Corporate Presentation JANUARY 2019

Transcription

1 Corporate Presentation JANUARY

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 & 2019 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 January 14, 2019 and are included herein to provide readers with an understanding of the anticipated funds available to Bellatrix to fund its operations and readers are cautioned that the information may not be appropriate for other purposes. Forward looking statements necessarily involve risks, including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals, actions taken by the Company's lenders that reduce the Company's available credit and ability to access sufficient capital from internal and external sources. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Bellatrix. In addition, forward looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect and which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on Bellatrix s future operations. Such information may prove to be incorrect and readers are cautioned that the information may not be appropriate for other purposes. Although the Company believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could affect Bellatrix s operations and financial results are included in reports on file with Canadian and United States securities regulatory authorities and may be accessed through the SEDAR website ( 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. 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. F&D costs are used as a measure of capital efficiency. F&D presented above has been calculated based on exploration and development capital divided by the expected ultimate recovery (EUR). The type curve and capital efficiency numbers have been presented to provide readers with information on the assumptions used for management's budgeting process and future planning. The half cycle economics and capital efficiencies may not be achieved on future wells as a result of a number of factors including the risks identified above under "Forward Looking Statements" and as such are not reliable indicators of future performance. In addition, there is no certainty that future wells will generate results to match historic type curves presented herein. Half cycle economics and capital efficiencies are not terms that have standardized meanings and therefore such calculations may not be comparable with the calculation of similar measures for other entities. FINANCIAL INFORMATION: Unless otherwise stated, financial information is based upon Bellatrix s audited consolidated financial statements for the years ended December 31, 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 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: 550,000/ U.S.: 85,000 Shares Outstanding million basic / 82.4 million diluted Market Capitalization 3 $59 million Bank Debt 4 $57 million Senior Unsecured Notes due US$154 million Second Lien Notes due US$87 million Convertible Debentures $50 million Enterprise Value 3 $475 million 2018 Estimated Annual Production 35,600 boe/d 2019 Estimated Annual Production 34,000 36,000 boe/d 2019 Natural Gas Weighting 72% 2019 Liquids Weighting 28% 1 Three month average at January 4, Share count at November 26, Diluted shares include options but exclude shares potentially issuable on conversion of convertible debentures which are included in net debt calculation. 3 Calculated using January 4, 2019 share price (C$0.73/share). Enterprise value includes market capitalization plus total net debt of $419 million as at September 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 September 30, Bank debt reflects $57 million outstanding on the Credit Facilities at September 30, Senior unsecured notes and Second Lien note balances reflect September 30, 2018 balances 4

5 2018 Guidance History ESTIMATED ANNUAL 2018 RESULTS SURPASSED HIGH END OF PREVIOUSLY SET GUIDANCE ESTIMATED 2018 ANNUAL RESULTS PREVIOUSLY SET 2018 ANNUAL GUIDANCE (NOV 1, 2018) PREVIOUSLY SET 2018 ANNUAL GUIDANCE (AUG 2, 2018) PREVIOUSLY SET 2018 ANNUAL GUIDANCE (APR 3, 2018) Production (boe/d) 2018 Average daily production 35,600 35,000 35,500 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 - $55 $50 - $60 $55 - $65 Expenses Production expense ($/boe) 2 $ $7.90 $ $8.00 $ $ 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. 5

6 2019 Guidance & Objectives 2019 CAPITAL BUDGET DELIVERS STABLE PRODUCTION VOLUMES 1 Production (boe/d) CURRENT 2019 ANNUAL GUIDANCE (JAN 15, 2019) 2018 Average daily production 34,000 36,000 Production mix (%) Natural gas 72 Crude oil, condensate and NGLs 28 Capital Expenditures ($MM) Total net capital expenditures 1 $40 - $ BUDGET ATTRIBUTES Reduced maintenance capital requirements. The combination of lower well capital costs ($3.4MM all-in) and improved results has reduced the number of assumed Spirit River wells to 12 per year (average 6.0 Bcf performance curve) required to maintain total corporate production volumes in the mid 30 mboe/d range. Financial Flexibility. Ability to accelerate or decelerate capital expenditures throughout the year, while preserving liquidity and balance sheet strength. Continued cost suppression focus. Third quarter 2018 production expenses of $7.71/boe and $23.8 million represent 27% and 23% reductions respectively, compared with fourth quarter 2016 levels. Cost suppression activities achieved through ongoing technological and operationally focused initiatives. Optimized returns. The drilling program will balance development of Spirit River liquids rich natural gas investment opportunities and higher liquids weighted opportunities in the Cardium play capital budget incorporates forward pricing expectations of US$65/bbl WTI and $1.60/GJ AECO 2 Excludes property acquisitions and dispositions. 6

