NAL Energy Corporation
TSX : NAE

NAL Energy Corporation

May 19, 2011 16:54 ET

NAL Energy Corporation Reports First Quarter 2011 Results

CALGARY, ALBERTA--(Marketwire - May 19, 2011) - NAL Energy Corporation ("NAL" or the "Corporation") (TSX:NAE) today announced its financial and operational results for the first quarter of 2011. All amounts are in Canadian dollars unless otherwise stated.

2011 YEAR TO DATE ACTIVITY

- Executed NAL's largest drilling program to date, with 52 (29 net) wells drilled of which 24 were Mississippian oil wells in SE Saskatchewan, 26 were in Alberta and two were Doig wells at Fireweed in NE British Columbia. Total capital expenditures were $83 million with $69 million directed to drilling, completion and tie-in activity, a 23 percent increase over a year ago;

- NAL's 12 well Cardium program at Garrington continues to deliver positive results. Recent changes to completion techniques that utilize water based fracs and increased frac density appear to be improving initial production performance;

- In the Hoffer area of SE Saskatchewan, NAL has successfully expanded the Ratcliffe play with new discoveries in the Beaubier, Neptune and Oungre blocks. The majority of drilling was centered on the greater Hoffer area with 13 of 24 wells drilled in this emerging Mississippian play;

- NAL's liquids rich natural gas programs included a significant Wilrich well in the Edson area which had a stabilized test rate of approximately 1,400 boe/d with production expected to commence in July, 2011. At Fireweed in NE B.C., NAL successfully drilled two high impact Doig horizontal wells that tested at rates of 1,475 boe/d and 1,600 boe/d. Production from these two wells will be rate limited by facility capacity but should hold production at Fireweed flat for several months at 2,500 - 3,000 boe/d. The wells will be tied-in after break up;

- Production volumes of 28,024 boe/d in the quarter were impacted by higher than anticipated decline in certain properties and uncontrollable factors related to timing and delay caused by third party facility outages, access to equipment and frac services and extreme weather. NAL currently has approximately 3,500 boe/d ready for tie-in post spring break-up and expects production to average over 30,000 boe/d in Q3 and Q4;

- The Corporation had its credit facility review in April and the facility has been renewed at $550 million of which $295 million remains available to the Corporation as at March 31, 2011

-Successfully completed the transition to International Financial Reporting Standards ("IFRS"). The implementation of IFRS has not had an impact on the Corporation's operations and strategic decisions.

UPDATED 2011 GUIDANCE

First quarter 2011 production of 28,024 boe/d was internally forecast to be 29,000 - 29,500 boe/d based on declines from new horizontal wells coming off high initial production rates in Q4, 2010. The 2011 drilling program commenced in January, as planned, and our internal forecast assumed new volumes would offset declines by the end of the second quarter. However, tie-ins of new production from first quarter drills have been impacted by extreme weather, road bans and frac services which delayed the program by approximately three months. Additional unforecasted down time and restrictions through third party facilities (Kaybob - Sem/Cams and Spectra McMahon) are also contributing to this short fall.

Second quarter 2011 production is expected to be impacted by a total of 2,000 - 2,500 boe/d through continued down time, delay and facility outages. Severe wet weather in southeast Saskatchewan is causing down time, and in extreme cases, shutting down entire fields where single well battery leases are under water making truck access impossible during periods in April and May.

As shown in the table entitled "Currently Drilled and Tested Wells Awaiting Tie-in", significant production (estimated at 3,500 boe/d) is behind pipe waiting for ground conditions to improve allowing tie-ins to be completed, pipelines to be built and single well batteries to come on stream. Adding these volumes is expected to increase second half 2011 production as shown in the Production Forecast table below.


CURRENTLY DRILLED AND TESTED WELLS AWAITING TIE-IN

                                                                   Forecast
                                                                    Working
                                                                   Interest
                                                                 Production
                                               Estimated on  (Average first
Wells                                           Stream Date     month boe/d)
----------------------------------------------------------------------------
Crude Oil
----------

8 Cardium wells in Garrington                    May - July           1,000
5 wells in Hoffer/Oungre/Beaubier                      July             200
14-36-35-7W5M (Caroline - Viking)                    June 1            300

Liquids Rich Gas
-----------------

13-07-56-19W5M (Wilrich - Edson)        June 15 - facility
                                                 restricted             500
b-96-I / 94-A-12 (Doig - Fireweed)          July - facility
                                                 restricted             500
d-94-I / 94-A-12 (Doig - Fireweed)          July - facility
                                                 restricted             500
4-11-43-4W5M (Glauc.- Wilson Ck)              July 1 Non Op             500
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Total                                                                3,500e
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2011 PRODUCTION FORECAST RANGES BY QUARTER (BOE/D)

Q1                       Q2              Q3              Q4       Full Year
----------------------------------------------------------------------------
28,024
 (actual)   26,800 - 27,600 29,500 - 30,500 30,300 - 31,300 28,500 - 29,500
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NAL's revised 2011 guidance is currently 28,500 - 29,500 boe/d, an adjustment of -1,200 boe/d, from our January, 2011 guidance. Capital and operating cost guidance remains unchanged.


