1. Corporate Presentation
March, 2012

2. NAL Energy Corporation Profile
TSX Symbol NAE
Market Capitalization1 $1.1 Billion
Monthly Dividend $0.05/share
Net Debt2 $363 Million
Current Shares Outstanding2 151.9 Million
Convertible Debentures
Trading Symbol NAE.DB NAE.DB.A NAE.DB.B
Coupon 6.75% 6.25% 6.25%
Principal Outstanding ($MM) 80 115 150
Conversion Price ($/share) 14.0 16.50 9.90
Maturity Date 31AUG12 31DEC14 31MAR17
Notes:
1) As at March 7, 2012
2) As at 31DEC11
2

3. 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
• Disciplined acquisition focus
• Balance dividend with sustaining capital
3

4. Key Focus – Grow Liquids Volumes
16,000
15,000
14,000
13,000
Volumes (boe/d)
12,000
11,000
10,000
9,000
8,000
Q1/11 Q2/11 Q3/11 Q4/11 Q1/12E Q2/12E Q3/12E Q4/12E
NAL Liquids Volumes
4

5. 2012 Corporate Plan
• Grow liquids volumes – oil +4%, liquids mix @ 50%
• Capital focused on high ROR and recycle ratio projects
• Higher proportion of low risk development capital
• Continued appraisal activity in new oil resource plays
• Maintain financial flexibility
5

6. Executed Financial Action Plan
Reduced monthly
dividend to $0.05
per share
Maintain credit
Refinanced 2012
lines by
convertible
focusing capital
maturity ($80MM)
on oil and
with bank debt
Financial liquids plays
Flexibility
Converted bank
Termed out $150 MM
line from one to
of bank debt with
three year term
convertible
in 2011
6

7. 2012 Full Year Guidance
• Production (boe/d) 28,000 – 29,000
• Capital ($MM) 200
• Operating Costs ($/boe) 11.50 – 12.00
7

8. 2011 Fourth Quarter & Full Year Results
• Q4 volumes of 29,795 boe/d exceeded expectations
• Oil & liquids volumes up 19% from Q2 to Q4
• Cash flow of $0.45 per share beat forecast
• Full year operating netback of $30.41/boe was up 11% y-
o-y
• Added acreage in two of NAL’s core oil properties – Cardium in AB &
Mississippian in SK
8

9. Reserves Profile
• P+P reserves: 104 MMBoe – 100% total production replacement
• Proved reserves: 64% of total P+P
• Current RLI: 10.0 years
• Higher liquids mix in 2011: 51% Liquids – 49% Natural gas
• 3 yr average F&D including FDC of $21.99/boe; FD&A of $21.99/boe
120,000 Reserves @ Jan 1 2012
100,000
Natural Gas
P+P Reserves (Mboe)
80,000
Oil & Liquids
PROBABLE
60,000 36% PROVED
PRODUCING
56%
40,000
20,000
PUD's
8%
0
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
9

10. Reserves & Capital Efficiency Summary
2011 2010
Reserves (MMboe)
Proved 66.2 71.0
Proved + Probable (“P+P) 103.8 103.9
P+P Reserves/sh (boe/sh) 0.69 0.71
RLI (years)
P+P 10.0 9.4
Reserves Replacement Ratio
P+P (excluding A&D) 127% 90%
P+P (including A&D) 99% 109%
Three Year
Weighted Average
Including Changes in Future Development Capital 2011 2010 2009 2009 – 2011
Finding & Development Costs ($/boe)
Proved 27.09 21.41 18.52 21.99
P+P 24.86 22.60 17.86 21.99
F&D Recycle Ratio(3)
Proved 1.1 1.4 1.7 1.4
P+P 1.2 1.3 1.8 1.4
Finding, Development & Acquisition Costs ($/boe)
Proved 33.16 22.37 27.87 27.23
P+P 29.23 22.85 22.33 23.59
10