7 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 part of long term notes and extend debt maturities 2019 Advance debt refinance strategy 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 7

8 Diversified Balance Sheet & Financial Flexibility Actively exploring refinancing opportunities and additional sources of liquidity BANK DEBT $57MM AT SEPTEMBER 30, 2018 CREDIT FACILITY FINANCIAL COVENANTS LONG TERM DEBT MATURITIES Undrawn Utilized Debt/EBITDA Q4/17 Q1/18 Q2/18 Q3/18 First Lien Debt to EBITDA Senior Debt to EBITDA Debt maturities (C$) $250 $200 $150 $100 $50 $ Bank debt $57MM at September 30, 2018 $100MM credit facility confirmed September 2018 with total commitments set at $95MM Next semi-annual redetermination May 2019 Two financial covenants First Lien Debt/EBITDA; maximum ratio of 3.0x Senior Debt/EBITDA; maximum ratio of 5.0x Q3/18 ratios of 1.24x and 2.78x respectively were both well below financial covenant levels 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 2023 Balances as at September 30,

9 AECO Natural Gas Expansion Projects Underway ADDITIONAL EXPORT CAPACITY BEING DEVELOPED OUT OF THE CANADIAN BASIN 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 Forecasts anticipate the basin will become long egress and domestic demand between Q4/19 and Q1/21 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% Capacity expansions add over 2.1 Bcf/d of incremental export capacity through 2021, an increase of 19% compared to current capacity levels Source: Scotiabank Energy Research, Altacorp Capital Research 9

10 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 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 Hedging & Market Diversification Q Total Corporate Volumes Oil Hedged 7% Liquids Unhedged 17% Dawn 12% Malin 7% Chicago Dawn NGL Hedged 3% AECO Unhedged 10% Chicago 12% Henry Hub AECO Fixed Price Hedges 32% 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 Commodity Price Risk Management & Diversification NATURAL GAS MARKET DIVERSIFICATION & FIXED PRICE HEDGING COVERAGE % of total forecast 2018 gas volumes 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Q4/18 Q1/19 Q2/19 Q3/19 Q4/19 Q1/20 Q2/20 Q3/20 Q4/20 AECO/NYMEX Basis Swap AECO Fixed Price Swaps U.S. Fixed Price Contracts Market Diversification Contracts NATURAL GAS FIXED PRICE HEDGES AECO fixed price swap contracts: 67 $3.03/Mcf (Oct Dec 2018) 8 $1.72/Mcf (Oct 2018) 18 $2.01/Mcf (Apr-Oct 2019) U.S fixed price contracts 1 : 50 $4.33/Mcf (Dec 2018) 30 $4.20/Mcf (Jan-Mar 2019) STRONG PRICE RISK MANAGEMENT PROTECTION OIL HEDGES WTI fixed price swap contracts: 1,000 $70.14/bbl (Oct Dec 2018) WTI call option contracts: 1,500 $80.00/bbl (Oct Dec 2018) 1,000 $87.50/bbl (Jan Dec 2019) 1,000 $77.90/bbl (Jan Dec 2020) Percent of forecast volumes based on the mid-point of average 2019 production guidance of mboe/d (72% natural gas weighted). Natural gas hedges converted from $/GJ to $/Mcf based on an assumed average corporate heat content of 40.0 Mj/m3. All hedges denominated in Canadian dollars unless otherwise noted. 1 Net Canadian equivalent price is calculated as the US$ fixed price, less contracted differential, adjusted to Canadian dollars at an assumed exchange rate of $1.30 USD/CAD. 12

