ATHABASCA OIL CORPORATION

Transcription

1 ATHABASCA OIL CORPORATION FOCUSED EXECUTING DELIVERING DECEMBER 218 CORPORATE UPDATE

2 ATHABASCA PREMIER RESOURCE EXPOSURE INTERMEDIATE OIL WEIGHTED PRODUCER o ~4, boe/d (~9% liquids) ASSETS IN CANADA S TOP RESOURCE PLAYS Hangingstone o ~1% corporate decline o Liquids rich shale at Greater Kaybob o 8, Montney acres Corner o 2, Duvernay acres Leismer o Oil sands in northeastern Alberta o 8, bbl/d of top quality projects CORPORATE HIGHLIGHTS (ATH TSX) Market Capitalization $578 MM Q3/18 Net Debt $372 MM Enterprise Value $95 MM 2P Reserves 1,25 MMBOE Tax Pools (total / NCL & CEE) $3.1 / $1.9 Billion Footnotes and additional information included in the back as endnotes 1

3 LEISMER INFRASTRUCTURE TRANSACTION STRATEGIC TRANSACTION WITH ENBRIDGE o $265MM cash consideration o 3 year term with an annual toll of ~$26MM o Priority service on pipelines & dilbit/diluent tanks (2x 15mbbl) o Excess volumes above firm commitments receive a discounted toll o Enhanced credit terms with Enbridge across our Thermal Oil business Unlocking Value Proceeds ~5% of market cap Bolstered Liquidity ~$525MM funding capacity Competitive Break evens US$43 WTI US$18 WCS diff Recouped Leismer acquisition cash consideration ($435MM) within two years through free cash flow, contingent bitumen royalty and infrastructure proceeds (combined ~$5MM) Q4/18e funding capacity pro forma infrastructure sale. Includes: cash, available credit facilities & Duvernay capital carry. 2

4 ATHABASCA STRATEGIC OUTLOOK A BALANCED PORTFOLIO o Thermal Oil: long life low decline assets o 8 year 2P reserve life o Light Oil: high margin growth o Top netbacks in peer group ($32/boe Q3/18) o Low maintenance capital o $95 $11MM to maintain base production o Low risk and high quality expansion projects o 2 Montney & 1, Duvernay well inventory 1 o 8, bbl/d regulatory approved Thermal projects RESILIENT BUSINESS MODEL o Flexible and disciplined capital allocation o No land expiries; Duvernay JV capital carry o Strong balance sheet o >$525MM funding capacity o Unparalleled exposure to oil price o $US5 WTI = $8MM funds flow mboe/d $MM $4 $3 $2 $1 $ Thermal Oil Light Oil Capex Funds Flow PRODUCTION 38, 4,* * Does not reflect Government of Alberta mandated short term production curtailments Proportional share estimated at 1,5 2, bbl/d in Q1 219 FUNDS FLOW & CAPITAL + $265MM Infrastructure Sale $95 $11MM Prelim Budget Footnotes and additional information included in the back as endnotes 219: US$65 WTI, US$2 WCS diff, US$1 MSW diff, US$7.5 C5 diff, C$1.5 AECO,.75 FX 22/21: US$65 WTI, US$18 WCS diff, US$7.5 MSW diff, US$5. C5 diff, C$1.5 AECO,.75 FX 3

