Analyst Day Presentation SEPTEMBER 18, 2018

Transcription

1 Analyst Day Presentation SEPTEMBER 18,

2 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, 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, 2018 guidance relating to production, production mix, net capital expenditures and production expense, sensitivity of annualized funds flow from operations, 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 forwardlooking information contained herein constitute a financial outlook, they were approved by management on September 17, 2018 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 ( through the SEC website ( and at Bellatrix s website ( 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 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 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 354 net Spirit River drilling locations identified herein, 102 are proved locations, 27 are probable locations and 225 are unbooked locations. Of the 213 net Cardium drilling locations identified herein, 97 are proved locations, 21 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, 2017 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 calculatingthe 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, 2017 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, 2017 using forecast prices and costs. Land acreage information is as available at December 31, 2017, 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 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. 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, 2017 and

3 Agenda TOPIC Slide #'s Introduction 1-3 Corporate Strategy & Key Themes Corporate Strategy & Three Pillars 4-19 Last 18 Months in Review Strategic Objectives & Guidance Marketing & Risk Management Risk Management Strategy Asset Overview Intro Cost & Performance Leadership in the Spirit River Play Overview - Geology Play Comparisons & Economics Drilling & Performance Improvements Unlocking the Value of the Cardium Play overview - Geology Drilling Evolution Cardium Value Strategy Strategic Infrastructure Value & Competitive Advantage Infrastructure Overview & Value Financial Strategy Balance Sheet and Liquidity Position Debt Refinancing Transaction Value Proposition Investment Highlights Concluding Remarks and Q&A 3

4 Key Themes & Takeaways SCORECARD OF PAST 18 MONTHS AND STRATEGIC OBJECTIVES ACHIEVED COST AND PERFORMANCE LEADER IN THE SPIRIT RIVER UNLOCKING THE MATERIAL UPSIDE VALUE OF THE CARDIUM IMPROVED FINANCIAL STRENGTH AND RUNWAY FOR EXTENDED DEBT MATURITY VALUE PROPOSITION 4

5 Bellatrix Investment Highlights 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 Ownership and control of strategic infrastructure including pipelines, compression, and processing facilities Infrastructure control creates significant barriers to competition within core area 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 & 3 rd party processing plants Long term fractionation agreements in place for 100% of volumes 5

6 Corporate Profile MARKET SUMMARY Ticker Symbol TSX / NYSE: BXE Average Daily Volume 1 Canada: ~550,000/ U.S.: ~100,000 Shares Outstanding million basic / 63.4 million diluted Market Capitalization 3 $78 million Bank Debt 4 $71 million Senior Unsecured Notes due US$154 million Second Lien Notes due US$87 million Convertible Debentures $50 million Enterprise Value 3 $510 million 2018 Estimated Annual Production 34,000 35,500 boe/d 2018 Natural Gas Weighting 74% 2018 Liquids Weighting 26% 1 Three month average at September 10, Share count at June 30, Diluted shares include options but exclude shares potentially issuable on conversion of convertible debentures as convertible debentures included in net debt calculation. 3 Calculated using September 10, 2018 share price (C$1.26/share). Enterprise value includes market capitalization plus total net debt of $430 million as at June 30, Total net debt includes bank debt, adjusted working capital deficiency, the liability component of the convertible debentures, and assumes conversion of US notes at Cdn/US $ as at June 30, Bank debt reflects $71 million outstanding on the Credit Facilities at June 30, Senior unsecured notes and Second Lien note balances reflect debt refinancing transaction closed September 11,

7 Leadership Brent Eshleman President & CEO Max Lof Executive VP & CFO Garrett Ulmer COO Charles Kraus Executive VP, General Counsel & Corporate Secretary 7

8 Last 18 Months in Review Debt reduction and maturity extension Over 1/3 of 2020 note maturities extended to 2023 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 Operating cost reductions 29% reduction in production expenditures to $7.55/boe in Q218 from $10.57/boe in Q4/16 Operational performance 2018 program delivering performance 38% above management expectations Leading F&D cost performance All-in PDP FD&A $5.27/boe in 2017 Pre-eminent capital efficient operator in the WCSB 2018 program delivering capital efficiencies <$5,000/boe/d on an IP365 basis Prudent downside protection $45 million in risk management gains Q1/17 to Q2/18 Tight project control Phase 2 brought onstream, on schedule and $5MM under budget Expanding high value liquids production corporate liquids weighting increased to 28% in Q2/18 from 25% in Q1/17 while retaining meaningful upside potential to improving natural gas prices 8

9 Debt Reductions & Maturity Extension $300 DEBT MATURITY PROFILE SEPTEMBER 11, 2018 Debt maturities (C$) $250 $200 $150 $100 $50 $0 Over 1/3 of 2020 notes exchanged with maturity extended to 2023 through Phase 1 of debt refinancing strategy Actual 30-Jun-18 Proforma 30-Jun-18 Bank Debt $71.4 $51.7 Total Working Capital Def $16.8 $16.8 Unsecured Senior Notes $301.4 $196.3 Convertible Debentures (liability portion) $40.5 $40.5 Second Lien Notes $0.0 $114.3 Total Net Debt $430.2 $419.7 US$80MM of Unsecured Senior Notes exchanged for US$72MM of Second Lien Notes. On a proforma basis, total debt reduces by ~$10.5MM (US$8MM) Note: September 11, 2018 balances incorporate completion of phase 1 of Debt refinancing transaction announced September 11, 2018 (the "Debt Refinancing Transaction") and includes US$15MM (gross) of additional Second Lien Notes due 2023 advanced on September 11, 2018 providing capital for completion of the Company s 2018 capital program. June 30, 2018 FX rate of used for proforma analysis 9

