2. Disclaimers
• Forward Looking Statements
• This document contains statements that constitute “forward-looking information” within the meaning of applicable securities legislation as to NAL
Energy Corporation’s (“NAL’s”) internal projections, expectations and beliefs relating to future events or future performance. This forward-looking
information includes, among others, statements regarding: NAL’s strategic focus, business strategy and plans and budgets; business plans for drilling,
exploration and development, including drilling locations; estimates of production and operations performance; forecasted commodity price estimates
of future sales; estimated amounts, allocation and timing of capital expenditures; estimates of operating costs and unit operating costs; the estimated
timing and results of new development programs; estimates of anticipated funds from operations, cash flow, netbacks, dividends, working capital and
debt levels; estimated rates of return; the anticipated results of NAL’s divestiture program; various tax matters related to NAL; NAL’s hedging program;
NAL’s prospect inventory; and other expectations, beliefs, plans, goals, objectives, assumptions, information and statements about possible future
events, conditions, results of operations or performance.
• Various assumptions were used in drawing the conclusions or making the forecasts and projections contained in the forward-looking information
contained in this presentation including, without limitation, with respect to commodity prices, interest rates, exchange rates, royalty rates, general
and administrative expenses, the success of NAL's drilling programs and the production profile of NAL's oil and natural gas reserves. Forward-looking
information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and in
some instances to differ materially from those anticipated by NAL and described in the forward-looking information contained in this document. Undue
reliance should not be placed on forward-looking information. The material risk factors include, but are not limited to: the risks of the oil and gas
industry, such as operational risks in exploring for, developing and producing oil and natural gas, market demand and unpredictable facilities outages;
risks and uncertainties involving the geology of oil and gas deposits; the uncertainty of estimates and projections relating to production, costs and
expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; risk that adequate pipeline
capacity to transport oil and natural gas to market may not be available; fluctuations in oil and gas prices, foreign currency exchange rates and interest
rates; the outcome and effects of any future acquisitions and dispositions; safety and environmental risks; uncertainties as to the availability and cost
of financing and changes in capital markets; competitive actions of other industry participants; changes in general economic and business conditions;
the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; changes in tax laws; changes in
royalty rates; the results of NAL’s risk mitigation strategies, including insurance; and NAL’s ability to implement its business strategy. Readers are
cautioned that the foregoing list of risk factors is not exhaustive. Additional information on these and other factors which could affect NAL’s operations
or financial results are included in NAL’s most recent Annual Information Form and Annual Financial Report. In addition, information is available in
NAL’s other filings with Canadian securities regulatory authorities.
• Forward-looking information is based on the estimates and opinions of NAL’s management at the time the information is released.
• Boe Conversion
• Throughout this press release, the calculation of barrels of oil equivalent (boe) is based on the widely recognized conversion rate of six thousand cubic
feet (mcf) of natural gas for one barrel (bbl) of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is
based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.
• All dollar amounts in Canadian dollars, unless otherwise stated.
