ATHABASCA OIL CORPORATION

Transcription

1 ATHABASCA OIL CORPORATION FOCUSED EXECUTING DELIVERING MARCH 2019 CORPORATE UPDATE

2 ATHABASCA PREMIER RESOURCE EXPOSURE INTERMEDIATE OIL WEIGHTED PRODUCER ASSETS IN CANADA S TOP RESOURCE PLAYS o ~40,000 boe/d (~90% liquids) Hangingstone o ~10% corporate decline o Liquids rich shale at Greater Kaybob THERMAL OIL o 80,000 Montney acres (200 locations1) Corner o 200,000 Duvernay acres (1,000 locations1) o Oil sands in northeastern Alberta Leismer o 80,000 bbl/d of top quality projects CORPORATE HIGHLIGHTS (ATH TSX) Market Capitalization $516 MM Net Debt $292 MM Enterprise Value $808 MM Funding Capacity / Liquidity $550 / $468 MM Proved / P+P Reserves 450 / 1,300 MMBOE Tax Pools (total / NCL & CEE) $3 / $1.8 LIGHT OIL MONTNEY LIGHT OIL DUVERNAY Billion Footnotes and additional information included in the back as endnotes 1

3 ATHABASCA THE TRANSFORMATION PRODUCTION 85% DAPPS CAGR P RESERVES 75% DARPS CAGR CONTROLLABLE COST STRUCTURE 65% reduction in combined per boe costs NPV10 BT ($MM) $6,000 $5,000 $4,000 $3,000 $2,000 Proven Probable RESERVE VALUE (NPV10) Significant value growth across all reserve classifications NAVPS 2P $8.94 TP $4.50 PDP $1.28 $1,000 $ DAPPS debt adjusted production per share DARPS debt adjusted reserves per share NAPVPS = (2P NPV10 before tax less Q4/18 pro forma net debt) / basic shares Footnotes and additional information included in the back as endnotes 2

4 ATHABASCA DRIVE TO FREE CASH FLOW FINANCIAL RESILIENCY o Low sustaining capital to hold production o $95 $110MM in 2019 o Strong balance sheet o $468MM liquidity (cash & credit facilities) o High yield debt termed out until 2022 o Potential growth with improved commodity prices COMPLEMENTARY ASSETS o Thermal Oil: low corporate decline, free cash flow o 80 year 2P reserve life o Light Oil: high margin returns o Top tier netbacks ($26/boe 2019) o Funded growth through Duvernay JV o Flexible operated liquids rich Montney COMPELLING FREE CASH FLOW OPPORTUNITY o US$5 WTI = +C$80MM funds flow Optionality for returning sustainable FCF Growth, deleveraging and/or share buybacks $MM mboe/d FUNDS FLOW & FCF OUTLOOK Funds Flow (US$65 WTI & $17.50 WCS diff) Funds Flow (US$60) Funds Flow (US$55) Sustaining Capital Potential Growth Capital + $265MM Infrastructure Sale PRODUCTION Thermal Oil Light Oil Potential Growth Footnotes and additional information included in the back as endnotes 2019: budget details on slide 18; funds flow sensitivity includes Q1 strip pricing and flat pricing Q2 Q4 2020: funds flow sensitivity reflects growth scenario with balanced investment across Light & Thermal Oil 3

5 MARKET ACCESS AND RISK MANAGEMENT DIVERSIFIED PORTFOLIO MITIGATES RISK o Both business divisions contribute to the bottom line o $275MM 2019 operating income (40% LO & 60% TO) HEAVY OIL DIFFERENTIAL ENVIRONMENT o Mid term (Q2/ ): <US$20/bbl o Gov t curtailments (3.63mmbbl/d max AB production) o Crude by rail ramp up ( mbbl/d) o ENB mainline initiatives (~75mbbl/d) & L3R (370mbbl/d) o Tightness in the global heavy market o Long term (2022+): <US$15 o AOC has secured capacity on pipeline expansions o 25mbbl/d Keystone XL & 20mbbl/d TMX RISK MITIGATION o Financial hedges + direct refinery sales = synthetic rail contract o 40% dilbit hedged at US$20.50 WCS diff in 2019 o 40% direct sales to refineries in 2019 o Storage: 130mbbl secured at Edmonton mmbbl ALBERTA CRUDE INVENTORIES Range Average 2017 Athabasca 2019e inventory forecast Source: historical data from AER (2mo lagged) 40 Jan Apr Jul Oct CANADIAN CRUDE OIL BY RAIL Source: National Energy Board (2mo lagged) Footnotes and additional information included in the back as endnotes 4

