Corporate Presentation APRIL 2018

Transcription

1 Corporate Presentation APRIL

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, 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 forward-looking information contained herein constitute a financial outlook, they were approved by management on March 31, 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 calculating the aggregate production for the Company. The Company cautions that such production rates should be considered to be preliminary. BOE PRESENTATION: The term barrels of oil equivalent ( boe ) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf/ 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. All boe conversions in this presentation are derived from converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil. ESTIMATED ULTIMATE RECOVERY (EUR): In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented which are based on the assumptions used by InSite Petroleum Consultants Ltd. to estimate Bellatrix's proved plus probable reserves per well as evaluated effective December 31, 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 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 3

4 Corporate Profile MARKET SUMMARY Ticker Symbol TSX / NYSE: BXE Average Daily Volume 1 Canada: ~520,000/ U.S.: ~140,000 Shares Outstanding million basic / 51.2 million diluted Market Capitalization 3 $70 million Bank Debt 4 $52 million Senior Notes due 2020 US$250 million Convertible Debentures $50 million Enterprise Value 3 $490 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 March 31, Share count at December 31, Diluted shares include options but exclude shares potentially issuable on conversion of convertible debentures as the convertible debentures are included in the net debt calculation. 3 Calculated using March 31, 2018 share price (C$1.40/share). Enterprise value includes market capitalization plus total net debt of $421 million as at December 31, 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 December 31, Bank debt reflects $52 million outstanding on the Credit Facilities at December 31,

5 2017 Performance Recap Production (boe/d) INITIAL 2017 ANNUAL GUIDANCE (JAN 5, 2017) FIRST REVISION (JUNE 26, 2017) SECOND REVISION (AUG 10, 2017) THIRD REVISION (NOV 10, 2017) 2017 ANNUAL RESULTS CHANGE FROM INITIAL 2017 Average daily production 33,500 34,500 36,000 36,000 36,872 3, Exit production 35,000 35,500 36,500 36,500 36,600 1, Exit growth (to 2016 exit) +/-15% +/-15% >15% >15% 16% Production mix (%) Natural gas Crude oil, condi and NGLs Capital Expenditures ($MM) Total net capital expenditures 1 $105.0 $120.0 $120.0 $120.0 $123.2 Property dispositions cash 2 - ($34.5) ($34.5) ($50.5) ($48.8) Total net CAPEX after property dispositions - cash Expenses $105.0 $85.5 $85.5 $69.5 $74.4 $30.6 Production expense ($/boe) 3 $9.00 $9.00 $8.75 $8.50 $8.31 $ 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 Property dispositions cash guidance refers to the Strachan and West Pembina asset sales and does not include transaction costs or adjustments, 2017 results include adjustments. 3 Production expenses before net processing revenue/fees. 5

6 2018 Outlook & Guidance Production (boe/d) REVISED 2018 ANNUAL GUIDANCE (APRIL 3, 2018) INITIAL 2018 ANNUAL GUIDANCE (DECEMBER 14, 2017) 2018 Average daily production 34,000 35,500 35,000 37,000 Production mix (%) Natural gas Crude oil, condensate and NGLs Capital Expenditures ($MM) Total net capital expenditures 1 $55 - $65 $65 - $80 Expenses Production expense ($/boe) 2 $ $8.00 $ $ BUDGET FOCUSED ON STRATEGIC OBJECTIVES Completion of Phase 2 of the BXE Alder Flats Plant Optimize forecast returns from Spirit River (liquids rich gas) and Cardium (higher liquids weighted) opportunities Enhanced 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. 6

7 Low Cost FD&A Performance 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. 7

8 Maintained Production Volumes While Achieving Significant Debt Reduction Production (boe/d) 40,000 30,000 20,000 10,000 0 Q1/16 Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Average Average Production Flat Q1/16 to Q2/17 to Q4/17 $800 $700 Debt ($MM) $600 $500 $400 $300 $200 $100 Total Total Net Net Debt Debt Reduced 46% from 41% Q1/16 from to Q2/17 Q1/16 to Q4/17 $0 Q1/16 Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Net Bank Debt U.S. Senior Notes Convertible Debentures Net bank debt includes bank debt outstanding and working capital deficiency; convertible debentures include liability component 8

