NAL Energy Corporation is an oil and gas producer focused on light oil with assets in western Canada. Some key points: - Market cap of $1.2 billion with monthly dividend of $0.07/share and current yield of 10.4% - Produces over 28,000 boe/day from assets in Alberta, southeast Saskatchewan, and British Columbia. Reserves of 104 MMBoe with 50% liquids. - Focused on oil drilling for its 2011 $240 million capital program to maintain production of around 28,500 boe/day for the year. Hedges over 50% of oil volumes. - Operates across different oil resource plays like the Cardium, V

1. Solid Assets & Opportunities
Light Oil Focus
Financial Flexibility
November 2011
TSX: NAE

2. NAL Energy Corporation Profile
TSX Symbol NAE
Market Capitalization1 $1.2 Billion
Monthly Dividend $0.07/share
Current Yield1 10.4%
Net Debt2 $376 Million
Current Shares Outstanding3 150.4 Million
Convertible Debentures
Trading Symbol NAE.DB NAE.DB.A
Coupon 6.75% 6.25%
Principal Outstanding ($MM) 80 115
Conversion Price ($/Share) 14.00 16.50
Maturity Date 31AUG12 31DEC14
Notes: 1) As at 22NOV11; 2) As at 30SEP11; 3) As at 08NOV11. 2

3. Operate Across Western Canada
British Columbia
% Gas & NGL’s: 100%
% of Production: 14% SE Saskatchewan
% Crude Oil: 93%
% of Production: 25%
Alberta
% Crude Oil: 45%
% of Production: 59%
3

4. 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
4

5. Income vs Growth
• Increasing demand for yield
• Dividend payout model fits the WCSB asset base
• Payout ratio 40 – 50% of cash flow
• Growth through acquisitions – strategic/selective
5

6. Q3 Highlights
• Volumes up 2,000 boe/d or 7% Q3/11 vs. Q2/11
• Oil volumes up 7%
• Operational highlights
• Cardium Lochend performance
• Back to business in Saskatchewan
• Liquids-rich gas tie-ins
• New oil resource play – Sawn Lake
• Cash flow in-line with expectations
• $250 MM available on lines of $550 MM
6

7. Q3/11 Performance
Q3/11 Q2/11 % Change
Production (boe/d) 28,752 26,758 7.5
Funds from operations ($MM)1 64.8 60.4 7.3
Funds from operations ($/share) 0.44 0.41 7.3
Capital expenditures ($MM) 86.9 36.1 141
Revenue ($/boe)2 49.30 53.12 -7.2
Operating Netback ($/boe)3 28.64 32.39 -11.6
Notes:
1) All figures prepared in accordance with International Financial Reporting Standards 1 (“IFRS1”); 2) net of
7
transportation charges; 3) Before hedging gains/losses.

8. Maintaining Momentum Through Year-end
29,500
December Exit – 29,000 boe/d range
H1/11 Impacts
29,000
• Facility outages
• Availability of services - timing
28,500
• Wet weather
Q3 Actual – 28,752 boe/d
28,000
27,500
Boe/d
Q1 Actual- 28,025 boe/d
27,000
Q4 Key Drivers
• Saskatchewan recovery/drilling
26,500
Q2 Actual- 26,758 boe/d • Garrington/Lochend Cardium tie-ins
• Gas capacity constraints/outages
26,000
25,500
Q1 Q2 Q3e Q4e
8

9. Outlook
• On track to complete $240 MM capital program
• Production forecast in the 28,500 boe/d1 range
• Oil hedges in place for 51% of volumes for 2011 -
swaps at US$88/bbl and collars at US$ 90 x 100
Notes: 1) Does not account for unplanned gas facility outages in Q4/11 or volume constraints associated with Star Valley facility fire. 9

10. 2011 Operational Strategy
• Oil drilling - 85% of the capital program
• Focus on ROR and capital efficiency – 95% Hz drills
• Leverage BP and Cochrane partnerships
• Prove-up emerging opportunity inventory
• Farm-out non-core acreage – maintain upside
10

11. Capital Program On Track
(13 Garrington, 4 Cochrane, 1 Willesden Green)
(15 in greater Hoffer area)
(Pekisko , Viking, other Carbonates)
(2 Fireweed , 1 Kakwa, 4 Deep Basin (Wilrich)
11