10 Cost Reductions Achieved 29% REDUCTION IN PRODUCTION EXPENSES ($/BOE) Production expense ($/boe) $11.00 $10.00 $9.00 $8.00 $7.00 $6.00 $5.00 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 17% REDUCTION IN PRODUCTION EXPENSES ($MM) Production expense ($MM) $32 $30 $28 $26 $24 $22 $20 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 10

11 Operational Outperformance & 2018 RESULTS OUTPERFORMING EXPECTATIONS 12 Producing Day Volumes (MMCF/d) Days 2017 Wells 2018 Wells BXE Spirit River 5.2 Bcf Type Curve Historical daily well production (natural gas only) versus Bellatrix representative 5.2 Bcf type curve 11

12 Low FD&A Costs FD&A costs ($/boe) $8.00 $6.00 $4.00 $2.00 $ Year Avg ('15-'17) Year Avg ('15-'17) FD&A Costs Including Plant Capital PDP FD&A 1P FD&A 2P FD&A FD&A Costs Excluding Plant Capital FD&A Costs Including Plant Capital FD&A Costs Excluding Plant Capital Year Avg 3 Year Avg ('15-'17) ('15-17) PDP FD&A $/boe $5.27 $5.90 $7.14 $4.81 $5.30 $6.08 1P FD&A $/boe $4.34 $4.20 $4.05 $4.12 $3.98 $3.49 2P FD&A $/boe $3.36 $4.03 $2.39 $3.15 $3.83 $1.82 PDP Recycle Ratio x 1.71x 1.34x 1.33x 1.88x 1.49x 1.56x 1P Recycle Ratio x 2.08x 1.88x 2.35x 2.19x 1.99x 2.72x 2P Recycle Ratio x 2.68x 1.96x 3.98x 2.86x 2.07x 5.22x 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. 12

13 Pre-eminent Capital Efficient Operator in the WCSB $25,000 NATURAL GAS WEIGHTED & BALANCED PRODUCERS 2019 ESTIMATED CAPITAL EFFICIENCY 2019E Capital Efficiency $20,000 $15,000 $10,000 $5,000 $0 BXE ARX SRX PEY BNP AAV PNE BIR KEL CR POU ERF TVE Source: Peters & Co. Limited Research, August 27,

14 Risk Management Gains OVER $45 MILLION IN REALIZED RISK MANAGEMENT GAINS GENERATED IN LAST 18 MONTHS $50 $45 $40 Realized Gains ($MM) $35 $30 $25 $20 $15 $10 $5 $0 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Quarterly Realized Gains Cumulative Realized Gains 14

15 Tight Project Control PHASE 2 BROUGHT ON-STREAM SAFELY, AHEAD OF SCHEDULE AND ~5% BELOW BUDGET Enhanced control Improved value through additional natural gas liquids extraction Lower production expenses Lower transportation expenses Higher cash flow margins Task Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18 Mar-18 Piling Work Mechanical Work (equipment installation, pipe rack installation, piping & structure work) Electrical & Instrumentation Work Pre-Commissioning / Commissioning Work Start-Up 15

16 Growing High Value Liquids Corporate NGL yield (bbl/mmcf) Growing NGL Volumes & High Value Condensate Alder Flats Phase 2 Completed Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Q3/18EQ4/18E Product % of Total Crude Oil & Condensate Volumes (bbl/d) 100% 80% 60% 40% 20% Light oil Condensate 0% Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 High Condensate Weighting Drives Strong Realizations Relative to Benchmark Light Oil Prices Oil price (C$/bbl) $100 $80 $60 $40 $20 $0 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Canadian Light crude blend BXE crude oil and condensate BXE Crude Oil & Condensate Differential (C$/bbl) $8.00 $6.00 $4.00 $2.00 $0.00 ($2.00) ($4.00) Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 16

17 Strategic Objectives & Outlook Improving 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, operating and G&A costs Refinance majority of long term notes and extend debt maturities 2019 Sustain operational 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 Progress enhanced return profile from Cardium assets 17

18 Capital Allocation CAPITAL ALLOCATED TO HIGHEST EXPECTED RETURN PROJECTS COMMODITY AGNOSTIC RETURNS DRIVE INVESTMENT NOT PRODUCT (OIL OR GAS) Spirit River Ellerslie Rock Creek Glauconite >60 bbls/mmcf Liquids >40 bbls/mmcf Liquids Cardium Belly River Second White Specs Viking NATURAL GAS Drill ready development locations maintained across the commodity spectrum OIL 18