9 Diversified Balance Sheet & Financial Flexibility Actively exploring refinancing opportunities and additional sources of liquidity BANK DEBT $52MM AT DECEMBER 31, 2017 Undrawn Utilized Bank debt $52MM at December 31, 2017 $120MM credit facility reconfirmed November 2017 Next semi-annual redetermination May 2018 CREDIT FACILITY CONTAINS ONE FINANCIAL COVENANT Senior Debt/EBITDA Q1/17 Q2/17 Q3/17 One financial covenant is Senior Debt/EBITDA Maximum Senior Debt/EBITDA ratio of 3.0x Q4/17 ratio was 1.22x well below financial covenant Q4/17 Debt maturities (C$) $350 $300 $250 $200 $150 $100 $50 $0 LONG TERM DEBT MATURITIES Bellatrix has no term debt maturities until 2020 & 2021 US$250MM notes (C$305MM at Dec 31, 2017) due May 15, 2020 C$50MM convertible debenture due Sept 30,

10 Commodity Price & Currency Risk Management % of total forecast 2018 gas volumes 50% 40% 30% 20% 10% 0% $3.06 NATURAL GAS HEDGES NATURAL GAS HEDGING $2.90 $2.90 AECO fixed price swap contracts: 66.1 $3.06/Mcf (2018) 7.9 $1.74/Mcf (Apr-Oct 2018) 17.6 $2.03/Mcf (Apr-Oct 2019) CURRENCY HEDGES USD foreign exchange forward contract summary: USD/CAD (value date May 2020) $3.00 Q1/18 Q2/18 Q3/18 Q4/18 AECO Swap (C$/Mcf) % of total forecast 2018 oil & condi volumes OIL HEDGING OIL HEDGES WTI fixed price swap contracts: 1,000 $70.14/bbl (2018) PROPANE HEDGES Conway propane swap contracts: 1,000 47% WTI (2018) STRONG FIXED PRICE NATURAL GAS & OIL RISK MANAGEMENT PROTECTION 60% 50% 40% 30% 20% 10% 0% $70.14 $70.14 $70.14 $70.14 Q1/18 Q2/18 Q3/18 Q4/18 WTI Swap ($C/bbl) 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 40.3 Mj/m3. Conway propane price referenced as a percentage of WTI in U.S. dollars. All hedges denominated in Canadian dollars unless otherwise noted. 10

11 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 Chicago Dawn Hedging & Market Diversification 2018 Total Corporate Volumes Oil Hedged 3% Liquids Unhedged 20% Dawn 8% Malin 6% Chicago 8% NGL Hedged 3% Henry Hub AECO Unhedged 16% AECO Basis Diff Hedges 2% AECO Fixed Price Hedges 34% Note: Percentage of estimated 2018 production volumes based on midpoint of guidance range 34,000 35,500 boe/d (74% natural gas weighted) 11

12 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 December 2017 average field volumes 2 Proved and Probable and unbooked locations as at December 31, 2017 ~77 Kilometers (48 Miles) 12

13 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 13

14 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,

15 Spirit River Geology Summary Broad, thick, extensive sand rich valleys in Notikewin, Falher and Wilrich members Tight sandstone: long life reserves with long term hyperbolic decline profile Average thickness 25 to 40 meters (approximately 80 to 130 feet) Up to three wells per zone to fully develop a section Porosity 6 to 18%; permeability 1 to 3 md Open and closed fracture systems evident in rock core and to a lesser degree in rock cuttings SPIRIT RIVER STACKED SANDS One square mile section schematic Notikewin Falher A Falher B Wilrich 15

16 Spirit River Type Curves Producing Day Raw Gas Volumes (MMcf/d) SPIRIT RIVER 5.2 & 6.0 BCF TYPE CURVES IRR % 200% 150% 100% Bellatrix Spirit River Economics Economic Assumptions 5.2 Bcf 6.0 Bcf Gross CAPEX (DCE&T, $MM) $3.8 $3.8 Gross Natural Gas IP30 (MMcf/d) EUR (mboe) 1,037 1,184 Economic Outputs (C$2.50/ GJ) 5.2 Bcf 6.0 Bcf NPV10 BTAX ($MM) $4.7 $6.5 PIR (10%) Payout (years) IRR (%) Days 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. 50% 0% $1.50/GJ $2.50/GJ 5.2 Bcf 6.0 Bcf 16