2
3. Schedule
Introduction
Strategic Direction & Guidance 10 min
Financial Plan 10 min
Assets Overview 5 min
Operational Plan & Core Area Review 15 min
Emerging Prospect Inventory 10 min
Summary/Key Messages 10 min
3
4. NAL Energy Corporation Profile
TSX Symbol NAE
Market Capitalization1 $1.1 Billion
Monthly Dividend $0.05/share
Net Debt2 $376 Million
Current Shares Outstanding2 150.4 Million
Convertible Debentures
Trading Symbol NAE.DB NAE.DB.A
Coupon 6.75% 6.25%
Principal Outstanding ($MM) 80 115
Conversion Price ($/Share) 14.00 16.50
Maturity Date 31AUG12 31DEC14
Notes:
1) As at January 10, 2012
2) As at Q3/11
4
6. Strategic Direction – Long Term Sustainability
• Dividend paying E&P company
• Maximize cash flow
• Add scalable liquids opportunities
• Utilize new tools and technologies
• Deliver operating and capital cost efficiency
• Actively manage business risk
• Disciplined acquisition focus
• Balance dividend with sustaining capital
6
8. 2012 Corporate Plan
1. Grow cash flow and liquids volumes
• Targeting cash flow increase of 3%
• Forecast oil volumes increasing 5%
• Liquids mix increasing from 47% to 50%
2. Capital focused on high ROR and recycle ratio projects
• Oil focused capital projects
• Higher liquids yields on selected gas projects
• Less focused on delivering gas volumes (6:1 Boe)
8
9. 2012 Corporate Plan
3. Higher proportion of development capital
• Represents 95% of 2012 program – up 11%
• Lower risk improves volume certainty
4. Continued appraisal activity in new oil resource plays
5. Maintain financial flexibility
9
10. 2012 Full Year Guidance
• Production (boe/d) 28,000 – 29,000
• Capital ($MM) 200
• Operating Costs ($/boe) 11.50 – 12.00
10
12. Financial Strategy
Maintain Financial Flexibility
Maintain an
optimal capital Target total debt Total payout
to cash flow ratio ratios between
structure and at 2x and not to
strong balance exceed 2.5x 100% and 120%
sheet
Maintain Minimizes
appropriate mix financing charges Provide access to
of debt (term/mix of multiple markets
instruments fixed vs floating)
Capital Systematic
investment that hedging of
Increase liquids
Sustain cash flows replaces
weighting
commodities, FX
production at 2x and interest
recycle ratio rates
12
13. Financial Action Plan
Reduce monthly
dividend to $0.05
per share
Maintain credit
Refinance 2012
lines by
convertible
focusing capital
maturity ($80
on oil and
MM) with debt
Financial liquids plays
Flexibility
Term out a Converted bank
portion of existing line from one to
bank line with three year term
high yield in 2011
13
14. 2012 Key Assumptions
WTI ($US/bbl) 85.00 95.00 105.00
AECO ($C/GJ) 2.50 3.00 3.50
FX (CAD/US) 1.00 0.98 0.96
Monthly Dividend ($) 4.7 0.05 4.7
Volume (boe/d) 28,500
G&A ($/boe)2 3.00 2.50 3.00
Royalties (%) 17 18 19
Oil Differential (%)3 90 90 90
DRIP Participation (%) 23 23 23
Weighted Avg Shares O/S (MM) 152.3 152 152.3
Note: 1) Commodity, FX and Royalty assumptions are held constant through the year; 2) G&A excludes Unit Based
Compensation (UBC); 3) NAL forecast price differential to C$ WTI .
14
15. 2012 Financial Forecast
Funds From Operations “FFO” ($MM) 275 265 275
Net Capital Expenditures ($MM) (200) (200) (200)
Dividends ($MM) (90) (92) (90)
Payout Ratios (% of FFO):
Basic 46 35 46
Basic + Capital 122 110 122
Basic + Capital, net of DRIP 117 102 117
15
16. 2012 Balance Sheet Forecast
Year end 2012e ($MM)
Bank Debt at Year-end 2012e 412 305 412
Working Capital Deficit 72 70 72
Net Debt 484 375 484
Convertible Debentures1 115 195 115
Total Debt 599 570 599
Net Debt/2012e Cash Flow 1.8x 1.4x 1.8x
Total Debt/2012e Cash Flow 2.2x 2.2x 2.2x
Available Capacity ($550MM bank line) 138 245 138
Notes: 1) Assumes 2012 convertible maturity ($80MM) is refinanced with either high yield or convertible
debenture. 2015 maturity shown at face value and assumes no conversion in 2012.