19 2018 Outlook & Guidance 2018 CAPITAL GUIDANCE REDUCED BY $5MM NO CHANGE IN VOLUME GUIDANCE GIVEN STRONG RESULTS TO DATE Production (boe/d) CURRENT 2018 ANNUAL GUIDANCE (AUGUST 2, 2018) PREVIOUSLY SET 2018 ANNUAL GUIDANCE (APRIL 3, 2018) 2018 Average daily production 34,000 35,500 34,000 35,500 Production mix (%) Natural gas Crude oil, condensate and NGLs Capital Expenditures ($MM) Total net capital expenditures 1 $50 - $60 $55 - $65 Expenses Production expense ($/boe) 2 $ $8.00 $ $ BUDGET STRATEGIC OBJECTIVES Completed Phase 2 of the BXE Alder Flats Plant Optimize forecast returns from Spirit River (liquids rich gas) and Cardium (higher liquids weighted) opportunities Enhance funds flow through optimal delivery of volumes during periods of stronger commodity prices Preserving liquidity and balance sheet strength 1 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 Production expenses before net processing revenue/fees. 19

20 Risk Management and Marketing Overview 20

21 Commodity Price Risk Management % of total forecast 2018 gas volumes 50% 40% 30% 20% 10% 0% NATURAL GAS FIXED PRICE SWAPS $2.89 $2.98 NATURAL GAS HEDGES AECO fixed price swap contracts: 67 $3.03/Mcf (July-Dec 2018) 8 $1.72/Mcf (July-Oct 2018) 18 $2.01/Mcf (Apr-Oct 2019) $2.01 $2.01 $2.01 Q3/18 Q4/18 Q1/19 Q2/19 Q3/19 Q4/19 AECO Swap (C$/Mcf) % of total forecast 2018 oil & condi volumes 60% 50% 40% 30% 20% 10% 0% OIL FIXED PRICE SWAPS $70.14 $70.14 Q3/18 Q4/18 WTI Swap (C$/bbl) OIL HEDGES WTI fixed price swap contracts: 1,000 $70.14/bbl (July Dec 2018) PROPANE HEDGES Conway propane swap contracts: 1,000 47% WTI (July Dec 2018) STRONG FIXED PRICE NATURAL GAS & OIL RISK MANAGEMENT PROTECTION Percent of forecast volumes based on the mid-point of average 2018 production guidance of mboe/d (74% natural gas weighted, 6% oil/condensate weighted). Natural gas hedges converted from $/GJ to $/Mcf based on an assumed average corporate heat content of 40.0 Mj/m3. Conway propane price referenced as a percentage of WTI in U.S. dollars. All hedges denominated in Canadian dollars unless otherwise noted. 21

22 Hedging & Market Diversification AECO Market Diversification Contracts Market Start Date End Date Volume Chicago 01-Feb Oct-20 15,000 MMBtu/d Chicago 01-Nov Oct-20 15,000 MMBtu/d Dawn 01-Feb Oct-20 15,000 MMBtu/d Dawn 01-Nov Oct-20 15,000 MMBtu/d Malin 01-Feb Oct-20 15,000 MMBtu/d Malin Hedging & Market Diversification July-Dec 2018 Total Corporate Volumes Liquids Unhedged 20% Dawn 8% Malin 7% Chicago Dawn Oil Hedged 3% NGL Hedged 3% Chicago 8% Henry Hub AECO Unhedged 16% AECO Fixed Price Hedges 35% Note: Percentage of estimated 2018 production volumes based on midpoint of guidance range 34,000 35,500 boe/d (74% natural gas weighted) 22

23 Ample Takeaway Capacity & 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 ALBERTA NATURAL GAS MARKET EGRESS ALBERTA Montney Alliance Pipeline BXE core west central area ideally situated on the NGTL system, downstream of Montney & northern Deep Basin areas, with firm transportation capacity Nova Gas Transmission Ltd. (NGTL) System Pipelines 23

24 AECO Natural Gas Demand Growth Drivers 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 Source: Scotiabank Energy Research 24

25 AECO Natural Gas Expansion Projects Underway ADDITIONAL EXPORT CAPACITY BEING DEVELOPED OUT OF THE CANADIAN BASIN Winter Effective Capacity (MMcf/d) 2017A 2018E 2019E 2020E 2021E 2022E In Service Alliance 1,800 1,800 1,800 1,800 1,800 1,800 NGTL - Empress 3,800 3,800 3,800 3,800 3,800 3,800 NGTL - McNeill 1,500 1,500 1,500 1,500 1,500 1,500 NGTL - AB/BC 2,500 2,500 2,500 2,500 2,500 2,500 Spectra - T-South 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 Proceeding NGTL - AB/BC NGTL - Empress/McNeill ,280 1,280 Spectra - T-South Total ,255 2,135 2,135 Capacity Expansion (%) 0% 2% 3% 11% 19% 19% Source: Scotiabank Energy Research 25

26 Cost and Performance Leader in the Spirit River Formation 26

27 Highly Concentrated Land Base DOMINANT ACREAGE POSITION 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 ~100 Kilometers (60 Miles) WEST CENTRAL ALBERTA CORE AREA FERRIER WILLESDEN GREEN GREATER PEMBINA Production 1 (% of total): 99% P+P net locations 2 : 256 Unbooked net locations 2 : 535 Total net drilling locations: 791 Alberta 1 Reflects % of June 2018 average field volumes 2 Proved and Probable and unbooked locations as at December 31, 2017 ~77 Kilometers (48 Miles) 27