11. Operate Across Western Canada
British Columbia
% Gas & NGL’s: 100%
Alberta
% of Production: 14%
% Crude Oil: 45%
% of Production: 59%
SE Saskatchewan
% Crude Oil: 93%
% of Production: 25%
Cardium Oil
Mississippian Oil
Natural Gas
11

12. 2012 Operational Strategy
• Go forward - Oil 100% of the capital program
• Deliver capital performance – execution/results
• High grade opportunity inventory
• Farm-out high risk/unproven acreage
12

13. 2012 Capital – Focused Development
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
13

14. 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.
14

15. 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
15

16. 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
16

17. 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
17

18. 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
18

19. 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 increased through strategic farm-ins
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)
19

20. 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 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)
20

21. Montney – Fireweed - NE British Columbia
• Discovery well – IP’d >1,000 boe/d @ 100
NAL Access Lands bbls/mmcf of liquids
MNTY Penetrations
2012 Program
2011 Program • EUR - 630 Mboe per well
• 100% WI in 21 gas spacing units (sections)
• 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)
21

22. 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 50 4.1
Carbonate
Montney 12 8 20 630 12.6 100 12.6
635 95.7 62.9*
*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
22

23. 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
23

24. Summary & Key Messages
Attractive Sustainable
relative business
valuation model
Increasing Capital
liquids focused in
volumes core areas
24

25. Appendix

26. 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
26

27. Non-Taxable For Many Years
Available Tax Pools $ MM
Canadian Exploration Expense 91
Canadian Development Expense 516
Canadian Oil & Gas Property Expense 398
Undepreciated Capital Costs 245
Other (including loss carry forwards) 136
Total 1,386
Note: as at December 31, 2011
27

28. NAL Shareholder Analysis
Income Focused
High Canadian Ownership Institutional Presence
Foreign Manulife
8% 1%
U.S. Institutional
21% 39%
Canadian
Retail
71%
60%
Note: As at December 31, 2011
28

29. Available Credit Lines
Credit Lines ($MM)
2011
Bank of Montreal* 145 $365 MM of
credit
Royal Bank of Canada 110 available as
at Mar. 7th
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
29

30. 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
30

31. 2012 Hedging Program
• Crude oil hedges - 7,878 bbls of 2012 oil volumes
• Average floor price of US$ 97.37/bbl on swaps
• Average floor price of US$ 101.25/bbl on collars
• Natural gas hedges - 12,396 of 2012 gas volumes
• Average floor price of C$ 3.88/GJ on swaps
• Average floor price of C$ 2.50/GJ on collars
• Interest rate:
• 35 – 40% 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 4.7% after bank fees
31

32. Crude Oil Hedge Positions
Crude Oil Hedge Contracts as at 3/7/2012
Q1-12 Q2-12 Q3-12 Q4-12 Q1-13 Q2-13 Q3-13 Q4-13
US$ Collar Contracts
WTI Collar Volume (bbls/d) 900 900 700 700
Bought Puts – Avg. Strike Price ($/bbl) 101.11 101.11 101.43 101.43
Sold Calls – Avg. Strike Price ($/bbl) 117.07 117.07 117.66 117.66
US$ Swap Contracts
WTI Swap Volume (bbls/d) 7,115 7,200 7,000 7,000 500 500 500 500
Avg. WTI Swap Price ($/bbl)* 97.30 97.44 97.36 97.36 100.95 100.95 100.95 100.95
Total Oil Volume (bbls/d) 8,015 8,100 7,700 7,700 500 500 500 500
US$ Option Contracts
Volume (bbls/d) 2,000 2,000 2,000 2,000
Sold Calls – Avg. WTI Strike Price ($/bbl) 110 110 110 110
Premium Received ($/bbl/d) 10.33 10.33 10.33 10.33
Note: All counterparties are Canadian banks in our syndicate.
Quarterly contracts are a sum of multiple contracts aggregated for summary presentation.
Average prices are the weighted average price of all contracts summed in the respective quarters.
• For 2012, there are five swa p contracts for a total of 1,500 bbl/day at an average contract price of $102.30 that contain extendable call options. These call
options provide the Counterparty with the option to extend the contract into calendar 2013 under the same price and volumetric terms. The counterparty can
exercise this option at any time prior to December 31, 2012.
32

