOE PRESENTATION: The term barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf/ 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. All boe conversions in this presentation are derived from converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil. ESTIMATED ULTIMATE RECOVERY (EUR): In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented which are based on the assumptions used by InSite Petroleum Consultants Ltd. to estimate Bellatrix's proved plus probable reserves per well as evaluated effective December 31, 2016 based on forecast prices and costs. There is no certainty that such Bellatrix will ultimately recover such volumes from the wells it drills. CURRENCY: All dollar amounts in this presentation are Canadian dollars unless otherwise identified. RESERVES INFORMATION: Unless indicated otherwise, reserve estimates and related future net revenue and other reserves information is derived from Bellatrix’s independent reserve report prepared by InSite Petroleum Consultants Ltd. as at December 31, 2016 using forecast prices and costs. Land acreage information is as available at December 31, 2016, unless otherwise noted. TYPE CURVE AND CAPITAL EFFICIENCY: In this presentation information relating to the type curve, half cycle economics and capital efficiency for Bellatrix's Spirit River wells have been presented. The type curve set forth herein is based on all Bellatrix operated, Notikewin and Falher B wells drilled between October 2012 and September 2015, and represents the mean (P50) performance curve. Half cycle economics are based on Bellatrix's current expectations of drill, complete, equip and tie-in costs per well (and excluding land, seismic and related costs). Capital efficiency is a measure of expected capital expenditures per well based on half cycle economics divided by average first year production results (IP365) based on the type curve presented. The type curve and capital efficiency numbers have been presented to provide readers with information on the assumptions used for management's budgeting process and future planning. The half cycle economics and capital efficiencies may not be achieved on future wells as a result of a number of factors including the risks identified above under "Forward Looking Statements" and as such are not reliable indicators of future performance. In addition, there is no certainty that future wells will generate results to match historic type curves presented herein. Half cycle economics and capital efficiencies are not terms that have standardized meanings and therefore such calculations may not be comparable with the calculation of similar measures for other entities. FINANCIAL INFORMATION: Unless otherwise stated, financial information is based upon Bellatrix’s audited consolidated financial statements for the years ended December 31, 2016 and 2015.

2

Corporate Profile

MARKET SUMMARY

Ticker Symbol TSX / NYSE: BXE

Average Daily Volume1 Canada: 1.1 million / U.S.: 0.5 million

Shares Outstanding 2 246.6 million basic / 259.5 million diluted

Market Capitalization3 $259 million

Bank Debt4 $19 million

Senior Notes due 2020 US$250 million

Convertible Debentures $50 million

Enterprise Value3 $655 million

2016 Exit Production 31,500 boe/d

2017 Estimated Exit Production 35,000 boe/d

2016 Exit to 2017 Exit Growth 10 to 15%

2017 Natural Gas Weighting 76%

3

1 Three month average at March 10, 2017 2 Share count at December 31, 2016. Diluted shares include options but exclude shares potentially issuable on conversion of convertible debentures as the convertible debentures are included in the net debt calculation 3 Calculated using March 10, 2017 share price (C$1.05/share). Enterprise value includes market capitalization plus total net debt of $396 million as at December 31, 2016. Total net debt includes bank debt, $24 million working capital deficiency, the liability component of the convertible debentures, and assumes conversion of US notes at Cdn/US $1.3840 as at December 31, 2016. 4 Bank debt reflects December 31, 2016 balance

• Dominant core acreage position in west central Alberta • Spirit River represents one of North America’s lowest supply cost natural gas plays • Consistently deliver top ranked well productivity results • Asset portfolio provides balance of natural gas and oil/liquids weighted opportunities

• Secured firm transportation over approximately 120% of current gross operated natural gas volumes

• Maintain firm service contracts through owned & third party processing plants • Long term NGL fractionation agreements in place for 100% of volumes