12. Scalable Oil Development:
Cardium West Central AB
Key Attributes
Garrington/
Westward Ho Cochrane
Working Interest (%) 65 65
OOIP/SEC (MMbbl) Up to 4.21 2.62
Reserves per well (Mboe) 165 Up to 225
DCET Cap (Gross - $MM) $3.0 – 3.3 $3.5 – 3.8
OPEX ($/boe) 8 10
Capital Efficiency ($/boe) 16 – 22 15-24
Un-risked ROR (%) 45 35
• Cardium performance - continues to meet
or exceed type curves
• Successfully implementing water based
fracs on all new wells
• Approximately 300 gross risked locations
in inventory at 2 wells per section
• Positive results from downspacing to 3-4
wells/sec
12
**Resource Halo Areas provided by Canadian Discovery Notes: 1) Cardium A&B sands; 2) Cardium A sand only;

13. Advancements in the Cardium
• Completion technique advancements include:
• Switch to water-based fracs
• Longer lateral section – up to 1,500 metres
• Reduced inter-frac spacing to 75 metres
• Decreased per frac tonnage to 15 tonnes
• Target DCET costs: $3.0–3.3 MM in Garrington and
$3.5–3.8 MM at Lochend
13

14. Lochend Cardium Exceeding Expectations
Lochend
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
W5M
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)1 335 2002 3302 3502 770 3502 172
90 day IP (boe/d) 268 - - - - - 162
Current (boe/d) 189 - 400 617 400 - 137
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) 1082 1179 1024 1260 1132 1276 1000
• Q4 2011 results set-up active program for 2012
• Liquids and solution gas handling facilities added in 2011 14
Notes: 1) First full month average post load fluid recovery 2) Forecast

15. Stratigraphic Oil Plays:
Mississippian – Southeast SK
Key Attributes
Working Interest (%) 50
OOIP/Sec (MMbbls) Up to 5
Reserves per well (Mboe) 60 – 200
DCET Cap (Gross -$MM) 1.6 - 1.8
Capital Efficiency ($/boe) 18
Un-risked ROR (%) 40 -50%
• Stratigraphic plays laterally
extensive
• Positive reservoir
permeability/porosity
• Over 100 gross risked
locations
• Delineation continuing on
Neptune/Oungre
• Multi-zone potential:
Ratcliffe, Oungre, Red River,
Birdbear and Bakken
15

16. Profiling the Mississippian
• No multi-stage fracs – lower cost - $1.7MM DCET
• IP’s enhanced by under-balanced drilling
• New pool royalties at 2.5% on first 100,000 bbls
• New oil battery at Hoffer increases reliability
• Waterflood potential to increase recovery factors
16

17. Strong Oil Economics - $85/bbl WTI
Mississippian - SE Sask Cardium - Alberta
Capital Efficiency ($/boe) $16 - $25 $17 - $28
Operating Netback ($/boe) $60 - $70 $65
Recycle Ratio 2x - 3x 2x - 3x
Royalties 4.5%* 12%
Capital Costs/Well ($MM) 1.5 – 2.0 3.0 – 4.0
Operating Costs ($/boe) 10.00 8.00
Rates of Return 40% - 100% + Up to 40%
Note: Assuming US$85/bbl ; * On first 37,000/100,000 bbls. 17

18. Emerging Tight Oil Play:
Sawn Lake – North Central AB
NAL Land Position:
• 23 gross sections
• 50% - 100% WI
• Slave Point carbonate
Development Potential:
• Up to 4 wells per section
• 75 – 100 locations
• First well – Q1/12
Key Offsets1:
A: 16-35-91-13W5 Horizontal
On Production: March 2011
Peak Rate: 378 bbls/d @ 7% WC
August Rate: 335 bbls/d @11% WC
B: 1-26-91-13W5 Horizontal
On Production: April 2011
Peak Rate: 445 bbls/d @ 2% WC
August Rate: 445 bbls/d @ 1% WC
18
Notes: 1) Source - GeoScout

19. Liquids-rich Natural Gas Plays
Key Attributes (Wilrich)
Working Interest (%) 70
NGL Yield (Bbl/mcf) 15
Gross RGIP (Bcf/well) 3.7
Gross Reserves/Well (Mboe) Up to 620
Capital Efficiency ($/boe) 9.40
Un-risked ROR (%) 40
• Wilrich well performance exceeding
expectations with an average 30 day
IP capability in excess of 7 mmcf/d
• Production at Fireweed is in the
2,100 boe/d range
• Up to 90 gross risked locations in
inventory
19

20. 2012 Guidance Framework
• Guidance to be announced mid-January 2012
• Focus on lower risk operated oil opportunities
• Less proof-of-concept, land & facilities capital
• Commodity prices key driver of cash flow
• 2012 Hedging – 5,000 bbls/d at $97/bbl
20

21. 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
21
* Includes $15 million of working capital facility