6 ATHABASCA BEST IN CLASS FOR OIL EXPOSURE LIQUIDS WEIGHTED PORTFOLIO CASH FLOW & LEVERAGE SENSITIVITY o Athabasca a standout producer for oil exposure o ~90% liquids o Run rate annual unhedged funds flow sensitivity o ~C$80MM for US$5 WTI o ~C$45MM for US$2.50 WCS diff ATTRACTIVE VALUATION WITH LOW LEVERAGE Source: National Bank Initiation Report ( ) 2019 NBF Base: US$58 WTI & US$19.20 WCS diff Upside Case: US$63 WTI & US$19.20 WCS diff IMPLIED 2019 VALUATION (SHARE PRICE) o 2019 metrics (US$60 WTI & US$17.50 diff) o Current trading implies 3.7 EV/DACF & 1.7x D/CF o Significant share price upside with multiple compression o $65 WTI & $17.50 diff: 2.7x EV/DACF & 1.0x D/CF o $70 WTI & $17.50 diff: 2.1x EV/DACF & 0.6x D/CF Footnotes and additional information included in the back as endnotes 5

7 LIGHT OIL MONTNEY & DUVERNAY

8 PLACID MONTNEY HIGHLIGHTS AOC OPERATED 70%WI o 80,000 gross prospective acres o 48,000 high graded acres Pad 7 DUCS Future Pad PLACID DEVELOPMENT MAP o 200 well development inventory 1 o $20/boe 2019 operating netback (US$60 WTI) o bbl/mmcf initial free liquids o Operated strategic regional infrastructure o Secured egress through Pembina, Alliance and TCPL Wells Montney D Montney C ACTIVITY OVERVIEW o : 32 wells (7 pads) o 2018/19 Winter: tie in 6 wells & rig release 7 wells 10,000 7,500 PLACID PRODUCTION (NET) o H2/19: readiness to resume activity boe/d 5,000 2,500 Footnotes and additional information included in the back as endnotes 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q

9 PLACID MONTNEY STRONG ECONOMICS PRODUCTION PLOT INTERNAL TYPE WELL PARAMETERS Rate Sales Gas C5+ liquids boe/d mmcf/d bbl/d % IP30 1, % IP % IP % ~25 bbl/mmcf plant recovered NGLs included in IPs & EURs mboe bcf mbbl % EUR % Condensate Production (Mbbl) CUMULATIVE CONDENSATE PRODUCTION Gen 1 Gen 2 Gen 3 (facility restricted wells) Gen 3 (unrestricted wells) Internal Type Curve bbl/mmcf initial free liquids cuts (~60% liquids) Days INTERNAL TYPE WELL ECONOMICS US$WTI $55 $60 $65 Well Cost $MM ~$8MM drill & completed (2,750m hz) Payback months IRR BT % 35% 49% 64% NPV10 BT $MM $2.6 $3.8 $4.9 Netback $/boe $25.25 $28.25 $31.25 PDP F&D $/boe 11.8 $11.75 $11.75 Recycle Ratio x Cap Effcy (IP365) $/boed $12,985 $12,985 Flat pricing assumed in internal type well economics US$7.50 MSW diff, C$1.50 AECO, 0.75 FX 8