UPDATED 2011 GUIDANCE

                                               May 2011        January 2011
                                               Guidance            Guidance
----------------------------------------------------------------------------
Production (boe/d)                      28,500 - 29,500     29,700 - 30,700
Net capital expenditures ($MM)                200 - 230           200 - 230
Operating costs ($/boe)                     10.50-10.90       10.50 - 10.90
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OUTLOOK

- In the first quarter, NAL completed its most active drilling program to date and remains on track to complete the planned 139 well drilling program for 2011. The focus of drilling continues to be balanced between the Corporation's significant light oil resources in southeast Saskatchewan and central Alberta;

- As a result of success in the first quarter capital program, the Corporation currently forecasts production to exit the year above 30,000 boe/d;

- Given NAL's broad opportunities and financial flexibility Management is evaluating the potential for an increase in the capital program in the fourth quarter depending on market conditions. The Corporation's balance sheet provides flexibility to pursue internally generated opportunities or acquisition opportunities with approximately $295 million in available credit lines;

- NAL has commitments on approximately $30 million of a $40 million target in non-core divestments as at May 15, with the balance expected to be completed in the last half of the year;

- NAL continues to possess a strong inventory of over 1,300 risked drilling locations and an extensive land base to sustain activity in future years in each of its core Cardium oil, Mississippian oil and liquids rich gas resources of Alberta, SE Saskatchewan and NE British Columbia;

- The Board of Directors reviews its dividend policy quarterly based upon corporate and market conditions. Currently, the Corporation has no plans to change the monthly dividend of $0.07 per share.

FORWARD-LOOKING INFORMATION

Please refer to the disclaimer on forward-looking information set forth under the Management's Discussion and Analysis in this document. The disclaimer is applicable to all forward-looking information in this document, including the 2011 full year guidance set forth above.

CHANGES IN ACCOUNTING POLICIES

NAL adopted IFRS for financial reporting purposes, using a transition date of January 1, 2010.

NON-IFRS MEASURES

Please refer to the discussion of non-IFRS measures set forth under the Management's Discussion and Analysis regarding the use of the following terms: "funds from operations", "payout ratio" and "operating netbacks".

NOTE

When converting natural gas to barrels of oil equivalent (boe) within this press release, NAL uses the widely recognized standard of six thousand cubic feet (Mcf) to one barrel of oil. However, boes may be misleading, particularly if used in isolation. A conversion ratio of 6 Mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.


FINANCIAL AND OPERATING HIGHLIGHTS
Three months ended
(thousands of dollars, except per share and boe data)
(unaudited)

                                     March 31,      March 31,   December 31,
                                         2011           2010           2010
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FINANCIAL
Revenue(1)                           $121,752       $136,883       $116,888
Cash flow from operating activities    60,983         68,248         72,152
Cash flow per share - basic              0.41           0.50           0.49
Cash flow per share - diluted            0.40           0.47           0.47
Funds from operations                  62,997         79,481         67,645
Funds from operations per share
 - basic                                 0.43           0.58           0.46
Funds from operations per share
 - diluted                               0.41           0.55           0.44
Net income (loss)                      (1,510)        50,169        (22,017)
Dividends declared                     31,001         37,185         39,702
Dividends per share                      0.21           0.27           0.27
Basic payout ratio:
 based on cash flow from operating
  activities                               51%            54%            55%
 based on funds from operations            49%            47%            59%
Basic payout ratio including capital
 expenditures:
 based on cash flow from operating
  activities                              186%           169%            90%
 based on funds from operations           180%           145%            96%
Basic payout ratio including
 capital expenditures and proceeds
 from disposition:
 based on cash flow from operating
  activities                              142%           148%            80%
 based on funds from operations           137%           127%            86%
Shares outstanding (000's)
 Period end                           147,781        137,881        147,248
 Weighted average                     147,534        137,660        146,948
Capital expenditures(2)                82,587         78,298         25,524
Property acquisitions
 (dispositions), net(3)               (26,107)       (13,191)        15,963
Corporate acquisitions, net(4)              -            309              -
Net debt, excluding convertible
 debentures(5)                        334,003        308,455        310,302
Convertible debentures (at face
 value)                               194,744        194,744        194,744

OPERATING
Daily production prior to
 Reorganization(6)
 Crude oil (bbl/d)                     10,411         11,788         11,469
 Natural gas (Mcf/d)                   89,581         93,328         93,314
 Natural gas liquids (bbl/d)            2,683          2,777          2,635
 Oil equivalent (boe/d)                28,024         30,120         29,657
Daily production after
 Reorganization (6)(7)                 28,024         29,819         28,596

OPERATING NETBACK ($/boe)
 Revenue before hedging gains
  (losses)                              48.27          50.49          44.43
 Royalties                              (7.85)         (8.34)         (7.53)
 Operating costs                       (10.81)        (10.35)         (9.72)
 Other income                            0.11           0.16           0.20
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 Operating netback before hedging       29.72          31.96          27.38
 Hedging gains (losses)                 (0.34)          0.63           2.49
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 Operating netback                      29.38          32.59          29.87
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----------------------------------------------------------------------------

