POSITIONED FOR SUSTAINABLE LONG TERM VALUE CREATION EnerCom Presentation August 14, 2017
Advisories FORWARD LOOKING STATEMENTS: In the interest of providing Bellatrix s shareholders and potential investors with information regarding Bellatrix, including management s assessment of Bellatrix s future plans and operations, certain statements contained in these presentation materials (collectively, this presentation ) are forward looking statements or information within the meaning of applicable securities legislation, collectively referred to herein as forward looking statements. The forward looking statements contained in this presentation speak only as of the date of this presentation and are expressly qualified by this cautionary statement. Forward looking statements in this presentation include, but are not limited to: statements regarding the quality of the Company s assets and acreage, the Company s infrastructure and firm transportation capacity, including the expected timing of completion of Phase 2 of the Alder Flats Gas Plant, the Company s growth plans and forecasted capital efficiencies and investment returns, the Company s balance sheet and available liquidity, future production estimates, future drilling locations, 2017 guidance relating to production, production mix, net capital expenditures and production expense, the Company s net asset value, the Company s acreage position, the nature and profitability of the Company s Spirit River acreage, well results, the sustainability of cost reductions, drilling times and capital efficiencies, development metrics, future drilling inventory, the Company s land position, and the sufficiency and performance of the Company s infrastructure. To the extent that any forward-looking information contained herein constitute a financial outlook, they were approved by management on August 9, 2017 and are included herein to provide readers with an understanding of the anticipated funds available to Bellatrix to fund its operations and readers are cautioned that the information may not be appropriate for other purposes. Forward looking statements necessarily involve risks, including, without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other producers, inability to retain drilling rigs and other services, incorrect assessment of the value of acquisitions, failure to realize the anticipated benefits of acquisitions, delays resulting from or inability to obtain required regulatory approvals, actions taken by the Company's lenders that reduce the Company's available credit and ability to access sufficient capital from internal and external sources. Events or circumstances may cause actual results to differ materially from those predicted, as a result of the risk factors set out and other known and unknown risks, uncertainties, and other factors, many of which are beyond the control of Bellatrix. In addition, forward looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect and which have been used to develop such statements and information in order to provide shareholders with a more complete perspective on Bellatrix s future operations. Such information may prove to be incorrect and readers are cautioned that the information may not be appropriate for other purposes. Although the Company believes that the expectations reflected in such forward looking statements or information are reasonable, undue reliance should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development of exploration; the timing and costs of pipeline, storage and facility construction and expansion and the ability of the Company to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company operates; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements. Additional information on these and other factors that could affect Bellatrix s operations and financial results are included in reports on file with Canadian and United States securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com), through the SEC website (www.sec.gov), and at Bellatrix s website (www.bellatrixexploration.com). Furthermore, the forward looking statements contained herein are made as at the date hereof and Bellatrix does not undertake any obligation to update publicly or to revise any of the included forward looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. NON-GAAP MEASURES Throughout this presentation, the Company uses terms that are commonly used in the oil and natural gas industry, but do not have a standardized meaning presented by International Financial Reporting Standards ( IFRS ) and therefore may not be comparable to the calculations of similar measures for other entities. Management believes that the presentation of these non-gaap measures provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis. CAPITAL PERFORMANCE MEASURES In addition to the non-gaap measures described above, there are also terms that have been reconciled in the Company s financial statements to the most comparable IFRS measures. These terms do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculations of similar measures for other entities. These terms are used by management to analyze operating performance on a comparable basis with prior periods and to analyze the liquidity of the Company. This presentation contains the term total net debt which is not recognized measures under GAAP. Therefore reference to total net debt may not be comparable with the calculation of a similar measure for other entities. The Company s calculation of total net debt excludes other deferred liabilities, deferred capital obligations, long-term risk management contract liabilities, decommissioning liabilities, and deferred tax liabilities. Total net debt includes the working capital deficiency, long term loans receivable, convertible debentures (liability component), current bank debt and long term bank debt. DRILLING LOCATIONS In this presentation, the Company has disclosed certain drilling locations associated with Bellatrix's interest in the Spirit River and Cardium plays. Of the 381 net Spirit River drilling locations identified herein, 86 are proved locations, 30 are probable locations and 265 are unbooked locations. Of the 206 net Cardium drilling locations identified herein, 92 are proved locations, 29 are probable locations, and 85 are unbooked locations. Proved locations and probable locations are derived from Bellatrix s independent reserve report prepared by InSite Petroleum Consultants Ltd. as at December 31, 2016 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations as disclosed herein have been identified by management as an estimation of the Company's multi-year drilling activities using information including