22. NAL Investment Proposition
• Balanced portfolio of high quality assets
• Focus on light oil
• Strong inventory of opportunities
• Available lines of credit
• Non-taxable for many years
• Attractive valuation and yield
22

23. Appendix
23

24. Strategic Partnership with Manulife
Manulife:
NAL Resources Management • Direct investor in oil and gas assets since
1990
(manages 47,000 boe/d)
• Long term investment horizon
• Desire to increase investment
  Terms of Administrative Cost Sharing
NAL Energy Manulife Agreement:
• No management or acquisition fees
29,000 18,000 • Shared G&A costs
boe/d boe/d • Independently controlled board
• 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
24

25. NAL Shareholder Analysis
Income Focused
High Canadian Ownership
Institutional Presence
Foreign Manulife
3% 1%
U.S.
22%
Institutional
41%
Retail
Canadian 58%
75%
25
Note: As at September 30, 2011

26. Cardium Type-Curve
NAL’s Drilling Results Validate Type Curve
250
225 Typical Horizontal Well
200
Typical Vertical Well
175
Production (boe/d)
150
125
100
75
50
25
0
1 2 3 4 5 6 7 8 9 10 11 12
Months On Production
26

27. SE Sask Mississippian Type-Curve
Based on 2006 – 2010 drills
120
110
1st Month IP: 115 bbls/d
100
90 EUR: 110 mboe/well
80
Rate (bbl/d)
70
60
50
40
30
20
10
0
0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204
27
Months

28. 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
28
Notes: All reserves and production volumes data excludes royalty interest volumes; 1) 2009 reserves have been adjusted for the wind-up of the T&S partnership to be comparable with 2010.

29. Stable Reserves Per Share Performance
Stable reserves per share performance reinvesting approximately 53% of cash flow
1.50 200,000
180,000
160,000
P+P Reserves (Mboe)
Mboe / 000 units
140,000
1.00
120,000
100,000
80,000
0.50 60,000
40,000
20,000
0.00 0
2004 2005 2006 2007 2008 2009 2010
Note: DARPU calculated using year-end reserves, net debt, convertibles and units outstanding. 29
Net debt converted to units using annual average unit price. Converts converted to units at strike price

30. 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
30
PROVED PRODUCING PROVED NON-PRODUCING & UNDEVELOPED

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

32. Stable Production Per Share Performance
Stable production per share performance reinvesting approximately 46% of cash flow
120 35,000
100
30,000
80
Production (boe/d)
25,000
boe / 000 units
60
20,000
40
15,000
20
0 10,000
2006 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. 32
This metric is not debt-adjusted given complications in calculating average annual debt figures.

33. 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 30SEP11 33

34. 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 production after royalty
• Counterparties
• all Canadian chartered banks
34

35. Hedging Program Adding Protection
• Crude oil hedges:
• 49% of net 2011 liquids volumes - average floor price
above US$ 88/bbl
• 5,000 bbls/d in 2012 hedged at average floor price
above US$ 97/bbl
• Natural gas hedges:
• 31% of net 2011 gas volumes
• Average floor price of approximately C$4.00/GJ
• Interest rate:
• 45% of 2011 bank debt @ 1.67%
• Foreign Exchange:
• 36% of 2011 US$ exposure @ $1.0328
35
* Current all in Bank Interest rate 4.7% after Bank Fees; percent of commodity hedged based on mid-point of production guidance range of 29,000 boe/d.

36. Crude Oil Hedge Positions
Crude Oil Hedge Contracts as at 11/7/2011
Q4-11 Q1-12 Q2-12 Q3-12 Q4-12
US$ Collar Contracts
$US WTI Collar Volume (b/d) 200 900 900 700 700
Bought Puts – Average Strike Price ($US/bbl) 90.00 101.11 101.11 101.43 101.43
Sold Calls – Average Strike Price ($US/bbl) 100.50 117.07 117.07 117.66 117.66
US$ Swap Contracts
$US WTI Swap Volume (b/d)* 5,700 3,450 3,450 3,450 3,450
Average WTI Swap Price ($US/bbl) 88.10 95.38 95.38 95.38 95.38
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) 5,900 4,350 4,350 4,150 4,150
Note: All counterparties are Canadian banks in our syndicate.
• Two 500 bbl/d, calendar 2011, swap contracts with an average price of $95.00 contain extendable call options. The extendible call option provides the counterparty with the option
to extend the contract into calendar 2012 under the same price and volumetric terms. The counterparty can exercise this option any time before December 31, 2011.
• For calendar 2012, there is a 500 bbl/d and a 250 bb/d swap contract with a price of $87.15 and $100.25 respectively, 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 36
December 31, 2012.