(1) Oil, natural gas and liquid sales less transportation costs and prior
    to royalties and hedging.
(2) Excludes corporate acquisitions, and is net of drilling incentive
    credits of $2.7 million for the quarter ended March 31, 2011 (March 31,
    2010 - $2.4 million) 
(3) Represents costs to acquire properties less proceeds from dispositions.
(4) Represents total consideration for corporate acquisitions including
    fees. 
(5) Bank debt plus working capital and other liabilities, excluding
    derivative contracts, notes payable and deferred income tax balances.
(6) Production prior to conversion includes 100 percent of the volumes
    attributable to a jointly held partnership with Manulife Financial
    Corporation, see MD&A disclosure for details; all volumes include
    royalty interest volumes.
(7) Excludes 50 percent of volumes attributable to a jointly held
    partnership of NAL and Manulife dissolved as part of the Reorganization
    for 2010, see MD&A.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion and analysis ("MD&A") should be read in conjunction with the interim unaudited consolidated financial statements for the three months ended March 31, 2011 and the audited consolidated financial statements and MD&A for the year ended December 31, 2010 of NAL Energy Corporation ("NAL" or the "Corporation"). It contains information and opinions on the Corporation's future outlook based on currently available information. All amounts are reported in Canadian dollars, unless otherwise stated. Where applicable, natural gas has been converted to barrels of oil equivalent ("boe") based on a ratio of six thousand cubic feet of natural gas to one barrel of oil. The boe rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. Use of boe in isolation may be misleading.

Unless otherwise specifically stated, all financial information included and incorporated by reference in this MD&A is determined, for all periods prior to January 1, 2010, using Canadian generally accepted accounting principles in effect prior to January 1, 2010 and, for all periods beginning on and after January 1, 2010, using International Financing Reporting Standards as adopted by the Canadian Accounting Standards Board ("IFRS").

NAL is engaged in the exploration for, and the development and production of natural gas, natural gas liquids and crude oil in Western Canada. The Corporation resulted from a reorganization effective December 31, 2010 as part of the Plan of Arrangement involving, among others, NAL Oil & Gas Trust (the "Trust"), the Corporation, and the security holders of the Trust (the "Reorganization").

Pursuant to the Reorganization, the Trust was restructured from an open-end unincorporated trust to NAL Energy Corporation, a publicly traded exploration and development corporation. Unitholders of the Trust received one common share of the Corporation for each trust unit held. The Corporation and its subsidiaries now carry on the business formerly carried on by the Trust and its subsidiaries.

The Reorganization to a corporation has been accounted for on a continuity of interest basis and accordingly, the consolidated financial statements for 2010 reflect the financial position, results of operations and cash flows as if the Corporation had carried on the business formerly carried on by the Trust.

References to NAL or the Corporation in this MD&A for periods prior to December 31, 2010 are references to the Trust and for periods after December 30, 2010 are references to NAL Energy Corporation. Additionally, NAL or the Corporation refers to shares, shareholders, and dividends which are comparable to units, unitholders and distributions previously under the Trust.

CHANGES IN ACCOUNTING POLICIES

On January 1, 2011, NAL adopted IFRS for financial reporting purposes, using a transition date of January 1, 2010. The financial statements for the three months ended March 31, 2011, including required comparative information, have been prepared in accordance with International Financial Reporting Standards 1, First-time Adoption of International Financial Reporting Standards, and with International Accounting Standard ("IAS") 34, Interim Financial Reporting, as issued by the International Accounting Standards Board ("IASB"). Previously, the Corporation prepared its interim and annual consolidated financial statements in accordance with Canadian generally accepted accounting principles ("previous CGAAP" or "CGAAP"). Unless otherwise noted, 2010 comparative information has been prepared in accordance with IFRS.

The adoption of IFRS has not had an impact on the Corporation's operations and strategic decisions. The most significant area of impact was to property, plant and equipment. Further information on the IFRS impacts is provided in the Accounting Policies of this MD&A, including reconciliations between previous CGAAP and IFRS Net Income, funds from operations and other financial metrics.

NON-IFRS FINANCIAL MEASURES

Throughout this MD&A, Management uses the terms funds from operations, funds from operations per share, payout ratio, cash flow from operations per share, net debt to trailing 12 month cash flow, operating netback and cash flow netback. These are considered useful supplemental measures as they provide an indication of the results generated by the Corporation's principal business activities. Management uses the terms to facilitate the understanding of the results of its operations. However, these terms do not have any standardized meaning as prescribed by Canadian Generally Accepted Accounting Principles for publicly accountable enterprises, being IFRS. Investors should be cautioned that these measures should not be construed as an alternative to net income determined in accordance with IFRS as an indication of NAL's performance. NAL's method of calculating these measures may differ from other income funds and companies and, accordingly, they may not be comparable to measures used by other income funds and companies.

Funds from operations is calculated as cash flow from operating activities before changes in non-cash working capital. Funds from operations does not represent operating cash flows or operating profits for the period and should not be viewed as an alternative to cash flow from operating activities calculated in accordance with IFRS. Funds from operations is considered by Management to be a more meaningful key performance indicator of NAL's ability to generate cash to finance operations and to pay monthly dividends. Funds from operations per share and cash flow from operations per share are calculated using the weighted average shares outstanding for the period.

Payout ratio is calculated as dividends declared for a period as a percentage of either cash flow from operating activities or funds from operations; both measures are stated.

Net debt to trailing 12 months cash flow is calculated as net debt as a proportion of funds from operations for the previous 12 months. Net debt is defined as bank debt, plus convertible debentures at face value, plus working capital and other liabilities, excluding derivative contracts, notes payable/receivable and deferred income tax balances.