10 KAYBOB DUVERNAY JOINT VENTURE HIGHLIGHTS (30% WI) o Partnered with Murphy Oil in May 2016 o Cash/carry structure minimizes financial exposure $1B gross 4 yr program; $75MM net to retain 30%WI o Significant resource exposure o 2019 activity ~$280MM gross (~$20MM net) Continued volatile oil delineation with an initial emphasis on Two Creeks 200,000 acres and 1,000+ well inventory 1 DUVERNAY ACTIVITY OVERVIEW DUVERNAY RESULTS Volatile Oil Pad Wells IP30s (boe/d) liquids (%) 156,000 acres ~800 locations SIMONETTE O 2 E SAXON G KAYBOB WEST OIL R KAYBOB WEST GAS J D/ M A C B 1 2 I H 1 K N F KAYBOB EAST 2 2 Q 2 L P 1 TWO CREEKS Condensate Rich Gas 41,000 acres ~200 locations A ,040 73% B % C ,310 75% D * 100% E ** 71% F ,078 81% G ,320** 57% H ,178 57% I ** 83% J % K Intial Testing L * 100% M Exp % N % O Awaiting tie in P Completion Underway Q Completion Underway R Drilling Underway Pads on production Upcoming wells # Next phase of activity (# of wells per pad) Footnotes and additional information included in the back as endnotes * Facility constrained & gas flared ** Restricted rates Recent Well Results 9

11 DUVERNAY COMPETITIVE SHALE PLAY WHAT MAKES THE DUVERNAY COMPETITIVE o High liquids yields 200 1,000 bbl/mmcf initial yields (C5+) 40 55⁰ API condensate o Royalty advantage (5% for 3yr vs. ~25% US Shale Plays) o $34/boe 2019 operating netback (US$60 WTI) o C$8 10MM current development pad costs (D&C) KAYBOB WEST INTERNAL TYPE WELL ECONOMICS US$WTI $55 $60 $65 IP30/365 boe/d 950 (77% liquids) / 450 (69% liquids) EUR mboe ~650 (66% liquids) KAYBOB WEST OIL KAYBOB EAST Well Cost $MM ~$8.5MM drill & completed (2,800m hz) Payback months IRR BT % 42% 53% 65% NPV10 BT $MM $6.2 $7.7 $9.1 Netback $/boe $37.25 $41.50 $45.75 PDP F&D $/boe 13.5 $13.50 $13.50 Recycle Ratio x boe/d 1,200 1, KAYBOB WEST (21 WELLS) Days mbbl Flat pricing assumed in internal type well economics US$5 C5+ diff, C$1.50 AECO, 0.75 FX 10

12 LIGHT OIL NETBACK BENCHMARKING HIGHLIGHTS o Athabasca Light Oil boasts the top netback relative to its Montney/Duvernay peers (last 4 quarters) o Strong liquids weighting (>50%) o High quality product (condensate and light oil) o Low lifting costs (<$10/boe) OPERATING NETBACK BENCHMARKING* (Q3 2018) $/boe $35 $30 $25 $20 $ $26/boe $10 $5 $0 $31.95 $29.43 ATH LO $26.60 VII $21.53 NVA $20.93 $18.43 $15.26 $15.16 $15.14 $14.69 $13.03 $9.32 $8.64 $8.46 DEE KEL ARX CR POU CQE SRX BIR TOU PONY AAV Liquids Weighted Netback (>40% liquids) Gas Weighted Netback (>60% gas) Costs (Operating, Transportation, Royalties) Peer Median ~$15/boe * Excludes hedging gains/losses and third party processing income 11

13 THERMAL OIL LEISMER & HANGINGSTONE

14 THERMAL OIL ASSET OVERVIEW LEISMER TOP TIER OIL SANDS PROJECT o 20,000 22,000 bbl/d; ~3.5x SOR o 40,000 bbl/d AER approval Hangingstone 2015 project start up REGIONAL MAP o 675 mmbbl 2P reserves 1 ; 90 year 2P RLI o US$43 WTI breakeven* HANGINGSTONE o 9,000 10,000 bbl/d; ~4.5x SOR o 177 mmbbl 2P reserves 1 ; 55 year 2P RLI o US$53 breakeven* o Low near term sustaining capital CORNER LONG TERM DEVELOPMENT o Top tier lease with high quality reservoir o Delineation drilling completed o 40,000 bbl/d AER approval in place IPL Polaris Leismer 2010 project start up Corner 40,000 bbl/d regulatory approved future project Enbridge Cheecham Terminal Enbridge Waupisoo * Break evens reflect a US$17.50 WCS diff, US$5 C5 diff, C$1.50 AECO, 0.75 FX Footnotes and additional information included in the back as endnotes 13

