1. business and industrial
2. energy
3. natural gas

ATHABASCA OIL CORPORATION
FOCUSED | EXECUTING | DELIVERING
JANUARY 2015 CORPORATE UPDATE
FORWARD LOOKING STATEMENT
1
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”, “target”, “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 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 may contain forward-looking
information pertaining to the following: the Company’s strategic focus and related goals; the Company’s plans for, and results of, exploration and development activities; Athabasca’s plans with respect to its Light Oil assets, in particular in
respect of its Duvernay and Montney properties, and the expected benefits to be received by Athabasca from such assets; expectations regarding the Company’s Light Oil division including anticipated production levels and timing of receipt
of significant revenues and operating results therefrom; the Company’s 2015 production exit rate; the Company’s expected future cash flow from the Duvernay; future production and production potential from the Company’s Thermal Oil
division, including in respect of Hangingstone assets and the timing of and amount of plateau production from Hangingstone Project 1; future funding, financing, cash balances and liquidity; production targets, forecasts and guidance; cash
flow growth and cash flow potential; reserve growth potential; the timing of first steam and first production from Hangingstone Project 1; the receipt of proceeds from the promissory notes issued by Phoenix Energy Holdings Ltd. (“Phoenix”)
(the “Promissory Notes”); the timing of the drilling, completion and tie-in of planned Duvernay wells; the Company’s capital expenditure program and expectations regarding future capital expenditures and capital allocation; future well costs
and the Company’s anticipated cost learning curve in respect of drilling and completing such wells; projected Light Oil type curves; drilling and development plans, the expected quality and composition of the hydrocarbons that will be
produced from certain of the Company’s Light Oil assets; the Company’s estimated future commitments; the use of in-situ recovery methods such as Steam Assisted Gravity Drainage (“SAGD”) for production of recoverable bitumen,
including the potential benefits of such methods; economic and financial forecasts and estimates; and the expected receipt of regulatory approvals, including in respect of the Hangingstone Projects 2A and 2B.
With respect to forward-looking information contained in this presentation, assumptions have been made regarding, among other things: commodity prices for crude oil, natural gas and bitumen blend; 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 applicability of technologies for the recovery and production of the Company’s
reserves and resources; the quality of the quality of the Company’s Thermal Oil and Light 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 value of the Company’s tax pools; the Company’s Light Oil well type curves; the impact that the timing of the
Company’s receipt of payments made by Phoenix under the Promissory Notes will have on the Company, including the Company’s financial condition, capital programs and results of operations; future capital expenditures to be made by the
Company; the future sources of funding for the Company’s substantial capital programs; the Company’s future debt levels; 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 dated March 18, 2014 (“AIF”), which is available on
SEDAR at www.sedar.com, including, but not limited to: the substantial capital requirements of Athabasca’s projects and the ability to obtain financing for Athabasca’s capital requirements; failure by counterparties to make payments or
perform their obligations to Athabasca in compliance with the terms of contractual arrangements (including under the Promissory Notes) between Athabasca and such counterparties, including in compliance with the time schedules set out
in such contractual arrangements, and the possible consequences thereof; risks affecting the ability of HSBC Canada to honour obligations under the irrevocable letters of credit issued to secure the Promissory Notes; aboriginal claims;
fluctuations in market prices for crude oil, natural gas and bitumen blend; general economic, market and business conditions in Canada, the United States and globally; failure to obtain regulatory approvals or maintain compliance with
regulatory requirements; failure to meet development schedules and potential cost overruns; variations in foreign exchange and interest rates; factors affecting potential profitability; risks related to future acquisition and joint venture
activities; reliance on, competition for, loss of, and failure to attract key personnel; global financial uncertainty; uncertainties inherent in estimating quantities of reserves and resources; changes to Athabasca’s status given the current stage