28 Concentrated Multi-Zone Acreage DEEP BASIN MULTI-ZONE ACREAGE 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 TVD: True vertical depth 4,600 ft TVD 6,200 ft TVD 7,400 ft TVD 7,700 ft TVD 11,200 ft TVD Belly River Cardium Second White Specs Viking Notikewin Falher A Falher B Wilrich Glauconite Ostracod Ellerslie Rock Creek Nordegg Duvernay Spirit River 28

29 The Spirit River Deep Basin Gas Play Fluvial valleys km wide 100 to 150 km in length Valley systems up to 50m in thickness Stacked valley complexes 29

30 Spirit River Contribution to WCSB Volume Growth ~20% of all AB & BC natural gas production comes from the Spirit River 14 Production by zone (Bcf/d) Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11 Jul-11 Oct-11 Jan-12 Apr-12 Jul-12 Oct-12 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Other Montney Duvernay Spirit River Note: Includes BC and AB natural gas production Source: National Energy Board, Accumap, internal estimates 30

31 Bellatrix Focused Spirit River Growth SPIRIT RIVER PRODUCTION GROWTH % 2018 New Drill Techniques 32,000 Spirit River Spirit River % of Total Company Volumes 70% 60% 50% 40% 30% 20% 10% 2011 Slick Water Frac 2012 Megabore 2014 Falher A Validation 28,000 24,000 20,000 16,000 12,000 8,000 4,000 Average Monthly Production (boe/d) Other June 2018 Other Spirit River 0% 0 Jan-10 May-10 Sep-10 Jan-11 May-11 Sep-11 Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Jan-16 May-16 Sep-16 Jan-17 May-17 Sep-17 Jan-18 May-18 Spirit River % of Total Monthly Production (boe/d) Low cost Spirit River volumes comprise a growing proportion of total corporate production (~80%) Processing facilities and Firm Transportation (FT) capacity in place to facilitate growth 31

32 North American Supply Cost Comparison $4.00 $3.50 $3.00 Henry Hub (US$/MMbtu) $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 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 32

33 Bellatrix s Spirit River Play BXE Land Sections Gross 104 Net BXE Net Drilling Inventory proved 27 probable 225 unbooked 354 total True vertical formation depth ~2,250 meters (~7,400 feet) GREATER FERRIER AREA CORE SPIRIT RIVER PLAY Currently drilling one mile laterals Average 17 frac stages per well with 40 tonnes per stage Spirit River (Notikewin/Falher/Wilrich) provides significant upside 1 Includes Ferrier, Willesden Green, and greater Pembina. Acreage as at December 31, Proved, Probable, and unbooked locations as at December 31,

34 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 Over pressured and very low water saturation Open and closed fracture systems evident in rock core and to a lesser degree in rock cuttings SPIRIT RIVER STACKED SANDS One square mile section schematic Notikewin Falher A Falher B Wilrich 34

35 Greater Ferrier Spirit River Play Advantages Lateral reservoir continuity and predictability Repeatable results Moderate reservoir porosity and permeability Historical vertical production Low to moderate drilling risk Moderate drilling depth Effective completion model, stages and costs Available infrastructure from earlier vertical development Deep Basin setting low to no water risk Imaged by 3D seismic data High NGL and condensate yields High deliverability 35

36 Comparing Premier Resource Plays Spirit River Montney Duvernay Tight Conventional Sandstone Siltstone Shale Porosity 6 to 18%; Permeability 1 to 3 md Porosity 2 to 8%; Permeability to 0.1 md Porosity 0.6 to 8%; Permeability to md High Permeability High Porosity Low Permeability Low Porosity Source: Spirit River and Duvernay Core Photos from BXE core, Montney core photo from Tom Moslow Publication 36

37 Low Cost Competitive Advantage BXE Spirit River Versus Canadian Plays Average fluid pumped (m3) Average stage count ,000 50,000 40,000 30,000 20,000 10,000 STAGE COUNT Duvernay Montney BXE Spirit River FLUID PUMPED 0 Duvernay Montney BXE Spirit River Source: Accumap, Scotiabank Energy Research, internal costs Average total depth (m) Average proppant (tonnes) 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1, ,000 6,000 5,000 4,000 3,000 2,000 1,000 0 PROPPANT PLACED Duvernay Montney BXE Spirit River TOTAL DEPTH Duvernay Montney BXE Spirit River DCE&T well costs ($MM) $10 $9 $8 $7 $6 $5 $4 $3 $2 $1 $0 TOTAL WELL COST COMPARISON Duvernay Montney BXE Spirit River 37

38 Play Profitability Comparisons BXE Spirit River Montney Duvernay All-in Well Costs (DCE&T, $MM) Average IP365 (boe/d) IP365 Capital Efficiency ($/boe/d) Average Implied EUR (Bcfe) Estimated F&D ($/boe) $3.4 $6.4 $9.4 1, $3,180 $10,500 $20, $2.87 $6.07 $13.12 Source: Accumap, Scotiabank Energy Research Bellatrix average estimated production (IP365) based on 2017 & 2018 performance. EUR incorporates 6.0 Bcf (raw gas) type curve and utilizes all-in well costs of $3.4 million 38

39 Bellatrix Spirit River Drilling Inventory TOTAL INVENTORY OF 354 NET SPIRIT RIVER LOCATIONS FORMATIONAL BREAKOUT RESERVE BREAKOUT Unbooked Booked 129 Booked locations = > 10 years low risk drilling at current pace of development Notikewin Falher A Falher B Wilrich Note: Proved, Probable, and unbooked locations as at December 31,

