TD Securities Duvernay Overview October 8, 2013
Forward-Looking Statement 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, should, believe, predict, pursue and 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 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 forwardlooking 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 may contain forward-looking information pertaining to the following: the Company s capital expenditure programs; the estimated quantity of the Company s Proved Reserves, Probable Reserves and Contingent Resources; the Company s drilling plans, including the number of rigs that will be operated; the expected quality of oil that will be produced from certain of the Company s Light Oil assets, the Company s plans for, and results of, exploration and development activities; the Company s estimated future commitments; business plans, including the participation by the Company in joint ventures; development of the Company s Thermal Oil projects; timing of facilities construction, project start-up and production; estimated production capability and long term production goals; estimated timing of first steaming; estimated initial and full production potential of the Company s projects; Athabasca s plans with respect to the Light Oil assets and the expected benefits to be received by Athabasca from such assets; and expectations regarding the Company s Light Oil development areas including anticipated production levels and timing of receipt of significant revenues and operating results therefrom. With respect to forward-looking information contained in this presentation, assumptions have been made regarding, among other things: the Company s ability to successfully complete a joint venture involving either of its Light Oil assets or Thermal Oil assets; the Company s ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts and will conduct its business; the applicability of technologies for the recovery and production of the Company s reserves and resources; future capital expenditures to be made by the Company; future sources of funding for the Company s capital programs; the Company s future debt levels; geological and engineering estimates in respect of the Company s reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities; the impact that the agreements relating to the PetroChina Transaction (the PetroChina Transaction Agreements ) will have on the Company, including on the Company s financial condition and results of operations; and the Company s ability to obtain financing on acceptable terms. 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 most recent Annual Information Form filed on March 28, 2013 ( AIF ) that is available on SEDAR at www.sedar.com, including, but not limited to: fluctuations in market prices for crude oil and natural gas; general economic, market and business conditions; dependence on Phoenix Energy Holdings Limited ( Phoenix ) as the joint venture participant in the Dover oil sands projects; variations in foreign exchange and interest rates; factors affecting potential profitability; factors affecting funding, including the development of new business opportunities, the availability of financing, developments in technology, the priorities of the Company and of its current and future joint venture partners and general economic conditions; risk of reassessments of the Company's tax filings by taxation authorities; failure to satisfy certain conditions in connection with the Company s debt and credit facilities; the potential impact of the exercise of the Dover put/call options on the Company; failure to meet the conditions precedent to the exercise by the Company of the Dover put option, including failure to obtain necessary regulatory approvals for completion of the Dover put/call option transaction in 2013 or at all; failure to meet the conditions precedent to the closing of a Dover put/call option transaction in 2013 or at all; failure to meet development schedules and potential cost overruns; increases in operating costs making projects uneconomic; the potential for adverse consequences in the event that the Company defaults under certain of the PetroChina Transaction Agreements; the potential that counterparties to agreements with the Company default, including the potential for a counterparty to the PetroChina Transaction Agreements to default; environmental risks and hazards and the cost of compliance with environmental regulations; failure to obtain or retain key personnel; the substantial capital requirements of the Company s projects; the need to obtain regulatory approvals and maintain compliance with regulatory requirements; changes to royalty regimes; failure to accurately estimate abandonment and reclamation costs; risks inherent in the Company s operations, including those related to exploration, development and production of crude oil and natural gas reserves and resources, and the production of crude oil and natural gas using