33. Natural Gas Hedge Positions
Natural Gas Hedge Contracts as at 3/7/2012
Q1-12 Q2-12 Q3-12 Q4-12 Q1-13 Q2-13 Q3-13 Q4-13
C$ Collar Contracts
AECO Collar Volume (GJ/d) 2,000 2,000 2,000 2,000 2,000 2,000 2,000
Bought Puts & Avg Strike Price ($/GJ) $2.50 $2.50 $2.50 $2.50 $2.50 $2.50 $2.50
Sold Calls – Avg. Strike Price ($/GJ) $3.05 $3.05 $3.05 $3.05 $3.05 $3.05 $3.05
C$ Swap Contracts
AECO Swap Volume (GJ/d) 24,000 7,000 7,000 5,674 2,000 2,000 2,000 2,000
AECO Avg. Price ($/GJ) $3.98 $3.77 $3.77 $3.69 $2.81 $2.81 $2.81 $2.81
Total Natural Gas Volume (GJ/d) 24,000 9,000 9,000 7,674 4,000 4,000 4,000 4,000
Note: All counterparties are Canadian banks in our syndicate.
Quarterly contracts are a sum of multiple contracts aggregated for summary presentation.
Average prices are the weighted average price of all contracts summed in the respective quarters.
33

34. Interest Rate Hedge Positions
Financial Interest Rate Swap Contracts as at 3/7/2012
Remaining Term Notional Amount Floating Rate Fixed Rate
(C$ MM) (Receive) (Pay)
Jan 2012 – Jan 2013 22 CAD-BA-CDOR 3 month 1.3850%
Jan 2012 – Jan 2014 22 CAD-BA-CDOR 3 month 1.5100%
Jan 2012 – Mar 2013 14 CAD-BA-CDOR 3 month 1.8750%
Jan 2012 – Mar 2014 14 CAD-BA-CDOR 3 month 1.9850%
Jan 2012 – Mar 2013 14 CAD-BA-CDOR 3 month 1.8500%
Jan 2012 – Mar 2014 14 CAD-BA-CDOR 3 month 1.9300%
Total Notional (Cdn $) 100*
* Fixed approximately 40% of floating bank debt ($250MM average for 2012e)
Note: All counterparties are Canadian banks in our syndicate.
34

35. Foreign Exchange Hedge Positions
Optional Fixing Range Notional (US) per Term Counterparty Floating Rate
(USD/CAD) month
0.97 – 1.04 $1.0 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate
NAL has a commitment to sell the above notional USD at the lower fixing rate versus the Bank of Canada monthly average noon rate. If the Bank of Canada
monthly average noon rate falls within the option fixing range. NAL has no commitments to sell USD.
Option Payout Range Notional (US) per Term Counterparty Floating Rate Monthly
(USD/CAD) month Premium
Received
0.93 - 1.03 $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 upper 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 03/07/2012.
35

36. Foreign Exchange Hedge Positions – Cont’d
Fixed Rate Notional (US) per Term Counterparty Floating Rate
(USD/CAD) 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 notional amount of the above fixed rates against the Bank of Canada monthly
average noon rate.
Note: FX contracts as at 3/7/2012.
36