5 219 PRELIMINARY OUTLOOK CORPORATE* 219 OUTLOOK (US$65 WTI & US$2 WCS DIFF) o Minimal capital: $95 $11MM o Maintain production: 37,5 4, boe/d (88% liquids) o Nimbleness to accelerate high return projects 4 3 Op. Income ($MM) Capex ($MM) Production (mboe/d) Interest & G&A $3 $25 $2 LIGHT OIL o Capital: $15 $3MM net mboe/d 2 Funds Flow $15 $1 $MM o Production: 1, 11, boe/d (55% liquids) 1 $5 o Montney: activity deferred until H2/19 o Duvernay: self funded through joint venture capital carry Light Oil Thermal Oil Corporate $ o ATH pays 7.5% to earn a 3%WI ($2 $375MM gross) THERMAL OIL o Capital: $8MM o Production: 27,5 29, bbl/d* o Major projects: Leismer sustaining pad ($4MM) WCS Diff (US$) 219 FUNDS FLOW SENSITIVITY ($MM) WTI (US$) $226 $55 $6 $65 $7 $75 $8 $15. $15 $225 $3 $37 $43 $495 $17.5 $11 $19 $26 $335 $45 $465 $2. $75 $15 $225 $3 $37 $43 $22.5 $4 $115 $19 $265 $335 $41 $25. $ $75 $155 $225 $3 $375 Other assumptions: US$1 MSW diff, US$7.5 C5 diff, C$1.5 AECO,.75 FX * Production guidance does not reflect Government of Alberta mandated short term production curtailments. Proportional share estimated at 1,5 2, bbl/d through Q1 219 Corporate capital excludes ~$1MM of capitalized G&A 4

6 MARKET ACCESS AND RISK MANAGEMENT DIVERSIFIED PORTFOLIO MITIGATES RISK o Both business divisions contribute to the bottom line o ~$315MM 219e operating income (4% LO & 6% TO) HEAVY OIL DIFFERENTIAL ENVIRONMENT o Short term (H1/19): US$18 24/bbl o Gov t mandated industry curtailments (325mbbl/d) o Crude by rail ramp up (~4mbbl/d*) o Mid term (H2/19 221): <US$2/bbl o Inventories rebalance to normal operating levels o ENB Line 3 Replacement (~375mbbl/d) o Long term (222+): <US$15 o AOC has secured capacity on pipeline expansions o 25mbbl/d Keystone XL & 2mbbl/d TMX RISK MITIGATION o Apportionment protection: 4% direct sales to refineries in 219 o Hedging: 55% Q1/19 Thermal Oil at US$21 WCS diff** o Storage: 13mbbl secured at Edmonton mmbbl mbbl/d yr Range 218 5yr Average 217 Forecast Source: NBF Commodities & AER 4 Jan Apr Jul Oct CANADIAN CRUDE OIL EXPORTS BY RAIL 5 ALBERTA CRUDE INVENTORIES 5yr Range 218 5yr Average 217 NBF forecasts inventories to rebalance to normal operating levels by spring 219 Source: National Energy Board & Genscape Jan Apr Jul Oct Genscape 283mbbl/d October * Street research ** Hedge details provided on Slide 2 5

7 LIGHT OIL MONTNEY & DUVERNAY

8 PLACID MONTNEY HIGHLIGHTS AOC OPERATED 7%WI o 8, gross prospective acres o 48, high graded acres o 2 well development inventory 1 o Operated strategic regional infrastructure Pad On stream 16 3 Pad Rig Released Future Pad PLACID DEVELOPMENT MAP o Secured egress through Pembina, Alliance and TCPL o 1, bbl/d & 5 mmcf/d capacity o $23/boe 219 operating netback ACTIVITY OVERVIEW o 216/17 Winter: 2 wells (5 pads) 1, PLACID PRODUCTION (NET) o 217/18 Winter: 12 wells (2 pads) o H2/18 Fall o Tie in of multi well pad (6 wells) o Rig release multi well pad (7 wells) boe/d 7,5 5, 2,5 o H2/19: readiness to resume activity Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4e Footnotes and additional information included in the back as endnotes 7