40 Spirit River Type Curves Producing Day Raw Gas Volumes (MMcf/d) SPIRIT RIVER 5.2 & 6.0 BCF TYPE CURVES C4 8 Liquids (bbl/mmcf) C5+ 15 C3 13 C2 27 IRR % 200% 150% 100% Bellatrix Spirit River Economics Economic Assumptions 5.2 Bcf 6.0 Bcf Gross CAPEX (DCE&T, $MM) $3.4 $3.4 Gross Natural Gas IP30 (MMcf/d) Liquids yield (bbl/mmcf) EUR (mboe) 1,037 1,184 Economic Outputs (C$2.50/GJ) 5.2 Bcf 6.0 Bcf NPV10 BTAX ($MM) $5.1 $6.9 PIR (10%) Payout (years) IRR (%) Days 5.2 Bcf 6.0 Bcf 50% 0% $1.50/GJ $2.50/GJ 5.2 Bcf 6.0 Bcf Note: Type curves based on raw gas assumed recovery, total recovery including liquids 6.2 Bcfe and 7.1 Bcfe Economics assume liquids prices based on a US$60/bbl WTI oil price and a natural gas variable production expense cost of $0.79/Mcf. Assumed shrinkage, liquids yield and heat value based on average Bellatrix Spirit River well composition in the greater core Ferrier area. 40

41 Representative Spirit River Inventory Required to Maintain Production Volumes Approximately 15 net (5.2 Bcf type curve) Spirit River wells 1 per year maintains production in the high 30 mboe/d range through 2022 Alternatively, 12 net wells (6.0 Bcf type curve) achieve similar maintenance scenario Production (mboe/d) Jan-18 Jul-18 Jan-19 Jul-19 Jan-20 Jul-20 Jan-21 Jul-21 Jan-22 Jul-22 Base Bcf/d wells (12/year) Summary Beginning net location inventory Net locations drilled Ending net location inventory % drilled of total inventory 4% 4% 5% 5% 5% 21% 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 41

42 Spirit River All-In Profitability 5.2 Bcf Type Curve C$1.50/GJ C$2.50/GJ Full cycle F&D costs $/Mcfe ($0.71) ($0.71) Cash costs $/Mcfe ($2.16) ($2.24) Full Cycle F&D costs Drill Complete Equip & tie in Half cycle costs Land/seismic/facilities Full cycle costs $1.5MM $1.4MM $0.5MM $3.4MM $1.0MM $4.4MM Sales price $/Mcfe $3.26 $4.27 Profit $/Mcfe $0.39 $1.32 Profit margin % 12% 31% Half Cycle IRR % 49% 132% EUR (P50) Full cycle F&D 6.2 Bcfe $0.71/Mcfe Cash costs C$1.50/GJ C$2.50/GJ Royalties 8%) $0.26/Mcfe $0.34/Mcfe Operating costs 1 $0.73/Mcfe $0.73/Mcfe Transport 2 $0.34/Mcfe $0.34/Mcfe G&A 2 $0.35/Mcfe $0.35/Mcfe Interest & financing 2 $0.49/Mcfe $0.49/Mcfe Total costs $2.16/Mcfe $2.24/Mcfe Sales price C$1.50/GJ C$2.50/GJ Total sales price 3 $3.26/Mcfe $4.27/Mcfe Note: Numbers may not add due to rounding 1 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, Representative transport, G&A and interest costs based on first half 2018 corporate costs 3 Sales prices assume AECO at $1.70/Mcf ($1.50/GJ) or $2.84/Mcf ($2.50/GJ) as per scenario with net NGL pricing: $12/bbl, $25/bbl, $40/bbl and $70/bbl incorporating liquids extraction capabilities given mix of gas through third party and BXE Alder Flats Plant. 42

43 Spirit River Drilling Evolution Historic/Vertical Development Early HZ Development Current HZ Development Multi-well pad sites Intermediate casing w/liners Falher B Type Log Smaller casing strings, Monobore casing Openhole liner, 85m frac spacing Multiple stacked sands Drilled at various intervals 20T fracs -> 40T fracs, 11 stage -> 17 stages, foam -> slick water 60T fracs in thick, low porosity intervals Note: Performance chart includes Bellatrix operated wells 43

44 Drilling Performance Improvements Multi well pad sites Mud motors on surface Single well pad sites Top drive rigs Larger diameter drill pipe Big capacity pumps Kelly bar rigs Proprietary new techniques High losses in intermediate section Lower density fluid Raise intermediate casing depth Manage losses and well ballooning Monobores 44

45 Completion Performance Improvements Less water per stage, quicker clean up 200 m3 per stage 20T/stage 160 m3 per stage 50T/stage Hybrid Fluids 40T/stage 60T/stage for Falher A Slickwater fracing Fluid Dynamics Eliminate N2 Foam Fluids Cemented w/ball Drop Resin Coated Sand Ceramic Sand Cemented Liners w/coil Low Frac density Higher Frac Density Micro Seismic Zipper fracs 45