multi-stage fracture and other stimulation technologies; the potential for management estimates and assumptions to be inaccurate; reliance on third party infrastructure for project facilities; failure by counterparties (including without limitation Phoenix) to comply with contractual arrangements between the Company and such counterparties; the potential lack of available drilling equipment and limitations on access to the Company s assets; Aboriginal claims; seasonality; hedging risks; insurance risks; claims made in respect of the Company s operations, properties or assets; the potential for adverse consequences as a result of the change of control provisions in the PetroChina Transaction Agreements; competition for, among other things, capital, export pipeline capacity and skilled personnel; the failure of the Company or the holder of certain licenses or leases to meet specific requirements of such licenses or leases; risk of reassessments of the Company's tax filings by taxation authorities; the risk of having to post security to maintain an objection against any possible tax reassessment; risks arising from future acquisition and joint venture activities; risk of failing to complete a joint venture arrangement; and risks that joint venture arrangements will not perform as expected. In addition, information and statements in this presentation relating to reserves and resources are deemed to be forward-looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and that the reserves and resources described can be profitably produced in the future. The assumptions relating to the Company s reserves and resources are contained in the reports of GLJ Petroleum Consultants Ltd. and DeGolyer and MacNaughton Canada Limited, each dated effective December 31, 2012.. For additional information regarding the specific contingencies which prevent the classification of the Company s Contingent Resources as reserves see Independent Reserve and Resource Evaluations Contingent Resources Estimates in the AIF. The estimates of reserves and future net revenue for individual properties in this Presentation may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Contingent Resources has the meaning given to that term in the AIF. The forward-looking statements included in this presentation are expressly qualified by this cautionary statement. Athabasca does not undertake any obligation to publicly update or revise any forward-looking statements except as required by applicable securities laws. 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. 2
Athabasca Oil Corporation A growth strategy built on material thermal oil sands and light oil developments Assets Extensive positions in Alberta s prolific thermal oil sands and light oil resource plays Located in a stable fiscal jurisdiction People Experienced teams Funding Early cash flow from Light Oil production Evolving toward self-funded growth through partnerships Dover, MacKay with PetroChina in 2010 ($3.9 billion (1) total value) (1) Includes the anticipated receipt of $1.32 billion from the Dover put/call option 3
Pillars of Growth, Complementary Assets Light Oil Q2 2013 production ~7,250 Land base > 2.8 Proved plus probable reserves ~ 22.0 MMboe barrels of oil equivalent per day (boe/d) million (MM) acres (net) Light Oil Thermal Oil Thermal Oil Land base > 1.5 MM acres (net) Proved plus probable reserves ~ 0.3 billion barrels (Bbbl) Contingent resource (1) ~ 10.6 Bbbl ALBERTA Thermal Oil Land Purchase IPO Light Oil Land Purchase Expected First Steam Hangingstone Project 1 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 AOC Founded PetroChina Joint Venture Light Oil First Production (1) Contingent resource best estimate 4
Opportunities Drive Growth Montney Appraisal Development Duvernay Exploration Appraisal Development Slave Point Exploration Appraisal 2011 2012 2013 2014 2015 Prospective Acres (net) High-graded Acres (net) High-graded Locations Prospective Locations Montney 200,000 100,000 (3) > 500 > 400 Duvernay 350,000 (1) 200,000 (2) > 1,000 TBD Slave Point > 675,000 TBD TBD TBD (1) > 10 metres net pay thickness (2) > 20 metres net pay thickness (3) High-graded through appraisal drilling 5
Montney: Continuous Improvement in a Resource Play 65 Montney Horizontal Wells to Date Montney Appraisal Identifies >500 High-Graded Locations Appraisal drilling has held 95% of land Future development in high-graded areas Kaybob West >150 Locations Continuous Improvement Cycle times have decreased 20% Drilling costs down 35% Completion costs down 24% Saxon/Placid >250 Locations Kaybob East >100 Locations Depth, Thousands m (measured depth) (1) Average days Montney Time vs Depth Progression (1) 0.0 0.5 1.0 1.5 2.0 2.5 3.0 2012 Pacesetter 2011 3.5 2013 4.0 0 5 10 15 20 25 30 Days ($MM/ Well) 7,000 6,000 5,000 4,000 3,000 Montney Drilling & Completion Costs To Date Drilling Costs Completion Costs 35% Reduction 2,000 24% Reduction 1,000 Feb-11 Sep-11 Apr-12 Oct-12 May-13 6