of development; uncertainties inherent in SAGD and other bitumen recovery processes; expiration of leases and permits; risks inherent in Athabasca’s operations, including those related to exploration, development and production of
petroleum, natural gas and oil sands reserves and resources; risks related to gathering and processing facilities and pipeline systems; availability of drilling and related equipment and limitations on access to Athabasca’s assets; increases
in operating costs could make Athabasca’s projects uneconomic; the effect of diluent and natural gas supply constraints and increases in the costs thereof; gas over bitumen issues affecting operational results; environmental risks and
hazards and the cost of compliance with environmental regulations, including GHG regulations and potential Canadian and U.S. climate change legislation; extent of, and cost of compliance with, government laws and regulations and the
effect of changes in such laws and regulations from time to time; risks related to Athabasca’s filings with taxation authorities, including the risk of tax related reviews and reassessments; changes to royalty regimes; political risks; failure to
accurately estimate abandonment and reclamation costs; exploration, development and production risks inherent in crude oil and natural gas operations, including 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; long term reliance on third parties; reliance on third party infrastructure; seasonality; hedging risks; risks associated with establishing
and maintaining systems of internal controls; insurance risks; claims made in respect of Athabasca’s operations, properties or assets; competition for, among other things, capital, the acquisition of reserves and resources, export pipeline
capacity and skilled personnel; the failure of Athabasca or the holder of certain licenses, leases or permits to meet specific requirements of such licenses, leases or permits; risks related Athabasca’s credit facilities; alternatives to and
changing demand for petroleum; risks related to Athabasca’s common shares; and risks pertaining to Athabasca’s senior secured notes and term loans.
In addition, information and statements in this presentation relating to “reserves”, “resources”, “hydrocarbons in-place” and “bitumen in place” 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. (“GLJ”) and DeGolyer and MacNaughton Canada Limited (“D&M”), each dated effective December 31, 2013. There is no certainty
that it will be commercially viable to produce any portion of the resources. With respect to the estimates of undiscovered “bitumen-in-place”, there is no certainty that any portion of the resources will be discovered. 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. For important additional
information about the Company’s reserves and resources, please refer to the AIF. For additional information regarding the specific contingencies which prevent the classification of the Company’s Contingent Resources as reserves, please
see “Independent Reserve and Resource Evaluations – Contingent Resources Estimates” in the AIF. “Contingent Resources”, “Best Estimate”, “Proved Reserves” and “Probable Reserves” have the meanings given to those terms 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.
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.
REFINED STRATEGY FOR VALUE CREATION
BALANCE SHEET
STRENGTH
o $1.3 billion of funding in place2
o Focus on core areas
o Adapt the capital program to economic cycles and drilling results
GUIDING PRINCIPLES
WORLD CLASS ASSETS
Material Core Assets
o 1,000+ well inventory in the Duvernay shale play at Kaybob
o 80,000 bbl/d project potential at the Hangingstone thermal asset
Diverse portfolio provides long term optionality
o Montney exposure at Placid
o 9 billion bbl contingent resource1 (best estimate) in the oil sands
CASH FLOW
GROWTH
o Develop assets with self funding growth capability in the medium-term
o Maximize returns, netbacks and efficiencies
EXECUTION
EXCELLENCE
o Maintain operational agility
o Technical rigor helps minimize risk
o Capital and cost discipline sets the foundation for development
DELIVERING ON
COMMITMENTS
o Duvernay - transitioning from land to resource value
o Hangingstone Project 1 (HS1) - first steam expected at the end of Q1
o 2015 corporate exit target of 10,000 – 14,000 boe/d3 (>75% growth)
Footnotes and additional information included in the back as endnotes.
2
3
CORPORATE OVERVIEW
CAPITALIZATION OVERVIEW (Q3 2014)
Stock exchange listing
TSX
Trading symbol
ATH
Share Price (January 7th, 2015)
$2.25
$/sh
$2.02 - $8.84
$/sh
Basic shares outstanding
402.0
MM
Fully diluted shares
426.0
MM
52-week trading range
Insider ownership
4.1
Market capitalization
%
$905
MM
Cash and promissory notes1
~$3/sh
($1,217)
MM
Long-term debt*
~$2/sh
$802
MM
~$1/sh
($415)
MM
$490
MM
>$2,000
MM
Total enterprise value
Tax Pools
* Details on debt & credit facility provided on slide 22
Footnotes and additional information included in the back as endnotes.
