Corporate presentation november_2011_4

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.

3

Operate Across Western Canada

Alberta

% Crude Oil: 45%

% of Production: 59%

British Columbia

% Gas & NGL’s: 100%

% of Production: 14% SE Saskatchewan

% Crude Oil: 93%

% of Production: 25%

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

Reserves @ Jan 1 2011

PUD's 10%

PROVED PRODUCING

58%

PROBABLE 32%

0

20,000

40,000

60,000

80,000

100,000

120,000

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

P+P

Res

erve

s (M

boe)

Natural Gas

Oil & Liquids

5

• Increasing demand for yield

• Dividend payout model fits the WCSB asset base

• Payout ratio 40 – 50% of cash flow

• Growth through acquisitions – strategic/selective

Income vs Growth

6

• 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

Q3 Highlights

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 transportation charges; 3) Before hedging gains/losses.

25,500

26,000

26,500

27,000

27,500

28,000

28,500

29,000

29,500

Q1 Q2 Q3e Q4e

Q2 Actual- 26,758 boe/d

Q3 Actual – 28,752 boe/d

December Exit – 29,000 boe/d range

Q1 Actual- 28,025 boe/d

Q4 Key Drivers

• Saskatchewan recovery/drilling

• Garrington/Lochend Cardium tie-ins

• Gas capacity constraints/outages

H1/11 Impacts

• Facility outages

• Availability of services - timing

• Wet weather

Boe/

d Maintaining Momentum Through Year-end

8

9

• 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

Outlook

Notes: 1) Does not account for unplanned gas facility outages in Q4/11 or volume constraints associated with Star Valley facility fire.

10

• 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

2011 Operational Strategy

11

Capital Program On Track

(13 Garrington, 4 Cochrane, 1 Willesden Green)

(Pekisko , Viking, other Carbonates)

(15 in greater Hoffer area)

(2 Fireweed , 1 Kakwa, 4 Deep Basin (Wilrich)

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

**Resource Halo Areas provided by Canadian Discovery Notes: 1) Cardium A&B sands; 2) Cardium A sand only;

• 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

13

• 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

Advancements in the Cardium

14

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

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

Notes: 1) First full month average post load fluid recovery 2) Forecast

• Q4 2011 results set-up active program for 2012

• Liquids and solution gas handling facilities added in 2011

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

16

• 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

Profiling the Mississippian

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.

18

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

Emerging Tight Oil Play: Sawn Lake – North Central AB

Notes: 1) Source - GeoScout

19

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

Liquids-rich Natural Gas Plays

• 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

20

• 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

2012 Guidance Framework

21

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

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

Appendix

23

24

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 47,000 boe/d)

65% of assets are common

90% are operated

NAL Energy

29,000

boe/d

Manulife

18,000

boe/d

Canadian75%

U.S. 22%

Foreign3%

Institutional 41%

Retail58%

Manulife 1%

25

NAL Shareholder Analysis

Income Focused Institutional Presence

High Canadian Ownership

Note: As at September 30, 2011

26

Cardium Type-Curve

0

25

50

75

100

125

150

175

200

225

250

1 2 3 4 5 6 7 8 9 10 11 12Months On Production

Prod

uctio

n (b

oe/d

)

Typical Horizontal Well

Typical Vertical Well

NAL’s Drilling Results Validate Type Curve

27

SE Sask Mississippian Type-Curve

0

10

20

30

40

50

60

70

80

90

100

110

120

0 12 24 36 48 60 72 84 96 108 120 132 144 156 168 180 192 204

Months

Rate

(bb

l/d)

1st Month IP: 115 bbls/d

EUR: 110 mboe/well

Based on 2006 – 2010 drills

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

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

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 53% of cash flow

0.00

0.50

1.00

1.50

2004 2005 2006 2007 2008 2009 2010

Mbo

e / 0

00 u

nits

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

P+P

Res

erve

s (M

boe)

30

PDP reserves represent a high percentage of total proved

Conservatively Booked Reserves

86%85%

94%95%

94%93%

96%

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

2004 2005 2006 2007 2008 2009 2010

Mbo

e

PROVED PRODUCING PROVED NON-PRODUCING & UNDEVELOPED

31

Probables represent a low percentage of total P+P reserves

Conservatively Booked Reserves

32%31%

28%27%

30%30%

29%

0

20,000

40,000

60,000

80,000

100,000

120,000

2004 2005 2006 2007 2008 2009 2010

Mbo

e

PROVED PROBABLE

32

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 46% of cash flow

0

20

40

60

80

100

120

2006 2007 2008 2009 2010

boe

/ 000

uni

ts

10,000

15,000

20,000

25,000

30,000

35,000

Prod

uctio

n (b

oe/d

)

P+P Reserves Per Unit Annual Average Production

33

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

Non-Taxable For Many Years

Note: as at 30SEP11

34

• 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

Hedging Programs Manage Risk

35

• 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

Hedging Program Adding Protection

* 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.

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 December 31, 2012.

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

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


38

Interest Rate Hedge Positions

Financial Interest Rate Swap Contracts as at 11/7/2011

Remaining Term Notional (Cdn $MM) Floating Rate (Receive)

Fixed Rate (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%




Total Notional (Cdn $) 139*

* Fixed approximately 49% of floating bank debt ($285MM average for 2011e)


39

Foreign Exchange Hedge Positions

Fixed Rate (USD/CAD)

Notional (US) per month

Term Counterparty Floating Rate

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 (USD/CAD)



.94 - 1.06 $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.

40

Foreign Exchange Hedge Positions

Option Fixing Range

(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.

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 08/09/2011.

Fade-in Level (USD/CAD)

Strike Price (USD/CAD)

Participation Level (USD/CAD)



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



0.90 1.065 1.15 $1.0 MM Jan 1, 2013 to Sept 30, 2013 BofC Monthly Average Noon Rate

Option Payout Range

(USD/CAD)


Term Counterparty Floating Rate Monthly Premium 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

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.

41

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

Average of 22 years of E&P experience

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

Roger Serin TD Securities Hold

43

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: [email protected]

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

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.

All dollar amounts in Canadian dollars, unless otherwise stated.

Corporate presentation november_2011_4

Business

cardium performance

crude oil

oil liquidsp

natural gas reserves

capital efficiency

q211 oil volumes

stratigraphic oil plays

cardium ab sands