1

Annual General Meeting PresentationMAY 23, 2019

2

AdvisoriesFORWARD 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, acreage, well results, and capital efficiencies, the Company’s infrastructure and firm transportation capacity, the expected performance of the Alder Flats Gas Plant following completion of Phase 2, expected corporate natural gas liquids yields, the Company’s development plans and forecasted investment returns, the Company’s balance sheet and available liquidity, any refinancing of long term debt and the cost of any such refinancing, future production estimates, future drilling locations, 2019 guidance relating to production, production mix, and total net capital expenditures, the Company’s acreage position, the nature and profitability of the Company’s Spirit River acreage, well results, forecasted well performance, 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 May 21, 2019 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.bxe.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 MEASURESThroughout 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 MEASURESIn 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 a recognized measure 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.FD&A costs are used as a measure of capital efficiency. FD&A presented above has been calculated based on exploration and development capital and/or acquisition capital spent in the applicable period (both including and excluding changes in future development capital for that period) divided by the change in reserves for that period including revisions for that same period. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for the year.Recycle ratio calculates operating netback divided by FD&A costs. Operating netback is calculated by deducting transportation, royalties and operating costs from revenue and includes the impact of commodity price risk management contracts.

DRILLING LOCATIONSIn this presentation, the Company has disclosed certain drilling locations associated with Bellatrix's interest in the Spirit River and Cardium plays. Of the 382 net Spirit River drilling locations identified herein, 105 are proved locations, 27 are probable locations and 250 are unbooked locations. Of the 251 net Cardium drilling locations identified herein, 105 are proved locations, 22 are probable locations, and 124 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, 2018 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 PRODUCTIONReferences 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 boeconversions 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, 2018 based on forecast prices and costs. There is no certainty that 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, 2018 using forecast prices and costs. Land acreage information is as available at December 31, 2018, unless otherwise noted.Bellatrix reserves information includes the impact of IFRS 16, which changes the accounting treatment of certain operating leases so that the future lease payments associated with such leases are recognized as a financial liability on the Company’s balance sheet. As a result, for the purposes of preparing the reserves data presented herein, the lease payments associated with such leases are recognized as financing costs rather than as operating costs and have not been deducted in calculating the value of the Company's reserves. If such lease payments were recognized as operating costs in calculating the value of the Company's reserves, it would result in a reduction to the Company’s 2P NPV10 future net revenue by $88 million from approximately $1.5 billion to $1.412 billion.

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 5.2 Bcf type curve set forth herein is based on all Bellatrix operated, Notikewin and Falher B wells drilled between 2013 and 2017, and represents the mean (P50) performance curve. The 6.0 Bcf type curve set forth herein is based on all Bellatrix operated, Notikewin and Falher wells drilled in 2017 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. F&D costs are used as a measure of capital efficiency. F&D presented above has been calculated based on exploration and development capital divided by the expected ultimate recovery (EUR). 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, 2018 and 2017.

3

Bellatrix Investment Highlights

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

Infrastructure control creates significant barriers to competition

Alder Flats Phase 2 brings total gross processing capacity to 230 MMcf/d

Long term market diversification strategy in place through 2020

Firm transportation over current gross operated natural gas volumes

Firm service contracts through owned & 3rd

party processing plants Long term fractionation

agreements in place for 100% of volumes

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

Top tier capital efficiencies and cost profile deliver full cycle profitability

Asset portfolio provides balance of natural gas and oil/liquids weighted opportunities

4

2018 Guidance History Delivering on Expectations

PREVIOUS 2018 ANNUAL

GUIDANCE (APR 3, 2018)

PREVIOUS2018 ANNUAL

GUIDANCE (AUG 2, 2018)

PREVIOUS2018 ANNUAL

GUIDANCE (NOV 1, 2018)

2018ANNUAL RESULTS

ACTUAL VERSUS PRIOR3

Production (boe/d)

2018 Average daily production 34,000 – 35,500 34,000 – 35,500 35,000 – 35,500 35,635 +3%

Production mix (%)

Natural gas 74 74 74 72

Crude oil, condi and NGLs 26 26 26 28 +7%

Capital Expenditures ($MM)

Total net capital expenditures1 $55 - $65 $50 - $60 $50 - $55 $52 -13%

Expenses ($/boe)

Production expense2 $7.65 - $8.00 $7.65 - $8.00 $7.65 - $7.90 $7.50 -4%

1 Net capital spending includes exploration and development capital projects and corporate assets, and excludes property acquisitions and dispositions. 2 Production expenses before net processing revenue/fees.3 Represents actual results compared with midpoint of April 3, 2018 guidance range.