Investment Highlights

4

INFRASTRUCTURE OWNERSHIP &

CONTROL

HIGH QUALITY ASSETS & ACREAGE

TAKEAWAY CAPACITY &

MARKET EGRESS

PROFITABLE GROWTH

WELL MANAGED LONG TERM DEBT

PROFILE

• Ownership and control of strategic infrastructure including pipelines, compression, and processing facilities

• Infrastructure control creates significant barriers to competition within core area

• Defined three year outlook provides line of sight for 10% to 15% compound annual production volume growth

• Top tier capital efficiencies and cost profile deliver full cycle sustainable profitability • Current commodity prices drive strong forecast investment returns

• 80% unused capacity on bank credit facilities • Only $19.1 million of bank debt at year end 2016 • No term debt maturities until May 2020 and September 2021

Note: 80% unused capacity on bank credit facilities as at December 31, 2016 and references $19.1 million bank debt relative to credit facilities of $100 million. Unused capacity excludes outstanding letters of credit

Streamlined & Re-energized for Growth in 2017

5 Note: 2017 exit production volumes are management estimates based on Bellatrix forward guidance as announced January 5, 2017.

HIGHLY CONCENTRATED PURE PLAY DEEP BASIN FOCUSED OPERATOR • High impact natural gas growth from low cost Spirit River play

• Multi-zone potential with oil weighted opportunities in Cardium, Belly River, Viking & Rock Creek

• Strategic infrastructure and firm service capacity provide barriers to competition in core areas

• Exit 2016 production of ~31,500 boe/d with visibility to growth beyond 42,000 boe/d in 2019 (Over 10% CAGR) within internally generated funding

• 393 net Spirit River and 239 net Cardium drilling locations provide decades of development drilling opportunities

STRONG RESERVE GROWTH AND ESTABLISHED NET ASSET VALUE • Strong reserve growth achieved in 2016 with Proved (1P) and Proved plus Probable (2P) reserve growth

of 10% and 3% respectively

• Established a December 31, 2016 2P net asset value (2P NPV10 before tax) of $1.24 billion ($5.02/share) which incorporates future net revenue adjusted for year end total net debt, seismic and land value

2017 Outlook & Guidance

2017 GUIDANCE1

Production (boe/d)

2017 Exit production 35,000

2017 Average daily production 33,500

2017 Growth (2016 exit to 2017 exit) 10 to 15% Production mix (%)

Natural gas 76

Crude oil, condensate and NGLs 24 Net Capital Expenditures ($MM)2

Drilling, completing and equipping $70 Phase 2 of Alder Flats Plant $13

Land and infrastructure $7 Other capital $15 Total net capital expenditures $105

Expenses

Production expense ($/boe)3 $9.00

1 2017 Guidance as announced January 5, 2017.

2 Net capital spending includes exploration and development capital projects and corporate assets, and excludes property acquisitions and dispositions. Net capital spending also excludes the previously received prepayment portion of Bellatrix's partner’s 35% share of the cost of construction of Phase 2 of the Alder Flats Plant during calendar 2017. 3 Production expenses before net processing revenue/fees. 6

Three Year Development Plan

7 Note: Capital expenditures and development plans beyond 2017 represent management estimates, as formal plans have not been approved.

20,000

25,000

30,000

35,000

40,000

45,000

Exit Average Exit Average Exit Average Exit

2016 2017 2018 2019

Estim

ated

Pro

duct

ion

Volu

mes

(boe

/d)

THREE YEAR DEVELOPMENT PLAN DESIGNED TO DELIVER INTERNALLY FUNDED PRODUCTION VOLUME GROWTH OF 33% REPRESENTING A COMPOUND ANNUAL GROWTH RATE OF OVER 10%

$2.02

$2.16

$2.13

$0.32 ($1.61)

$5.02

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

PDP 1P 2P Undev land +seismic

Net debt 2P NAV

Valu

e ($

per

bas

ic sh

are)

