NAL Energy Corporation - Corporate Presentation - January 2012

1. Corporate Presentation
January, 2012

2. NAL Energy Corporation Profile
2
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

3. Strategic Direction – Long Term Sustainability
3
• 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

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

5. 2012 Corporate Plan
5
1. Grow liquids volumes
• Forecast oil volumes up 5% / Liquids mix 47% to 50%
2. Capital focused on high ROR and recycle ratio projects
• Oil focused capital projects / higher liquids yields
3. Higher proportion of low risk development capital
4. Continued appraisal activity in new oil resource plays
5. Maintain financial flexibility

6. Financial Action Plan
6
Reduce monthly
dividend to $0.05
per share
Maintain credit
lines by
focusing capital
on oil and
liquids plays
Converted bank
line from one to
three year term
in 2011
Term out a
portion of existing
bank line with
high yield
Refinance 2012
convertible
maturity ($80MM)
with debt
Financial
Flexibility

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

8. 8
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 .

9. 9
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

10. 10
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.

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

12. Operational Strategy
12
• 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

13. 13
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

14. Capital Allocation By Play
14
$26
$23
$40
$51
$42
$34
$51
$73
$26
$26
$39
$79
$0 $10 $20 $30 $40 $50 $60 $70 $80 $90
Liquids Rich Gas
Other Oil
Mississippian Oil
Cardium Oil
(Millions)
2012
2011
2010
Note: Does not include G&A, Facilities, Land & Seismic.
Drill, Complete & Tie-in - $170 MM

15. Cardium Oil: West Central AB
15
**Resource Halo Areas provided by Canadian Discovery
• Developing selectively to 3-4 wells/section
• Local sweet-spots emerging - focus on high-
graded lands in Garrington/Westward Ho
• De-risking non-core through farm-outs
• New land deal completed in January 2012
Gross Risked Locations assuming up to 4 wells/ sec
(see Appendix)
NAL Access Lands
Tier 1 Halo
Tier 2 Halo
Tier 3 Halo
Conventional
Garrington/
Westward Ho
Lochend

16. New Cardium Land Deal Increases Inventory
16
• 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

17. Cardium Oil: Cochrane / Lochend AB
17
• Sweet spot outperforming regional type
curve by 2-3 times
• New 3D applied to delineate sweet spot
• Solution gas infrastructure added
3D
0
50
100
150
200
250
300
350
400
450
500
1 13 25 37 49
ProductionVolumes(Boe/d)
Month
Lochend Sweet Spot
Lochend Normal
WWHO
Garrington
NAL Access Lands
Key Penetrations
2012 Program
2011 Program

18. Lochend Cardium Exceeding Expectations
18
• Q4 2011 results set-up active program for 2012
• Liquids and solution gas handling facilities added in 2011
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
On Production
August 27,
2010
December 1,
2011
November 3,
2011
November 3,
2011
September
5, 2011
December 1,
2011
August 6,
2011
30 day IP
(boe/d)
335 310 588 840 770 300 172
90 day IP
(boe/d)
268 - - - - - 162
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
(m)
1,082 1,179 1,024 1,260 1,132 1,276 1,000

19. 30
45
39
Mississippian Prospect
Inventory: n=114
2012 Program
Drillable Inventory
Contingent
Locations
Mississippian Oil – Greater Hoffer
19
• Multiple play trends now proven
• Infrastructure in-place to:
o Facilitate pressure maintenance
o Minimize production down-time
o Reduce operating costs
• Land position increasing through strategic
farm-ins completed in Q4/11
Gross Risked Locations assuming 300 m inter-well spacing
(see Appendix)
NAL Access Lands
MSSP Producers
2012 Program
2011 Program
MSSP Oil Pools
3D Seismic Outline
Area Play-Types Schematic
Hoffer
2009 Pool Discovery
Beaubier
New Pool Discovery
Neptune
New Pool Discovery
Oungre
Pool Extension

20. Emerging Tight Oil Play – Sawn Lake
20
• Scalable, repeatable oil resource play
targeting Slave Point Platform Carbonates
– positioned in 2010 - 2011
• 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
2
26
20
Slave Point Prospect
Inventory: n=48
2012 Program
Drillable Inventory
Contingent Locations
Gross Risked Locations assuming 4 wells/ sec (see Appendix)
NAL Access Lands
SLVP Penetrations
2012 Program
2011 Program
3D
1-26-91-13W5
IP: 445 bopd
& 2%WC
16-35-91-13W5
IP: 380 bopd
& 7%WC