16
18. Operate Across Western Canada
British Columbia Alberta
% Gas & NGL’s: 100% % Crude Oil: 45%
% of Production: 14% % of Production: 59%
SE Saskatchewan
% Crude Oil: 93%
% of Production: 25%
Cardium Oil
Mississippian Oil
Natural Gas
18
19. Reserves Profile
• P+P reserves: 104 MMBoe – 109% total production replacement
• Proved reserves: 68% of total P+P
• Current RLI: 9.4 years
• Mix: 50% Liquids – 50% Natural gas
• 3 yr average F&D of $18.80/boe; FD&A of $21.86/boe
120,000
100,000
Natural Gas
Reserves @ Jan 1 2011
Oil & Liquids
P+P Reserves (Mboe)
80,000
PROBABLE
60,000 32%
PROVED
40,000
PRODUCING
58%
20,000
PUD's
10%
0
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
19
20. Increasing RLI & Stable Reserves Per Share
10
9 • Production growth of 44%
over the same time
RLI (Years)
8
frame
7
6
5
2007 2008 2009 2010
0.70
0.60 • Stable reserves per share
0.50 performance reinvesting
approximately 59% of
Mboe / 000 units
0.40
0.30
cash flow
0.20
0.10
0.00
2007 2008 2009 2010
20
22. Operational Strategy
• Oil 85% of the capital program
• Deliver capital performance
• Actively managing execution risk
• Enhance capital / operational efficiency
• High grade opportunity inventory
• Farm-out unproven acreage
22
23. 2012 Capital Allocation
2011e 2012e
Drill, Complete & Tie-in 200 170
Plant & Facilities 18 10
Land & Seismic 18 10
Subtotal E&D 236 190
Other 10 10
Total 246 200
Note: Net dispositions totaled ~($29) MM in 2011
23
24. Capital Allocation By Play
Drill, Complete & Tie-in - $170 MM
$79
Cardium Oil $73
$51
$39
Mississippian Oil $51
$40
2012
$26 2011
Other Oil $34
$23 2010
$26
Liquids Rich Gas $42
$26
$0 $10 $20 $30 $40 $50 $60 $70 $80 $90
(Millions)
Note: Does not include G&A, Facilities, Land & Seismic.
24
26. Focusing Development on Best of Inventory
Title: Plot of Attribute A vesus Attribute B
Plot of Production Efficiency versus Recycle Ratio
-
Capital Efficiency ($/boed)
10,000
20,000
Increasing
30,000 Production
Volume
Potential
40,000 Greater Hoffer
MSSP Oil
50,000
Increasing Cash Flow Potential
60,000
1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0
Recycle Ratio
• 2012 program designed to drive cash flow
26
27. Lower Risk Profile in 2012 Drilling Program
2011 Program 2012e Program
Proof of Concept Development Proof of Concept Development
5%
17%
83% 95%
• A number of projects moving from positioning and appraisal phase in 2011 to
development phase in 2012 (Neptune, Sawn Lake, Cochrane, Fireweed)
27
28. Actively Managing Execution Risks
• Contracted equipment & core services
• Continuous programs to retain experienced crews
• Early regulatory and surface land approvals
• Operatorship and drill ready inventory provides
ability to substitute weather impacted areas
• Hoffer central gathering facility tied-in to
Enbridge – reduces costs and increases reliability
28
30. Cardium Oil: West Central AB
• Developing selectively to 3-4 wells/section
Garrington/ • Local sweet-spots emerging - focus on high-
Westward Ho
graded lands in Garrington/Westward Ho
• De-risking non-core through farm-outs
• New land deal completed in January 2012
Lochend
NAL Access Lands
Tier 1 Halo
Tier 2 Halo
Tier 3 Halo
Conventional
Gross Risked Locations assuming up to 4 wells/ sec
(see Appendix)
**Resource Halo Areas provided by Canadian Discovery
30
31. Cardium Oil: Cochrane / Lochend AB
• Sweet spot outperforming regional type
curve by 2-3 times
• New 3D applied to delineate sweet spot
