March 2012 NAL Energy Corporate Presentation

Corporate PresentationMarch, 2012

NAL Energy Corporation ProfileTSX Symbol NAEMarket Capitalization1 $1.1 BillionMonthly Dividend $0.05/shareNet Debt2 $363 MillionCurrent Shares Outstanding2 151.9 Million Convertible DebenturesTrading Symbol NAE.DB NAE.DB.A NAE.DB.BCoupon 6.75% 6.25% 6.25%Principal Outstanding ($MM) 80 115 150Conversion Price ($/share) 14.0 16.50 9.90Maturity Date 31AUG12 31DEC14 31MAR17Notes:1) As at March 7, 20122) As at 31DEC11 2

Strategic Direction – Long Term Sustainability• Dividend paying E&P company • Maximize cash flow • Add scalable liquids opportunities • Utilize new tools and technologies • Deliver operating and capital cost efficiency • Disciplined acquisition focus • Balance dividend with sustaining capital 3

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

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

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

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

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

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

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

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

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

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 200Note: Net dispositions totaled ~($29) MM in 2011 13

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

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

New Cardium Land Deal Increases Inventory• New four year deal finalized January 2012• Net $6MM commitment per year• Access to 280 (182 net) sections of Cardium prospective land directly offsetting existing Garrington/Westward Ho acreage• Adds 50 new drillable Cardium locations plus future upside 16

Cardium Oil: Cochrane / Lochend AB • Sweet spot outperforming regional type curve by 2-3 times • New 3D applied to delineate sweet spot • Solution gas infrastructure added 500 Lochend Sweet Spot 3D 450 Lochend Normal 400 WWHO Production Volumes (Boe/d) 350 Garrington 300 250 200 150 100NAL Access LandsKey Penetrations 502012 Program 02011 Program 1 13 25 37 49 Month 17

Lochend Cardium Exceeding Expectations Lochend W5M 3-17-027-03 1-17-027-03 1-18-027-03 16-19-027-03 14-20-027-03 16-20-027-03 8-33-027-03 August 27, December 1, November 3, November 3, September December 1, August 6,On Production 2010 2011 2011 2011 5, 2011 2011 201130 day IP 335 310 588 840 770 300 172(boe/d)90 day IP 268 - - - - - 162(boe/d)Current (boe/d) 174 153 258 660 234 167 100Formation Cardium A Cardium A Cardium A Cardium A Cardium A Cardium A Cardium AFrac Fluid Type Water Water Water Water Water Water WaterNumber of Fracs 10 15 11 13 14 14 12Lateral length 1,082 1,179 1,024 1,260 1,132 1,276 1,000(m) • Q4 2011 results set-up active program for 2012 • Liquids and solution gas handling facilities added in 2011 18

Mississippian Oil – Greater Hoffer • Multiple play trends now proven • Infrastructure in-place to: Neptune o Facilitate pressure maintenance New Pool Discovery o Minimize production down-time o Reduce operating costs Beaubier New Pool Discovery • Land increased through strategic farm-ins Oungre Pool ExtensionNAL Access Lands Mississippian ProspectMSSP Producers2012 Program Hoffer 2009 Pool Discovery Inventory: n=1142011 ProgramMSSP Oil Pools 2012 Program3D Seismic Outline 30 39 Area Play-Types Schematic Drillable Inventory 45 Contingent Locations Gross Risked Locations assuming 300 m inter-well spacing (see Appendix) 19

Emerging Tight Oil Play – Sawn Lake • Scalable, repeatable oil resource play targeting Slave Point Platform Carbonates – positioned in 2010 - 2011 3D • OOIP of up to 6 mmboe/section • Ave 50% WI in 32 gross sections • Analogous development at 8 wells/ sec • Play de-risked by offsetting activity 1-26-91-13W5IP: 445 bopd Slave Point Prospect & 2%WC Inventory: n=48 16-35-91-13W5 2IP: 380 bopd & 7%WC 2012 Program 20 NAL Access Lands 26 Drillable Inventory SLVP Penetrations 2012 Program 2011 Program Contingent Locations Gross Risked Locations assuming 4 wells/ sec (see Appendix) 20

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

Significant Potential To Increase Oil Reserves Gross Net Upside Upside Total EUR per Drillable Contingent Reserve Average Reserve Risked Well Inventory Inventory Potential WI% Potential Locations (mboe) (mmboe) (mmboe)Cardium 151 191 342 170 58.1 65 37.8Mississippian – 75 39 114 65 7.4 50 3.7EastMississippian – 74 37 111 85 9.4 50 4.7WestSlave Point 28 20 48 170 8.2 50 4.1CarbonateMontney 12 8 20 630 12.6 100 12.6 635 95.7 62.9**Note: includes 9.2 mmboe of booked reserves• Non-contingent development drilling inventory is drill-ready• Well defined production and capital profiles• Third Party activity is actively de-risking off-setting contingent locations• Incremental potential exists at Fireweed and Sawn Lake to double location tallies beyond that represented above 22