17 Spirit River All-In Profitability 5.2 Bcf Type Curve C$1.50/GJ C$2.50/GJ Full cycle F&D costs $/Mcfe ($0.77) ($0.77) Cash costs $/Mcfe ($2.08) ($2.16) Sales price $/Mcfe $3.26 $4.27 Profit $/Mcfe $0.41 $1.34 Profit margin % 12% 31% Half Cycle IRR % 36% 99% Full Cycle F&D costs Drill Complete Equip & tie in Half cycle costs Land/seismic/facilities Full cycle costs EUR (P50) Full cycle F&D $1.7MM $1.5MM $0.6MM $3.8MM $1.0MM $4.8MM 6.2 Bcfe $0.77/Mcfe Cash costs C$1.50/ GJ C$2.50/ GJ Royalties 8%) $0.26/Mcfe $0.34/Mcfe Operating costs 1 $0.69/Mcfe $0.69/Mcfe Transport 2 $0.29/Mcfe $0.29/Mcfe G&A 2 $0.36/Mcfe $0.36/Mcfe Interest & financing 2 $0.47/Mcfe $0.47/Mcfe Total costs $2.08/Mcfe $2.16/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. Assumed split is 65% 3rd party / 35% BXE plant. Includes estimated attributed operating cost impact from $75 million facilities disposition announced May 13, Representative transport, G&A and interest costs based on full year average 2017 corporate costs 3 Sales prices assume AECO at $1.71/Mcf ($1.50/GJ) or $2.84/Mcf ($2.50/GJ) as per scenario with 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. 17

18 Delivered on our 2017 Objectives RESULTS OUTPERFORMED EXPECTATIONS 14 Producing Day Volumes (MMcf/d) Days 2017 Wells BXE Spirit River 5.2 Bcf Type Curve BXE Spirit River 6.0 Bcf Type Curve 2017 Average Historical daily well production (natural gas only) versus Bellatrix representative 5.2 & 6.0 Bcf type curves 18

19 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 Q1 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)

20 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 DRIVES STRONG CAPITAL EFFICIENCIES (IP365 ESTIMATE) AVERAGING <$7,500/BOE/D wells Capital Efficiency ($/boe/d) 20,000 15,000 10,000 5, wells wells wells 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 wells Spirit River IP365 Capital Efficiency ($/boe/d) Full Capital Program Average 20

21 Focused Spirit River Growth 80% SPIRIT RIVER PRODUCTION GROWTH 32, Spirit River % of Total Company Volumes 70% 60% 50% 40% 30% 20% 28,000 24,000 20,000 16,000 12,000 8,000 Average Monthly Production (boe/d) Other Spirit River December 2017 Other 10% 0% 4,000 0 Spirit River 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 Spirit River % of Total Monthly Production (boe/d) Low cost Spirit River volumes comprise a growing proportion of total corporate production (>75%) Processing facilities and Firm Transportation (FT) capacity in place to facilitate growth 21

22 Improving Cost Structure PRODUCTION EXPENDITURES REDUCED; FURTHER IMPROVEMENT EXPECTED IN 2018 $11.00 Production expense ($/boe) $10.00 $9.00 $8.00 $7.00 $6.00 $5.00 Q4/16 Q1/17 Q2/17 Q3/17 Q4/ E Completion of Phase 2 of the Alder Flats Plant and production volume guidance are expected to deliver production expenses of between $7.65 to $8.00/boe in

23 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 130 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% 23

24 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 (in service 2018, remaining BXE cost plus prepayment capital ~$7MM) C2 Recovery 57% C3 Recovery 99% C4+ Recovery 100% Strategic advantage from owned infrastructure lowered costs and guaranteed access 24

25 Drill Bit Focused PLANT INVESTMENT & CONSTRUCTION & COMPLETE COMPLETE Q2/18 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 DRILLING DRILLING DRILLING DRILLING E 2019E 1 Drilling and completion capital includes capitalized items Note: Capital expenditures and development plans for 2018 are based on capital budget announced December 14, 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 which is expected to be completed in H1/2018. Plant Plant Land, G&G, and other capital BXE Alder Flats Plant Facilities & equipment (excluding BXE Plant) Drilling & completion capital 1 25

26 Ample Takeaway Capacity & Market Egress AMPLE FIRM TRANSPORTATION IN PLACE FOR CURRENT & GROWTH VOLUMES Firm Transportation (FT) agreements in place representing ~120% of current gross operated volumes at multiple receipt points along the Nova Gas Transmission Ltd. (NGTL) system Additional FT capacity secured upon completion of Phase 2 of Alder Flats Plant to facilitate increased forecast growth volumes FIRM SERVICE PROCESSING CAPACITY Maintain firm service capacity through several natural gas processing plants to ensure unfettered delivery capability for current & forecast growth volumes Multiple staggered third party processing contract maturities to align with anticipated in-service date of Phase 2 of Alder Flats Plant ALBERTA NATURAL GAS MARKET EGRESS ALBERTA Montney Alliance Pipeline AMPLE FRACTIONATION CAPACITY SECURED Long term agreements in place provide 100% coverage for current and forecast NGL volume growth BXE core west central area ideally situated on the NGTL system, downstream of Montney & northern Deep Basin areas, with ~120% firm transportation capacity Nova Gas Transmission Ltd. (NGTL) System Pipelines 26