21. Montney – Fireweed - NE British Columbia
21
• Scalable liquids-rich gas discovery in H2/11
• Initial production – 1,000 boe/d @ 100
bbls/mmcf of liquids
• EUR - 630 mboe per well
• 100% WI in 21 gas spacing units (sections)
• Second earning well drilled Q1/12
1
11
8
Montney Prospect Inventory:
n=20
2012 Program
Drillable Inventory
Contingent Locations
Gross Risked Locations assuming 3 wells/ sec (see Appendix)
NAL Access Lands
MNTY Penetrations
2012 Program
2011 Program

22. Significant Potential To Increase Oil Reserves
22
Gross Net
Drillable
Inventory
Contingent
Inventory
Total
Risked
Locations
EUR per
Well
(mboe)
Upside
Reserve
Potential
(mmboe)
Average
WI%
Upside
Reserve
Potential
(mmboe)
Cardium 151 191 342 170 58.1 65 37.8
Mississippian –
East
75 39 114 65 7.4 50 3.7
Mississippian –
West
74 37 111 85 9.4 50 4.7
Slave Point
Carbonate
28 20 48 170 8.2 100 8.2
Montney 12 8 20 630 12.6 100 12.6
635 95.7 67.0*
• 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
*Note: includes 9.2 mmboe of booked reserves

23. Extensive Land Base
23
Note: Excludes Approx 950,000 Acres (Gross) of undifferentiated Developed and Undeveloped Lands
955,000
919,000
294,000
NAL Access Lands (Gross Acres)
Developed
Undeveloped
JV
195,000
747,000
271,000
NAL Undeveloped Access Lands
(Gross Acres)
BC
Alberta
Saskatchewan
• 2.2 million gross acres • 1.2 million gross acres

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

25. Appendix

26. 26
Experienced Management Team
Andrew Wiswell
President & CEO
John Kanik
Director, Marketing
Alex Tworo
A&D Geology
John Koyanagi
VP Business Dev.
Clayton Paradis
Director, IR
Tracy Heck
Controller
Vacant
VP Ops & COO
Keith Steeves
VP Finance & CFO
Angele Mullins
Director, HR
David Allen
Director, E&D
Deric Orton
Director, Land
Darcy Reding
Western BU
Tim Brandenborg
Non-Operated BU
Darcy Erickson
Drilling &
Completions
Jim Van Camp
Saskatchewan BU
Lance Berg
Sylvan Lake BU

27. 27
Manulife:
• Direct investor in oil and gas assets since
1990
• Long term investment horizon
• Desire to increase investment
Terms of Administrative Cost Sharing
Agreement:
• No management or acquisition fees
• Shared G&A costs
• Independently controlled board
• Long term contract - 90 day NAL Energy
exit option
Benefits:
• Enhanced technical/financial capability
• Broad market view & investment discipline
• Financial partner in transactions
Strategic Partnership with Manulife
NAL Resources Management
(manages 46,500 boe/d)
65% of assets are common
90% are operated
NAL Energy
28,500
boe/d
Manulife
18,000
boe/d

28. Non-Taxable For Many Years
28
Note: as at September 30, 2011
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

29. Canadian
75%
U.S.
22%
Foreign
3%
Institutional
41%
Retail
58%
Manulife
1%
29
NAL Shareholder Analysis
Income Focused
Institutional Presence
High Canadian Ownership
Note: As at September 30, 2011

30. 30
Available Credit Lines
Credit Lines ($MM)
2011
Bank of Montreal* 145
Royal Bank of Canada 110
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
$247 MM of
credit
available as
at Sept. 30th

31. Hedging Programs Manage Risk
31
• 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

32. 2012 Hedging Program
32
•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

33. 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 $100.96, that contain extendable call options. These options
provide the counterparty with the right to extend the contract into calendar 2013 under the same price and volumetric terms. The counterparty can exercise
this option anytime before December 31, 2012.
33
Crude Oil Hedge Positions
Crude Oil Hedge Contracts as at 1/5/2012
Q1-12 Q2-12 Q3-12 Q4-12
US$ 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

34. 34
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.