46 Enduring Efficiency Gains on Drill Times AVERAGE SPIRIT RIVER DRILLING CURVES DAYS SPUD TO RIG RELEASE BY YEAR Measured Depth (m) ,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5, Spirit River Average 2015 Spirit River Average 2016 Spirit River Average 2017 Spirit River Average 2018 H1 Spirit River Average Days Spud to Rig Release DRILL COST BY YEAR 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 compared with updated 2018 year to date drilling performance Days (Spud to Rig Release) Drill Cost ($MM)

47 Capital Cost Reductions BELLATRIX HAS MATERIALLY IMPROVED BOTH DRILLING TIMES AND METERS/DAY REDUCING BOTH TIME AND COSTS Days (spud to rig release) Meters/day BXE Industry BXE Industry Source: Accumap, internal estimates 47

48 Delivering on our Objectives RESULTS OUTPERFORMING EXPECTATIONS 12 Producing Day Volumes (MMCF/d) Days 2017 Wells 2018 Wells BXE Spirit River 5.2 Bcf Type Curve BXE Spirit River 6.0 Bcf Type Curve Historical daily well production (natural gas only) versus Bellatrix representative 5.2 & 6.0 Bcf type curves 48

49 Spirit River Well Costs & Capital Efficiencies FOCUSED CAPITAL COST REDUCTIONS Costs ($millions) $6.0 $5.0 $4.0 $3.0 $2.0 Long Reach Long Reach Long Reach Equip & Tie-in Complete Drill $1.0 $ wells wells wells wells DRIVES STRONG CAPITAL EFFICIENCIES (IP365 ESTIMATE) AVERAGING <$7,000/BOE/D Capital Efficiency ($/boe/d) 20,000 15,000 10,000 5,000 0 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 of operated wells only and does not include promoted spend within historical JV development. Spirit River IP365 Capital Efficiency ($/boe/d) Full Capital Program Average wells wells wells wells 49

50 Unlocking the Value of the Cardium 50

51 Paleo Setting Cardium Modern Analogue Baja Mexico Stacked shoreface system 100 km wide 800 km in length 30-60m in thickness Multiple facies 51

52 Bellatrix s Cardium Value Strategy Edson 4 wells West Pembina 73 wells Recent Cardium Activity Wells drilled since Jan 2017 East Pembina 53 wells Area Peak 30 day Oil Rate (bbl/d) Peak 30 day Gas Rate (mmcf/d) Oil EUR (mboe) Gas EUR (Bcf) NGL EUR (mboe) Total EUR (mboe) 2 Greater Ferrier Edson Bellatrix s Cardium Acreage is Top Tier Among the highest total liquids, EUR s and IP rates Greater Ferrier 18 wells Wilson Creek 23 wells West Pembina East Pembina Willy Green 50 wells Wilson Creek Strachan 47 wells Willy Green Strachan Harmattan 5 wells Harmattan Majority of horizontal wells in Wilson Creek are 2 mile laterals. Production not normalized per meter. 2 Total EUR after 10% shrink applied Source: Accumap, internal estimates 52

53 Cardium Light Oil Resource Play BXE Land Sections Gross 84 Net BELLATRIX Activity Since Jan Wells Drilled BXE Net Drilling Inventory 2 97 proved 21 probable 95 unbooked 213 total Cardium Resource Play Summary Largest WCSB light oil accumulation Approximately 20,000 square miles Approximately 1.9 Billion bbls produced to date 1 Acreage as at December 31, Proved, Probable, and unbooked locations as at December 31, 2017 Cardium provides light oil exposure with optionality to improving prices Remains a key focus formation for Bellatrix long-term within its core areas 53

54 Bellatrix Cardium Drilling History BELLATRIX HAS DRILLED >200 WELLS IN THE CARDIUM SINCE Most active Cardium driller in the Basin $120 $100 $80 # Wells drilled $60 $40 $20 WTI ($US/bbl) Cardium Wells Spirit River Wells WTI $0 54

55 Industry Cardium Activity 51 wells drilled in the Greater Ferrier area since January 2017 (all utilize new technology ) Number of stages has been increasing over time (up to 80 stages/ mile) Longer lateral being drilled; 32 of the 51 wells drilled are extended reach BELLATRIX Alder Flats Activity Since Jan Well Drilled Peak 30D AVG: 133bbl/d, 3.0MMcf/d BELLATRIX Ferrier Activity Since Jan WellS Drilled Peak 30D AVG: 90BBL/d, 3.6MMcf/d TAMARACK VALLEY Alder Flats Activity Since Jan Wells Drilled Peak 30D AVG: 101BBL/d, 1.1MMcf/d TORC Brazeau Activity Since Jan Wells Drilled Peak 30D AVG: 518BBL/d, 1.1MMcf/d YANGARRA Ferrier Activity Since Jan Well Drilled Peak 30D AVG: 86BBL/d, 4.3MMcf/d OBSIDIAN Willy Green Activity Since Jan Wells Drilled (not including injectors) Peak 30D AVG: 449BBL/d, 0.62MMcf/d TAMARACK VALLEY NW Wilson Creek Activity Since Jan Wells Drilled Peak 30D AVG: 307BBL/d, 0.36MMcf/d OTHER WILLY GREEN ACTIVITY Since Jan 2017 INPLAY - 9 Wells Drilled WHITECAP - 1 Wells Drilled BACCALIEU - 4 Wells Drilled YANGARRA - 6 Wells Drilled ENTRADA - 4 Wells Drilled Peak 30D AVG: 323BBL/d, 0.65MMcf/d 55