15 THERMAL OIL LEISMER ACTIVITY L7 SUSTAINING PAD (~$40MM CAPITAL) o Rig released 5 well pairs in February o Encountered higher reservoir quality than predicted o Well pair design o 1,250m laterals (50% longer) & flow control equipped o Production anticipated Q4/19 o Steaming to commence this summer o 4,000 4,500 bbb/d peak pad production LEISMER DEVELOPMENT 1,500 1,250 1,000 LEISMER WELL PAIR PERFORMANCE Industry Average Industry Top Quartile Leismer (AOC) PAD L7 OVERVIEW PAD 1 PAD 2 PAD 7 High quality reservoir in all laterals Achieved flat trajectories & ~5m targeted separation bbl/d Month Source: McDaniel & Consultants Ltd. 14

16 THERMAL OIL OUTLOOK OPTIMIZATION INITIATIVES o Significant cost savings across Hangingstone & Leismer o ~$40MM in run rate annual savings from 2017 (non energy op. costs & Norlite diluent sourcing) o Savings more than offset ENB midstream toll ($26MM) CONTROLLABLE COSTS 2019 BUDGET ($80MM) o Leismer L7 sustaining pad (~$40MM) o Operations capital at both projects (~$40MM) o Pump changes & facility maintenance WELL PAIR COST PROGRESSION LONG TERM DEVELOPMENT o Minimal sustaining capital to maintain production o C$5 10/bbl annually (5 year range) o P Thermal Oil FDC reduced by ~$750MM or 6% Y/Y o Full field development optimized for longer laterals 15

17 SUPPLEMENTAL INFORMATION

18 CORPORATE SNAPSHOT & HEDGING CAPITALIZATION OVERVIEW (ATH TSX) Basic Shares Outstanding 516 MM Market Capitalization $516 MM Q4/18 Pro Forma Net Debt $292 MM Total Enterprise Value $808 MM Term Debt (9.875% due Feb 2022) US$450 MM Undrawn Reserve Based Facility $120 MM Funding Capacity / Liquidity $550 / $468 MM Tax Pools (total / NCL & CEE) $3 / $1.8 Billion Pro Forma Q4/18 Net debt = FV term debt + Current Liabilities Current Assets (excl. infrastructure deposit) Infrastructure Proceeds Funding capacity = cash & equivalents + available credit facilities + Duvernay capital carry. On closing of infrastructure transaction Jan. 15, 2019 Liquidity = cash & equivalents + available credit facilities. On closing of infrastructure transaction Jan. 15, Q Q Q Q WTI / WCS Differential Volume Price C$ Price US$ Volume Price C$ Price US$ Volume Price C$ Price US$ Volume Price C$ Price US$ Financial Swaps 16,300 (27.30) (20.53) 18,000 (27.01) (20.31) 15,000 (28.35) (21.31) 13,000 (28.46) (21.40) FX Forward August 2019 US$ 22.2 MM interest payment hedged at US/CAD rate US$ price converted at 1.33 US/CAD rate HEDGING OVERVIEW ( ) 17