5

2019 Guidance & First Quarter Results

FIRST THREE MONTH 2019 RESULTS

2019 ANNUAL GUIDANCE

(JAN 15, 2019)

ACTUAL RESULTS VERSUS MIDPOINT

OF GUIDANCE

Production (boe/d)

2019 Average daily production 36,991 34,000 – 36,000 +6%

Production mix (%)Natural gas 71 72 -1%

Crude oil, condensate and NGLs 29 28 +4%

Capital Expenditures ($MM)

Total net capital expenditures 2 $20.5 $40 - $50 n/a

1 2019 capital budget incorporates forward pricing expectations of US$65/bbl WTI and $1.60/GJ AECO2 Excludes property acquisitions and dispositions.

STRONG OPERATIONAL PEFORMANCE IN THE FIRST QUARTERRELATIVE TO ANNNUAL GUIDANCE EXPECTATIONS1

6

Strategic Objectives & OutlookImproving financial strength and value preservation in low commodity price environment

2017

New management team established

Enhanced production guidance three times during the year

Reduced capital costs by ~10% and operating costs by ~5% YoY

Enhance deliverability of wells with average results tracking ~6.0 Bcf type curve

Achieved leading PDP FD&A costs of $5.27/boe

2018

Manage capital investment levels within funding

Complete Phase 2 of BXE Alder Flats Plant on-time and $5MM under budget

Deliver on guidance expectations

Reduce capital and operating costs

Refinance part of long term notes and extend debt maturities

Achieved leading PDP FD&A costs of $3.22/boe

2019

Advance debt refinance strategy

Sustain production levels and optimize liquidity

Target further reductions in cash costs (operating costs, G&A)

Optimize returns from balanced portfolio investment

Preserve long term resource value

7

Macro Conditions

Macro Conditions Current Situation Potential Improvements

AECO basis differential widening

• Reflects changes initiated in July 2017 to the operating methodology used by the pipeline operator to regulate the flow of available gas in the market during periods of maintenance

• Increased production volumes

• Capacity expansions add over 2.1 Bcf/d of incremental export capacity through 2021, an increase of 19% compared to current capacity levels

• Forward strip shows narrowing of the differential over time

Investor sentiment

• Weak investor sentiment towards Canadian energy due to government policies and lack of egress

• Improving commodity prices for both oil and natural gas

• Improved egress and takeaway capacity

Limited access to capital

• Debt and equity markets relatively inaccessible for junior / intermediate Canadian E&Ps

• Challenged debt refinance market

• Alberta provincial government change and policy initiatives

• Upcoming Federal (Fall 2019) election

• Improved egress and takeaway capacity

8

AECO Basis Differential

The AECO market was negatively impacted by the changes initiated in July 2017 This changed operating methodology used by the pipeline operator to regulate the flow of available gas in the Alberta market during periods of maintenanceAECO pricing has been highly discounted from pricing in other North American markets and producing basins

Source: Bloomberg; forward strip as at May 8, 2019

The AECO basis differential shows narrowing towards historical levels given anticipated future egress capacity, with a material increase in egress capacity expected in 2020

($3.00)

($2.50)

($2.00)

($1.50)

($1.00)

($0.50)

$0.00

$0.50

$1.00

Historical average(Jan 2003 to May 2018)

US$0.80/MMBtu

Historical Forecast

AECO Basis Differential (US$/MMBtu)

9

Effective Capacity (MMcf/d) 2017A 2018 2019E 2020E 2021E 2022E 2023E 2024E

In ServiceAlliance 1,800 1,800 1,800 1,800 1,800 1,800 1,800 1,800NGTL - Empress 3,800 3,800 3,800 3,800 3,800 3,800 3,800 3,800NGTL - McNeill 1,500 1,500 1,500 1,500 1,500 1,500 1,500 1,500NGTL - AB/BC 2,500 2,500 2,500 2,500 2,500 2,500 2,500 2,500Spectra - T-South 1,700 1,700 1,700 1,700 1,700 1,700 1,700 1,700

