March 2012 NAL Energy Corporate Presentation

Corporate Presentation March, 2012

NAL Energy Corporation Profile

2

TSX Symbol NAE

Market Capitalization1 $1.1 Billion

Monthly Dividend $0.05/share

Net Debt2 $363 Million

Current Shares Outstanding2 151.9 Million

Notes:

1) As at March 7, 2012

2) As at 31DEC11

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

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

• Disciplined acquisition focus

• Balance dividend with sustaining capital

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 Q4/11 Q1/12E Q2/12E Q3/12E Q4/12E

Volu

mes

(bo

e/d)

NAL Liquids Volumes

2012 Corporate Plan

5

• 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

Executed Financial Action Plan

6

Reduced 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

Termed out $150 MM of bank debt with

convertible

Refinanced 2012 convertible

maturity ($80MM) with bank debt

Financial Flexibility

2012 Full Year Guidance

7

•Production (boe/d) 28,000 – 29,000

•Capital ($MM) 200

•Operating Costs ($/boe) 11.50 – 12.00

2011 Fourth Quarter & Full Year Results

8

• 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

Reserves Profile

9

• 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

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

2011

P+P

Res

erve

s (M

boe) Natural Gas

Oil & Liquids

PROVED PRODUCING

56%

PUD's8%

PROBABLE 36%

Reserves @ Jan 1 2012

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

Operate Across Western Canada

11

Alberta

% Crude Oil: 45%

% of Production: 59%

British Columbia

% Gas & NGL’s: 100%


SE Saskatchewan

% Crude Oil: 93%


Cardium Oil

Mississippian Oil

Natural Gas

2012 Operational Strategy

12

• Go forward - Oil 100% of the capital program

• Deliver capital performance – execution/results

• High grade opportunity inventory

• Farm-out high risk/unproven acreage

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

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

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

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

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

Prod

ucti

on V

olum

es (

Boe/

d)

Month

Lochend Sweet SpotLochend NormalWWHOGarrington

NAL Access Lands Key Penetrations 2012 Program 2011 Program

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

30

45

39

Mississippian Prospect Inventory: n=114

2012 Program

Drillable Inventory

ContingentLocations

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 increased through strategic farm-ins

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

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 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

Montney – Fireweed - NE British Columbia

21

• Discovery well – IP’d >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

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 50 4.1

Montney 12 8 20 630 12.6 100 12.6

635 95.7 62.9*

• 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

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

Summary & Key Messages

Sustainable business model

Capital focused in core areas

Increasing liquids

volumes

Attractive relative

valuation

Appendix

26

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

Non-Taxable For Many Years

27

Note: as at December 31, 2011

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

Institutional 39%

Retail 60%

Manulife 1%

28

NAL Shareholder Analysis

Note: As at December 31, 2011

Canadian 71%

U.S. 21%

Foreign 8%

Income Focused Institutional Presence High Canadian Ownership

29

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

$365 MM of credit available as at Mar. 7th

Hedging Programs Manage Risk

30

• 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

2012 Hedging Program

31

•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

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

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

33

Natural Gas Hedge Positions


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.

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

34

Interest Rate Hedge Positions

Financial Interest Rate Swap Contracts as at 3/7/2012

Remaining Term Notional Amount (C$ MM)

Floating Rate (Receive)

Fixed Rate (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%




Total Notional (Cdn $) 100*

* Fixed approximately 40% of floating bank debt ($250MM average for 2012e)


35

Foreign Exchange Hedge Positions

Optional 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

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.

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.

Note: FX contracts as at 03/07/2012.

Fade-in Level (USD/CAD)

Strike Price (USD/CAD)

Participation Level (USD/CAD)



0.92 0.985 1.03 $2.0 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)


Term Counterparty Floating Rate Monthly 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

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.

36

Foreign Exchange Hedge Positions – Cont’d

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.

Fixed Rate (USD/CAD)



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

2012 Program: Half Cycle Play Metrics

37

Note: See Appendix for price assumptions

App

roxi

mat

e %W

I

DCE

T Ca

pita

l- G

ross

($

MM

)

EU

R pe

r W

ell -

Gro

ss

(mbo

e)

% G

as

F &

D (

$/bo

e)

Net

back

($/

boe)

Rec

ycle

Rat

io (

x)

BTA

X N

PV @

15 -

Gro

ss

($M

M)

BTA

X RO

R (%

)

BTA

X Pa

yout

(m

nths

)

201

2e P

rogr

am

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

Understanding Our Inventory

38

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

Understanding Our Inventory

39

• 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

40

PDP reserves represent a high percentage of total proved

Conservatively Booked Reserves

96%93%

94% 95%

94%

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

2007 2008 2009 2010 2011

Mbo

e

PROVED PRODUCING PROVED NON-PRODUCING & UNDEVELOPED

41

Probables represent a low percentage of total P+P reserves

Conservatively Booked Reserves

29%

30%

30% 27% 28%

0

20,000

40,000

60,000

80,000

100,000

120,000

2007 2008 2009 2010 2011

Mbo

e

PROVED PROBABLE

42

NAL’s RLI has increased to 10 years in 2011

Increasing Reserves Life Index

5

6

7

8

9

10

2007 2008 2009 2010 2011

RLI (

Year

s)

43

Stable Reserves Per Share Performance

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

Stable reserves per share performance reinvesting approximately 66% of cash flow

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

2007 2008 2009 2010 2011

Mbo

e /

000

unit

s

44

Stable Production Per Share Performance

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.

0

20

40

60

80

100

120

2007 2008 2009 2010 2011

boe

/ 00

0 un

its

P+P Reserves Per Unit

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

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

Economic Evaluation Price Assumptions

47

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

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

49

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

Disclaimers

50

• 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.

March 2012 NAL Energy Corporate Presentation

Investor Relations

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