19 2019 BUDGET OVERVIEW CORPORATE 2019 OUTLOOK ($60 WTI & $17.50 WCS DIFF) o Minimal capital: $95 $110MM o Maintain production: 37,500 40,000 boe/d (88% liquids) o Nimbleness to accelerate high return projects Interest, G&A, Hedging LIGHT OIL o Capital: $15 $30MM net o Production: 10,000 11,000 boe/d (55% liquids) o Montney: activity deferred until H2/19 o Duvernay: self funded through joint venture capital carry o ATH pays 7.5% to earn a 30%WI (~$280MM gross) THERMAL OIL o Capital: $80MM o Production: 27,500 29,000 bbl/d o Major projects: Leismer sustaining pad ($40MM) WCS Diff (US$) Funds Flow 2019 FUNDS FLOW SENSITIVITY ($MM) WTI (US$) $226 $55 $60 $65 $70 $75 $15.00 $130 $185 $240 $295 $340 $17.50 $110 $165 $220 $275 $330 $20.00 $85 $140 $200 $255 $305 $22.50 $65 $120 $175 $230 $285 $25.00 $40 $100 $155 $210 $265 Q1 2019: strip pricing, flat pricing assumptions thereafter Q2 Q4 2019: US17.50 WCS diff, US$10 MSW diff, US$5 C5 diff, C$1.50 AECO, 0.75 FX Includes corporate hedges outlined on slide 17 Note: The Government mandated curtailments are estimated to have up to a 2,000 bbl/d impact on Thermal Oil productive capacity through Q which equates to 500 bbl/d on an annualized basis. The Company s annual production guidance only incorporates the mandated cuts through Q

20 LEISMER INFRASTRUCTURE TRANSACTION STRATEGIC TRANSACTION WITH ENBRIDGE o $265MM cash consideration o 30 year term with an annual toll of ~$26MM o Priority service on pipelines & dilbit/diluent tanks (2x 150mbbl) o Excess volumes above firm commitments receive a discounted toll o Enhanced credit terms with Enbridge across our Thermal Oil business Unlocking Value Proceeds ~50% of market cap Bolstered Liquidity ~$550MM funding capacity Competitive Break evens US$43 US$17.50 WCS diff Recouped Leismer acquisition cash consideration ($435MM) within two years through free cash flow, contingent bitumen royalty and infrastructure proceeds (combined ~$500MM) 19

21 THERMAL OIL INFRASTRUCTURE Illustrative map not to scale HANGINGSTONE CHEECHAM Tank Farms 8 Diluent Line 12 Dilbit Line LEISMER 40mbbl Dilbit 6mbbl Diluent 150mbbl Dilbit 150mbbl Diluent 100mbbl Dilbit 10mbbl Diluent IPL Polaris Diluent Enbridge Waupisoo Dilbit take away Enbridge Norlite Diluent supply Egress optionality Keyera South Cheecham Truck & Rail Terminal Enbridge Athabasca EDMONTON HARDISTY INTERNATIONAL MARKET Kinder Morgan Terminal TMX 20,000 bbl/d Enbridge Terminal Shell leased storage 130mbbl Enbridge Mainline Keystone XL 25,000 bbl/d US MARKET 20

22 DUVERNAY KAYBOB REGIONAL OVERVIEW DUVERNAY HIGHLIGHTS (30% WI) o 200,000 gross acres; ~1,000 potential locations 1 (mgmt est) o Exposure to liquids rich & volatile oil fairways (200 1,000 bbl/mmcf) o Supermajors remain active mboe/d KAYBOB DUVERNAY PRODUCTION* GREATER KAYBOB MAP Raw Gas Liquids DUVERNAY INDUSTRY ACTIVITY Industry remains active ~675 spuds since 2014 ~125 spuds within 1 year Wells (#) Athabasca JV Wells Drilled within last year Athabasca Drilled Chevron licensed Encana Paramount Repsol Footnotes and additional information included in the back as endnotes * Generated from public AER data with internal estimates for liquids mapping on single stream reporting Shell XTO Cumulative Licenses Cumulative Spuds Cumulative Wells on Production

23 LIGHT OIL INFRASTRUCTURE Gas Pipeline (gross) Up to Gas Capacity 180 MMcf/d Dually connected to regional gas plants Flexibility with takeaway options; scalable for future growth Kaybob East AOC 91 km Pipeline Keyera Simonette Saxon Kaybob West Fort McMurray SemCAMS KA AOC owns and operates regional midstream infrastructure Placid Total Battery Capacity (gross) Oil Capacity 36,000 bbl/d Gas Capacity 154 MMcf/d, expandable to >169 MMcf/d Condensate connected to Pembina s Peace Pipeline EDMONTON Comments Gas (mmcf/d) Alliance Chicago & Alberta ATP sales point TCPL AECO sales point Liquids (bbl/d) Pembina Cond. / Oil 6,000 6,000 Saxon, Placid, Kaybob West & East egress Pembina NGL 1,000 1,000 NGL egress from Keyera Simonette plant CALGARY Gas pipelines (TCPL/Alliance) Oil pipelines (Pembina) Diluent pipelines (Inter Pipeline) 22