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

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

Appendix

Strategic Partnership with Manulife Manulife: • Direct investor in oil and gas assets since NAL Resources Management 1990 • Long term investment horizon (manages 46,500 boe/d) • Desire to increase investment Terms of Administrative Cost Sharing Agreement: NAL Energy Manulife • No management or acquisition fees • Shared G&A costs 28,500 18,000 • Independently controlled board boe/d boe/d • Long term contract - 90 day NAL Energy exit option 65% of assets are common Benefits: 90% are operated • Enhanced technical/financial capability • Broad market view & investment discipline • Financial partner in transactions 26

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

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

Available Credit Lines Credit Lines ($MM) 2011 Bank of Montreal* 145 $365 MM of credit Royal Bank of Canada 110 available as at Mar. 7th CIBC 87.5 Bank of Nova Scotia 87.5 Alberta Treasury Branch 40 National Bank Financial 40 Union Bank of California 40 Total 550* Includes $15 million of working capital facility 29

Hedging Programs Manage Risk• Objective - Protect cash flow for the purposes of sustaining dividends and maintaining an active capital program• Board approval: maximum of 60% of net revenue• Counterparties: all Canadian chartered banks 30

2012 Hedging Program• Crude oil hedges - 7,878 bbls of 2012 oil volumes • Average floor price of US$ 97.37/bbl on swaps • Average floor price of US$ 101.25/bbl on collars• Natural gas hedges - 12,396 of 2012 gas volumes • Average floor price of C$ 3.88/GJ on swaps • Average floor price of C$ 2.50/GJ on collars• Interest rate: • 35 – 40% of 2012 bank debt @ 1.71%*• Foreign Exchange: • 45% of 2012 US$ exposure @ 1.01(70% collared to 1.045) * All in bank interest rate 4.7% after bank fees 31

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

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

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

Foreign Exchange Hedge Positions Optional Fixing Range Notional (US) per Term Counterparty Floating Rate (USD/CAD) month 0.97 – 1.04 $1.0 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate NAL has a commitment to sell the above notional USD at the lower fixing rate versus the Bank of Canada monthly average noon rate. If the Bank of Canada monthly average noon rate falls within the option fixing range. NAL has no commitments to sell USD. Option Payout Range Notional (US) per Term Counterparty Floating Rate Monthly (USD/CAD) month Premium Received 0.93 - 1.03 $2.0 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate CAD $40K 0.90 - 1.15 $1.0 MM Jan 1, 2013 to Sept 30, 2013 BofC Monthly Average Noon Rate CAD $40K When the monthly average noon spot foreign exchange rate is outside the payout range, the monthly premium is forfeited. NAL is committed to selling the above listed USD at the upper payout range value for that month when the average noon spot foreign exchange rate exceeds the upper payout range. Fade-in Level Strike Price Participation Level Notional (US) Term Counterparty Floating Rate (USD/CAD) (USD/CAD) (USD/CAD) per month 0.92 0.985 1.03 $2.0 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate 0.91 1.0075 1.05 $1.5 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate 0.935 1.00 1.05 $0.5 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate 0.92 1.012 1.0625 $0.5 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate 0.92 0.995 1.035 $1.0 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate 0.93 1.04 1.075 $0.5 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate 0.90 1.065 1.15 $1.0 MM Jan 1, 2013 to Sept 30, 2013 BofC Monthly Average Noon Rate NAL is fixed to sell USD on a monthly basis at the strike price. If the Bank of Canada monthly average noon rate is below the fade-in level or between the strike and participating level, NAL has no commitment to sell USD.Note: FX contracts as at 03/07/2012. 35

Foreign Exchange Hedge Positions – Cont’d Fixed Rate Notional (US) per Term Counterparty Floating Rate (USD/CAD) month 0.9954 $2.0 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate 1.0565 $1.5 MM Jan 1, 2012 to Dec 31, 2012 BofC Monthly Average Noon Rate NAL has a monthly commitment to settle the notional amount of the above fixed rates against the Bank of Canada monthly average noon rate.Note: FX contracts as at 3/7/2012. 36