9 PLACID MONTNEY STRONG ECONOMICS boe/d 1,2 1, PRODUCTION PLOT Gen 1 Gen 2 Gen 3 (facility restricted wells) Gen 3 (recent unrestricted wells) Internal Type Curve INTERNAL TYPE WELL PARAMETERS Rate Sales Gas C5+ liquids boe/d mmcf/d bbl/d % IP3 1, % IP % IP % mboe bcf mbbl % EUR % Condensate Production (Mbbl) Days CUMULATIVE CONDENSATE PRODUCTION Gen 1 Gen 2 Gen 3 (facility restricted wells) Gen 3 (recent unrestricted wells) Internal Type Curve 2 3 bbl/mmcf initial free liquids cuts (~6% liquids) Days ~25 bbl/mmcf plant recovered NGLs included in IPs & EURs INTERNAL TYPE WELL ECONOMICS US$WTI $6 $65 $7 Well Cost $MM ~$8MM drill & completed (2,75m hz) Payback months IRR BT % 49% 64% 81% NPV1 BT $MM $3.8 $4.9 $6. Netback $/boe $28.25 $31.25 $34.25 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$7.5 MSW diff, C$1.5 AECO,.75 FX 8

10 KAYBOB DUVERNAY JOINT VENTURE HIGHLIGHTS (3% WI) o Partnered with Murphy Oil in May 216 o Cash/carry structure minimizes financial exposure $1B gross 4 yr program; $75MM net to retain 3%WI o Significant resource exposure o 219 preliminary activity $2 $375MM gross ($15 $3MM net) Continued volatile oil delineation with an initial emphasis on Two Creeks 2, acres and 1,+ well inventory 1 DUVERNAY ACTIVITY OVERVIEW DUVERNAY RESULTS Volatile Oil 156, acres ~8 locations SIMONETTE P E SAXON R G KAYBOB WEST OIL J D/ M A C B KAYBOB WEST GAS I H K O F KAYBOB EAST N L Q TWO CREEKS Condensate Rich Gas 41, acres ~2 locations IP3s (boe/d) liquids (%) Pad Wells A ,4 73% B % C ,31 75% D * 1% E ** 71% F ,78 81% G ,32** 57% H ,178 57% I ** 83% J December On Stream K Rig Released L December On Stream M Exp % N O % P Completions Underway Q Q1/19e Spud R Footnotes and additional information included in the back as endnotes *Facility constrained & gas flared ** Restricted rates 9

11 DUVERNAY COMPETITIVE SHALE PLAY WHAT MAKES THE DUVERNAY COMPETITIVE o High liquids yields 2 1, bbl/mmcf initial yields (C5+) 4 55⁰ API condensate o Royalty advantage (5% for 3yr vs. ~25% US Shale Plays) o $38/boe 219 operating netback o C$8 1MM current development pad costs (D&C) KAYBOB WEST INTERNAL TYPE WELL ECONOMICS US$WTI $6 $65 $7 IP3/365 boe/d 95 (77% liquids) / 45 (69% liquids) EUR mboe ~65 (66% liquids) Well Cost $MM ~$8.5MM drill & completed (2,8m hz) Payback months IRR BT % 53% 65% 78% NPV1 BT $MM $7.7 $9.1 $1.5 Netback $/boe $41.5 $45.75 $5. PDP F&D $/boe 13.5 $13.5 $13.5 Recycle Ratio x Flat pricing assumed in internal type well economics US$5. C5+ diff, C$1.5 AECO,.75 FX boe/d boe/d boe/d 2, 1,6 1, , 1,6 1, ,2 1, SAXON (3 WELLS) 4 Production (boe/d) Cumulative Liquids (mbbl) Days KAYBOB WEST OIL KAYBOB EAST (4 WELLS) KAYBOB WEST OIL (3 WELLS) 2 KAYBOB EAST Days KAYBOB WEST (17 WELLS) Days mbbl mbbl mbbl 1