24 MANAGEMENT TEAM AND BOARD MANAGEMENT TEAM Robert Broen, P.Eng. President & Chief Executive Officer Kim Anderson, CA Chief Financial Officer Angela Avery General Counsel & VP Business Development Karla Ingoldsby, P. Eng. VP Thermal Oil Dave Stewart VP Operations Matt Taylor, CFA VP Capital Markets & Communications BOARD OF DIRECTORS Ronald Eckhardt Chair of the Board, member of the Reserves Committee Robert Broen, P.Eng. President & Chief Executive Officer Bryan Begley Chair of the Compensation & Governance Committee and member of the Reserves Committee Anne Downey, P. Eng. Chair of the Reserves Committee Thomas Ebbern Member of the Compensation & Governance Committee and member of the Audit Committee Carlos Fierro Member of the Compensation & Governance Committee and member of the Audit Committee Marshall McRae, CA Chair of the Audit Committee 23

25 ENDNOTES & RISK MANAGEMENT Slide Endnotes Multi year outlook price assumptions: 2018 Q Q2-Q e 2020e WTI US$/bbl $65.50 $53.58 $60.00 $58.40 $60.00 FX C$/US$ Heavy Diff US$/bbl -$ $ $ $ $17.50 WCS C$/bbl $50.61 $54.44 $56.67 $56.11 $56.67 MSW Diff US$/bbl -$ $5.87 -$ $8.97 -$10.00 MSW (Ed. Par. Light Oil) C$/bbl $70.27 $61.04 $66.67 $65.26 $66.67 C5 Diff US$/bbl -$4.17 -$4.47 -$5.00 -$4.85 -$5.00 Condensate C$/bbl $79.34 $64.60 $73.33 $71.15 $73.33 AECO C$/mcf $1.48 $1.77 $1.50 $1.57 $ (1) Consolidated reserves as at December 31, 2018 evaluated by McDaniel & Associates Consultants Ltd. (2) Pro Forma Q4/18 Net debt = FV term debt + Current Liabilities Current Assets (excl. infrastructure deposit) Infrastructure Proceeds (3) Funding capacity = cash & equivalents + available credit facilities + Duvernay capital carry. On closing of the infrastructure sale Jan. 15, 2019 (4) Liquidity = cash & equivalents + available credit facilities. On closing of the infrastructure sale Jan. 15, (1) corporate reserves evaluated by GLJ Petroleum Consultants and DeGolyer and MacNaughton Canada Limited (2) corporate reserves evaluated by McDaniel & Associates Consultants Ltd. (3) Reserve value NPV10 before tax (4) For additional information regarding Athabasca s reserves and resources estimates, please see Independent Reserve and Resource Evaluations in the Company s 2018 Annual Information Form which is available on Company s website or on SEDAR 3/13 (1) Thermal Oil reserve life index calculated on 852mmboe 2P reserves (Leismer & Hangingstone) and 29,000 bbl/d production (2) Thermal Oil McDaniel & Associates Consultants Ltd. reserve evaluation as at December 31, 2018 (675mmboe Leismer, 177mmboe Hangingstone, 353mmboe Corner) 1/3/7/9/ 21 (1) Gross Montney inventory based on management estimate of 4 wells per section Gross Duvernay acres and inventories. Well inventory based on management estimate of 4 6 wells per section See reader advisory Drilling Locations for more detail 24