NAV of $1.24 Billion or $5.02 Per Share

8

$499MM

1 Based on 246.6 million common shares outstanding as at December 31, 2016 (excluding common shares issuable pursuant to securities that are convertible, exercisable or exchangeable into common shares). 2 As evaluated by InSite Petroleum Consultants Ltd. as at December 31, 2016 based on forecast prices and costs before income tax. 3 As estimated by Bellatrix as at December 31, 2016 based on 180,203 net acres of undeveloped land at an average price of $289.50 per acre. Seismic value based on 26% of $100.3 million replacement value based on seismic costs to buy data at an average of $1,500/km for 2D and $14,500/km2 for 3D. 4 2016 year end total net debt.

$532MM $525MM $78MM ($396MM) $1,238MM

2

2P NAV PER SHARE1

2 2

3

4

Commodity Price & Currency Risk Management

9

AECO fixed price swap contracts: • 101.4 MMcf/d @ C$3.36/Mcf (2017) • 65.6 MMcf/d @ C$3.08/Mcf (2018)

STRONG FIXED PRICE NATURAL GAS RISK MANAGEMENT PROTECTION

Percent of forecast volumes based on the midpoint of 2017 average production guidance of 33,500 boe/d (76% natural gas weighted). Natural gas hedges converted from $/GJ to $/Mcf based on an assumed average corporate heat content of 40.6 Mj/m3. Conway propane price referenced as a percentage of WTI in U.S. dollars. All hedges denominated in Canadian dollars unless otherwise noted.

CURRENCY HEDGES

USD foreign exchange forward contract summary: • $62.5MM @ 1.308 USD/CAD

(value date May 2020)

NATURAL GAS HEDGES

$3.36 $3.36 $3.36 $3.36

$3.08 $3.08 $3.08 $3.08

0%

10%

20%

30%

40%

50%

60%

70%

Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Q3/18 Q4/18

% o

f tot

al fo

reca

st 2

017

gas v

olum

es

AECO Swap (C$/Mcf)

PROPANE HEDGES

Conway propane swap contracts: • 1,500 bbl/d @ 50.7% WTI (2017) • 1,000 bbl/d @ 47.0% WTI (2018)

Balance Sheet & Financial Flexibility

10

BANK DEBT $19 MILLION AT DECEMBER 31, 20161

CREDIT FACILITY CONTAINS ONE FINANCIAL COVENANT

LONGER DATED TERM DEBT MATURITIES

Bank debt of $19.1MM at December 31, 2016

$100MM credit facility at December 31, 2016

Next semi-annual redetermination May, 2017

Senior (bank) debt reduced by $321 million (down 94%) at

December 31, 2016 compared with December 31, 2015 levels

One financial covenant is Senior Debt/EBITDA (3.50:1)

Q4/16 ratio was 1.57x

Bellatrix has no term debt maturities until 2020 & 2021.

US$250MM notes (C$325MM at December 31, 2016) mature

May 15, 2020

C$50MM convertible debenture mature Sept 30, 2021

1 Bank debt (before deducting outstanding letters of credit).

Utilized

Undrawn

Effective capital resource management, balancing liquidity and flexibility

0.00.51.01.52.02.53.03.54.0

Q2/16 Q3/16 Q4/16

Seni

or D

ebt/

EBIT

DA

$0$50

$100$150$200$250$300$350

2017 2018 2019 2020 2021

Debt

mat

uriti

es (C

$)

Highly Concentrated Land Base

WEST CENTRAL ALBERTA CORE AREA

11

~77 Kilometers (48 Miles)

~10

0 Ki

lom

eter

s (60

Mile

s)

Alberta

Highly focused land base in the prolific Deep Basin of Alberta

>90% of total corporate production and 100% of capital investment focused in the Greater Ferrier, Willesden Green & Pembina areas of Alberta

Control of significant infrastructure (facilities, pipelines, compression) creates barriers to competition