37. Natural Gas Hedge Positions
Natural Gas Hedge Contracts as at 11/7/2011
Q4-11 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) 27,000 24,000 5,000 5,000 3,674
AECO Average Price ($Cdn/GJ) 3.99 3.98 4.16 4.16 4.17
Total Volume (GJ/d) 27,000 24,000 5,000 5,000 3,674
Note: All counterparties are Canadian banks in our syndicate. 37

38. Interest Rate Hedge Positions
Financial Interest Rate Swap Contracts as at 11/7/2011
Remaining Term Notional (Cdn $MM) Floating Rate Fixed Rate
(Receive) (Pay)
Oct 2011 – Dec 2011 39 CAD-BA-CDOR 3 month 1.5864%
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 $) 139*
* Fixed approximately 49% of floating bank debt ($285MM average for 2011e)
Note: All counterparties are Canadian banks in our syndicate. 38

39. Foreign Exchange Hedge Positions
Fixed Rate Notional (US) Term Counterparty Floating Rate
(USD/CAD) per month
1.05 $2.0 MM Oct 1, 2011 to Dec 31, 2011 BofC Monthly Average Noon Rate
1.0608 $0.5 MM Oct 1, 2011 to Dec 31, 2011 BofC Monthly Average Noon Rate
0.9954 $2.0 MM Jan 1, 2011 to Dec 31, 2011 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.
The 1.0565 fixed rate calendar 2012 contract contains the premium from the sale of a 1.05 extendable call option that expires
December 31, 2011. If exercised the option will be converted to an additional equivalent contract at a fixed rate of 1.05.
Option Fixing Range Notional (US) Term Counterparty Floating Rate
(USD/CAD) per month
.94 - 1.06 $0.5 MM Oct 1, 2011 to Dec 31, 2011 BofC Monthly Average Noon Rate
.95 - 1.07 $0.5 MM Oct 1, 2011 to Dec 31, 2011 BofC Monthly Average Noon Rate
.94 - 1.08 $0.5 MM Oct 1, 2011 to Dec 31, 2011 BofC Monthly Average Noon Rate
.95 - 1.04 $0.5 MM Oct 1, 2011 to Dec 31, 2011 BofC Monthly Average Noon Rate
.95 – 1.0138 $1.0 MM Oct 1, 2011 to Dec 31, 2012 BofC Monthly Average Noon Rate
When the monthly average noon spot foreign exchange rate exceeds the lower fixing rate, NAL is committed to selling the above
listed USD’s at the upper fixing rate for that month. To the extent the monthly average noon spot foreign exchange rate is below the
lower fixing rate, NAL has no commitment to sell USD.
Note: FX contracts as at 08/09/2011. 39

40. Foreign Exchange Hedge Positions
Notional (US) Term Counterparty Floating Rate
Option Fixing Range per month
(USD/CAD)
1.05 - 1.15 $1.0 MM Oct 1, 2011 to Dec 31, 2011 BofC Monthly Average Noon 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.
Option Payout Notional (US) Term Counterparty Floating Rate Monthly
Range per month Premium
(USD/CAD) Received
0.93 - 1.01 $3.0 MM Oct 1, 2011 to Dec 31, 2011 BofC Monthly Average Noon Rate CAD $60K
0.93 - 1.01 $2.0 MM Jan 1, 2012 to Jun 30, 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 Jul 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 Oct 1, 2011 to Dec 31, 2011 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
0.90 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 08/09/2011. 40

41. 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
Average of 22 years of E&P experience
Darcy Reding
Western BU
Tim Brandenborg
Non-Operated BU
Darcy Erickson
Drilling &
Completions
Deric Orton 41
Director, Land

42. Sell-side Research
Analyst Firm Recommendation
Gordon Tait BMO Capital Markets Market Perform
Grant Hofer Barclays Capital Underweight
Jeremy Kaliel CIBC World Markets Sector Outperformer
Kevin C.H. Lo FirstEnergy Capital Market Perform
Stacey McDonald GMP Securities Buy
Cristina Lopez Macquarie Capital Neutral
Kyle Preston National Bank Financial Outperform
Jeff Martin Peters & Co. Sector Perform
Kristopher Zack Raymond James Market Perform
Mark Friesen RBC Capital Markets Sector Perform
Gordon Currie Salman Partners Hold
Patrick Bryden Scotia Capital Sector Perform
Michael Zuk Stifel Nicolaus Sell
42
Roger Serin TD Securities Hold

43. 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 43

44. 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.
44
All dollar amounts in Canadian dollars, unless otherwise stated.