applicable geologic, seismic, engineering, production, pricing assumptions and reserves information. There is no certainty that Bellatrix will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which Bellatrix actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While the majority of Bellatrix's unbooked locations are extensions or infills of the drilling patterns already recognized by the Company's independent qualified reserves evaluator, other unbooked drilling locations are farther away from existing wells where management may have less information about the characteristics of the reservoir and therefore there may be more uncertainty whether wells will be drilled in such locations and if drilled there may be more uncertainty that such wells will result in additional oil and gas reserves, resources or production. INITIAL RATES OF PRODUCTION References in this presentation to initial production rates associated with certain wells are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. The Company cautions that such production rates should be considered to be preliminary. BOE PRESENTATION: The term barrels of oil equivalent ( boe ) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf/ 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. All boe conversions in this presentation are derived from converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil. ESTIMATED ULTIMATE RECOVERY (EUR): In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented which are based on the assumptions used by InSite Petroleum Consultants Ltd. to estimate Bellatrix's proved plus probable reserves per well as evaluated effective December 31, 2016 based on forecast prices and costs. There is no certainty that such Bellatrix will ultimately recover such volumes from the wells it drills. CURRENCY: All dollar amounts in this presentation are Canadian dollars unless otherwise identified. RESERVES INFORMATION: Unless indicated otherwise, reserve estimates and related future net revenue and other reserves information is derived from Bellatrix s independent reserve report prepared by InSite Petroleum Consultants Ltd. as at December 31, 2016 using forecast prices and costs. Land acreage information is as available at December 31, 2016, unless otherwise noted. TYPE CURVE AND CAPITAL EFFICIENCY: In this presentation information relating to the type curve, half cycle economics and capital efficiency for Bellatrix's Spirit River wells have been presented. The type curve set forth herein is based on all Bellatrix operated, Notikewin and Falher B wells drilled between October 2012 and September 2015, and represents the mean (P50) performance curve. Half cycle economics are based on Bellatrix's current expectations of drill, complete, equip and tie-in costs per well (and excluding land, seismic and related costs). Capital efficiency is a measure of expected capital expenditures per well based on half cycle economics divided by average first year production results (IP365) based on the type curve presented. The type curve and capital efficiency numbers have been presented to provide readers with information on the assumptions used for management's budgeting process and future planning. The half cycle economics and capital efficiencies may not be achieved on future wells as a result of a number of factors including the risks identified above under "Forward Looking Statements" and as such are not reliable indicators of future performance. In addition, there is no certainty that future wells will generate results to match historic type curves presented herein. Half cycle economics and capital efficiencies are not terms that have standardized meanings and therefore such calculations may not be comparable with the calculation of similar measures for other entities. FINANCIAL INFORMATION: Unless otherwise stated, financial information is based upon Bellatrix s audited consolidated financial statements for the years ended December 31, 2016 and 2015. 2
Corporate Profile MARKET SUMMARY Ticker Symbol TSX / NYSE: BXE Average Daily Volume 1 Canada: ~165,000/ U.S.: ~100,000 Shares Outstanding 2 49.4 million basic / 51.2 million diluted Market Capitalization 3 $162 million Bank Debt 4 $13 million Senior Notes due 2020 US$250 million Convertible Debentures $50 million Enterprise Value 3 $545 million 2016 Exit Production 31,500 boe/d 2017 Estimated Exit Production 36,500 boe/d 2016 Exit to 2017 Exit Growth >15% 2017 Natural Gas Weighting 76% 3 1 Three month average at August 8, 2017 2 Share count at July 6, 2017 (post consolidation). 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 August 8, 2017 share price (C$3.27/share). Enterprise value includes market capitalization plus total net debt of $383 million as at June 30, 2017. Total net debt includes bank debt, $16 million adjusted working capital deficiency, the liability component of the convertible debentures, and assumes conversion of US notes at Cdn/US $1.2983 as at June 30, 2017. 4 Bank debt reflects $13 million outstanding on the Credit Facilities at June 30, 2017
Investment Highlights HIGH QUALITY ASSETS & ACREAGE INFRASTRUCTURE OWNERSHIP & CONTROL TAKEAWAY CAPACITY & MARKET EGRESS PROFITABLE GROWTH STRONG LIQUIDITY Dominant core acreage position in west central Alberta Spirit River represents one of North America s lowest supply cost natural gas plays Consistently deliver top ranked well productivity results Asset portfolio provides balance of natural gas and oil/liquids weighted opportunities Ownership and control of strategic infrastructure including pipelines, compression, and processing facilities Infrastructure control creates significant barriers to competition within core area Secured firm transportation over approximately 120% of current gross operated natural gas volumes Maintain firm service contracts through owned & third party processing plants Long term NGL fractionation agreements in place for 100% of volumes Defined three year outlook provides line of sight for +/-15% compound annual production volume growth Top tier capital efficiencies and cost profile deliver full cycle sustainable profitability Current commodity prices drive strong forecast investment returns 89% unused capacity on bank credit facilities at June 30, 2017 Liquidity enhanced on May 9, 2017 with bank credit facilities increasing to $120 million (from $100 million) and reconfirmed at $120 million post-closing of Strachan asset sale No term debt maturities until May 2020 and September 2021 4 Note: 89% unused capacity on bank credit facilities at June 30, 2017 and references $13 million bank debt relative to credit facilities of $120 million. Unused capacity excludes outstanding letters of credit.