The Duvernay is a World-Class Resource World Class Resource Large in place resource High liquid content: 100-350 bbl/mmcf free condensate Initial results compare favorably to the Eagleford Select Unconventional Plays In North America AOC Strategic Position Acreage in heart of liquids-rich Kaybob sub-basin > 90% of lands in condensate-rich gas window ~1,000 potential locations at four wells/section (1) Strategic ownership of key infrastructure in the area Land Holdings (net acres) 350,000 prospective acres 200,000 high-graded acres (>20 metres net pay thickness) 13 additional wells will hold 95% of high-graded land The Rock Brittle due to low clay content (< 20%) Extremely low water saturations (< 15%) Over pressured (0.60 0.90 psi/ft) Duvernay estimated hydrocarbons in place (2) 443 Tcf of natural gas 11.3 billion bbl of NGLs 61.7 billion bbl of oil (1) Ultimate well spacing to be determined (2) ERCB/AGS Open File Report 2102-06 Summary of Alberta s Shale and Siltstone Hosted Hydrocarbon Resource Potential P50 resource estimate 7
AOC in the Heart of the Duvernay Fairway Athabasca Encana/PetroChina Husky Shell Duvernay Kaybob Land Positions Talisman 08-18-64-17W5 Chevron ConocoPhillips Trilogy Cenovus Exxon > 20m Isopach excluding carbonate Licensed Duvernay Wells 02/02-34-62-20W5 Drilled Duv Hz Completed Duv Hz Completed Duv Vert 06-10-62-23W5 AOC Producing Duv Hz Limited open crown leases available. New entrants must either acquire or joint venture existing operations to gain position in the Kaybob Area 8
Focused on Liquids-Rich Gas Pressure (1000 psi) 0 5 10 15 0 AOC Industry Duvernay Maturity Map (1) Depth (1000ft) 5 10 08-18 02-34 Liquids Rich Gas Oil Window V 06-10 Under-pressured Over-pressured V V 8-18 15 0.44 0.6 0.7 0.8 0.9 Over pressuring similar to Eagle Ford Liquid Rich Acreage 6-10 V V 2-34 08-18-64-17W5 IP30: 775 boe/d GOR 860 scf/bbl AOC Duvernay Rights V AOC Producing Duvernay Duvernay Licence Duvernay Producer/Test Duvernay RR 06-10-62-23W5 IP30: 600 boe/d 175 bbl/mmcf Restricted Rate Dry Gas 02/02-34-62-20W5 IP30: 1350 boe/d 245 bbl/mmcf Restricted Rate Pyrolysis/XRD Measured Ro Verified by production: liquids yield 3 initial Duvernay wells were strategically drilled across the Kaybob sub-basin >90% of the high graded acreage (>20m Duvernay shale) mapped within the liquids rich gas window (1) Maturity Map Constructed From: Liquid yields, Measured Ro,Tmax and HI 9
Initial Duvernay Results are Very Encouraging Target Well Parameters (Condensate Gas Window) 3,000 02/2-34-062-20W5 Production Production (boe/d) Tubing Pressure 35 Well cost: $10 - $15 MM (D&C) IP30: 600 1,000 boe/d 2,500 30 EUR: 600 1,000 Mboe Free liquid yields: 100 350 bbl/mmcf 2,000 25 02/2-34-06-20W5 Results Eight months on production 107 Mbbl WH condensate 0.6 bcf gas Realized netback of ~$55/boe (Boe/d) 1,500 1,000 Current Rate: ~530 boe/d ~2650 psi flowing pressure > 160 bbl/mmcf 20 15 10 (Mpa) 55 o API condensate 500 5 Improved Stimulation Design 14 stages, 160 tonnes/stage 0 0 High pump rate: 16-18 m 3 /min 9 10
Duvernay Eagle Ford Comparison Aspect Duvernay Eagle Ford Shale Thickness 15-80 m 15-85 m Over-pressured Rock 0.60-0.90 psi/ft 0.55-0.80 psi/ft Thermal Maturity Dry gas Oil Dry gas Oil Water Saturation Under-saturated Normally saturated Drill and Complete Costs $10-15 MM $8-12 MM Single Well Rate of Return (1) 46-79% (150 200 bbls/mmcf) 43-53% (0il gas/condensate window) Development Maturity < 200 Hz wells > 3,200 Hz Wells (1) Scotiabank Playbook Sept 2013. Excludes land, seismic, dry hole and infrastructure costs. WTI/AECO $90/bbl, Edmonton Par $4/mcf, Henry Hub $4.75/mcf 11
Strategic Ownership of Infrastructure Operatorship to control development pace Ensure flexibility with takeaway options Scalable for future growth Total AOC Battery Capacity Oil Capacity 36,000 bbl/d 48 mmcf/d, Gas Capacity expandable to >130 mmcf/d 63 km AOC Gas Pipeline Up to Gas Capacity 180 mmcf/d Note: Keyera dually connected to both Alliance and TCPL sales lines 12
Duvernay Development Summary Production potential to exceed 100,000 boe/d for >10 years Inventory of >1,000 wells 50/50 split between gas and liquids Timeline can be accelerated with more aggressive rig ramp up Production (boe/d) 140,000 120,000 100,000 80,000 60,000 40,000 20,000 Natural Gas Condensate Oil NGLs 0 2013 2016 2019 2022 2025 2028 2031 2034 2037 2040 World class project economics (1) : Cumulative free cash flow positive by 2017 Rate of return: 50-75% Free Cash Flow ($MM) 1,250 1,000 750 500 250 0 Free Cash Flow Cumulative 3,000 2,500 2,000 1,500 1,000 500 0 Cumulative Free Cash Flow ($MM) -250 2013 2014 2015 2016 2017 2018 2019 2020-500 (1) Before tax 13
Next Steps What s Next Quality Assets Operational Excellence Profitable Growth 2013/14 Duvernay delineation program Focused Montney development Further Caribou appraisal drilling Optimize operations JV partnership process started in Q3 2013 North Muskwa South Muskwa Caribou Red Earth Kaybob Saxon/Placid 14