• Solution gas infrastructure added
500
Lochend Sweet Spot
3D 450
Lochend Normal
400 WWHO
Production Volumes (Boe/d)
350 Garrington
300
250
200
150
100
NAL Access Lands
Key Penetrations
50
2012 Program 0
2011 Program 1 13 25 37 49
Month
31
32. Lochend Cardium Exceeding Expectations
Lochend
W5M 3-17-027-03 1-17-027-03 1-18-027-03 16-19-027-03 14-20-027-03 16-20-027-03 8-33-027-03
August 27, December 1, November 3, November 3, September December 1, August 6,
On Production
2010 2011 2011 2011 5, 2011 2011 2011
30 day IP
335 310 588 840 770 300 172
(boe/d)
90 day IP
268 - - - - - 162
(boe/d)
Current (boe/d) 174 153 258 660 234 167 100
Formation Cardium A Cardium A Cardium A Cardium A Cardium A Cardium A Cardium A
Frac Fluid Type Water Water Water Water Water Water Water
Number of Fracs 10 15 11 13 14 14 12
Lateral length
1,082 1,179 1,024 1,260 1,132 1,276 1,000
(m)
• Q4 2011 results set-up active program for 2012
• Liquids and solution gas handling facilities added in 2011
32
33. Production (Boe/d)
1000
1500
2000
2500
3000
3500
4000
4500
5000
0
500
Jan
Feb
Mar
Apr
May
Jun
2010
Jul
Aug
Sep
Oct
Nov
Dec
Jan
Base
Feb
Mar
Apr
May
Jun
2011
Cardium Volume Profile
Jul
Aug
Sep
Oct
Nov
Dec
Jan
2012 Program
Feb
Mar
Apr
May
Jun
300% volume growth over 3 years
Jul
2012
Aug
Sep
Oct
Nov
Dec
33
35. SE Saskatchewan - Mississippian
Chapleau Lake
Greater Williston Area
Weyburn
Hardy Nottingham/ Alida
Midale
Greater Hoffer
Area NAL Access Lands
Estevan Mississippian Oil Pools
3D Seismic Outline
Hoffer
• NAL has more than doubled land position in past 2 years
• Greater Hoffer area is core growth oil area for company
35
36. Mississippian Oil – SE Saskatchewan
Chapleau Lake • Greater Williston area
provides 3 to 5 year
inventory of low risk
development locations
• Significant oil & cash
Weyburn
generating region for NAL
since 1996
Nottingham/ Alida
Midale
Greater Williston Mississippian
Prospect Inventory: n=111
2012 Program
Estevan
NAL Access Lands 23
Mississippian Oil Pools 37
3D Seismic Outline Drillable Inventory
51 Contingent Locations
Gross Risked Locations (see Appendix)
Gross Risked Locations (see Appendix)
36
37. Mississippian Oil – Greater Hoffer
• Multiple play trends now proven
• Infrastructure in-place to:
Neptune o Facilitate pressure maintenance
New Pool Discovery
o Minimize production down-time
o Reduce operating costs
Beaubier
New Pool Discovery • Land position increasing through strategic
farm-ins completed in Q4/11
Oungre
Pool Extension
NAL Access Lands Mississippian Prospect
MSSP Producers
2012 Program Hoffer
2009 Pool Discovery
Inventory: n=114
2011 Program
MSSP Oil Pools 2012 Program
3D Seismic Outline
30
39
Area Play-Types Schematic Drillable Inventory
45
Contingent
Locations
Gross Risked Locations assuming 300 m inter-well spacing
(see Appendix)
37
38. Mississippian Oil Volume Profile
Strong cash generator with volumes returning to 2010 levels
Production (Boe/d)
2009 2010 2011e
Cash flow $100MM Cash flow $119MM Cash flow $125MM
Capex $23MM Capex $50MM Capex $57MM
Severe weather impacts
volumes Q1 through Q3 of 2011
2010 2011 2012
Base 2012 Program
38
40. Emerging Tight Oil Play – Sawn Lake
• Scalable, repeatable oil resource play
targeting Slave Point Platform Carbonates
– positioned in 2010 - 2011
3D • OOIP of up to 6 mmboe/section
• Ave 50% WI in 32 gross sections
• Analogous development at 8 wells/ sec
• Play de-risked by offsetting industry
activity