DOMINANT ACREAGE POSITION

FERRIER & WILLESDEN GREEN

Production1 (% of total): 90%

P+P net locations2: 244

Unbooked net locations2: 385

Total net drilling locations: 629

GREATER PEMBINA Production1 (% of total): 2%

P+P net locations2: 4

Unbooked net locations2: 59

Total net drilling locations: 63

OTHER Production1 (% of total): 8%

P+P net locations2: 48

Unbooked net locations2: 47

Total net drilling locations: 95

1 Reflects % of estimated January 2017 average field volumes 2 Proved and Probable and unbooked locations as at December 31, 2016

Concentrated Multi-Zone Acreage

12

Deep Basin is highly coveted for: • Sweet, liquids rich natural gas • Sweet, light gravity crude oil • Multi-zone hydrocarbon charged

formations • Low production cost with no formation

water • Year round access

Benefits of multi-zone development: • Pad drilling reduces above ground

footprint • Lease sizes minimized • Manufacturing style approach • Half-cycle returns expected longer term

as subsequent formation development utilizes existing lease pads, pipelines, and infrastructure

DEEP BASIN MULTI-ZONE ACREAGE

4,600 ft TVD— — Belly River

— Cardium

— Second White Specs

— Viking

— Notikewin

— Falher A

— Falher B

— Wilrich

Spirit River

— Glauconite

— Ostracod

— Ellerslie

— Rock Creek

— Nordegg

— Duvernay

6,200 ft TVD—

7,400 ft TVD—

7,700 ft TVD—

11,200 ft TVD—

TVD: True vertical depth

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

Jan

10Ap

r 10

Jul 1

0O

ct 1

0Ja

n 11

Apr 1

1Ju

l 11

Oct

11

Jan

12Ap

r 12

Jul 1

2O

ct 1

2Ja

n 13

Apr 1

3Ju

l 13

Oct

13

Jan

14Ap

r 14

Jul 1

4O

ct 1

4Ja

n 15

Apr 1

5Ju

l 15

Oct

15

Jan

16Ap

r 16

Jul 1

6O

ct 1

6

Aver

age

mon

thly

pro

duct

ion

(boe

/d)

Spirit River is the Growth Engine

13

Low cost Spirit River volumes comprise a growing proportion of total corporate production (~65%) Processing facilities and Firm Transportation (FT) capacity in place to facilitate growth

SPIRIT RIVER PRODUCTION GROWTH 2010

December 2016

Spirit River

Other

Spirit River

Other

Spirit River - The Quiet Giant

14

WESTERN CANADA 2016 WELLS – CALENDAR DAY PRODUCTION BY ZONE

Source: Data from Canadian Discovery Ltd.; excludes oilsands and thermal oil wells/volumes

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000

Charlie LakeMississippian

ColoradoShaunavon

DuvernayCardium

GlauconiticBakken

VikingL Mannville

MontneySpirit River

Calendar average daily cumulative volumes (boe/d)

2016 WELL (BOE) VOLUMES BY ZONE 2016 WELL (MCF) VOLUMES BY ZONE

Spirit River accounted for ~33% of total Western Canada hydrocarbon volumes (boes) from new wells drilled in 2016

Spirit River

Other

Montney

Spirit River accounted for ~50% of total Western Canada natural gas volumes (Mcf) from new wells drilled in 2016

Spirit River

Other

Montney

Spirit River Geology Summary

• Broad, thick, extensive sand rich valleys in Notikewin, Falher and Wilrich members

• Tight sandstone: long life reserves with long term hyperbolic decline profile

• Average thickness 25 to 40 meters (approximately 80 to 130 feet)

• Up to three wells per zone to fully develop a section

• Porosity 6 to 18%; permeability 1 to 3 mD

• Open and closed fracture systems evident in rock core and to a lesser degree in rock cuttings