27 Ample Firm Takeaway Capacity FIRM TRANSPORTATION CAPACITY PROVIDES A STRATEGIC ADVANTAGE Natural gas volumes (MMcf/d) FT Future Optionality Provides the opportunity to enhance funds flow from operations through optimal delivery of production volumes during periods of stronger commodity prices Mitigates against risk of volume downtime during periods of system constraints Bellatrix has managed its firm transportation at ~120% of gross operated natural gas volumes 0 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 Jan-19 Apr-19 Jul-19 Oct-19 Jan-20 Apr-20 Jul-20 Oct-20 Additional firm capacity step-up in April 2018 upon completion of Phase 2 of Alder Flats Plant BXE gross Nova firm transportation capacity BXE gross marketed natural gas volumes (includes non-op partner gas) BXE net before royalty natural gas volumes 27

28 Supplemental Information 28

29 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 29

30 Cardium Light Oil Resource Play BXE Land Sections1 144 Gross 84 Net BXE Net Drilling Inventory2 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 Cardium provides light oil exposure with material optionality to improving prices Remains a key focus formation for Bellatrix long-term within its core areas 1 2 Acreage as at December 31, 2017 Proved, Probable, and unbooked locations as at December 31, 2017 Conventional (vertical) Cardium development Expanded (horizontal) Cardium development Cardium wells 30

31 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 31

32 Material Deleveraging & Strategic Repositioning SUCCESSFULLY RAISED OVER $450 MILLION IN THE PAST 18 MONTHS OVER MULTIPLE TRANSACTIONS WITH MINIMAL PRODUCTION DIVESTED # Transaction Announcement Date Gross Proceeds $MM Production sold boe/d 1 Facilities monetization 13-May-16 $ % Alder Flats Plant sale 07-Jul-16 $ Bought deal financings 19-Jul-16 $ Pembina non-core asset sale 19-Sep-16 $ CDE Flow-through financing 04-Oct-16 $ Harmattan non-core asset sale 05-Dec-16 $80 3,076 7 Strachan non-core asset sale 14-Jun-17 $35 1,750 8 W. Pembina non-core asset sale 15-Sep-17 $ Total $456 6,326 FOCUS REMAINS ON STRATEGIC POSITIONING AND CORE VALUE OPTIMIZATION Note: Bought deal financings refer to the issuance of $50 million aggregate principal amount of 6.75% extendible unsecured subordinated convertible debentures and 25,000,000 subscription receipts (subsequently converted into common stock of Bellatrix) for aggregate gross proceeds of $80 million as announced on July 19, CDE flow-through financing refers to private placement flow-through basis in respect of Canadian Development Expenses ( CDE ) resulting in gross proceeds of $10 million announced on October 4,

33 Representative Spirit River Inventory Required to Maintain Production Volumes Approximately 15 net Spirit River wells 1 per year maintains production in the high 30 mboe/d range through 2022 Represents scenario of drilling only 21% of net Spirit River well inventory Production (mboe/d) Jan-18 Jul-18 Jan-19 Jul-19 Jan-20 Jul-20 Jan-21 Jul-21 Jan-22 Jul-22 Base 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 33

34 Corporate Information BOARD OF DIRECTORS W.C. (Mickey) Dunn Chairman Murray L. Cobbe John H. Cuthbertson, QC Brent A. Eshleman, P.Eng Lynn Kis, P.Eng Keith E. Macdonald, CPA, CA Thomas E. MacInnis, B.Comm, MBA Steven J. Pully, CPA, CFA Murray B. Todd, B.Sc., P.Eng. Keith S. Turnbull, B.Sc., CPA, CA SENIOR OFFICERS Brent A. Eshleman, P.Eng. President & CEO Max Lof, CFA Executive Vice President & CFO Charles R. Kraus, Esq. Executive Vice President, General Counsel & Corporate Secretary Garrett Ulmer, P.Eng Chief Operating Officer Steve G. Toth, CFA Vice President, Investor Relations & Corporate Development ADDRESS 1920, 800 5th Avenue SW Calgary, Alberta Canada T2P 3T6 Tel: (403) Fax: (403) BANKERS National Bank of Canada Alberta Treasury Branches The Bank of Nova Scotia Canadian Western Bank EVALUATION ENGINEERS InSite Petroleum Consultants Ltd. REGISTRAR & TRANSFER AGENT Computershare Trust Company of Canada AUDITORS KPMG LLP EXCHANGE LISTING The Toronto Stock Exchange - BXE The New York Stock Exchange - BXE RATING AGENCIES Moody s Investor Service Inc. Corporate Rating: B3 Senior Notes Rating: Caa1 Standard and Poor s Rating Service Corporate Rating: B Senior Notes Rating: B