The following table reconciles cash flows from operating activities to funds from operations:


                                                Three months ended March 31
                                              ------------------------------
$(000s)                                                 2011           2010
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Cash flow from operating activities                  $60,983        $68,248
Add back change in non-cash working capital            2,014         11,233
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Funds from operations                                $62,997        $79,481
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FORWARD-LOOKING INFORMATION

This MD&A contains forward-looking information as to the Corporation's internal projections, expectations and beliefs relating to future events or future performance. Forward looking information is typically identified by words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "could", "plan", "intend", "should", "believe", "outlook", "project", "potential", "target", and similar words suggesting future events or future performance. In addition, statements relating to "reserves" are forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities estimated and can be profitably produced in the future.

In particular, this MD&A contains forward-looking information pertaining to the following, without limitation: the amount and timing of cash flows and dividends to shareholders; reserves and reserves values; 2011 production; future tax treatment of the Corporation; the Corporation's tax pools; future oil and gas prices; operating, drilling and completion costs; the amount of future asset retirement obligations; future liquidity and future financial capacity; the initiation of an "at-the-market" financing program; future results from operations; payout ratios; cost estimates and royalty rates; drilling plans; tie-in of wells; future development, exploration, and acquisition and development activities and related expenditures; and rates of return.

With respect to forward-looking statements contained in this MD&A and the press release through which it was disseminated, we have made assumptions regarding, among other things: future oil and natural gas prices; future capital expenditure levels; future oil and natural gas production levels; future exchange rates; the amount of future cash dividends that we intend to pay; the cost of expanding our property holdings; our ability to obtain equipment in a timely manner to carry out exploration and development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and exploitation activities.

Although NAL believes that the expectations reflected in the forward-looking information contained in the MD&A and the press release through which it was disseminated, and the assumptions on which such forward-looking information are made, are reasonable, readers are cautioned not to place undue reliance on such forward looking statements as there can be no assurance that the plans, intentions or expectations upon which the forward-looking information are based will occur. Such information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated and which may cause NAL's actual performance and financial results in future periods to differ materially from any estimates or projections of future performance. These risks and uncertainties include, without limitation: changes in commodity prices; unanticipated operating results or production declines; the impact of weather conditions on seasonal demand and NAL's ability to execute its capital program; risks inherent in oil and gas operations; the imprecision of reserve estimates; limited, unfavorable or no access to capital or credit markets; the impact of competitors; the lack of availability of qualified operating or management personnel; the inability to obtain industry partner and other third party consents and approvals, when required; failure to realize the anticipated benefits of acquisitions; general economic conditions in Canada, the United States and globally; fluctuations in foreign exchange or interest rates; changes in government regulation of the oil and gas industry, including environmental regulation; changes in royalty rates; changes in tax laws; stock market volatility and market valuations; OPEC's ability to control production and balance global supply and demand for crude oil at desired price levels; political uncertainty, including the risk of hostilities in the petroleum producing regions of the world; and other risk factors discussed in other public filings of the Corporation including the Corporation's current Annual Information Form.

NAL cautions that the foregoing list of factors that may affect future results is not exhaustive. The forward-looking information contained in this MD&A is made as of the date of this MD&A. The forward-looking information contained in this MD&A is expressly qualified by this cautionary statement.

STRUCTURE OF THE BUSINESS

On December 31, 2010, NAL Oil & Gas Trust completed a plan of arrangement whereby the Trust unitholders exchanged their trust units for common shares of NAL Energy Corporation on a one-to-one basis thereby effectively converting the Trust into a corporation ("Reorganization"). As a result of the Reorganization, the Trust was dissolved and NAL Energy Corporation received all the assets and assumed all the liabilities of the Trust.

In conjunction with the Reorganization, a partnership ("Partnership") that was indirectly owned jointly by the Corporation and Manulife Financial Corporation ("MFC") was dissolved on December 31, 2010. This Partnership held the assets acquired from the acquisitions of Tiberius and Spear in February 2008.

Prior to December 31, 2010 the Corporation, by virtue of being the owner of the general partner of the Partnership, was required to consolidate the results of the Partnership into its financial statements on the basis that the Corporation had control over the Partnership. The March 31, 2010 MD&A and financial information of the Corporation therefore reflects all the assets, liabilities, revenues and expenses of the Partnership, of which 50 percent are effectively removed through the minority interest. As a result of the Partnership dissolution on December 31, 2010, the Corporation only reflects its proportionate share of the Partnership's assets, liabilities, revenues and expenses in the March 31, 2011 MD&A and financial information.

NAL's conversion from a trust to a corporation had no effect on its strategic or operational objectives.

EXPLORATION & DEVELOPMENT ACTIVITIES

The Corporation spent $68.8 million on drilling, completion and tie-in operations during the first quarter of 2011 compared to $56.0 million during the first quarter of 2010. There were 52 (29.3 net) wells drilled in the first quarter compared to 48 (21.1 net) wells during the same period in 2010 which is consistent with an expanded capital program year-over-year. Operations were conducted across NAL's operations with 24 wells drilled in Saskatchewan, two in British Columbia and 26 in Alberta.

The Corporation participated in 49 (28 net) horizontal wells with 85 percent of the activity focused on oil projects across Saskatchewan and Alberta. The Corporation will continue to focus on horizontal oil drilling for the remainder of the year with significant programs in the Cardium drilling 18 (12 net) additional wells and in the Mississippian throughout southeast Saskatchewan drilling 35 (16 net) wells.