15

SPIRIT RIVER STACKED SANDS

— Notikewin

— Falher A

— Falher B

— Wilrich

One square mile section schematic

Spirit River Liquids Rich Gas

BXE Land Sections1

256 Gross

144 Net

BXE Net Drilling Inventory2

86 proved 30 probable 277 unbooked 393 total

Spirit River (Notikewin/Falher/Wilrich) provides significant upside

1 Includes Ferrier, Willesden Green, Greater Pembina and Strachan. Acreage as at December 31, 2016 2 Proved, Probable, and unbooked locations as at December 31, 2016

16

GREATER FERRIER AREA CORE SPIRIT RIVER PLAY

• True vertical formation depth ~2,250 meters (~7,400 feet)

• Currently drilling one mile laterals

• Average 17 frac stages per well with 40 tonnes per stage

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

Henr

y Hu

b (U

S$/M

Mbt

u)

North American Supply Cost Comparison

17 Economics assume 15% Before tax IRR, assumes $US0.83 = $CDN1.00, US$0.75/MMbtu AECO basis, and a 20:1 oil-to-gas pricing ratio; Note (*): Bellatrix economics assume to be free of GORR Source: RBC Capital Markets Research

C$2.50/GJ C$3.00/GJ

Full cycle F&D costs $/Mcfe ($0.85) ($0.85)

Cash costs $/Mcfe ($2.07) ($2.11)

Sales price $/Mcfe $3.91 $4.42

Profit $/Mcfe $0.99 $1.46

Profit margin % 25% 33%

Half Cycle IRR % 35% 62%

Spirit River All-In Profitability

18

Note: Numbers may not add due to rounding 1 Operating costs assume $0.56/Mcf for natural gas through third party plants, $0.20/Mcf for gas processed through BXE Alder plant and $8.00/bbl for oil/condensate. Assumed split is 80% 3rd party / 20% BXE plant. Includes estimated attributed operating cost impact from $75 million facilities disposition announced May 13, 2016. 2 Representative transport, G&A and interest costs based on full year average 2016 corporate costs 3 Sales prices assume AECO at $2.85/Mcf ($2.50/GJ) or $3.42/Mcf ($3.00/GJ) as per scenario with NGL pricing: ethane @ $10/bbl, propane @ $15/bbl, butane @ $30/bbl and condensate @ $60/bbl incorporating liquids extraction capabilities given mix of gas through third party and BXE Alder Flats Plant.

Full Cycle F&D costs

Drill $1.7MMComplete $1.6MMEquip & tie in $0.7MMHalf cycle costs $4.0MMLand/seismic/facilities $1.1MMFull cycle costs $5.1MM

EUR (P50) 6.0 BcfeFull cycle F&D $0.85/Mcfe

Cash costs C$2.50/GJ C$3.00/GJ

Royalties (est @ 8%) $0.31/Mcfe $0.35/McfeOperating costs1 $0.75/Mcfe $0.75/McfeTransport2 $0.16/Mcfe $0.16/McfeG&A2 $0.26/Mcfe $0.26/McfeInterest & financing2 $0.59/Mcfe $0.59/McfeTotal costs $2.07/Mcfe $2.11/Mcfe

Sales price C$2.50/GJ C$3.00/GJ

Total sales price3 $3.91/Mcfe $4.42/Mcfe

Delivering on our 2017 Objectives

19

2017 PRELIMINARY RESULTS OUTPERFORMING TYPE CURVE EXPECTATIONS

Historical daily well production (natural gas only) versus Bellatrix representative 5.2 Bcf type curve

0

2

4

6

8

10

12

14

16

18

20

0 30 60 90 120 150 180 210 240 270 300 330 360

Prod

ucin

g da

y vo

lum

es (M

Mcf

/d)