1-26-91-13W5
IP: 445 bopd Slave Point Prospect
& 2%WC Inventory: n=48
16-35-91-13W5 2
IP: 380 bopd
& 7%WC 2012 Program
20
NAL Access Lands
26 Drillable Inventory
SLVP Penetrations
2012 Program
2011 Program
Contingent Locations
Gross Risked Locations assuming 4 wells/ sec (see Appendix)
40
41. Montney – Fireweed - NE British Columbia
• Scalable liquids-rich gas discovery in H2/11
NAL Access Lands
MNTY Penetrations
• Initial liquids yield of ~100 bbl/mmcf
2012 Program
2011 Program • Initial gas rates of up to 4 mmcf/d
• EUR - 630 mboe per well
• 100% WI in 21 gas spacing units
• Second earning well drilled Q1/12
Montney Prospect Inventory:
n=20
1
2012 Program
8
11 Drillable Inventory
Contingent Locations
Gross Risked Locations assuming 3 wells/ sec (see Appendix)
41
42. Significant Potential To Increase Oil Reserves
Gross Net
Upside Upside
Total EUR per
Drillable Contingent Reserve Average Reserve
Risked Well
Inventory Inventory Potential WI% Potential
Locations (mboe)
(mmboe) (mmboe)
Cardium 151 191 342 170 58.1 65 37.8
Mississippian –
75 39 114 65 7.4 50 3.7
East
Mississippian –
74 37 111 85 9.4 50 4.7
West
Slave Point
28 20 48 170 8.2 100 8.2
Carbonate
Montney 12 8 20 630 12.6 100 12.6
635 95.7 67.0*
*Note: includes 9.2 mmboe of booked reserves
• Non-contingent development drilling inventory is drill-ready
• Well defined production and capital profiles
• Third Party activity is actively de-risking off-setting contingent locations
• Incremental potential exists at Fireweed and Sawn Lake to double location
tallies beyond that represented above
42
43. Extensive Land Base
NAL Access Lands (Gross Acres) NAL Undeveloped Access Lands
(Gross Acres)
195,000
294,000 Developed BC
271,000
955,000
Undeveloped Alberta
919,000
747,000
JV Saskatchewan
• 2.2 million gross acres • 1.2 million gross acres
Note: Excludes Approx 950,000 Acres (Gross) of undifferentiated Developed and Undeveloped Lands
43
47. Experienced Management Team
Andrew Wiswell
President & CEO
Keith Steeves Vacant Angele Mullins John Kanik John Koyanagi Clayton Paradis
VP Finance & CFO VP Ops & COO Director, HR Director, Marketing VP Business Dev. Director, IR
Tracy Heck David Allen Alex Tworo
Controller Director, E&D A&D Geology
Jim Van Camp
Saskatchewan BU
Lance Berg
Sylvan Lake BU
Darcy Reding
Western BU
Tim Brandenborg
Non-Operated BU
Darcy Erickson
Drilling &
Completions
Deric Orton
Director, Land
47
48. Strategic Partnership with Manulife
Manulife:
• Direct investor in oil and gas assets since
NAL Resources Management 1990
• Long term investment horizon
(manages 46,500 boe/d)
• Desire to increase investment
Terms of Administrative Cost Sharing
Agreement:
NAL Energy Manulife • No management or acquisition fees
• Shared G&A costs
28,500 18,000 • Independently controlled board
boe/d boe/d • Long term contract - 90 day NAL Energy
exit option
65% of assets are common Benefits:
90% are operated • Enhanced technical/financial capability
• Broad market view & investment discipline
• Financial partner in transactions
48
49. Non-Taxable For Many Years
Available Tax Pools $ MM
Canadian Exploration Expense 91
Canadian Development Expense 442
Canadian Oil & Gas Property Expense 417
Undepreciated Capital Costs 261
Other (including loss carry forwards) 328
Total 1,539
Note: as at September 30, 2011
49
50. NAL Shareholder Analysis
Income Focused
High Canadian Ownership
Institutional Presence
Foreign Manulife
3% 1%
U.S.