56 Cardium Type Log with HZ Placement Conglomerate 4-10% Porosity mD Sandstone 7-15% Porosity mD HZ Path Bioturbated 4-10% Porosity mD Shale 4-10% Porosity <0.0001mD 56

57 Cardium Drilling Evolution 1,400 Historical Vertical Development Current HZ Development Monobore Casing Spud to RR: 8 days stages 25T/ stage Early HZ Development Intermediate Casing Spud to RR: 19 days stages 20-40T/ stage Sales (boed) 1,200 1, Average of Cemented Liner 1 Average of Openhole Liner (1) Days OIL OIL Openhole Liner Cemented Liner High Porosity Sandstone Bioturbated Sand and Shale Organic Rich Shale BXE has been primarily focused on drilling in the bioturbated section since BXE Wells only 57

58 Bellatrix s Cardium Value Strategy Cardium task force established Goal is to reduce Cardium costs and enhance productivity Focus on realizing a return profile for the Cardium that is as (or more) competitive with the Spirit River Sales (boe/d) 1,400 1,200 1, Total EUR (mboe) Ferrier Cardium Old Technology (1-mile) New Technology (1-mile) New Technology (2-mile) ~1, x 1.8x Old Technology New Technology (1-Mile) New Technology (2-Mile) 58

59 Efficiency Improvements Achieved BELLATRIX CARDIUM PERFORMANCE IS COMPETITIVE WITH INDUSTRY RESULTS 100,000 90,000 80,000 70,000 Cum (boes) 60,000 50,000 40,000 30,000 20,000 10, Normalized Months Competitor 1 Mile Competitor Extended Reach BXE 1 Mile Source: Accumap 59

60 Efficiency Improvements Achieved BELLATRIX HAS USED ITS LEARNINGS AND EFFICIENCY GAINS DRILLING IN THE SPIRIT RIVER AND HAVE SUCCESSFULLY APPLIED TO THE CARDIUM Days (spud to rig release) Meters/day No wells No wells

61 Strategic Infrastructure Value & Competitive Advantage 61

62 Bellatrix Alder Flats Phase 2 PHASE 2 ON-STREAM MARCH 2018 Phase 2 brought on-stream safely, ahead of schedule, and approximately 5% under budget More than doubles throughput capacity at the plant to 230 MMcf/d (from 110 MMcf/d) Operating costs for natural gas processed under Bellatrix s ownership interest are approximately $0.16/Mcf Combined NGL recovery increases to 55 to 60 bbl/mmcf (from 45 bbl/mmcf under Phase 1) in addition to plant condensate yield of an additional 10 bbl/mmcf Phase 1 Phase 2 Design capacity 110 MMcf/d 120 MMcf/d Temperature -70 C -95 C First Sales May 22, 2015 March 19, 2018 Recoveries Ethane (C2) 19% 57% Propane (C3) 100% 100% Butane (C4) 100% 100% Pentane (C5+) 100% 100% 62

63 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 GREATER FERRIER AREA STRATEGIC INFRASTRUCTURE Phase I MMcf/d inlet capacity (on-stream May 2015) Phase II MMcf/d inlet capacity (on-stream March 2018) C2 Recovery 57% C3 Recovery 100% C4+ Recovery 100% Strategic advantage from owned infrastructure lowered costs and guaranteed access 63

64 Meaningful Lease/Pad Buildout Complete PAD DESIGNS ALLOW MAXIMUM FLEXIBILITY AND REDUCED COSTS $1MM savings on 4 well pad drilled sequentially vs 4 single well pads Utilizes less space than allowable by the AER, minimizing ongoing maintenance and future reclamation costs Existing leases can be expanded at low cost Wellbores can be switched in a matter of weeks to target other formations >200 Locations can be ready within 0-3 months 85% of remaining 2018 and 2019 locations are existing or require minor lease extensions minimizing both time and cost 64

65 Material Facilities & Infrastructure Value MAJOR FACILITIES & INFRASTRUCTURE VALUE >$190MM NET TO BXE $200 $180 $160 $29MM $9MM $11MM Estimated Value ($MM) $140 $120 $100 $80 $60 $40 $20 $55MM $87MM $0 BXE Alder Flats Plant Major Gathering & Sales Pipelines Multi-Well Batteries Compression BXE Ownership in 3rd Party Plants Owned facilities provide strategic long term advantage with material tangible value Note: Estimated facilities and infrastructure value based on Bellatrix net working ownership interest based on insured value and/or historical cost as a representation for estimated replacement value. 65

66 Drill Bit Focused PLANT PHASE INVESTMENT 2 CONSTRUCTION & CONSTRUCTION COMPLETE MARCH COMPLETE 2018 Q2/18 Major compressor stations, pipelines and Bellatrix Alder Flats Plant capital investment nearing completion 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 2018 & 2019 % of Total E&D Capital Expenditures 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Plant DRILLING ALLOCATION OF TOTAL CORPORATE E&D CAPITAL EXPENDITURES Plant DRILLING Plant Plant Plant DRILLING DRILLING DRILLING DRILLING E 2019E Land, G&G, and other capital BXE Alder Flats Plant Facilities & equipment (excluding BXE Plant) Drilling & 1completion capital 1 Drilling and completion capital includes capitalized items Note: Capital expenditures and development plans for 2018 are based on current capital budget guidance. For representation purposes 2019 capital investment levels assume similar capital spending levels as 2018 for each category, excluding capital for Phase 2 of the Bellatrix Alder Flats Plant. 66