Reintroducing Bellatrix NEW LEADERSHIP Brent Eshleman appointed President, CEO and a member of the Board of Directors on February 15, 2017 Max Lof appointed Executive Vice President & CFO on June 19, 2017 TRANSFORMATIONAL CHANGES COMPLETED IN 2016 & 2017 Strategic repositioning efforts completed which includes increased asset concentration, a materially stronger balance sheet and an enhanced net asset value June 30, 2017 January 1, 2016 Change Total net debt $383 million $718 million Reduced 46% Bank debt $13 million $341 million Reduced 96% Sharpening our focus on the highest value core assets 1 Core areas = 99% of total production Core areas = 83% of total production Sold Strachan, Harmattan & Pembina Cardium 5 1 Current core area (Greater Ferrier, Willesden Green & Pembina areas) production % of total based on first week of August 2017 field level estimates; year end 2015 core area production based on January 2016 field estimates.
Maintain 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 Average Production Flat Q1/16 to Q2/17 $800 $700 Debt ($MM) $600 $500 $400 $300 $200 $100 Total Net Debt Reduced 46% from Q1/16 to Q2/17 $0 Q1/16 Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Net Bank Debt U.S. Senior Notes Convertible Debentures 6 Net bank debt includes bank debt outstanding and working capital deficiency; convertible debentures include liability component
2017 Outlook & Guidance Production (boe/d) INITIAL 2017 ANNUAL GUIDANCE (JANUARY 5, 2017) PREVIOUSLY SET 2017 ANNUAL GUIDANCE (JUNE 26, 2017) REVISED 2017 ANNUAL GUIDANCE (AUGUST 10, 2017) CHANGE FROM INITIAL 2017 Average daily production 33,500 34,500 36,000 2,500 2017 Exit production 35,000 35,500 36,500 1,500 2017 Growth (2016 exit to 2017 exit) +/-15% +/-15% >15% Production mix (%) Natural gas 76 76 76 Crude oil, condensate and NGLs 24 24 24 Capital Expenditures ($MM) Total net capital expenditures 1 $105.0 $120.0 $120.0 Property disposition cash 2 - ($34.5) ($34.5) Total net capital expenditures after property disposition - cash $105.0 $85.5 $85.5 $19.5 Expenses Production expense ($/boe) 3 $9.00 $9.00 $8.75 $0.25 7 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 2017. 2 Property disposition cash refers to the Strachan asset sale and does not include transaction costs or adjustments. 3 Production expenses before net processing revenue/fees.
Commodity Price & Currency Risk Management STRONG FIXED PRICE NATURAL GAS RISK MANAGEMENT PROTECTION % of total forecast 2017 gas volumes 80% 70% 60% 50% 40% 30% 20% 10% 0% $3.19 $3.33 $3.06 $3.06 $3.06 $3.06 Q3/17 Q4/17 Q1/18 Q2/18 Q3/18 Q4/18 AECO Swap (C$/Mcf) NATURAL GAS HEDGES AECO fixed price swap contracts: 117.0 MMcf/d @ C$3.19/Mcf (Q3 2017) 102.2 MMcf/d @ C$3.33/Mcf (Q4 2017) 66.1 MMcf/d @ C$3.06/Mcf (2018) PROPANE HEDGES Conway propane swap contracts: 1,500 bbl/d @ 50.7% WTI (Q3-Q4 2017) 500 bbl/d @ 51.5% WTI (Q3-Q4 2017) 1,000 bbl/d @ 47.0% WTI (2018) CURRENCY HEDGES USD foreign exchange forward contract summary: $62.5MM @ 1.308 USD/CAD (value date May 2020) 8 Percent of forecast volumes based on the mid-point of updated (August 10, 2017) 2017 average production guidance of 36,000 boe/d (76% natural gas 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.