22%
Institutional
41%
Retail
Canadian 58%
75%
Note: As at September 30, 2011
50
51. Available Credit Lines
Credit Lines ($MM)
2011
Bank of Montreal* 145 $247 MM of
credit
Royal Bank of Canada 110 available as
at Sept. 30th
CIBC 87.5
Bank of Nova Scotia 87.5
Alberta Treasury Branch 40
National Bank Financial 40
Union Bank of California 40
Total 550
* Includes $15 million of working capital facility
51
52. Hedging Programs Manage Risk
• Objective - Protect cash flow for the purposes of
sustaining dividends and maintaining an active capital
program
• Board approval: maximum of 60% of net revenue
• Counterparties: all Canadian chartered banks
52
53. 2012 Hedging Program
• Crude oil hedges:
• 67% of 2012 oil volumes
• Average floor price of US$ 97.42/bbl
• Natural gas hedges:
• 12% of 2012 gas volumes
• Average floor price of C$ 4.05/GJ
• Interest rate:
• 30 – 35% of 2012 bank debt @ 1.71%*
• Foreign Exchange:
• 45% of 2012 US$ exposure @ 1.01(70% collared to 1.045)
* All in bank interest rate 5.1% after bank fees
53
54. Crude Oil Hedge Positions
Crude Oil Hedge Contracts as at 1/5/2012
Q1-12 Q2-12 Q3-12 Q4-12
US$ Collar Contracts
$US WTI Collar Volume (b/d) 900 900 700 700
Bought Puts – Average Strike Price ($US/bbl) 101.11 101.11 101.43 101.43
Sold Calls – Average Strike Price ($US/bbl) 117.07 117.07 117.66 117.66
US$ Swap Contracts
$US WTI Swap Volume (b/d)* 6,950 6,950 6,750 6,750
Average WTI Swap Price ($US/bbl) 97.03 97.03 96.93 96.93
Cdn$ Collar Contracts
$Cdn WTI Collar Volume (b/d)
Bought Puts – Average Strike Price ($Cdn/bbl)
Sold Calls – Average Strike Price ($Cdn/bbl)
Cdn$ Swap Contracts
$Cdn WTI Swap Volume (b/d)
Average WTI Swap Price ($Cdn/bbl)
Total Volume (b/d) 7,850 7,850 7,450 7,450
Note: All counterparties are Canadian banks in our syndicate.
• For calendar 2012, there are 4 swap contracts for a total of 1,250 bbl/d at an average price of $100.96, that contain extendable call options. These options
provide the counterparty with the right to extend the contract into calendar 2013 under the same price and volumetric terms. The counterparty can exercise
this option anytime before December 31, 2012.
54
55. Natural Gas Hedge Positions
Natural Gas Hedge Contracts as at 1/5/2012
Q1-12 Q2-12 Q3-12 Q4-12
Collar Contracts
AECO Collar Volume (GJ/d)
Bought Puts – AECO Average Strike Price
($Cdn/GJ)
Sold Calls – AECO Average Strike Price
($Cdn/GJ)
Swap Contracts
AECO Swap Volume (GJ/d) 24,000 5,000 5,000 3,674
AECO Average Price ($Cdn/GJ) 3.98 4.16 4.16 4.17
Total Volume (GJ/d) 24,000 5,000 5,000 3,674
Note: All counterparties are Canadian banks in our syndicate.
55
56. Interest Rate Hedge Positions
Financial Interest Rate Swap Contracts as at 1/5/2012
Remaining Term Notional (Cdn $MM) Floating Rate Fixed Rate
(Receive) (Pay)
Oct 2011– Jan 2013 22 CAD-BA-CDOR 3 month 1.3850%
Oct 2011– Jan 2014 22 CAD-BA-CDOR 3 month 1.5100%
Oct 2011 – Mar 2013 14 CAD-BA-CDOR 3 month 1.8500%
Oct 2011 – Mar 2013 14 CAD-BA-CDOR 3 month 1.8750%
Oct 2011 – Mar 2014 14 CAD-BA-CDOR 3 month 1.9300%
Oct 2011 – Mar 2014 14 CAD-BA-CDOR 3 month 1.9850%
Total Notional (Cdn $) 100*
* Fixed approximately 30% of floating bank debt ($325MM average for 2012e)
Note: All counterparties are Canadian banks in our syndicate.