Days

BXE Spirit River 5.2 Bcf Type Curve 2017 Wells

Spirit River Well Costs & Capital Efficiencies

20

FOCUSED CAPITAL COST REDUCTIONS

DRIVES STRONG CAPITAL EFFICIENCIES (IP365 ESTIMATE) AVERAGING ~$8,000/BOE/D

Note: IP365 forecasts based on initial well productivity, reservoir characteristics, and full year well production modeling Capital efficiency calculated as gross well costs (drill, complete, equip and tie-in) divided by gross IP365 production expectation of Falher B and Notikewin wells drilled Analysis does not include promoted spend within historical JV development

$0

$5,000

$10,000

$15,000

$20,000

Capi

tal E

ffici

ency

($/b

oe/d

)

Spirit River IP365Capital Efficiency($/boe/d)

Full CapitalProgram Average

2015 - 24 gross wells 2016 - 19 gross wells

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

Cost

s ($m

illio

ns) Equip & Tie-in

Complete

Drill

Long

reac

h

Long

reac

h

2015 - 24 gross wells 2016 - 19 gross wells

Enduring Efficiency Gains

21

AVERAGE SPIRIT RIVER DRILLING CURVES SPUD TO RIG RELEASE BY YEAR

DRILL COST BY YEAR

Note: Comparative drilling curves based on Bellatrix “hybrid” drilling style which constitutes technique employed for majority of wells drilled since 2014

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,0000 5 10 15 20

Mea

sure

d De

pth

(m)

Days Spud to Rig Release

2014 Spirit River Average

2015 Spirit River Average

2016 Spirit River Average

0

5

10

15

20

2014 2015 2016

Days

(Spu

d to

Rig

Rel

ease

) $0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

2014 2015 2016Dr

ill C

ost (

$MM

)

Spirit River Development Comparison

22 Source: Canadian Discovery Frac Database. Data sourced December 2016. Calendar data based on spud date.

COMPARATIVE 2015 & 2016 SPIRIT RIVER COST & EFFICIENCY METRICS

Bellatrix is an industry leader in the development of the Spirit River play

0

5

10

15

20

BXE Industry

Num

ber o

f sta

ges

Frac stages

0

5

10

15

20

25

30

BXE Industry

Days

to c

ompl

ete

Number of completion days

010203040506070

BXE Industry

Prop

pant

per

sta

ge (t

onne

s) Avg proppant placed per stage

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

BXE Industry

Wel

l cos

ts ($

mill

ions

)

Reported costs

Completion cost

Drill cost

0.01.02.03.04.05.06.07.0

BXE Industry

IP90

(MM

cf/d

)

IP90 Gas rate

01,0002,0003,0004,0005,0006,0007,000

BXE IndustryCa

pita

l effi

cien

cy ($

/boe

pd)

IP90 Capital efficiency

Representative Spirit River Inventory Required to Maintain Production Volumes

23

2017 2018 2019 2020 Total Beginning net well inventory 393 379 365 351 393 Net wells drilled 14 14 14 14 56 Ending net well inventory 379 365 351 337 337 % drilled of total inventory 4% 4% 4% 4% 14%

Assumes phased drilling development with average well results in line with Bellatrix Spirit River type curve. Representative example only as future budgets, drill plans ,and anticipated well results are uncertain

Approximately 14 net Spirit River wells1 per year maintains production in the low to mid 30 mboe/d range through 2020

Represents scenario of drilling of only 14% of net Spirit River well inventory

0

10

20

30

40

Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19 Jan-20 Jul-20

Prod

uctio

n (m

boe/

d)

Base 2017 2018 2019 2020

Strategic Land Position

24 Source: Accumap, company presentations and various public sources

GREATER FERRIER/BRAZEAU/WILLESDEN GREEN AREAS OF WEST CENTRAL ALBERTA

Brazeau

Ferrier

Pembina

Willesden Green

Bellatrix

Greater Ferrier Area Infrastructure Overview

GREATER FERRIER EXISTING INFRASTRUCTURE ACCESS:

Infrastructure gives Bellatrix control of production and growth Working interest or operatorship in

3 major gas processing facilities 9 compressor sites 4 oil batteries

BELLATRIX ALDER FLATS PLANT Bellatrix 25% owner and operator • Keyera 70% owner • O’Chiese 5% owner

Phase I - 110 MMcf/d inlet capacity (on-stream May 2015) Phase II - 120 MMcf/d inlet capacity (in service 2018, remaining BXE cost plus prepayment capital ~$41MM) • C2 Recovery 57% • C3 Recovery 99% • C4+ Recovery 100%

Strategic advantage from owned infrastructure –

lowered costs and guaranteed access

25

GREATER FERRIER AREA STRATEGIC INFRASTRUCTURE

BXE Alder Flats – Superior Operational Performance in Core West Central AB Area

SUPERIOR & CONSISTENT PLANT PERFORMANCE

26

FUEL/DISPOSITION EFFICIENCY

Source: Bellatrix internal data and Alberta Energy Regulator (AER) Note plant efficiency compares monthly receipts versus licensed gas capacity for third party plants. BXE Alder compares monthly gas receipts versus sales capacity Note: Fuel disposition efficiency includes fuel, flared and vented dispositions as a % of input plant receipts Third party plants include greater Ferrier area gas plants: Tidewater Brazeau River Complex, Conoco Sand Creek, Conoco Alder Flats, Keyera Minnehik Buck Lake, Keyera Nordegg, Keyera Brazeau East, Keyera West Pembina, Keyera Brazeau North, Penn West Crimson Lake

BXE Alder Flats has averaged a 96% utilization rate since July 1, 2015

BXE Alder Flats ranks best in group as the most efficient plant

0% 20% 40% 60% 80% 100%

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

Bellatrix Alder Flats

2016 utilization

Highest Utilization

0.0% 2.0% 4.0%

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

3rd Party Plant

Bellatrix Alder Flats

2016 Disposition % of Receipts

Most efficient

Compelling Investment Opportunity

27

Leadership Experienced management

with a history of creating value

World Class Asset

Large inventory of high rate of return drilling

locations

Low Cost Low cost operator and finder

Effective Capital

Management

Demonstrated proactive balance

of liquidity and flexibility

High Torque Material leverage

to commodity price recovery

Excellent Organic Growth Potential

Competitive Economics

De-risked

Leading Well Results

Technically Astute

Unfettered growth potential with firm processing capacity

Economics highly competitive with

Marcellus

Low risk development opportunities geared

for growth

Well performance consistently ranked among best in basin

Strong technical team at leading edge of

resource development

Corporate Information

BOARD OF DIRECTORS W.C. (Mickey) Dunn Chairman

Murray L. Cobbe

John H. Cuthbertson, QC

Brent A. Eshleman, P.Eng

Keith E. Macdonald, CA

Thomas E. MacInnis, B.Comm, MBA

Steven J. Pully, CPA, CFA

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

Keith S. Turnbull, B.Sc., CA

OFFICERS Brent A. Eshleman, P.Eng. President & CEO

Edward J. Brown, C.A. Executive Vice President, Finance & CFO

Charles R. Kraus, Esq. Executive Vice President, General Counsel & Corporate Secretary

Garrett Ulmer, P.Eng Chief Operating Officer

Steve G. Toth, CFA Vice President, Investor Relations

ADDRESS 1920, 800 – 5th Avenue SW Calgary, Alberta Canada T2P 3T6 Tel: (403) 266-8670 Fax: (403) 264-8163 www.bellatrixexploration.com investor.relations@bellatrixexp.com

BANKERS National Bank of Canada Alberta Treasury Branches HSBC Bank Canada Canadian Imperial Bank of Commerce The Bank of Nova Scotia Bank of Montreal The Toronto Dominion Bank Union Bank, Canada Branch Wells Fargo Bank N.A., Canadian Branch

EVALUATION ENGINEERS InSite Petroleum Consultants Ltd.