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 (>5%) o High quality product (condensate and light oil) o Low lifting costs (<$1/boe) OPERATING NETBACK BENCHMARKING* (Q3 218) $35 $3 Liquids Weighted Netback (>4% liquids) Gas Weighted Netback (>6% gas) Costs (Operating, Transportation, Royalties) $25 $2 $15 $1 $5 $ $31.95 ATH LO $29.43 VII $26.6 NVA $21.53 DEE $2.93 KEL $18.43 $15.26 $15.16 $15.14 $14.69 $13.3 $9.32 $8.64 $8.46 ARX CR POU CQE SRX BIR TOU PONY AAV $/boe Q3 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 2, 22, bbl/d; ~3.5x SOR o 4, bbl/d AER approval Hangingstone 215 project start up REGIONAL MAP o 66 mmbbl 2P reserves 1 ; 85 year 2P RLI o US$43 WTI breakeven* HANGINGSTONE o 9, 1, bbl/d; ~4.5x SOR o 18 mmbbl 2P reserves 1 ; 45 year 2P RLI 5km 16 Dilbit Line 15mbbl Dilbit Tank 15mbbl Diluent Tank Cheecham Terminal o US$53 breakeven* o Low near term sustaining capital CORNER LONG TERM DEVELOPMENT IPL Polaris Corner 4, bbl/d regulatory approved future project 75km 12 Dilbit Line 8 Diluent Line Norlite Diluent 218 o Top tier lease with high quality reservoir o 4, bbl/d AER approval in place Leismer 21 project start up Enbridge Waupisoo * Break evens reflect mid term US$18 WCS differential assumption Footnotes and additional information included in the back as endnotes 13

15 THERMAL OIL ACTIVITY OVERVIEW OPTIMIZATION INITIATIVES o Record low non energy op. costs in Q3/18 o 25% reduction Y/Y o Leismer $6.69/bbl & Hangingstone $12.2/bbl o Norlite diluent tie in (~$2MM annual savings) o Maintained production with minimal capital o Tie in of predrilled infills o Flow control devices & gas co injection LEISMER LEASE LEISMER PAD OVERVIEW 219 BUDGET ($8MM) o Leismer L7 sustaining pad (~$4MM capital) o Drilling underway; H2/19 on stream o 1,25m laterals (5% longer) & FCD equipped o 4, 4,5 bbb/d peak pad production 1,5 1,25 1, LEISMER WELL PAIR PERFORMANCE Industry Average Industry Top Quartile Leismer (AOC) LONG TERM DEVELOPMENT o Minimal sustaining capital for Thermal assets o C$5 1/bbl annually (5 year range) bbl/d Month Source: McDaniel & Consultants Ltd. 14

16 SUPPLEMENTAL INFORMATION

17 CORPORATE SNAPSHOT CAPITALIZATION OVERVIEW (ATH TSX) Basic Shares Outstanding 516 MM Market $1.12/sh $578 MM Q3/18 Net Debt $372 MM Total Enterprise Value $95 MM Term Debt (9.875% due Feb 222) US$45 MM Undrawn Reserve Based Facility $12 MM Pro Forma Funding Capacity Q4/18e >$525 MM Tax Pools (total / NCL & CEE) $3.1 / $1.9 Billion 218/19 GUIDANCE 217a 218e 219e Liquids Production boe/d 35,421 39, 41, 37,5 4, 88% Light Oil boe/d 7,535 1,5 11,5 1, 11, 55% Thermal Oil bbl/d 27,886 28,5 29,5 27,5 29, 1% Capital $MM $213 $19 $95 $11 Light Oil $MM $154 $15 $15 $3 Thermal Oil $MM $57 $85 $8 Adj. Funds Flow $MM $12 ~$2 ~$225 Operating Income $MM $18 ~$13 ~$315 Net debt: FV debt less WC surplus (adj. for hedging G/L). Funding capacity: cash & equivalents, available credit facilities & Duvernay capital carry. Funding capacity pro forma infrastructure sale. 218/19 capital excludes capitalized G&A. 219 commodity assumptions: US$65 WTI, US$2 WCS diff, US$1 MSW diff, US$7.5 C5 diff, C$1.5 AECO,.75 FX 16