56
57. Foreign Exchange Hedge Positions
Notional (US) per Term Counterparty Floating Rate
Option Fixing Range month
(USD/CAD)
0.97 – 1.04 $1.0 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate
When the monthly average noon spot foreign exchange rate exceeds the fixing range, NAL is committed to selling the above listed USD at the lower fixing rate
for that month. To the extent the monthly average spot foreign exchange rate is below the lower fixing rate, NAL has a commitment to sell the above listed
USD at the lower fixing rate. When the monthly average noon spot foreign exchange rate falls within the fixing range, NAL has no commitment to sell USD.
Option Payout Range Notional (US) per Term Counterparty Floating Rate Monthly
(USD/CAD) month Premium
Received
0.93 - 1.01 $2.0 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate CAD $40K
0.90 - 1.15 $1.0 MM Jan 1, 2013 to Sept 30, 2013 BofC Monthly Average Noon Rate CAD $40K
When the monthly average noon spot foreign exchange rate is outside the payout range, the monthly premium is forfeited. NAL is committed to selling the
above listed USD at the upper payout range value for that month when the average noon spot foreign exchange rate exceeds the payout range.
Fade-in Level Strike Price Participation Level Notional (US) Term Counterparty Floating Rate
(USD/CAD) (USD/CAD) (USD/CAD) per month
0.92 0.985 1.03 $2.0 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate
0.91 1.0075 1.05 $1.5 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate
0.935 1.00 1.05 $0.5 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate
0.92 1.012 1.0625 $0.5 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate
0.92 0.995 1.035 $1.0 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate
0.93 1.04 1.075 $0.5 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate
0.90 1.065 1.15 $1.0 MM Jan 1, 2013 to Sept 30, 2013 BofC Monthly Average Noon Rate
NAL is fixed to sell USD on a monthly basis at the strike price. If the Bank of Canada monthly average noon rate is below the fade-in level or between the strike and
participating level, NAL has no commitment to sell USD.
Note: FX contracts as at 01/05/2012.
57
58. Foreign Exchange Hedge Positions
Fixed Rate Notional (US) Term Counterparty Floating Rate
(USD/CAD) per month
0.9954 $2.0 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate
1.0565 $1.5 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate
NAL has a monthly commitment to settle the above fixed rates against the Bank of Canada monthly average noon rate.
Note: FX contracts as at 01/05/2012.
58
60. Understanding Our Inventory
Geoscience Professionals
feeding Prospect Hopper
Economic
Prospect Proven
Attributes Well Constrained by Mapping
Positioning complete
Un-Risked
Tier 1 locations Tier 2 locations Tier 3 locations
Inventory
(n=2,750)
Risk Execution Barriers
Factors Failed Proof-of-concept
Positioning Barriers
80%
50%
20%
>100% ROR
Drillable
Immediately Drillable in Risked
20% ROR
Near Term Drillable in Inventory
Medium Term (n=1,150)
60
61. Understanding Our Inventory
• Drillable Inventory equals
• 100% of Tier 1 Locations
• Total Risked Inventory equals
• 90% of Tier 1 locations plus
• 50% of Tier 2 locations plus
• 10% of Tier 3 locations
• Contingent Inventory equals
• Total Risked Inventory minus Drillable Inventory
61
62. 2010 – Stable Reserves Performance
• Reserves performance in the McDaniel report
was stable and predictable
• 109% total production replacement,
approximately 90% through the drill bit
• 3 yr average F&D of $18.80/boe; FD&A of
$21.86/boe
62
63. Reserves & Capital Efficiency Summary
2010 2009
Reserves (MMboe)
Proved 71.0 70.91
Proved + Probable (“P+P) 103.9 102.21
P+P Reserves/sh (boe/sh) 0.71 0.74
RLI (years)
P+P 9.4 9.2
Reserves Replacement Ratio
P+P (excluding A&D) 90% 131%
P+P (including A&D) 109% 445%
Three Year
Weighted Average
Including Changes in Future Development Capital 2010 2009 2008 2008 – 2010
Finding & Development Costs ($/boe)
Proved 21.41 18.52 14.18 17.92
P+P 22.60 17.86 16.24 18.80
F&D Recycle Ratio(3)
Proved 1.4 1.7 3.0 1.9
P+P 1.3 1.8 2.6 1.8
Finding, Development & Acquisition Costs ($/boe)
Proved 22.37 27.87 19.41 24.77
P+P 22.85 22.33 19.66 21.86
63
64. Conservatively Booked Reserves
PDP reserves represent a high percentage of total proved
80,000
85% 86%
70,000
60,000
94%
95%
50,000 93%
94%
Mboe
40,000
30,000 96%
20,000
10,000
0
2004 2005 2006 2007 2008 2009 2010
PROVED PRODUCING
64
66. Stable Reserves Per Share Performance
Stable reserves per share performance reinvesting approximately 59% of cash flow
0.70
0.60
0.50
Mboe / 000 units
0.40
0.30
0.20
0.10
0.00
2007 2008 2009 2010
Note: DARPU calculated using year-end reserves, net debt, convertibles and units outstanding.