4
WELL POSITIONED FOR GROWTH
2015 HIGHLIGHTS
o Building a business that is self funded in the medium-term
o Exit volumes expected to grow by >75% in 2015
o Conservative approach to capital allocation and spending
PRODUCTION (boe/d)
CAPEX/ FUNDING IN PLACE*
$1,200
$MM
$1,000
$800
$600
$400
$200
14,000
Thermal Oil Capex ~$1.3bln
Light Oil Capex
Funding
12,000
Gas
Liquids
10,000-14,000
10,000 - 14,000
10,000
$0.7bln
$445
>$1bln
(end of Q1/15)
8,000
6,000
6,397
6,000 - 6,250
2013
2014e
~5,000
4,000
$350
$282
$238
$93
$167**
2013
2014e
2015e
$0
boe/d
$1,400
* Funding reflects cash, available credit facilities & promissory notes
** Initial winter program spending
2,000
0
Q1/15e
2015e Exit
5
FOCUSED ON OUR CORE ASSETS
LIGHT OIL: GREATER KAYBOB
2014/15 winter program
o $167 million initial 2015 budget1
o 11 Duvernay and 2 Montney wells
Go forward flexibility
o Near-term Duvernay land retention requirements met by the spring
o Ownership and operatorship in strategic regional infrastructure
Long term potential
Hangingstone
Greater
Kaybob
o 200,000 Duvernay acres with the potential for 1,000+ wells
EDMONTON
THERMAL OIL: HANGINGSTONE
2015 program
o $77 million budget for Hangingstone Project 1 and Project 2A engineering
o Hangingstone Project 1 commissioning in Q1 2015
o Plateau production of 12,000 bbl/d expected in 2016
Long term potential
CALGARY
o ~1 billion bbl2,* resource supports production potential of 80,000 bbl/d
o Expansion contingent upon a successful ramp-up and market conditions
*Includes 51.1 MMbbl proved reserves, 174.0 MMbbl probable reserves and 782.0
MMbbl of best estimate contingent resource based on GLJ and D&M reports as of
December 31, 2013.
Footnotes and additional information included in the back as endnotes.
DUVERNAY OVERVIEW
THE DUVERNAY IS A WORLD CLASS RESOURCE
WORLD
CLASS
RESOURCE
o
o
o
o
Large in place resource
High liquids yield: 100 -1,000 bbl/MMcf liquids
Initial results compare favorably to the Eagle Ford
Major E&Ps active in the play
DUVERNAY
ADVANTAGE
o
o
o
o
Proactive fiscal and regulatory environment
Minimal surface land use conflicts
Well situated to services and infrastructure
Premium pricing on condensate – strong local market
AOC
ADVANTAGE
o
o
o
o
100%WI Kaybob position, industry activity ramping up
> 200,000 acres across the liquids fairway
Excellent land tenure – ability to control pace
Strategic ownership of key infrastructure
MATERIALITY
o
o
o
o
High Duvernay exposure relative to market cap
Superior economics
Opportunity to accelerate production & cash flow growth
1,000+ wells
7
SELECT UNCONVENTIONAL PLAYS IN
NORTH AMERICA
DUVERNAY ESTIMATED HYDROCARBONS IN PLACE1
o 443 Tcf of natural gas
o 11.3 Bbbl of NGLs
o 61.7 Bbbl of oil
Footnotes and additional information included in the back as endnotes.
MATERIAL EXPOSURE ACROSS THE KAYBOB
DUVERNAY FAIRWAY
Volatile Oil
Sections: >150,000 acres
Locations: 1,300+
2
2
Condensate Rich Gas
Sections: >35,000 acres
Locations: 200+
AOC Duvernay Land
AOC 2014/15 Winter Program (11)
AOC Drilled Duvernay (9)
8
9
KAYBOB DUVERNAY ACTIVITY UPDATE
4-29 S/C/Hz.
On stream: June 16, 2014
30 day IP (restricted) – 615 boe/d
CTD – 47 mboe, 71% liquids
8-29 Hz.
On stream: June 21, 2014
30 day IP (restricted) – 784 boe/d
CTD – 67 mboe, 77% liquids
13-23 Vert./C
16-36 S/C/Hz.