35. 35
Interest Rate Hedge Positions
Financial Interest Rate Swap Contracts as at 1/5/2012
Remaining Term Notional (Cdn $MM) Floating Rate
(Receive)
Fixed Rate
(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.

36. 36
Foreign Exchange Hedge Positions
Option Fixing Range
(USD/CAD)
Notional (US) per
month
Term Counterparty Floating Rate
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.
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.
Note: FX contracts as at 01/05/2012.
Fade-in Level
(USD/CAD)
Strike Price
(USD/CAD)
Participation Level
(USD/CAD)
Notional (US)
per month
Term Counterparty Floating Rate
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
Option Payout Range
(USD/CAD)
Notional (US) per
month
Term Counterparty Floating Rate Monthly
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
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.

37. 37
Foreign Exchange Hedge Positions
Fixed Rate
(USD/CAD)
Notional (US)
per month
Term Counterparty Floating Rate
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.

38. 2012 Program: Half Cycle Play Metrics
38
Note: See Appendix for price assumptions
Approximate%WI
DCETCapital-Gross
($MM)
EURperWell-Gross
(mboe)
%Gas
F&D($/boe)
Netback($/boe)
RecycleRatio(x)
BTAXNPV@15-Gross
($MM)
BTAXROR(%)
BTAXPayout(mnths)
2012eProgram
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

39. Understanding Our Inventory
39
Prospect
Attributes
Risked
Inventory
>100% ROR
Tier 1 locations Tier 2 locations Tier 3 locations
Failed Proof-of-concept
Positioning Barriers
Execution Barriers
80%
50%
20%
Drillable
Immediately
Proven
Economic
Well Constrained by Mapping
Positioning complete
Drillable in
Near Term Drillable in
Medium Term
20% ROR
Geoscience Professionals
Feeding Prospect Hopper
Un-Risked
Inventory
(n=2,750)
(n=1,150)
Risk
Factors

40. Understanding Our Inventory
40
• 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

41. 2010 – Stable Reserves Performance
41
•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

42. 42
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

43. 43
PDP reserves represent a high percentage of total proved
Conservatively Booked Reserves
96%
93%
94%
95%
94%
85% 86%
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
2004 2005 2006 2007 2008 2009 2010
Mboe
PROVED PRODUCING

44. 44
Probables represent a low percentage of total P+P reserves
Conservatively Booked Reserves
29%
30%
30%
27%
28%
31% 32%
0
20,000
40,000
60,000
80,000
100,000
120,000
2004 2005 2006 2007 2008 2009 2010
Mboe
PROVED PROBABLE

45. 45
Stable Reserves Per Share Performance
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
Stable reserves per share performance reinvesting approximately 59% of cash flow
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
2007 2008 2009 2010
Mboe/000units

46. 46
Stable Production Per Share Performance
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.
Stable production per share performance reinvesting
approximately 59% of cash flow
10,000
15,000
20,000
25,000
30,000
35,000
0
20
40
60
80
100
120
2007 2008 2009 2010
Production(boe/d)
boe/000units
P+P Reserves Per Unit Annual Average Production

47. 47
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

48. 48
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

49. Economic Evaluation Price Assumptions
49
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

50. 50
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

51. 51
EXECUTIVE TEAM
Andrew Wiswell President & CEO
Keith Steeves VP Finance & CFO
John Koyanagi VP Business Development
INVESTOR RELATIONS
Clayton Paradis Director, Investor Relations
Local: (403) 294-3620
Toll-free: (888) 223.8792
E-mail: investor.relations@nal.ca
Corporate Information
TRUSTEE AND TRANSFER AGENT
Computershare Trust Company
of Canada
AUDITOR
KPMG
ENGINEERING CONSULTANTS
McDaniel & Associates
LEGAL COUNSEL
Bennett Jones LLP
STOCK EXCHANGE LISTING
& SYMBOL
Toronto Stock Exchange: NAE
EXECUTIVE OFFICE
1000 – 550 6th Avenue SW, Calgary, Alberta, T2P 0S2
Website: www.nalenergy.com

52. Disclaimers
52
• 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.