First Quarter Drilling Activity

                                                           Dry &
                   Crude Oil Natural Gas Service Wells Abandoned      Total
                  ----------------------------------------------------------
                  Gross  Net   Gross Net  Gross    Net Gross Net Gross  Net
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Operated wells       41   24       6 4.4      0      0     0   0    47 28.4
Non-operated wells    2  0.1       2 0.3      0      0     1 0.5     5  0.9
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Total wells drilled  43 24.1       8 4.7      0      0     1 0.5    52 29.3
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Southeast Saskatchewan

In Saskatchewan, there were 24 (11.6 net) horizontal oil wells drilled during the first quarter with activity focused on the Mississippian in the greater Hoffer area (13), Steelman (2), Alida (2), Bryant (3), Hardy (1) and overall results are meeting internal expectations.

Extreme cold weather and high winter storm frequency translated into 12 lost drilling days and five fewer wells being drilled than planned in the quarter. Greater than normal snowfall has also amplified the impact of break up as very wet conditions have shut in many new areas where trucking from single well oil batteries is restricted and has curtailed production. This limited access has delayed new well tie-ins toward the end of the second quarter. NAL expects to have its base production back to full capacity in June.

New wells in Beaubier and Oungreare currently producing at initial production rates of 150 boe/d (50 percent WI), confirming additional accumulations in the Ratcliffe and Oungre directly offsetting Hoffer. Construction on a central battery at Hoffer is now expected to commence in the summer with facility start up scheduled by year end. The first Hardy Bakken drill at 13-32-5-21W2 is awaiting stimulation and tie-in which was delayed at the end of the quarter and is now scheduled for the end of June.

Drilling operations are expected to resume in June with four rigs drilling 35 gross wells (17.5 net) over the balance of the year.

Alberta

In Alberta, NAL participated in drilling 26 (15.7 net) locations including 12 (7 net) Cardium wells, eight (5.5 net) oil wells in Millard Lake, Irricana and Hussar and five (2.1 net) gas wells. Generally, equipment was available and NAL's drilling programs were executed as planned with some delay, especially in completion and tie-in activities.

NAL management continues to be encouraged by the performance of its Cardium programs and in aggregate, results continue to be in line with our internal type curve. Of the 12 Cardium wells drilled in the quarter, four are on stream, three wells are tied in recovering load fluid and waiting on infrastructure capacity, three wells are waiting on completion and two wells are waiting on tie-in with all remaining activities to be completed by the end of the second quarter. The Corporation has changed its completion process executing water-based fracs instead of oil in eight Cardium wells, using higher density 75 meter inter-frac spacing (14-18 stages per well) and lower (10-15)tonnes per stage. The 2-21-34-4W5M Cardium well came on production in early May with current production of over 500 boe/d (60 percent WI),which is above the Corporation's type curve. It is expected that an increased density of fracs will have a positive impact on reserves and initial production rates. NAL expects cost savings from using water versus oil based fracs will be offset by an increase in stages pumped and general cost escalation due to increased activity.

NAL has successfully drilled two (1.2 net) horizontal Viking oil wells at Caroline as part of a program to test the significant potential of the Viking on the Corporation's extensive land base in central Alberta. The first well 14-36-35-07W5M was completed with limited frac placement due to extremely high treating pressures but subsequently tested at greater than 1,000 boe/d. Production is expected to be on stream by June 1st and the Corporation will continue to assess performance as there is no analogous horizontal production in the area. The second well will be completed in the third quarter.

Infill oil drilling in Millard Lake, Hussar and Irricana has added 250 boe/d of production from four (3.4 net) wells.

The Corporation's liquids rich gas projects in the Edson area continue to drive strong capital efficiencies. In the quarter there were two (1.1 net) gas wells drilled and completed including the 13-07-56-19W5M (70 percent WI) Wilrich well which had a test rate of 1,400 boe/d (7.8 mmcf/d + 15 bbl/mmcf of free condensate) at 700 psi flowing wellhead pressure. Line looping and compression projects are coming on stream in the area in June and will increase Wilrich production from NAL's four wells, including 13-07, from 11 to 15 mmcf/d with well deliverability expected to hold production flat for several months. NAL also drilled a development Bluesky gas well at 1-32-54-17W5M which is tied in and flowed at 2 mmcf/d initial production.

The Corporation is planning 18 (12 net) Cardium wells for the remainder of the year with 12 in the greater Garrington area and six wells at Lochend/North Cochrane following up on successful operated and industry activity. Drilling is expected to commence in June.

Northeast British Columbia

There were two wells drilled in Fireweed (100 percent WI) during the first quarter. Access to frac services in this region proved challenging and the on stream forecast for these wells was delayed three months from original plans. The Doig horizontal b-96-I/94-A-12 was tested at final clean up rates of 1,600 boe/d (5 mmcf/d + 150 bbls/mmcf of free condensate) at a flowing tubing pressure of 500 psi and is expected to be on stream by June 1st. A second well at d-94-I/94-A-12 was tested at final clean up rates of 1,475 boe/d (6 mmcf/d + 80 bbls/mmcf of free condensate) at a flowing tubing pressure of 600 psi and has commenced production in May. Production from these two wells will be rate limited by facility capacity but should hold production flat for several months at 2,500 - 3,000 boe/d.