Completion: Q4 2014
Planned on stream: Jan. 2015
8-18 S/Hz.
On stream: Jan. 2, 2013
30 Day IP – 775 boe/d
CTD – 98 mboe, 79% liquids
2
2
1-25 S/Hz.
On stream: May 9, 2014
30 day IP (restricted) – 1,461 boe/d
CTD – 127 mboe, 52% liquids
S - vertical strat
C - core
AOC Duvernay Land
1-7 S/Hz.
On stream: March 15, 2014
30 day IP (restricted) – 750 boe/d
CTD – 101 mboe, 65% liquids
6-10 S/Hz.
On stream: Dec. 28, 2012
30 Day IP – 600 boe/d
CTD – 111 mboe, 37% liquids
2-34 S/Hz.
On stream: Dec. 2012
30 Day IP – 1,350 boe/d
CTD – 374 mboe, 48% liquids
Apache
Chevron
Hitic
Shell
Trilogy
Shell Partial
Xto
Conoco
Encana
Talisman
Other
Apache Partial
AOC 2014/15 Winter Program (11)
AOC Drilled Duvernay (9)
Licensed Duvernay (394)
Drilled Duvernay (238)
Winter program will retain 95% of land prospective for commercial development into the intermediate term. Continued lands gain 5 years of tenure beyond the 4 year primary term
LIQUIDS AND OVERPRESSURE DRIVES
ECONOMICS
10
o Industry drilling has confirmed the overpressured nature of the basin
o High quality product (API low 40s to mid 50s)
o Material exposure across all thermal maturity windows
Pressure (1,000 psi)
0
5
10
15
AOC
0
Depth (1,000 ft)
2
2
Industry
5
08-18
01-07
02-34
4-32 Pad
10
0.44
Under-Pressured
15
Liquid yield is cum/cum for wells with > 3 months production.
Public domain data with the exception of AOC wells
0 - 50
50 - 250
bbl/MMcf
250 - 550
550+
01-25
06-10
0.6 0.7
0.8 0.9
Over-Pressured
11
CONDENSATE RICH GAS
SAXON
Capital (Cur./Dev.)
Restricted IP30
Initial Liquids Yields
EUR
1
$MM
$17/$10
boe/d
1,000 - 1,400
700 - 1,000
bbl/MMcf
50 - 400
50 - 400
mboe
700 - 1000
600 - 900
ECA, CVX, APA
ECA, CVX, RDSA, TET
Regional Players
Royalties 2
$15/$8
Eligible for shale gas & NGDDP royalty incentive
Inventory 3
~160
~50
Kaybob West South
Saxon
3,500m vertical depth
1.5 – 2.0x over pressured
~50o API
KAYBOB WEST
SOUTH
2
2
3,000m vertical depth
~1.5x over pressured
~45-50o API
VALUE FROM CONDENSATE RICH GAS AND
VOLATILE OIL
2-34-62-20W5 WELL ECONOMICS
Development
Capital
$MM
$15.0
$10.0
IP30
boe/d
1,350
1,350
EUR
mboe
970
970
ROR
%
42%
96%
$MM
$10.3
$15.2
x
2.7x
4.1x
$/bbl WTI
~$50
~$20
NPV 10
Recycle Ratio
Breakeven
WELL NPV SENSITIVITY TO LIQUIDS YIELDS1
15
NPV 10% ($MM)
Current
6
3
0.5
600
300
Development payout
400
200
200
100
0
0
24
36
Months
48
60
Yield bbl/MMcf
400
1-07-064-20W5
8-29-064-20W5
2-34-062-20W5
800
mboe
boe/d
1000
700
Current payout
12
2.0
2.5
3.0
EXTENDED FREE LIQUIDS YIELDS
500
0
1.5
1.0
Raw Gas (BCF)
1,000
600
01-07-64-20W5
* Assumes $15 million well cost, represent initial liquids yield
Gas (boe/d)
Liquids
Cumulative
800
2-34-62-20W5
9
0
2-34-62-20W5 TYPE CURVE
1,200
8-29-064-20W5
12
* Based on single well economics
1,400
12
600
Extended production data
confirming expectations
that high liquids yields
stabilize
400
200
0
10
30
1
59
2
88
117
3
4
Months
146
5
175
6
204
7
Flat pricing (US$80/bbl, $4/mcf AECO, 0.9 FX) – see endnotes
Footnotes and additional information included in the back as endnotes.