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

Understanding Our Inventory Geoscience Professionals Feeding Prospect Hopper Economic Prospect ProvenAttributes Well Constrained by Mapping Positioning complete Un-Risked Tier 1 locations Tier 2 locations Tier 3 locations Inventory (n=2,750) Risk Execution Barriers Factors Failed Proof-of-concept Positioning Barriers 80% 50% 20% >100% ROR Drillable Immediately Drillable in Risked 20% ROR Near Term Drillable in Inventory Medium Term (n=1,150) 38

Understanding Our Inventory• Drillable Inventory equals • 100% of Tier 1 Locations• Total Risked Inventory equals • 90% of Tier 1 locations plus • 50% of Tier 2 locations plus • 10% of Tier 3 locations• Contingent Inventory equals • Total Risked Inventory minus Drillable Inventory 39

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

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

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

Stable Reserves Per Share PerformanceStable reserves per share performance reinvesting approximately 66% of cash flow 0.70 0.60 0.50 Mboe / 000 units 0.40 0.30 0.20 0.10 0.00 2007 2008 2009 2010 2011 Note: DARPS calculated using year-end reserves, net debt, convertibles and shares outstanding. Net debt converted to shares using annual average share price. Converts converted to shares at strike price 43

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

2012 Sensitivities on FFO Impact on FFO – Excluding Hedges Change ($MM) $/shareWTI ($US/bbl) $5.00 16.9 0.11AECO ($C/GJ) $0.50 14.4 0.09FX (CAD/US) $0.01 3.4 0.02Prime Rate 1.0% 3.4 0.02Production (bbl/d) 100 2.1 0.01Production (mmcf/d) 1 0.4 0.003Oil Differential 1.0% 3.9 0.03Gas Differential 1.0% 0.9 0.01Note: Excludes impact of hedge contracts 45

2012 Sensitivities on FFO Impact on FFO – Including Hedges ($MM) $/shareWTI ($US/bbl) $5.00 2.9 0.02AECO ($C/GJ) $0.50 12.7 0.08FX (CAD/US) $0.01 2.3 0.02Prime Rate 1.0% 2.4 0.02Note: Includes impact of hedge contracts 46

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

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

Corporate InformationEXECUTIVE TEAM TRUSTEE AND TRANSFER AGENTAndrew Wiswell President & CEO Computershare Trust Company of CanadaKeith Steeves VP Finance & CFO AUDITORJohn Koyanagi VP Business Development KPMG ENGINEERING CONSULTANTSINVESTOR RELATIONS McDaniel & AssociatesClayton Paradis Director, Investor Relations LEGAL COUNSELLocal: (403) 294-3620 Bennett Jones LLPToll-free: (888) 223.8792 STOCK EXCHANGE LISTINGE-mail: ir@nal.ca & SYMBOL Toronto Stock Exchange: NAE EXECUTIVE OFFICE 1000 – 550 6th Avenue SW, Calgary, Alberta, T2P 0S2 Website: www.nalenergy.com 49

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 NALs drilling programs and the production profile of NALs oil and natural gas reserves. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by NAL and described in the forward-looking information contained in this document. Undue reliance should not be placed on forward-looking information. The material risk factors include, but are not limited to: the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing oil and natural gas, market demand and unpredictable facilities outages; risks and uncertainties involving the geology of oil and gas deposits; the uncertainty of estimates and projections relating to production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; risk that adequate pipeline capacity to transport oil and natural gas to market may not be available; fluctuations in oil and gas prices, foreign currency exchange rates and interest rates; the outcome and effects of any future acquisitions and dispositions; safety and environmental risks; uncertainties as to the availability and cost of financing and changes in capital markets; competitive actions of other industry participants; changes in general economic and business conditions; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; changes in tax laws; changes in royalty rates; the results of NAL’s risk mitigation strategies, including insurance; and NAL’s ability to implement its business strategy. Readers are cautioned that the foregoing list of risk factors is not exhaustive. Additional information on these and other factors which could affect NAL’s operations or financial results are included in NAL’s most recent Annual Information Form and Annual Financial Report. In addition, information is available in NAL’s other filings with Canadian securities regulatory authorities.• Forward-looking information is based on the estimates and opinions of NAL’s management at the time the information is released.• Boe Conversion• Throughout this press release, the calculation of barrels of oil equivalent (boe) is based on the widely recognized conversion rate of six thousand cubic feet (mcf) of natural gas for one barrel (bbl) of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalence at the wellhead.• All dollar amounts in Canadian dollars, unless otherwise stated. 50

March 2012 NAL Energy Corporate Presentation

by NALenergy on Mar 15, 2012

Accessibility

Categories

Upload Details

Usage Rights

Statistics

March 2012 NAL Energy Corporate Presentation Presentation Transcript