13 Growing High Value Liquids Growing NGL Volumes & High Value Condensate Corporate NGL Yield (bbl/mmcf) Alder Flats Phase 2 Completed Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Q3/18 Q4/18E 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 Q3/18 High Condensate Weighting Drives Strong Realizations Relative to Benchmark Light Oil Prices $100 $80 Oil Price (C$/bbl) $60 $40 $20 $0 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Q3/18 Canadian Light crude blend BXE crude oil and condensate BXE Crude Oil & Condensate Differential (C$/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 Q3/18 13

14 Highly Concentrated Land Base DOMINANT ACREAGE POSITION WEST CENTRAL ALBERTA CORE AREA 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) 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 September 2018 average field volumes 2 Proved and Probable and unbooked locations as at December 31, 2017 ~77 Kilometers (48 Miles) 14

15 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 15

16 Pre-eminent Capital Efficient Operator in the WCSB BXE 2018 AVERAGE NATURAL GAS WELL PERFORMANCE (IP90) RANKS BEST IN BASIN 2018 Best IP90 Average Natural Gas Rate (MMcf/d) BXE Repsol IBR TDW PPY TOU BNP VET Exshaw Delphi 2019E Capital Efficiency $25,000 $20,000 $15,000 $10,000 $5,000 $0 BXE BEST IN CLASS ON 2019 ESTIMATED CAPITAL EFFICIENCY BXE POU SRX ARX BNP PEY PNE AAV CR BIR KEL ERF TVE Source: XI Technologies Inc. based on January June 2018 average corporate natural gas well performance; capital efficiency estimates from Peters & Co. Limited Research, January 2,

17 Bellatrix s Spirit River Play BXE Land Sections Gross 104 Net BXE Net Drilling Inventory proved 27 probable 225 unbooked 354 total GREATER FERRIER AREA CORE SPIRIT RIVER PLAY True vertical formation depth ~2,250 meters (~7,400 feet) Currently drilling one mile laterals Average 17 frac stages per well with 40 tonnes per stage 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,

18 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 18

19 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 19

20 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 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 PROPPANT PLACED Duvernay Montney BXE Spirit River TOTAL DEPTH 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 0 Duvernay Montney BXE Spirit River 0 Duvernay Montney BXE Spirit River Source: Accumap, Scotiabank Energy Research, internal costs 20

21 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) performance curve and utilizes all-in well costs of $3.4 million 21

22 Spirit River Type Curves SPIRIT RIVER 5.2 & 6.0 BCF TYPE CURVES Bellatrix Spirit River Economics Producing Day Raw Gas Volumes (MMcf/d) C4 8 Liquids (bbl/mmcf) C5+ 15 C3 13 C2 27 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 (%) IRR % 200% 150% 100% 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. 22

23 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 ($2.19) ($2.27) Sales price $/Mcfe $3.24 $4.27 Profit $/Mcfe $0.34 $1.29 Profit margin % 11% 30% Half Cycle IRR % 49% 132% 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 $1.5MM $1.4MM $0.5MM $3.4MM $1.0MM $4.4MM 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 $0.35/Mcfe $0.35/Mcfe G&A 2 $0.35/Mcfe $0.35/Mcfe Interest & financing 2 $0.50/Mcfe $0.50/Mcfe Total costs $2.19/Mcfe $2.27/Mcfe Sales price C$1.50/GJ C$2.50/GJ Total sales price 3 $3.24/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 nine month 2018 corporate costs 3 Sales prices assume AECO at $1.69/Mcf ($1.50/GJ) or $2.82/Mcf ($2.50/GJ) as per scenario with net NGL pricing: $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. 23

24 Delivering on our Objectives RESULTS OUTPERFORMED 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 24

25 Enduring Efficiency Gains on Drill Times AVERAGE SPIRIT RIVER DRILLING CURVES DAYS SPUD TO RIG RELEASE BY YEAR 0 20 Measured Depth (m) 500 1,000 1,500 2,000 2,500 3, Spirit River Average 2015 Spirit River Average 2016 Spirit River Average 2017 Spirit River Average 2018 Spirit River Average Days (Spud to Rig Release) DRILL COST BY YEAR 3, ,000 4,500 5, Days Spud to Rig Release Drill Cost ($MM) 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 25