13
UNLOCKING THE VOLATILE OIL WINDOW
WHAT WE KNOW
VOLATILE OIL WINDOW
Capital (Cur./Dev.)
o Encouraged by initial success from AOC and others
(restricted IPs >300 bbl/d, over-pressured, high quality
product)
Restricted IP30
o Kaybob East lowest cost area (due to shallower depth)
EUR
WINTER ACTIVITY
o 1 producer (2-7-65-18W5 hz) and 3 non-producers (2
vt & 1 hz)
$MM
$12 - $17 / $7 - $12
boe/d
400 - 800+
1
Initial Liquids Yields bbl/MMcf
mboe
Regional Players
400 - 1,000
400 - 600
RDSA, TET, Hitic
Royalties 2
Eligible for shale gas incentive
Inventory 3
1,300+
KAYBOB EAST
08-18-64-18W5 42°API
Kaybob
2
2,500m vertical depth
>1.0x over pressured
>40o API
2
Simonette
3,500m vertical depth
very over pressured
Footnotes and additional information included in the back as endnotes.
14
CONTROL OF STRATEGIC INFRASTRUCTURE
Total Battery Capacity
Oil Capacity
Gas Capacity
Gas Pipeline
Up to
Gas Capacity
180 MMcf/d
36,000 bbl/d
84 MMcf/d,
expandable to
>130 MMcf/d
Kaybob East
AOC 91 km Pipeline
Fort
McMurray
Kaybob West
Saxon
Keyera
Simonette
Placid
SemCAMS KA
EDMONTON
o Operatorship provides flexibility to control pace of development
o 91km gas pipeline (50% WI); dually connected to regional gas plants
CALGARY
o 3 batteries process field condensate; connected to Pembina’s Peace Pipeline
o Flexibility with takeaway options; scalable for future growth
Gas pipelines (TCPL/Alliance)
Oil pipelines (Pembina)
Diluent pipelines (Inter Pipeline)
15
DUVERNAY GROWTH SCENARIO
PROJECTED DAILY PRODUCTION
SCENARIO OVERVIEW
70,000
o Cost learnings with the transition to development
60,000
o Self funding in the mid-term1
o Project rate of return ~40%1
50,000
6
Oil (bbl/d)
Condensate
NGL's
Gas
Rig Count
5
4
40,000
3
30,000
2
20,000
1
10,000
0
0
2015
Completions
Drilling
Initial Appraisal
Mid Term
Long Term
Annual Free Cash flow ($ MM)
20
18
16
14
12
10
8
6
4
2
0
500
400
300
200
100
0
-100
-200
-300
-400
-500
2016
2017
2018
2019
PROJECTED FREE CASH FLOW
go-forward BT Cash flow
go-forward Cumulative Cash flow
2015
2016
2017
2018
500
400
300
200
100
0
-100
-200
-300
-400
-500
2019
Flat pricing (US$80/bbl, $4/mcf AECO, 0.9 FX) – see endnotes
Footnotes and additional information included in the back as endnotes.
Cumulative Cash flow ($MM)
D&C Cost ($MM)
ANTICIPATED COST LEARNING CURVE
Rig Count
Production (boe/d)
o Potential for significant annual production growth
16
MONTNEY APPRAISAL AT PLACID
PLACID MONTNEY
WELL ECONOMICS1
o 2 well winter appraisal program aimed at
demonstrating well performance similar to offsetting
operators
o 100+ potential inventory (2 separate Montney cycles)
o No near term land expiries
o Upside to type curve with longer laterals and refined
completion techniques
Current
Development
Capital
$MM
$12.2
$8.1
IP30
boe/d
1,520
1,520
EUR
mboe
715
715
ROR
%
26%
73%
$MM
$3.9
$8.1
x
2.1x
3.2x
NPV 10
Recycle Ratio
TYPE CURVE
1,600
1,400
1,200
Current payout
boe/d
1,000
8-20-60-23W5
completing
Development payout
800
600
400
200
0
0
12
24
36
Months
48
60
Flat pricing (US$80/bbl, $4/mcf AECO, 0.9 FX) – see endnotes
Footnotes and additional information included in the back as endnotes.