Total 11,300 11,300 11,300 11,300 11,300 11,300 11,300 11,300

ProceedingNGTL - AB/BC 230 350 650 650 650 650 650NGTL - Empress/McNeill 400 1,280 1,280 1,280 1,280Spectra - T-South 190 190 190 190 190Coastal Gaslink 2,100

Total 230 350 1,240 2,120 2,120 2,120 4,220

Capacity Expansion (%) 0% 2% 3% 11% 19% 19% 19% 37%

AECO Natural Gas Expansion Projects Underway

Source: Scotiabank Energy Research, Altacorp Capital Research

ADDITIONAL EXPORT CAPACITY BEING DEVELOPED OUT OF THE CANADIAN BASIN

Capacity expansions add over 2.1 Bcf/d of incremental export capacity through 2021, an increase of 19% compared to

current capacity levels

Forecasts anticipate the basin will become long egress and domestic

demand between Q4/19 and Q1/21

10

AECO Natural Gas – Demand Growth Drivers

Source: Scotiabank Energy Research

External forecasts see intra-Alberta demand growth of:

↑ 500 MMcf/d YoY in 2018 to 5.3 Bcf/d

↑ 245 MMcf/d YoY in 2019 to 5.5 Bcf/d

↑ 190 MMcf/d YoY in 2020 to 5.7 Bcf/d

INTRA-ALBERTA DEMAND GROWTH

11

Hedging & Market Diversification

AECO

Malin

Chicago Dawn

Henry Hub

Note: Percentage of estimated 2019 production volumes based on midpoint of guidance range 34,000 – 36,000 boe/d (72% natural gas weighted)

Hedging & Market Diversification Q2-Q4 2019 Total Corporate Volumes

Market Diversification ContractsMarket Start Date End Date VolumeChicago 01-Feb-18 31-Oct-20 15,000 MMBtu/dChicago 01-Nov-18 31-Oct-20 15,000 MMBtu/dDawn 01-Feb-18 31-Oct-20 15,000 MMBtu/dDawn 01-Nov-18 31-Oct-20 15,000 MMBtu/dMalin 01-Feb-18 31-Oct-20 15,000 MMBtu/d

75,000 MMBtu/d

Dawn Floating

5%Malin

Floating2%

Chicago Floating

7%

U.S. Fixed Price Hedges

23%

AECO Fixed Price Hedges

6%

AECO Unhedged

29%

Oil Hedged3%

Liquids Unhedged

25%

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Commodity Price Risk Management & Diversification

AECO fixed price swap contracts:• 18 MMcf/d @ $2.01/Mcf (Apr – Oct 2019)

Percent of forecast volumes based on the mid-point of average 2019 production guidance of 34 – 36 mboe/d (72% natural gas weighted). Natural gas hedges converted from $/GJ to $/Mcf based on an assumed average corporate heat content of 40.0 Mj/m3.All hedges denominated in Canadian dollars unless otherwise noted. 1 Net Canadian equivalent price is calculated as the US$ fixed price, less contracted differential, adjusted to Canadian dollars at an assumed exchange rate of $1.33 USD/CAD.

NATURAL GAS FIXED PRICE HEDGES OIL HEDGESWTI call option contracts:• 1,000 bbl/d @ $87.50/bbl (Jan – Dec 2019)• 1,000 bbl/d @ $77.90/bbl (Jan – Dec 2020)

NATURAL GAS MARKET DIVERSIFICATION & FIXED PRICE HEDGING COVERAGE

STRONG PRICE RISK MANAGEMENT & MARKET DIVERSIFICATION COVERAGE

U.S fixed price contracts1:• 62 MMcf/d @ $1.77/Mcf (Apr – Oct 2019)

0%

10%

20%

30%

40%

50%

60%

70%

Q2/19 Q3/19 Q4/19 Q1/20 Q2/20 Q3/20 Q4/20

% o

f tot

al fo

reca

st 2

019

gas v

olum

es

AECO/NYMEX Basis Swap AECO Fixed Price Swaps U.S. Fixed Price Contracts Market Diversification Contracts

13

Proposed Recapitalization Transaction Benefits

Total outstanding debt reduced by approximately $110 million (approximately 23%)

Results in no maturity date of any non-revolving debt to 2023

Annual cash interests payments reduced by approximately $12 million (approximately 30%) until December 2021