CAPITAL EXPENDITURES

Capital expenditures, before property acquisitions and dispositions, for the quarter ended March 31, 2011 totaled $82.6 million compared with $78.3 million for the quarter ended March 31, 2010. The year-over-year increase is tied to the corresponding increase in wells drilled as well as a continued shift towards horizontal drilling and multi stage frac completions which significantly increases per well costs. Spending was slightly below expectations ($6 million) as some drilling and completions late in the quarter were delayed and subsequent tie-ins were moved into the second and third quarter. First quarter land and seismic expenditures of $11.3 million represent a combination of Crown and private land purchases in and around established core areas and proprietary 3D seismic to help delineate play concepts on significant land blocks acquired in 2010.


Capital Expenditures ($000s)
                                                Three months ended March 31
                                              ------------------------------
                                                        2011           2010
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Drilling, completion and production equipment         68,793         55,993
Plant and facilities                                   2,121            427
Seismic                                                4,536          1,660
Land                                                   6,719         19,931
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Total exploitation and development                    82,169         78,011
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Office equipment                                         418            287
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Total capitalized expenditures before acquisitions    82,587         78,298
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Property acquisitions                                    983          1,485
Proceeds on disposition                              (27,090)       (14,676)
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Total property acquisitions (dispositions), net      (26,107)       (13,191)
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Total capitalized expenditures                        56,480         65,107
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PRODUCTION

First quarter 2011 production of 28,024 boe/d was six percent below production of 29,819 boe/d in the comparable period of 2010. One of the primary contributing factors to this year-over-year decline is that the first quarter of 2010 contained significant peak flush production from high impact horizontal wells at Irricana and Fireweed from the recently completed Breaker acquisition. Flush production was forecast to decline at rates of 70 percent through the remainder of 2010. Consequently, the first quarter of 2011 was negatively impacted higher than anticipated declines but the production profile on whole, is consistent with a typical front end loaded capital program where production peaks in the fourth quarter and is in decline during the first quarter. NAL also completed approximately 650 boe/d of dispositions in the first quarter of 2011 that impacts year-over-year performance.


Average Daily Production Volumes

                                                Three months ended March 31
                                              ------------------------------
                                                       2011            2010
----------------------------------------------------------------------------
Oil (bbl/d)                                          10,411          11,788
Natural gas (Mcf/d)                                  89,581          93,328
NGLs (bbl/d)                                          2,683           2,777
----------------------------------------------------------------------------
Oil equivalent (boe/d)                               28,024          30,120
Less 50% of oil equivalent production relating to
 the non-controlling interest (boe/d)(1)                  -            (301)
----------------------------------------------------------------------------
Oil equivalent (boe/d)                               28,024          29,819
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(1) See Structure of the Business

For the quarter ended March 31, 2011, oil and natural gas liquids production represented 47 percent of total production volume with natural gas representing 53 percent of total production volume.


Production Weighting

                                                Three months ended March 31
                                              ------------------------------
                                                       2011            2010
----------------------------------------------------------------------------

Oil                                                      37%             39%
Natural gas                                              53%             52%
NGLs                                                     10%              9%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

REVENUE

Gross revenue from oil, natural gas and natural gas liquids sales, after transportation costs and prior to hedging, totaled $121.8 million for the three months ended March 31, 2011, 11 percent lower than the first quarter of 2010. The decrease is due to a six percent decrease in production and a four percent decrease in the average realized price per boe, driven by a 27 percent decrease in the realized natural gas price offset by an eight percent increase in the realized crude oil price and a 12 percent increase in the realized price for natural gas liquids.


Revenue

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Revenue(1) ($000s)
 Oil                                                  77,007         81,085
 Gas                                                  29,692         42,064
 NGLs                                                 14,878         13,752
 Sulphur                                                 175            (18)
----------------------------------------------------------------------------
Total revenue                                        121,752        136,883
$/boe                                                  48.27          50.49
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Oil, natural gas and liquid sales less transportation costs and prior to
    royalties and hedging.

OIL MARKETING

NAL markets its crude oil based on refiners' posted prices at Edmonton, Alberta and Cromer, Manitoba adjusted for transportation and the quality of crude oil at each field battery. The refiners' posted prices are influenced by the WTI benchmark price, transportation costs, exchange rates and the supply/demand situation of particular crude oil quality streams during the year.

NAL's first quarter average realized Canadian crude oil price per barrel, net of transportation costs excluding hedging, was $82.19, as compared to $76.43 for the comparable quarter of 2010. The increase in realized price quarter-over-quarter of eight percent, or $5.76/bbl, was primarily driven by a 20 percent increase in the WTI price (U.S.$/bbl) over the comparable period, partially offset by a five percent increase in the value of the Canadian dollar.

For the first quarter of 2011, NAL's crude oil price differential was 89 percent, a decrease of four percentage points from the comparable period in 2010. The differential is calculated as realized price as a percentage of the WTI price stated in Canadian dollars. The differentials in the first quarter of 2010 were higher than NAL's historical average. In the first quarter of 2011, high inventory levels across North America combined with pipeline constraints resulted in lower NAL differentials at the start of the quarter, which started improving later in the quarter.

Natural gas liquids averaged $61.61/bbl in the first quarter of 2011, a 12 percent increase from the $55.02/bbl realized in 2010.

NATURAL GAS MARKETING

Approximately 72 percent of NAL's current gas production is sold under marketing arrangements tied to the Alberta monthly or daily spot price ("AECO"), with the remaining 28 percent tied to NYMEX or other indexed reference prices.