mboe
9-26-60-24W5
drilling
180
160
140
120
100
80
60
40
20
0
Gas (boe/d)
Liquids
Cumulative
HANGINGSTONE OVERVIEW
18
HANGINGSTONE DEVELOPMENT
HANGINGSTONE PROJECT 1 (12,000 BBL/D)
Fort McMurray
o $63 million forecasted remaining spend in 2015
o Targeting first steam at the end of Q1 2015
o $708 million project capital – on time/budget
o US$55/bbl cash flow break-even
CPF
WHAT HS1 MEANS FOR ATHABASCA
o Stable production for ~35 years
o Demonstrated executional performance in the oil
sands
o 1 billion bbl
resource1,*;
80,000 bbl/d potential
o Potential HS2A 8,000 bbl/d debottleneck to take
advantage of economies of scale
o Sanctioning of future phases considered following
successful ramp-up of HS1
Enbridge
Cheecham
Additional footnotes are located at the end of the presentation
$175
$150
$125
14,000
Daily Bitumen Production
Cash from Operations
Start-up Cost
12,000
10,000
$100
8,000
$75
6,000
$50
4,000
$25
$0
2,000
-0
-$25
-2,000
-$50
Daily production (bbl/d)
o Regional infrastructure in place for expansion
12,000 bbl/d
12,000 bbl/d
CASH FLOW AND PRODUCTION GROWTH
Operations Cash Flow ($MM)
LONG TERM POTENTIAL
Sales pipeline
Fuel gas
Diluent
-4,000
2015
2016
2017
*Includes 51.1 MMbbl proved reserves, 174.0 MMbbl probable reserves and 782.0
MMbbl of best estimate contingent resource based on GLJ and D&M reports as of
December 31, 2013.
Flat pricing (US$80/bbl, $4/mcf AECO, 0.9 FX) – see endnotes
Footnotes and additional information included in the back as endnotes.
AOC LEARNINGS LEAD TO SUCCESS
POTENTIAL
ISSUE
KNOW THE
RESERVOIR
ENGINEERING
LEARNINGS APPLIED
~ 5m of separation as per design
Drilled more delineation wells than industry
average
High definition 3D Seismic
Engineering and construction best practices
(on budget/schedule)
25 well pairs drilled
(18 required in reservoir simulation)
WELL DESIGN
19
Stayed within effective pay zone
(>90% in all producers)
Drilling path and separation survey
Clean bitumen saturated sand
Reservoir image logs to support defining facies along SAGD Wellpairs
Parallel wells
(5m separation for all well pairs)
STEAM
CAPACITY
3.5x SOR built vs. 3.2x simulation
UNDERSTAND
THE ANALOGS
In depth competitor analysis to support
assumptions
TECHNOLOGY
Utilizing proven SAGD technology
Effective wellbore length average above design target > 90%
Production & injection wellbores in the HS1 the reservoir
SUPPLEMENTAL INFORMATION
21
ACTIVITY LEVELS REMAIN ROBUST
PLAY DEVELOPMENT
INDUSTRY TRANSITIONING TO DEVELOPMENT
Play Maturity / Valuation
o Majors are accelerating activity from the appraisal
to development stage
o 6 - 8 multi-well pads (Apache, Chevron, Encana,
Shell); companies remain active
o $1.5 billion Chevron/KUFPEC deal implies a valuation
of ~US$15,000/acre
Eagle Ford
Montney
Willesden Green
Duvernay
Edson
Duvernay
Kaybob Duvernay
Emerging
Plays
Cumulative Licenses per Operator
80
60
40
400
300
200
100
20
0
0
Q1
Q2
Q3
2012
Q4
Q1
Q2
Q3
2013
Q4
Q1
Q2
Q3
2014
*Reflects industry activity for Kaybob operators with 10+ licenses. 2014-Qtr4 is as of December 31, 2014
Q4
Total Industry Cumulative Licenses
500
Total Industry Licenses
Trilogy Rsrcs Ltd
Husky Oil Oprtns Ltd
Chevron Cda Ltd
XTO Enrg Cda ULC
Encana Corp
Shell Cda Ltd
Athabasca Oil Corp
100
Blowdown
Assets
Commercial
Development
DUVERNAY LICENSING ACTIVITY