Improves annual cash flow

Positions company favorably to utilize existing infrastructure and high value assets to deliver long term sustainable growth for all stakeholders

Increases runway to capitalize on Bellatrix’s significant reserve value1

DESIGNED TO STRENGTHEN FINANCIAL POSITION

Note 1: Bellatrix Proved plus Probable (2P) reserve value at December 31, 2018 as evaluated by InSite Petroleum Consultants Ltd. is $1.5 billion

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Proposed Recapitalization Transaction Overview

Senior unsecured notes

Convertible debentures

Equity shareholders

US$145.8MMSenior Notes due May 2020 and

US$2MM in accrued interest

STAKEHOLDER CURRENT OWNERSHIP PROFORMA OWNERSHIP

$50MM Convertible debentures and all accrued interest

US$50MMSecond Lien Notes due 2023

US$50MMThird Lien Notes due 2023

51%1 Equity

BOTTOM LINE: $110MM IN DEBT REDUCTION AND $12MM IN ANNUALIZED CASH INTEREST SAVINGS

32.5%1 Equity

16.5%1 EquityEquity

Note 1: Based on undiluted shares outstanding following closing of Recapitalization TransactionNote: Does not include Credit Facility and existing Second Lien Notes who are unaffected and who have already confirmed their support for the transaction

15

Transaction Benefits

Note: U.S. denominated debt face value converted at $1.32 CAD/USD for comparability purposesNote 1: Annualized cash interest assumes Third Lien notes paid in kind 9.5% with 3% cash pay interest to December 31, 2021

TRANSACTION REDUCES DEBT BY ~$110MM AND CASH INTEREST BY $12MM ANNUALLY

Debt reduced by $110MM

Cash interest reduced by

$12MM

Current LeverageProforma

TransactionChange

Term DebtSenior Unsecured Notes $MM $192.4 $0.0 -$192.4Second Lien Notes $MM $134.8 $200.8 $66.0Third Lien Notes $MM $0.0 $66.0 $66.0Convertible Debentures (face) $MM $50.0 $0.0 -$50.0Total term debt $MM $377.2 $266.8 -$110.4

Estimated annualized cash interest 1

Senior Unsecured Notes $MM $16.4 $0.0 -$16.4Second Lien Notes $MM $11.5 $17.1 $5.6Third Lien Notes $MM $0.0 $2.0 $2.0Convertible Debentures (face) $MM $3.4 $0.0 -$3.4Total term debt $MM $31.2 $19.0 -$12.1

16

Debt Maturity Profile

Note: U.S. denominated debt face value converted at exchange rate of $1.320 CAD/USD for comparability purposesNote 1: Credit Facilities represent drawn balances at March 31, 2019; excludes letters of creditNote 2: Reflects principle value at issue. Does not reflect future face value that may result from company electing to pay in kind

$50.0

$192.4

$134.8

$134.8

$46.8$0

$50

$100

$150

$200

$250

$300

$350

2019 2020 2021 2022 2023 2024 2025

Prin

cipa

l Am

ount

(C$m

m)

MATURITY PROFILE - MARCH 31, 2019 Credit FacilitiesSecond Lien NotesSenior NotesConvertible Debentures

Second Lien Note Matures in May 2020 if Senior Unsecured balance is not below US$

$46.8

$200.8

$66.0

$0

$50

$100

$150

$200

$250

$300

$350

2019 2020 2021 2022 2023 2024 2025

Prin

cipa

l Am

ount

(C$m

m)

MATURITY PROFILE - PROFORMA Third Lien NotesSecond Lien NotesCredit Facilities1

1

2

17

Highly Concentrated Land Base

WEST CENTRAL ALBERTA CORE AREA

~77 Kilometers (48 Miles)

~100

Kilo

met

ers (

60 M

iles)

Alberta

Highly focused land base in the prolific Deep Basin of Alberta

99% 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

FERRIERWILLESDEN GREEN GREATER PEMBINA

Production1 (% of total): 99%

P+P net locations2: 275

Unbooked net locations2: 585

Total net drilling locations:

860

1 Reflects % of March 2019 average field volumes 2 Proved, Probable and unbooked locations as at December 31, 2018

18

$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

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 GORRSource: RBC Capital Markets Research