67 Improved Financial Strength 67

68 Diversified Balance Sheet & Financial Flexibility Actively exploring refinancing opportunities and additional sources of liquidity BANK DEBT $71MM AT JUNE 30, Undrawn Utilized Bank debt $71MM at June 30, 2018 $100MM credit facility confirmed September 2018 with total commitments set at $95MM Next semi-annual redetermination November 2018 Senior Debt/EBITDA CREDIT FACILITY FINANCIAL COVENANT Q3/17 Q4/17 Q1/18 Financial covenant is Senior Debt/EBITDA Q2/18 Maximum Senior Debt/EBITDA ratio of 3.0x Q2/18 ratio was 1.36x well below financial covenant Debt maturities (C$) $300 $250 $200 $150 $100 $50 $0 LONG TERM DEBT MATURITIES Bellatrix has no long term debt maturities until 2020 US$154MM Senior unsecured notes due May 15, 2020 C$50MM convertible debenture due Sept 30, 2021 US$87MM Second Lien notes due Bank debt balance and terms as at June 30, 2018; long term debt maturities as at September 11,

69 Debt Refinancing Transaction Closed STRENGTHENS LIQUIDITY AND INCREASES FINANCIAL FLEXIBILITY EXCHANGE NEW MONEY COMMITMENT ADDITIONAL 2 ND LIEN CAPACITY Exchanged US$80 million of Existing Senior Unsecured Notes due 2020 ( 2020 Notes ) for US$72 million of second lien Exchange Notes due 2023, extending the maturity of over 1/3 of the outstanding 2020 Notes by 3 years, reducing outstanding debt by approximately $10.5 million, and maintaining the cash interest rate at 8.5% New money commitment of US$30 million to US$40 million in additional New Money Notes for drilling and subsequent 2020 Note exchanges Provide a basket for up to US$50 million of Additional Notes for subsequent 2020 Note exchanges and the capacity to issue additional subordinate secured and unsecured debt in subsequent refinancing and capital raising activities SETS THE STAGE FOR ADDITIONAL 2020 NOTE EXCHANGES IN THE FUTURE THAT, BELLATRIX EXPECTS, WILL SIGNIFICANTLY INCREASE ITS ABILITY TO REFINANCE ALL OF THE REMAINING 2020 NOTES IN ADVANCE OF THEIR MATURITY Note: Debt refinancing transaction announced closed September 11, 2018 (the "Debt Refinancing Transaction") 69

70 Debt Reduction PROFORMA CAPITALIZATION AND LIQUIDITY IMPROVEMENT Actual 30-Jun-18 Proforma 30-Jun-18 Bank Debt $71.4 $51.7 Letters of Credit $11.6 $11.6 Total Facility Utilized $83.0 $63.3 Total Loan Facility $100.0 $95.0 % Utilized 83% 67% Bank Debt $71.4 $51.7 Total Working Capital Def $16.8 $16.8 Unsecured Senior Notes $301.4 $196.3 Convertible Debentures (liability portion) $40.5 $40.5 Second Lien Notes $0.0 $114.3 Total Net Debt $430.2 $419.7 Note: Proforma analysis includes completion of Debt refinancing transaction announced September 11, 2018 (the "Debt Refinancing Transaction") with June 30 balances Proforma analysis assumes US$15MM (gross) of additional Second Lien Notes advanced on September 11, 2018 providing capital for completion of the Company s 2018 capital program June 30, 2018 FX rate of used for proforma analysis 70

71 Extending Term Debt Maturities LONG TERM DEBT MATURITY PROFILE JUNE 30, 2018 Debt maturities (C$) Debt maturities (C$) $300 $250 $200 $150 $100 $50 $0 $300 $250 $200 $150 $100 $50 $ LONG TERM DEBT MATURITY PROFILE SEPTEMBER 11, 2018 Over 1/3 of 2020 notes exchanged with maturity extended to 2023 through Phase 1 of debt refinancing strategy Note: September 11, 2018 balances incorporate completion of phase 1 of Debt refinancing transaction announced September 11, 2018 (the "Debt Refinancing Transaction") and includes US$15MM of additional Second Lien Notes due 2023 advanced on September 11, 2018 providing capital for completion of the Company s 2018 capital program. June 30, 2018 FX rate of used for proforma analysis 71

72 Value Proposition 72

73 Bellatrix Investment Highlights 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 Ownership and control of strategic infrastructure including pipelines, compression, and processing facilities Infrastructure control creates significant barriers to competition within core area 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 & 3 rd party processing plants Long term fractionation agreements in place for 100% of volumes 73

74 Strategic Land Position GREATER FERRIER/BRAZEAU/WILLESDEN GREEN AREAS OF WEST CENTRAL ALBERTA Pembina Brazeau Ferrier Willesden Green Bellatrix Peyto Cenovus Tourmaline Source: Accumap, company presentations and various public sources TAQA Westbrick 74