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 : 248 Unbooked net locations 2 : 444 Total net drilling locations: 692 Alberta ~77 Kilometers (48 Miles) 9 1 Reflects % of June 2017 average field volumes and excludes divested Strachan area which closed June 26, 2017 2 Proved and Probable and unbooked locations as at December 31, 2016
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 10 TVD: True vertical depth
Focused Spirit River Growth 75% SPIRIT RIVER PRODUCTION GROWTH 30,000 2010 60% 45% 30% 15% 0% 24,000 18,000 12,000 6,000 0 Other Spirit River June 2017 Spirit River Other Jan 10 May 10 Sep 10 Jan 11 May 11 Sep 11 Jan 12 May 12 Spirit River % of Total Company Volumes Average Monthly Production (boe/d) 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 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 11
Spirit River - The Quiet Giant Spirit River Montney L Mannville Viking Bakken Glauconitic Cardium Duvernay Shaunavon Colorado Mississippian Charlie Lake WESTERN CANADA 2016 WELLS CALENDAR DAY PRODUCTION BY ZONE 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 Calendar average daily cumulative volumes (boe/d) 2016 WELL (BOE) VOLUMES BY ZONE 2016 WELL (MCF) VOLUMES BY ZONE Other Spirit River Montney Spirit River accounted for ~33% of total Western Canada hydrocarbon volumes (boes) from new wells drilled in 2016 Other Montney Spirit River Spirit River accounted for ~50% of total Western Canada natural gas volumes (Mcf) from new wells drilled in 2016 12 Source: Data from Canadian Discovery Ltd.; excludes oilsands and thermal oil wells/volumes
Spirit River Liquids Rich Gas BXE Land Sections 1 204 Gross 112 Net GREATER FERRIER AREA CORE SPIRIT RIVER PLAY BXE Net Drilling Inventory 2 86 proved 30 probable 265 unbooked 381 total 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 13 1 Includes Ferrier, Willesden Green, and greater Pembina. Acreage as at June 30, 2017 2 Proved, Probable, and unbooked locations as at December 31, 2016 and excludes Strachan area
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 14 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
Spirit River All-In Profitability C$2.50/GJ C$3.00/GJ Full Cycle F&D costs Full cycle F&D costs $/Mcfe ($0.85) ($0.85) Cash costs $/Mcfe ($2.14) ($2.18) Drill Complete Equip & tie in Half cycle costs Land/seismic/facilities Full cycle costs $1.7MM $1.6MM $0.7MM $4.0MM $1.1MM $5.1MM Sales price $/Mcfe $3.91 $4.42 Profit $/Mcfe $0.92 $1.39 Profit margin % 24% 31% Half Cycle IRR % 35% 62% EUR (P50) Full cycle F&D 6.0 Bcfe $0.85/Mcfe Cash costs C$2.50/GJ C$3.00/GJ Royalties (est @ 8%) $0.31/Mcfe $0.35/Mcfe Operating costs 1 $0.75/Mcfe $0.75/Mcfe Transport 2 $0.26/Mcfe $0.26/Mcfe G&A 2 $0.34/Mcfe $0.34/Mcfe Interest & financing 2 $0.48/Mcfe $0.48/Mcfe Total costs $2.14/Mcfe $2.18/Mcfe Sales price C$2.50/GJ C$3.00/GJ 15 Total sales price 3 $3.91/Mcfe $4.42/Mcfe Note: Numbers may not add due to rounding 1 Incremental operating costs assume $0.56/Mcf for natural gas through third party plants, $0.20/Mcf for gas processed through BXE Alder plant and $8.00/bbl for oil/condensate. Assumed split is 80% 3rd party / 20% BXE plant. Includes estimated attributed operating cost impact from $75 million facilities disposition announced May 13, 2016. 2 Representative transport, G&A and interest costs based on average first half 2017 corporate costs 3 Sales prices assume AECO at $2.84/Mcf ($2.50/GJ) or $3.41/Mcf ($3.00/GJ) as per scenario with NGL pricing: ethane @ $10/bbl, propane @ $15/bbl, butane @ $30/bbl and condensate @ $60/bbl incorporating liquids extraction capabilities given mix of gas through third party and BXE Alder Flats Plant.