19

Bellatrix’s Spirit River Play

BXE Land Sections1

• 198 Gross• 118 Net

BXE Net Drilling Inventory2

• 105 proved• 27 probable• 250 unbooked• 382 total

Spirit River (Notikewin/Falher/Wilrich) provides significant upside1 Includes Core Areas, Acreage as at December 31, 20182 Proved, Probable and unbooked locations as at December 31, 2018

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 mile with 40 tonnes per stage

20

C$1.50/GJ C$2.50/GJ

Full cycle F&D costs $/Mcfe ($0.71) ($0.71)

Cash costs $/Mcfe ($2.22) ($2.30)

Sales price $/Mcfe $3.24 $4.24

Profit $/Mcfe $0.31 $1.23

Profit margin % 9% 29%

Half Cycle IRR % 52% 127%

Spirit River All-In Profitability5.2 Bcf Type Curve

Note: Numbers may not add due to rounding1 Incremental operating costs assume $0.56/Mcf for natural gas through third party plants, $0.16/Mcf for gas processed through BXE Alder plant and $8.00/bbl for oil/condensate. 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 first quarter 2019 corporate costs3 Sales prices assume AECO at $1.69/Mcf ($1.50/GJ) or $2.82/Mcf ($2.50/GJ) as per scenario with net NGL pricing: ethane @ $12/bbl, propane @ $25/bbl, butane @ $40/bbl and condensate @ $70/bbl incorporating liquids extraction capabilities given mix of gas through third party and BXE Alder Flats Plant.

Full Cycle F&D costs

Drill $1.5MMComplete $1.4MMEquip & tie in $0.5MMHalf cycle costs $3.4MMLand/seismic/facilities $1.0MMFull cycle costs $4.4MM

EUR (P50) 6.2 BcfeFull cycle F&D $0.71/Mcfe

Cash costs C$1.50/GJ C$2.50/GJ

Royalties (est @ 8%) $0.26/Mcfe $0.34/McfeOperating costs1 $0.73/Mcfe $0.73/McfeTransport2 $0.40/Mcfe $0.40/McfeG&A2 $0.25/Mcfe $0.25/McfeInterest & financing2 $0.58/Mcfe $0.58/McfeTotal costs $2.22/Mcfe $2.30/Mcfe

Sales price C$1.50/GJ C$2.50/GJ

Total sales price3 $3.24/Mcfe $4.24/Mcfe

21

Delivering on our ObjectivesRESULTS OUTPERFORMING EXPECTATIONS

Historical daily well production (natural gas only) versus Bellatrix representative 5.2 & 6.0 Bcf type curves

0

2

4

6

8

10

12

14

0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 480 510 540 570 600 630 660 690 720

Prod

ucin

g da

y vo

lum

es (M

Mcf

/d)

Days2018/19 Wells 2018 Average 2019 Average BXE Spirit River 5.2 Bcf Type Curve BXE Spirit River 6.0 Bcf Type Curve

22

Enduring Efficiency Gains on Drill Times

AVERAGE SPIRIT RIVER DRILLING CURVES

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

DAYS SPUD TO RIG RELEASE BY YEAR

DRILL COST BY YEAR

0

5

10

15

20

2014 2015 2016 2017 2018 2019

Days

(Spu

d to

Rig

Rel

ease

)

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

2014 2015 2016 2017 2018 2019

Drill

Cos

t ($M

M)

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 RiverAverage

2015 Spirit RiverAverage

2016 Spirit RiverAverage

2017 Spirit RiverAverage

2018 Spirit RiverAverage

2019 Q1 SpiritRiver Average

Pace Setter

23

Cost Reductions Achieved45% REDUCTION IN PRODUCTION EXPENSES ($/BOE)

37% REDUCTION IN PRODUCTION EXPENSES ($MM)

$5.00$6.00$7.00$8.00$9.00

$10.00$11.00

Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Q3/18 Q4/18 Q1/19

Prod

uctio

n ex

pens

e ($

/boe

)

$18$20$22$24$26$28$30$32

Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Q3/18 Q4/18 Q1/19

Prod

uctio

n ex

pens

e ($

MM

)

Note: First quarter 2019 production expenditures includes the Company’s prospective adoption of IFRS 16 Leases effective January 1, 2019, whereby lease payments for certain processing and infrastructure fees which were previously recognized as production expenses, are now classified as repayments of lease obligations and finance expense.