120
Source: RBC Rundle
22
DEBT AND CREDIT FACILITY OVERVIEW
UNDRAWN CREDIT FACILITIES
Cdn $125 million senior secured revolving
credit facility due 2017
US $50 million senior secured term loan
delayed draw facility due 2019
Q3 2014
INTEREST RATE
PRE-PAYMENT TERMS
$125
~ 5%
Pre-payable without penalty
$56
LIBOR + 7.25%
1.00% LIBOR floor
05/2015 – 102%
05/2016 – 101%
05/2017 and beyond – 100%
Total undrawn facilities
$181
OUTSTANDING DEBT
Q3 2014
US $225 million senior secured term loan
due 20191
$252
Cdn $550 million senior secured second
lien notes due 20172
$550
Total outstanding debt
$802
INTEREST RATE
PRE-PAYMENT TERMS
LIBOR + 7.25%
1.00% LIBOR floor
05/2015 – 102%
05/2016 – 101%
05/2017 and beyond – 100%
7.50%
11/2014 – 107.50%
11/2015 – 103.75%
11/2016 and beyond – 100%
Footnotes and additional information included in the back as endnotes.
23
OTHER LONG TERM ASSETS
GROSMONT
o 418 MMbbl contingent resource1 (best estimate, AOC interest)
SLAVE POINT
BIRCH
Slave Point
o 2.1 Bbbl contingent resource1
(best estimate)
o > 675,000 acre land position
o Validated oil production
with 2013 pilot program
Birch
Grosmont
DOVER WEST SANDS
Dover
West
MONTNEY
o ~2.7 Bbbl contingent resource2
(best estimate)
o ~100,000 acres of Montney
prospective for commercial
development
DOVER WEST CARBONATES
Montney
Edmonton
o 3.0 Bbbl contingent resource2
(best estimate)
Footnotes and additional information included in the back as endnotes.
24
MANAGEMENT TEAM AND BOARD
MANAGEMENT TEAM
Thomas Buchanan, FCA
Chief Executive Officer
o Over 30 years experience in the oil and natural gas sector, and currently
Chairman of Spyglass Resources Corp.
o Formerly CEO of Spyglass Resources Corp. prior thereto, CEO of Provident
Energy Trust, previously known as Founders Energy
o Brings extensive experience in the energy sector, a strong financial
background, leading growth through internal expansion, mergers and
acquisitions and investor relations
Rob Broen, P.Eng.
President & Chief Operating Officer
o Joined Athabasca Oil Corporation in Nov. 2012 as Senior Vice President Light
Oil, promoted to Chief Operating Officer in Oct. 2013 and promoted to
President and COO in Jan. 2015
o Brings over 20 years of exploration and production expertise
o Prior to joining Athabasca, Mr. Broen held the role of President and Director,
Talisman Energy USA Inc. based in Pittsburgh, PA. He was promoted to Senior
Vice-President, North American Shale based in Calgary where he managed a
capital budget of over $1 billion and a 120,000 boe/d North American shale
gas portfolio (Montney, Duvernay, Marcellus and Eagle Ford)
Kim Anderson, CA
Chief Financial Officer
o Joined Athabasca Oil Corporation in February 2014, as Chief Financial Officer
o Brings 14 years of diversified financial experience in the energy industry
o Prior to joining Athabasca, Ms. Anderson was CFO of KANATA Energy Group
Ltd. and prior thereto, held various roles at Provident Energy Ltd.
Matt Taylor, CFA
Vice-President, Capital Markets & Communications
403.817.9104
[email protected]
BOARD OF DIRECTORS
Thomas Buchanan, FCA
Chairman & Chief Executive Officer
Ronald Eckhardt
Lead Director, Chair of the Reserves and HSE
Committee, and member of the Compensation and
Governance Committee
Sveinung Svarte, MBA, MSc.