26 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 Long Reach Equip & Tie-in Complete Drill $1.0 Capital Efficiency ($/boe/d) $ wells wells wells wells DRIVES STRONG CAPITAL EFFICIENCIES (IP365 ESTIMATE) AVERAGING <$7,000/BOE/D 20,000 15,000 10,000 5,000 0 Note: IP365 forecasts based on initial well productivity, reservoir characteristics, and full year well production modeling Capital efficiency calculated as gross well costs (drill, complete, equip and tie-in) divided by gross IP365 production expectation of Falher B and Notikewin wells drilled Analysis of operated wells only and does not include promoted spend within historical JV development. Spirit River IP365 Capital Efficiency ($/boe/d) Full Capital Program Average wells wells wells wells 26

27 Bellatrix Focused Spirit River Growth 80% SPIRIT RIVER PRODUCTION GROWTH 32, Spirit River % of Total Company Volumes 70% 60% 50% 40% 30% 20% 2011 Slick Water Frac 2012 Megabore 2014 Falher A Validation 2018 New Drill Techniques 28,000 24,000 20,000 16,000 12,000 8,000 Average Monthly Production (boe/d) Other Spirit River 10% 4,000 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 Sep-18 December 2018 Other Spirit River 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 27

28 Cost Reductions Achieved 27% REDUCTION IN PRODUCTION EXPENSES ($/BOE) Production expense ($/boe) $11.00 $10.00 $9.00 $8.00 $7.00 $6.00 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Q3/18 Production expense ($MM) $32 $30 $28 $26 $24 $22 $20 23% REDUCTION IN PRODUCTION EXPENSES ($MM) Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Q3/18 28

29 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 as future budgets, drill plans, and anticipated well results are uncertain 29

30 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% 30

31 Greater Ferrier Area Infrastructure Overview GREATER FERRIER EXISTING INFRASTRUCTURE ACCESS: Infrastructure gives Bellatrix control of production and growth Working interest or operatorship in 3 major gas processing facilities 9 compressor sites 4 oil batteries BELLATRIX ALDER FLATS PLANT Bellatrix 25% owner and operator Keyera 70% owner O Chiese 5% owner Phase I 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% GREATER FERRIER AREA STRATEGIC INFRASTRUCTURE Strategic advantage from owned infrastructure lowered costs and guaranteed access 31

32 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 $55MM $87MM $20 $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. 32

33 Drill Bit Focused PLANT PHASE 2 CONSTRUCTION COMPLETE MARCH 2018 Major compressor stations, pipelines and Bellatrix Alder Flats Plant capital investment completed Proportion of incremental capital to drilling & completion expected to increase Increased drill bit directed capital positions Bellatrix to deliver enhanced corporate capital efficiency rates in 2019 & beyond % 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) 1 Drilling & completion 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. 33

34 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 ALBERTA NATURAL GAS MARKET EGRESS Montney ALBERTA 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 BXE core west central area ideally situated on the NGTL system, downstream of Montney & northern Deep Basin areas, with firm transportation capacity Alliance Pipeline Nova Gas Transmission Ltd. (NGTL) System Pipelines 34

35 Supplemental Information 35

36 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 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 TVD: True vertical depth 36

37 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 37

38 Strategic Land Position GREATER FERRIER/BRAZEAU/WILLESDEN GREEN AREAS OF WEST CENTRAL ALBERTA Pembina Brazeau Ferrier Willesden Green Bellatrix Cenovus Peyto Tourmaline TAQA Westbrick Source: Accumap, company presentations and various public sources 38

39 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 27% reduction in production expenditures to $7.71/boe in Q3/18 from $10.57/boe in Q4/16 Operational performance 2018 program delivering average IP90 well 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 $53 million in risk management gains Q1/17 to Q3/18 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 Q3/18 from 25% in Q1/17 while retaining meaningful upside potential to improving natural gas prices 39

40 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. Standard and Poor s Rating Service 40