24

Low Cost FD&A Performance

FD&A Costs Including Plant Capital FD&A Costs Excluding Plant Capital

2018 2017 3 Year Avg ('16-'18) 2018 2017 3 Year Avg

('16-'18)PDP FD&A $/boe $3.22 $5.27 $4.67 $3.12 $4.81 $4.31 1P FD&A $/boe $2.36 $4.34 $3.76 $2.28 $4.12 $3.57 2P FD&A $/boe $2.05 $3.36 $3.22 $1.99 $3.15 $3.05

PDP Recycle Ratio x 2.64x 1.71x 1.82x 2.73x 1.88x 1.97x1P Recycle Ratio x 3.61x 2.08x 2.26x 3.73x 2.19x 2.38x2P Recycle Ratio x 4.15x 2.68x 2.64x 4.28x 2.86x 2.78x

FD&A costs are used as a measure of capital efficiency. FD&A presented above has been calculated based on exploration and development capital and/or acquisition capital spent in the applicable period (both including and excluding changes in future development capital for that period) divided by the change in reserves for that period including revisions for that same period. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for the year. Recycle ratio calculates operating netback divided by FD&A costs. Operating netback is calculated by deducting transportation, royalties and operating costs from revenue and includes the impact of commodity price risk management contracts.

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

2018 2017 3 Year Avg('16-'18)

2018 2017 3 Year Avg('16-'18)

FD&A Costs Including Plant Capital FD&A Costs Excluding Plant CapitalPDP FD&A 1P FD&A 2P FD&A

FD&

A co

sts (

$/bo

e)

25

Greater Ferrier Area Infrastructure Overview

GREATER FERRIER EXISTING INFRASTRUCTURE ACCESS:Infrastructure gives Bellatrix control of production and growthWorking interest or operatorship in

• 3 major gas processing facilities• 9 compressor sites• 4 oil batteries

BELLATRIX ALDER FLATS PLANTBellatrix 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 (on-stream March 2018)

• C2 Recovery 57%• C3 Recovery 100%• C4+ Recovery 100%

GREATER FERRIER AREA STRATEGIC INFRASTRUCTURE

Strategic advantage from owned infrastructure –

lowered costs and guaranteed access

26

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

2014 2015 2016 2017 2018 2019E

DRIL

LIN

G

DRIL

LIN

G

DRIL

LIN

G

DRIL

LIN

G

DRIL

LIN

G

DRIL

LIN

G

Plant

Plant

Plant Plant Plant

% o

f Tot

al E

&D

Capi

tal E

xpen

ditu

res Land, G&G, and other capital

BXE Alder Flats Plant

Facilities & equipment(excluding BXE Plant)

Drilling & completion capital

Drill Bit Focused

1 Drilling and completion capital includes capitalized itemsNote: Capital expenditures and development plans for 2019 are based on current capital budget guidance.

ALLOCATION OF TOTAL CORPORATE E&D CAPITAL EXPENDITURES

• Major compressor stations, pipelines and Bellatrix Alder Flats Plant capital investment completed• Proportion of incremental capital to drilling & completion expected to increase• Increased drill bit directed capital positions Bellatrix to deliver enhanced corporate capital efficiency

rates in 2019 & beyond

1

PLANT PHASE 2 CONSTRUCTION COMPLETE MARCH 2018

27

Ample Takeaway Capacity & Market EgressALBERTA NATURAL GAS MARKET EGRESS

AMPLE FIRM TRANSPORTATION IN PLACE FOR CURRENT & GROWTH VOLUMES• Firm Transportation (FT) agreements in

place for gross operated volumes at multiple receipt points along the Nova Gas Transmission Ltd. (NGTL) system

FIRM SERVICE PROCESSING CAPACITY• Maintain firm service capacity through

several natural gas processing plants to ensure unfettered delivery capability for current & forecast growth volumes

AMPLE FRACTIONATION CAPACITY SECURED• Long term agreements in place provide

100% coverage for current and forecast NGL volume growth

Alliance Pipeline

Nova Gas Transmission Ltd. (NGTL)

System Pipelines

BXE core west central area ideally situated on the NGTL system, downstream of

Montney & northern Deep Basin areas, with firm transportation capacity

Montney

ALBERTA

28

Liability Management Rating - Alberta

LMR as at April 6, 2019

BELLATRIX RETAINS A STRONG LMR POSITION

0

4

8

12

16

20

24

28

AER

Calc

ulat

ed LM

R

Peer Group LMR Comparison

Industry average

29

Water Use and Sourcing Strategy

• Actual volumes of water sourced per frac stage decreased from 218 m3 in 2017 to 193.4 m3 in 2018 due to multi-well pad approach and excess water transfers between wells.• Reduced number of wells drilled in 2018 due to improving capital efficiencies has also

contributed to reduced water usage year over year.