Vice Chairman of the Board and member of the
Reserves and HSE Committee
Gary Dundas, CMA, MBA
Board member, Chair of the Compensation and
Governance Committee, and member of the Audit,
Reserves and HSE Committees
Carlos Fierro – appointed January 2015
Paul Haggis – appointed January 2015
Marshall McRae, CA
Board member, Chair of the Audit Committee, and
member of the Compensation and Governance
Committee
Peter Sametz, P.Eng.
Board member, member of the Reserves and HSE
Committee and member of the Audit Committee
25
ENDNOTES
Slide
Endnotes
2
(1)
(2)
(3)
Best estimate contingent resource adjusted for the Dover disposition
Estimated funding in place as of December 31, 2014; includes cash and cash equivalents, available credit facility and promissory notes
Corporate production guidance based on a $167 million initial 2015 light oil budget, predominately reflects drilling & completion activity until spring
break-up; $93 million full year thermal budget
3
(1)
$584 million promissory notes issued by Phoenix Energy Holdings Ltd. (subsidiary of PetroChina). $300 million due March 2015, $150MM due August
2015 and $134 million due August 2016. Notes are unconditional and secured by irrevocable standby letters of credit issued by HSBC Bank Canada
5
(1)
(2)
7
(1)
$167 million initial 2015 light oil budget, predominately reflects drilling & completion activity until spring break-up
Includes 51.1 MMbbl proved reserves, 174.0 MMbbl probable reserves and 782.0 MMbbl of best estimate contingent resource based on GLJ and D&M
reports as of December 31, 2012
ERCB/AGS open file report 2012-06 – Summary of Alberta’s shale and siltstone hosted hydrocarbon resource potential – P50 resource estimate
11
(1)
(2)
(3)
Field condensate; excludes NGLs
Wells qualify for the Shale Gas New Well Royalty Rate (SGNWRR) and the Natural Gas Deep Drilling Program (NGDDP) in the Alberta Royalty framework
Inventory is based on 4 wells per section
12
(1)
(2)
13
(1)
(2)
(3)
(1)
Initial field condensate cuts & gas recovery estimates
Commodity price assumptions used throughout economics in the presentation are WTI US$80/bbl, C$/US$0.90, Edmonton Par Differential (US$7.00),
20% WCS heavy differential, C5+ 100% WTI, AECO C$4/mcf
Field condensate; excludes NGLs
Wells qualify for the Shale Gas New Well Royalty Rate (SGNWRR) in the Alberta Royalty framework
Inventory is based on 6 wells per section
Commodity price assumptions used throughout economics in the presentation are WTI US$80/bbl, C$/US$0.90, Edmonton Par Differential (US$7.00),
20% WCS heavy differential, C5+ 100% WTI, AECO C$4/mcf
Management type curve estimate based on regional results
Commodity price assumptions used throughout economics in the presentation are WTI US$80/bbl, C$/US$0.90, Edmonton Par Differential (US$7.00),
20% WCS heavy differential, C5+ 100% WTI, AECO C$4/mcf
Includes 51.1 MMbbl proved reserves, 174.0 MMbbl probable reserves and 782.0 MMbbl of best estimate contingent resource based on GLJ and D&M
reports as of December 31, 2013.
Commodity price assumptions used throughout economics in the presentation are WTI US$80/bbl, C$/US$0.90, Edmonton Par Differential (US$7.00),
20% WCS heavy differential, C5+ 100% WTI, AECO C$4/mcf
Athabasca has entered into a US dollar forward contract of US$270.8 million relating to the interest payments and principal repayments for the Term
Loans at a rate of US$1.00 = C$1.1211 expiring on March 31, 2017.
The senior secured second lien notes have an assigned B credit rating from both DBRS and S&P
Contingent resource best estimate; based on December 31, 2013 D&M Report
Contingent resource best estimate; based on December 31, 2013 GLJ Report
15
16
(1)
(2)
18
(1)
(2)
22
(1)
23
(2)
(1)
(2)
Corporate Office
1200, 215 - 9 Ave SW, Calgary, Alberta
Telephone: 403-237-8227
Fax: 403-264-4640
www.atha.com