37. 2012 Program: Half Cycle Play Metrics
BTAX NPV @15 - Gross
BTAX Payout (mnths)
EUR per Well - Gross
DCET Capital- Gross
Approximate %WI
Recycle Ratio (x)
Netback ($/boe)
2012e Program
F & D ($/boe)
BTAX ROR (%)
(mboe)
% Gas
($MM)
($MM)
Cochrane CRDM 65 3.5 - 3.7 200 - 300 21 12 - 20 60 3.5 - 5.0 1.7 - 6.0 30 - 200 8 - 36 16
Garr/ WWho CRDM 65 - 70 3.0 -3.3 160 20 20 75 4.0 1.4 - 1.7 34 - 40 24 - 30 15
Deep Basin Gas 20 - 70 3.0 - 6.0 300 - 550 60 - 94 9 - 14 20 - 35 2.0 - 4.0 0.6 - 2.0 20 - 50 22 - 40 10
Fireweed- MNTY 100 7.5 - 9.0 630 60 14 29 2.1 0.45 17 58 1
SW Williston MSSP 50 1.8 - 2.3 85 - 105 0 20 - 27 55 - 60 2.0 - 3.0 0.8 - 1.4 30 - 50 24 - 36 23
Greater Williston MSSP 35 - 100 1.2 - 1.7 60 - 70 0 - 10 18 - 28 70 - 85 2.5 - 4.0 0.9 - 1.9 45 - 190 12 - 24 22
Sawn Lake- SLVP 50 4.0 - 5.0 167 5 25 62 2.5 1.9 55 15 2
Other Oil 35 - 100 1.5 - 3.0 80 - 270 0 - 60 6 - 30 40 - 60 2.0 - 9.0 0.8 - 3.5 35 - 200 10 - 34 24
Misc. 11
Note: See Appendix for price assumptions
37

38. 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)
38

39. 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
39

40. Conservatively Booked Reserves
PDP reserves represent a high percentage of total proved
80,000
94% 95%
70,000
94%
60,000
93%
96%
50,000
Mboe
40,000
30,000
20,000
10,000
0
2007 2008 2009 2010 2011
PROVED PRODUCING PROVED NON-PRODUCING & UNDEVELOPED
40

41. Conservatively Booked Reserves
Probables represent a low percentage of total P+P reserves
120,000
30% 27% 28%
100,000
80,000 30%
29%
Mboe
60,000
40,000
20,000
0
2007 2008 2009 2010 2011
PROVED PROBABLE
41

42. Increasing Reserves Life Index
NAL’s RLI has increased to 10 years in 2011
10
9
RLI (Years)
8
7
6
5
2007 2008 2009 2010 2011
42

43. Stable Reserves Per Share Performance
Stable reserves per share performance reinvesting approximately 66% 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 2011
Note: DARPS calculated using year-end reserves, net debt, convertibles and shares outstanding.
Net debt converted to shares using annual average share price. Converts converted to shares at strike price
43

44. Stable Production Per Share Performance
120
100
80
boe / 000 units
60
40
20
0
2007 2008 2009 2010 2011
P+P Reserves Per Unit
Note: Production per share calculated using annual average production and annual average shares outstanding.
This metric is not debt-adjusted given complications in calculating average annual debt figures.
44

45. 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
45

46. 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
46

47. Economic Evaluation Price Assumptions
Edmonton Par ($C/bbl) AECO Gas ($C/GJ)
2012 88.95 3.50
2013 92.00 3.90
2014 93.98 4.15
2015 95.96 4.40
2016 97.94 4.65
Thereafter +2%/year +2%/year
47

48. Sell-side Research
Analyst Firm
Gordon Tait BMO Capital Markets
Grant Hofer Barclays Capital
Jeremy Kaliel CIBC World Markets
Katrina Karkkainen FirstEnergy Capital
Stacey McDonald GMP Securities
Cristina Lopez Macquarie Capital
Kyle Preston National Bank Financial
Cindy Mah Peters & Co.
Kristopher Zack Raymond James
Mark Friesen RBC Capital Markets
Gordon Currie Salman Partners
Patrick Bryden Scotia Capital
Michael Zuk Stifel Nicolaus
Travis Wood TD Securities
48

49. 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: ir@nal.ca & SYMBOL
Toronto Stock Exchange: NAE
EXECUTIVE OFFICE
1000 – 550 6th Avenue SW, Calgary, Alberta, T2P 0S2
Website: www.nalenergy.com
49

50. 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.
50