Delivering on our 2017 Objectives 20 18 16 2017 RESULTS OUTPERFORMING TYPE CURVE EXPECTATIONS Producing day volumes (MMcf/d) 14 12 10 8 6 4 2 0 0 30 60 90 120 150 180 210 240 270 300 330 360 Days 2017 Wells 2017 Average BXE Spirit River 5.2 Bcf Type Curve 16 Historical daily well production (natural gas only) versus Bellatrix representative 5.2 Bcf type curve
Spirit River Well Costs & Capital Efficiencies FOCUSED CAPITAL COST REDUCTIONS $6.0 Costs ($millions) $5.0 $4.0 $3.0 $2.0 Long Reach Long Reach Long Reach Equip & Tie-in Complete Drill $1.0 $0.0 2015-24 wells 2016-19 wells 2017-8 wells DRIVES STRONG CAPITAL EFFICIENCIES (IP365 ESTIMATE) AVERAGING ~$8,000/BOE/D 20,000 Capital Efficiency ($/boe/d) 15,000 10,000 5,000 0 17 2015-24 wells 2016-19 wells 2017-8 wells Spirit River IP365 Capital Efficiency ($/boe/d) Full Capital Program Average 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. Two June 2017 Spirit River wells excluded from analysis due to limited time on-stream
Enduring Efficiency Gains 0 AVERAGE SPIRIT RIVER DRILLING CURVES 20 SPUD TO RIG RELEASE BY YEAR Measured Depth (m) 500 1,000 1,500 2,000 2,500 3,000 2014 Spirit River Average 2015 Spirit River Average 2016 Spirit River Average 2017 Spirit River Average Days (Spud to Rig Release) 15 10 5 0 $3.0 2014 2015 2016 2017 DRILL COST BY YEAR 3,500 $2.5 4,000 4,500 5,000 0 5 10 15 20 Days Spud to Rig Release Drill Cost ($MM) $2.0 $1.5 $1.0 $0.5 $0.0 2014 2015 2016 2017 18 Note: Comparative drilling curves based on one mile Bellatrix hybrid drilling style which constitutes technique employed for majority of wells drilled since 2014
Representative Spirit River Inventory Required to Maintain Production Volumes 40 Approximately 14 net Spirit River wells 1 per year maintains production in the mid 30 mboe/d range through 2020 Represents scenario of drilling of only 15% of net Spirit River well inventory 30 Production (mboe/d) 20 10 0 Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19 Jan-20 Jul-20 Base 2017 2018 2019 2020 2017 2018 2019 2020 Total Beginning net location inventory 381 367 353 339 381 Net locations drilled 14 14 14 14 56 Ending net location inventory 367 353 339 325 325 % drilled of total inventory 4% 4% 4% 4% 15% 19 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
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 GREATER FERRIER AREA STRATEGIC INFRASTRUCTURE BELLATRIX ALDER FLATS PLANT Bellatrix 25% owner and operator Keyera 70% owner O Chiese 5% owner Phase I - 110 MMcf/d inlet capacity (on-stream May 2015) Phase II - 120 MMcf/d inlet capacity (in service 2018, remaining BXE cost plus prepayment capital ~$25MM) C2 Recovery 57% C3 Recovery 99% C4+ Recovery 100% Strategic advantage from owned infrastructure lowered costs and guaranteed access 20
Drill Bit Focused PLANT INVESTMENT & CONSTRUCTION COMPLETE 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% ALLOCATION OF TOTAL CORPORATE E&D CAPITAL EXPENDITURES Plant Plant Plant Plant Plant DRILLING DRILLING DRILLING DRILLING DRILLING DRILLING 2014 2015 2016 2017E 2018E 2019E Land, G&G, and other capital BXE Alder Flats Plant Facilities & equipment (excluding BXE Plant) 1 Drilling & completion capital 21 1 Drilling and completion capital includes capitalized items Note: Capital expenditures and development plans beyond 2017 represent management estimates, as formal plans have not been approved. For representation purposes 2018 & 2019 capital investment levels assume similar capital spending levels as 2017 for each category, with assumed completion of Phase 2 of the Bellatrix Alder Flats Plant in H1/2018.
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 22 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
Compelling Investment Opportunity SUSTAINABILITY PROFITABILITY Excellent Organic Growth Potential Competitive Economics De-risked LONG TERM GROWTH Leading Well Results Technically Astute 23