Net debt converted to units using annual average unit price. Converts converted to units at strike price
66
67. Stable Production Per Share Performance
Stable production per share performance reinvesting
approximately 59% of cash flow
120 35,000
100
30,000
80
Production (boe/d)
boe / 000 units
25,000
60
20,000
40
15,000
20
0 10,000
2007 2008 2009 2010
P+P Reserves Per Unit Annual Average Production
Note: Production per unit calculated using annual average production and annual average units outstanding.
This metric is not debt-adjusted given complications in calculating average annual debt figures.
67
68. 2012 Sensitivities on FFO
Impact on FFO – Excluding Hedges
Change ($MM) $/share
WTI ($US/bbl) $5.00 16.9 0.11
AECO ($C/GJ) $0.50 14.4 0.09
FX (CAD/US) $0.01 3.4 0.02
Prime Rate 1.0% 3.4 0.02
Production (bbl/d) 100 2.1 0.01
Production (mmcf/d) 1 0.4 0.003
Oil Differential 1.0% 3.9 0.03
Gas Differential 1.0% 0.9 0.01
Note: Excludes impact of hedge contracts
68
69. 2012 Sensitivities on FFO
Impact on FFO – Including Hedges
($MM) $/share
WTI ($US/bbl) $5.00 2.9 0.02
AECO ($C/GJ) $0.50 12.7 0.08
FX (CAD/US) $0.01 2.3 0.02
Prime Rate 1.0% 2.4 0.02
Note: Includes impact of hedge contracts
69
71. Sell-side Research
Analyst Firm Recommen
Gordon Tait BMO Capital Markets Market
Grant Hofer Barclays Capital Unde
Jeremy Kaliel CIBC World Markets Sector Outpe
Kevin C.H. Lo FirstEnergy Capital Market
Stacey McDonald GMP Securities
Cristina Lopez Macquarie Capital
Kyle Preston National Bank Financial Out
Jeff Martin Peters & Co. Sector
Kristopher Zack Raymond James Market
Mark Friesen RBC Capital Markets Sector
Gordon Currie Salman Partners
Patrick Bryden Scotia Capital Sector
Michael Zuk Stifel Nicolaus
Travis Wood TD Securities
71
72. New Cardium Land Deal Increases Inventory
• New four year deal finalized January 2012
• Net $6MM commitment per year
• Access to 280 (182 net) sections of Cardium
prospective land directly offsetting existing
Garrington/Westward Ho acreage
• Adds 50 new drillable Cardium locations plus
future upside
72
73. Corporate Information
EXECUTIVE TEAM TRUSTEE AND TRANSFER AGENT
Andrew Wiswell President & CEO Computershare Trust Company
of Canada
Keith Steeves VP Finance & CFO
AUDITOR
John Koyanagi VP Business Development
KPMG
ENGINEERING CONSULTANTS
INVESTOR RELATIONS McDaniel & Associates
Clayton Paradis Director, Investor Relations LEGAL COUNSEL
Local: (403) 294-3620 Bennett Jones LLP
Toll-free: (888) 223.8792 STOCK EXCHANGE LISTING
E-mail: investor.relations@nal.ca & SYMBOL
Toronto Stock Exchange: NAE
EXECUTIVE OFFICE
1000 – 550 6th Avenue SW, Calgary, Alberta, T2P 0S2
Website: www.nalenergy.com
73