26 READER ADVISORY Forward Looking Statements This Presentation contains forward looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward looking information. The use of any of the words anticipate, plan, continue, estimate, expect, may, will, project, believe, contemplate, target, potential and similar expressions are intended to identify forward looking information. The forward looking information is not historical fact, but rather is based on the Company s current plans, objectives, goals, strategies, estimates, assumptions and projections about the Company s industry, business and future operating and financial results. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward looking information. No assurance can be given that these expectations will prove to be correct and such forward looking information included in this Presentation should not be unduly relied upon. This information speaks only as of the date of this Presentation. In particular, this Presentation contains forward looking information pertaining to, but not limited to, the following: the Company s 2019 guidance and multiyear outlook; type well economic metrics; estimated recovery factors and reserve life index; and other matters. Information relating to "reserves" is also deemed to be forward looking information, as it involves the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. With respect to forward looking information contained in this Presentation, assumptions have been made regarding, among other things: commodity outlook; the regulatory framework in the jurisdictions in which the Company conducts business; the Company s financial and operational flexibility; the Company s, capital expenditure outlook, financial sustainability and ability to access sources of funding; geological and engineering estimates in respect of Athabasca s reserves and resources; and other matters. Actual results could differ materially from those anticipated in this forward looking information as a result of the risk factors set forth in the Company s Annual Information Form ( AIF ) dated March 6, 2019 that is available on SEDAR at including, but not limited to: fluctuations in commodity prices, foreign exchange and interest rates; political and general economic, market and business conditions in Alberta, Canada, the United States and globally; changes to royalty and tax regimes, environmental risks and hazards; the potential for management estimates, assumptions and regulatory interpretations to be inaccurate; the dependence on Murphy as the operator of the Company s Duvernay assets; the capital requirements of Athabasca s projects and the ability to obtain financing; operational and business interruption risks; failure by counterparties to make payments or perform their operational or other obligations to Athabasca in compliance with the terms of contractual arrangements; aboriginal claims; failure to obtain regulatory approvals or maintain compliance with regulatory requirements; uncertainties inherent in estimating quantities of reserves and resources; litigation risk; environmental risks and hazards; reliance on third party infrastructure; hedging risks; insurance risks; claims made in respect of Athabasca s operations, properties or assets; risks related to Athabasca s amended credit facilities and senior secured notes; and risks related to Athabasca s common shares. For important additional information regarding Athabasca s reserves and resources estimates and the evaluations that were conducted by McDaniel & Associates, please see Independent Reserve and Resource Evaluations in the Company s most recent AIF. The forward looking statements included in this presentation are expressly qualified by this cautionary statement. The forward looking statements contained herein are made as of the date hereof and Athabasca does not undertake any obligation to publicly update or revise any forward looking statements except as required by applicable securities laws. Drilling Locations: The 1,000 Duvernay drilling locations referenced include: 50 proved undeveloped or non producing locations and 35 probable undeveloped locations for a total of 85 booked locations with the balance being unbooked locations. The 200 Montney drilling locations include: 77 proved undeveloped locations and 12 probable undeveloped locations for a total of 89 booked locations with the balance being unbooked locations. Proved undeveloped locations and probable undeveloped locations are booked and derived from the Company's most recent independent reserves evaluation as prepared by McDaniel as of December 31, 2018 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal management estimates. Unbooked locations do not have attributed reserves or resources (including contingent or prospective). Unbooked locations have been identified by management as an estimation of Athabasca s multi year drilling activities expected to occur over the next two decades based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company 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 the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, oil and natural gas prices, provincial fiscal and royalty policies, costs, actual drilling results, additional reservoir information that is obtained and other factors. Additional Oil and Gas Information: BOEs 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. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil 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. Test Results and Initial Production Rates: The well test results and initial production rates provided in this presentation should be considered to be preliminary, except as otherwise indicated. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery. Non GAAP Financial Measures: The "Adjusted Funds Flow, "Light Oil Operating Income", Light Oil Operating Netback, Light Oil Capital Expenditures Net of Capital Carry, "Thermal Oil Operating Income (Loss)", "Thermal Oil Operating Netback", Consolidated Operating Income, Consolidated Operating Netback, Consolidated Capital Expenditures Net of Capital Carry and Net Debt financial measures contained in this Presentation do not have standardized meanings which are prescribed by IFRS and they are considered to be non GAAP measures. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation with measures that are prepared in accordance with IFRS. Complete definitions are outlined in the Company s Q4 MD&A and financials available on SEDAR ( or the Company s website ( 25