REGISTRAR & TRANSFER AGENT Computershare Trust Company of Canada

AUDITORS KPMG LLP

EXCHANGE LISTING The Toronto Stock Exchange - BXE The New York Stock Exchange - BXE

28

SUPPLEMENTAL INFORMATION

Capital Resource Management

30 Note: Undrawn capacity on bank credit facilities reflect credit facilities of $100 million at December 31, 2016 versus year end bank debt of $19.1 million (before deducting outstanding letters of credit).

• 94% REDUCTION IN BANK DEBT IN 2016 • TOTAL NET DEBT REDUCED BY APPROXIMATELY $321

MILLION IN 2016 • JOINT VENTURES CONCLUDED – SIMPLIFIED HIGH WORKING

INTEREST ORGANIC DEVELOPMENT PLAN GO FORWARD

• ENHANCED FINANCIAL FLEXIBILITY & LIQUIDITY

• 80% UNDRAWN ON CREDIT FACILITIES AT YEAR END 2016

• MATERIAL COMMODITY PRICE RISK MANAGEMENT PROTECTION THROUGH 2018

2016 In Review: Material Deleveraging & Strategic Repositioning

31

# Transaction Announcement Date

Gross Proceeds $MM

Production sold boe/d

1 Facilities monetization 13-May-16 $75 0

2 35% Alder Flats Plant sale 07-Jul-16 $113 0

3 Bought deal financings 19-Jul-16 $80 0

4 Pembina non-core asset sale 19-Sep-16 $47 930

5 CDE Flow-through financing 04-Oct-16 $10 0

6 Harmattan non-core asset sale 05-Dec-16 $80 3,076

Total $405 4,006

MINOR NON-CORE DISPOSITION EFFORTS CONTINUE… FOCUS REMAINS ON STRATEGIC POSITIONING AND CORE VALUE OPTIMIZATION

Note: Bought deal financings refer to the issuance of $50 million aggregate principal amount of 6.75% extendible unsecured subordinated convertible debentures and 25,000,000 subscription receipts (subsequently converted into common stock of Bellatrix) for aggregate gross proceeds of $80 million as announced on July 19, 2016 CDE flow-through financing refers to private placement “flow-through” basis in respect of Canadian Development Expenses (“CDE”) at a price of $1.18 per share resulting in gross proceeds of $10 million announced on October 4, 2016

SUCCESSFULLY RAISED OVER $400 MILLION IN 2016 OVER MULTIPLE TRANSACTIONS WITH MINIMAL PRODUCTION DIVESTED

Significant Debt Reduction Achieved

32 Net bank debt includes bank debt outstanding and working capital deficiency

$0

$100

$200

$300

$400

$500

$600

$700

$800

Q1/15 Q2/15 Q3/15 Q4/15 Q1/16 Q2/16 Q3/16 Q4/16

Debt

($M

M)

Net Bank Debt US Senior Notes Convertible Debentures

Sold $75MM facilities Sold 35% of

Plant for $112.5MM &

$80MM Financings

Sold US$250MM Senior notes

$47MM Pembina & $80MM

Harmattan non-core asset sales

Cardium Light Oil Resource Play

BXE Land Sections1 195 Gross

120 Net

BXE Net Drilling Inventory2

107 proved 37 probable 95 unbooked 239 total

Average Lease Operate Expense ~$9.00/boe

Cardium Resource Play Summary Largest accumulation of light oil in the WCSB Approximately 20,000 square miles Approximately 1.9 Billion bbls produced to date

Cardium provides light oil exposure with material optionality to improving prices

Remains a key focus formation for Bellatrix long-term within its core areas

33

Strachan

Ferrier

Willesden Green

1 Acreage as at December 31, 2016 2 Proved, Probable, and unbooked locations as at December 31, 2016

bellatrixexploration.com