• Increased use of groundwater in 2018 provided the following benefits: • Significant reduction in truck traffic.• Reduced reliance on costly and safety/environmentally sensitive river transfers. • Reduced reliance on surface water and town water sources.

Source Type (m3) 2017 2018Groundwater Wells* 92,411 39,828Fish Bearing Rivers 5,003 360Borrow Pits/Dugouts 19,855 1,117Recycled Frac Flowback Water 171 286Bought Water 5,172 2,087Total 122,612 43,678

Groundwater Wells91%

Bought Water

5%

Borrow Pits/Dugouts

2%

Fish Bearing Rivers

1%

Recycled Frac Flowback

1%

2018 Water Use

* Groundwater Wells refers to water pumped from wells in Bellatrix’s operating area

30

Bellatrix Environmental Metrics

0.30

0.35

0.40

0.45

0.50

0.55

2015 2016 2017 2018

Tonn

es C

O2e

(mill

ions

)

DIRECT GHG EMISSIONS FLARED & VENTED GAS

0

2,000

4,000

6,000

8,000

2015 2016 2017 2018

e3m

3/ye

ar

Flared Gas Vented Gas

05101520253035

0

20

40

60

80

100

2015 2016 2017 2018

Num

ber o

f Rel

ease

s

Volu

me

(m3)

Total Volume (m3) Reportable Releases (#)

REPORTABLE RELEASES

31

Operational Execution Scorecard

Production expense reductions 45% reduction in production expenditures to a record low reported level of $5.83/boe in Q1/19 from $10.57/boe in Q4/16

Capital cost reductions 20% reduction in all-in well costs to under $3.4 million (drill, complete, equip and tie-in) from ~$4.2 million in Q4/16

Operational performance 2018 program delivered average IP180 well performance 35% above management expectations; 2019 program 15% outperformance on an IP45 basis

Leading peer group F&D cost performance All-in PDP FD&A $3.22/boe ($0.54/Mcfe) in 2018. 2P FD&A $2.05/boe in 2018 and three year average $3.22/boe. Top decile results.

Pre-eminent capital efficient operator in the WCSB 2018/2019 program delivering capital efficiencies <$5,000/boe/d on an IP365 basis

Prudent downside protection $61.8 million in risk management gains in 2017 & 2018

Tight project control Phase 2 brought onstream, on schedule and $5MM under budget

Expanding high value liquids production corporate liquids weighting increased to 29% in Q1/19 from 25% in Q1/17 while retaining meaningful upside potential to improving natural gas prices

32

Corporate Information

BOARD OF DIRECTORSW.C. (Mickey) DunnChairman

John H. Cuthbertson, QC

Brent A. Eshleman, P.Eng

Lynn Kis, P.Eng

Keith E. Macdonald, CPA, CA

Thomas E. MacInnis, B.Comm, MBA

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

Keith S. Turnbull, B.Sc., CPA, CA

SENIOR OFFICERSBrent A. Eshleman, P.Eng.President & CEO

Max Lof, CFAExecutive Vice President & CFO

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

Garrett Ulmer, P.EngChief Operating Officer

Steve G. Toth, CFAVice President, Investor Relations & Corporate Development

ADDRESS1920, 800 – 5th Avenue SWCalgary, Alberta Canada T2P 3T6

Tel: (403) 266-8670 Fax: (403) 264-8163www.bxe.cominvestor.relations@bxe.com

BANKERSNational Bank of CanadaAlberta Treasury BranchesThe Bank of Nova ScotiaCanadian Western Bank

EVALUATION ENGINEERSInSite Petroleum Consultants Ltd.

REGISTRAR & TRANSFER AGENTComputershare Trust Company of Canada

AUDITORSKPMG LLP

EXCHANGE LISTINGThe Toronto Stock Exchange - BXE