18 DUVERNAY KAYBOB REGIONAL OVERVIEW KAYBOB DUVERNAY PRODUCTION* DUVERNAY HIGHLIGHTS (3% WI) 12 o 2, gross acres; ~1, potential locations1 (mgmt est) 1 mboe/d o Exposure to liquids rich & volatile oil fairways (2 1, bbl/mmcf) o Supermajors remain active GREATER KAYBOB MAP Raw Gas 2 Liquids DUVERNAY INDUSTRY ACTIVITY Licensing remains active 65+ industry spuds since Wells (#) Cumulative Licenses Cumulative Spuds Cumulative Wells on Production 1 ATH JV Wells 214 Athabasca Chevron Encana Paramount Shell Repsol XTO 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 17

19 LIGHT OIL INFRASTRUCTURE Gas Pipeline (gross) Up to Gas Capacity 18 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, 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, 6, Saxon, Placid, Kaybob West & East egress Pembina NGL 1, 1, NGL egress from Keyera Simonette plant CALGARY Gas pipelines (TCPL/Alliance) Oil pipelines (Pembina) Diluent pipelines (Inter Pipeline) 18

20 THERMAL OIL INFRASTRUCTURE Illustrative map not to scale HANGINGSTONE CHEECHAM Tank Farms 8 Diluent Line 12 Dilbit Line LEISMER 4mbbl Dilbit 6mbbl Diluent 15mbbl Dilbit 15mbbl Diluent 1mbbl Dilbit 1mbbl 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 2, bbl/d Enbridge Terminal Shell leased storage 13mbbl Enbridge Mainline Keystone XL 25, bbl/d US MARKET 19

21 RISK MANAGEMENT HEDGE POSITIONS 218 Q4 218 WTI / WCS Differential Volume Price C$ Price US$ Financial Swaps 3, (17.72) (13.32) WTI Collars 4, Q1 219 Q2 219 Q3 219 Q4 219 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 15,267 (27.96) (21.2) 7, (3.6) (22.6) 7, (3.6) (22.6) 7, (3.6) (22.6) FX Forward February 219 US$ 22.2 MM interest payment hedged at US/CAD rate US$ price converted at 1.33 US/CAD rate 2

22 MANAGEMENT TEAM AND BOARD MANAGEMENT TEAM Robert Broen, P.Eng. President & Chief Executive Officer Kim Anderson, CA Chief Financial Officer Angela Avery VP, General Counsel & 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 and member of the Audit 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 Carlos Fierro Member of the Compensation & Governance Committee and member of the Audit Committee Marshall McRae, CA Chair of the Audit Committee 21

23 ENDNOTES Slide Endnotes Multi year outlook price assumptions: 218e 219e 22e 221e WTI US$/bbl $65.5 $65. $65. $65. FX C$/US$ Heavy Diff US$/bbl -$ $2. -$18. -$18. WCS C$/bbl $5.61 $6. $62.67 $62.67 MSW Diff US$/bbl -$ $1. -$7.5 -$7.5 MSW (Ed. Par. Light Oil) C$/bbl $7.27 $73.33 $76.67 $76.67 C5 Diff US$/bbl -$4.17 -$7.5 -$5. -$5. Condensate C$/bbl $79.34 $76.67 $8. $8. AECO C$/mcf $1.48 $1.5 $1.5 $1.5 1 (1) Consolidated reserves as at December 31, 217 1/7 (1) Gross Montney inventory based on management estimate of 4 wells per section; see reader advisory Drilling Locations for more detail 1/9/17 (1) 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 13 (1) 1,169mmboe consolidated 2P thermal oil reserves. McDaniel & Associates Consultants Ltd. reserve evaluation as at December 31, 217 (988mmboe 2P reserves at Leismer and Corner; 181mmbboe 2P reserves at Hangingstone) 22

24 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 218/19 guidance and multi year 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 7, 218 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, Duvernay drilling locations referenced in this presentation include: 64 proved undeveloped or non producing locations and 35 probable undeveloped locations for a total of 99 undeveloped booked locations with the balance being unbooked locations. The 2 Montney drilling locations referenced include: 84 proved undeveloped 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, 217 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 and 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 Q3 MD&A and financials available on SEDAR ( or the Company s website ( 23