For the three months ended March 31, 2011, the Corporation's natural gas sales averaged $3.68/Mcf compared to $5.01/Mcf in the comparable period of 2010, a decrease of 27 percent. The quarter-over-quarter decrease in gas price was largely attributable to the AECO daily spot price decreasing 24 percent quarter-over-quarter.

Price for Lake Erie natural gas was $4.71/Mcf in the first quarter of 2011, a decrease of 17 percent compared to $5.70/Mcf in 2010. Lake Erie production of 3.0 mmcf/d accounted for three percent of the Corporation's natural gas production in the first quarter of 2011, consistent with the comparable period of 2010. Natural gas sales from the Lake Erie property generally receive a higher price due to the close proximity of the Ontario and Northeastern U.S. markets.


Average Pricing 
(net of transportation charges)

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Liquids
 WTI (US$/bbl)                                         94.10          78.69
 NAL average oil (Cdn$/bbl)                            82.19          76.43
 NAL natural gas liquids (Cdn$/bbl)                    61.61          55.02

Natural Gas (Cdn$/mcf)
 AECO - daily spot                                      3.77           4.96
 AECO - monthly                                         3.77           5.36
 NAL Western Canada natural gas                         3.65           4.98
 NAL Lake Erie natural gas                              4.71           5.70
 NAL average natural gas                                3.68           5.01

NAL Oil Equivalent before hedging (Cdn$/boe - 6:1)     48.27          50.49
Average Foreign Exchange Rate (Cdn$/US$)               0.986          1.041
----------------------------------------------------------------------------
----------------------------------------------------------------------------

RISK MANAGEMENT

NAL employs risk management practices to assist in managing cash flows and to support capital programs and distributions. NAL currently has derivative contracts in place to assist in managing the risks associated with commodity prices, interest rates and foreign exchange rates.

NAL's commodity hedging policy currently provides authorization for management to hedge up to 60 percent of forecasted total production, net of royalties. Management's practice is to layer in hedges such that more volumes are hedged in the current 12 month forward period with lesser volumes hedged in the 13 - 24 months forward time period. The execution of NAL's commodity hedging program is layered in using a combination of swaps and collars. As at March 31, 2011, NAL had several financial WTI oil contracts and AECO natural gas contracts in place.

NAL's interest rate hedging policy currently provides authorization to hedge up to 50 percent of outstanding bank debt for periods of up to five years. As at March 31, 2011, NAL had several interest rate swaps outstanding with a total notional value of US$139 million.

NAL's foreign exchange hedging policy currently provides authorization to hedge up to 50 percent of the Corporation's US dollar exposure for up to 24 months. As at March 31, 2011, NAL had several foreign exchange rate swaps outstanding with a total notional value of US$111 million.

All derivative contract counterparties are Canadian chartered banks in the Corporation's lending syndicate.

Realized losses on derivative contracts were $1.0 million for the first quarter of 2011, compared to a gain of $1.4 million in the comparable quarter of 2010. The losses in 2011 are due primarily to higher oil prices versus contracted positions and lower gains on gas positions due to reduced hedged positions. Oil losses are somewhat offset by foreign exchange gains related to a rising Canadian dollar.

All derivative contracts are recorded on the balance sheet at fair value based upon forward curves at March 31, 2011. Changes in the fair value of the derivative contracts are recognized in net income for the period.

Fair value is calculated at a point in time based on an approximation of the amounts that would be received or paid to settle these instruments, with reference to forward prices at March 31, 2011. Accordingly, the magnitude of the unrealized gain or loss will continue to fluctuate with changes in forward commodity prices, interest rates and foreign exchange rates.

The fair value of the derivatives at March 31, 2011 was a net liability of $30.2 million, comprised of a $36.7 million liability on oil contracts, offset by a $1.7 million asset on gas contracts, a $3.8 million asset on foreign exchange contracts and a $1.0 million asset on interest rate swaps.

First quarter income for 2011 includes a $20.3 million unrealized loss on derivatives resulting from the change in the fair value of the derivative contracts during the quarter from an unrealized loss of $9.9 million at December 31, 2010 to an unrealized loss of $30.2 million at March 31, 2011. The $20.3 million unrealized loss was comprised of a $21.3 million unrealized loss on crude oil contracts, a $0.3 million unrealized gain on interest rate swaps, a $0.1 million unrealized gain on natural gas contracts and a $0.6 million unrealized gain on foreign exchange contracts.


The gain/loss on all forward derivative contracts is as follows:

Gain / (Loss) on Derivative Contracts ($000s)

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Unrealized gain (loss):
 Crude oil contracts                                 (21,318)         1,546
 Natural gas contracts                                    56         15,021
 Interest rate swaps                                     306            191
 Exchange rate swaps                                     678          1,751
----------------------------------------------------------------------------
Unrealized gain (loss)                               (20,278)        18,509
Realized gain (loss):
 Crude oil contracts                                  (3,127)        (2,082)
 Natural gas contracts                                   916          2,497
 Interest rate swaps                                    (129)          (257)
 Exchange rate swaps                                   1,342          1,290
----------------------------------------------------------------------------
Realized gain (loss)                                    (998)         1,448
----------------------------------------------------------------------------
Gain (loss) on derivative contracts                  (21,276)        19,957
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The following is a summary of the realized gains and losses on risk
management contracts:

                 Realized Gain (Loss) on Derivative Contracts

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Commodity contracts:
Average crude volumes hedged (bbl/d)                   5,700          6,366
Crude oil realized gain (loss) ($000s)                (3,127)        (2,082)
 Gain (loss) per bbl hedged ($)                        (6.09)         (3.63)

Average natural gas volumes hedged (GJ/d)              5,000         37,967
Natural gas realized gain ($000s)                        916          2,497
 Gain per GJ hedged ($)                                 2.04           0.73

Average BOE hedged (boe/d)                             6,490         12,363
Total realized commodity contracts gain (loss)
 ($000s)                                              (2,211)           415
 Gain (loss) per boe hedged ($)                        (3.78)          0.37
 Gain (loss) per boe ($)                               (0.88)          0.15

Exchange rate swaps realized gain ($000s)              1,342          1,290
 Gain per boe ($)                                       0.53           0.48

Interest rate swaps realized loss ($000s)               (129)          (257)
 Loss per boe ($)                                      (0.05)         (0.09)

Total realized gain (loss) ($000s)                      (998)         1,448
 Gain (loss) per boe ($)                               (0.40)          0.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Average hedged boes for the first quarter of 2011 were 6,490 as compared to
11,049 for the fourth quarter of 2010.

NAL has the following interest rate risk management contracts outstanding:  

                                                               Counterparty
INTEREST RATE           Remaining         Amount   Corporation     Floating
 CONTRACT                    Term  (millions)(1)    Fixed Rate         Rate
----------------------------------------------------------------------------
Swaps-floating to      Apr 2011 -                               CAD-BA-CDOR
 fixed                   Dec 2011       $   39.0        1.5864%   (3 months)
Swaps-floating to      Apr 2011 -                               CAD-BA-CDOR
 fixed                   Jan 2013       $   22.0        1.3850%   (3 months)
Swaps-floating to      Apr 2011 -                               CAD-BA-CDOR
 fixed                   Jan 2014       $   22.0        1.5100%   (3 months)
Swaps-floating to      Apr 2011 -                               CAD-BA-CDOR
 fixed                   Mar 2013       $   14.0        1.8750%   (3 months)
Swaps-floating to      Apr 2011 -                               CAD-BA-CDOR
 fixed                   Mar 2014       $   14.0        1.9850%   (3 months)
Swaps-floating to      Apr 2011 -                               CAD-BA-CDOR
 fixed                   Mar 2013       $   14.0        1.8500%   (3 months)
Swaps-floating to      Apr 2011 -       $   14.0        1.9300% CAD-BA-CDOR
 fixed                   Mar 2014                                 (3 months)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional debt amount


NAL has the following Canadian dollar / U.S. dollar foreign exchange option
contracts outstanding.

Fixed Rate    Notional (US)
(CAD/USD)        per month               Term     Counterparty Floating Rate
----------------------------------------------------------------------------
1.05             $  2.0 MM     Apr 1, 2011 to           BofC Monthly Average
                                 Dec 31, 2011                      Noon Rate
1.0608           $  0.5 MM     Apr 1, 2011 to           BofC Monthly Average
                                 Dec 31, 2011                      Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------

NAL has a monthly commitment to settle the above fixed rates against the
Bank of Canada monthly average noon rate.

Option                                                              Monthly
Payout Range      Notional                                          Premium
(CAD/USD)         (US) per                   Counterparty          Received
                     month     Term         Floating Rate              (CAD)
----------------------------------------------------------------------------
                           May 1, 2011 to  BofC Monthly Average      
$0.93 - $1.01    $  3.0 MM  Dec 31, 2011   Noon Rate                 $  60K 

                           Jan 1, 2012 to  BofC Monthly Average     
$0.93 - $1.01    $  2.0 MM  Jun 30, 2012   Noon Rate                 $  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.

                          Notional                                          
Option Fixing Rate        (US) per                              Counterparty
 (CAD/USD)                   month               Term          Floating Rate
----------------------------------------------------------------------------
$0.94 - $1.06                          Apr 1, 2011 to   BofC Monthly Average
                         $  0.5 MM       Dec 31, 2011              Noon Rate

$0.95 - $1.07                          Apr 1, 2011 to   BofC Monthly Average
                         $  0.5 MM       Dec 31, 2011              Noon Rate

$0.94 - $1.08                          Apr 1, 2011 to   BofC Monthly Average
                         $  0.5 MM       Dec 31, 2011              Noon Rate

$0.95 - $1.04                          Apr 1, 2011 to   BofC Monthly Average
                         $  0.5 MM       Dec 31, 2011              Noon Rate

$0.95 - $1.0125                        Apr 1, 2011 to   BofC Monthly Average
                         $  0.5 MM       Jun 30, 2012              Noon Rate

$0.95 - $1.0138                        Apr 1, 2011 to   BofC Monthly Average
                         $  1.0 MM       Jun 30, 2012              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 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.


                        Notional                                            
Option Fixing Range     (US) per                                Counterparty
 (CAD/USD)                 month                   Term        Floating Rate
----------------------------------------------------------------------------
$1.05 - $1.15          $  1.0 MM     Apr 1, 2011 to Dec         BofC Monthly
                                               31, 2011    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.

NAL has the following commodity risk management contracts outstanding:

CRUDE OIL              Q2-11   Q3-11   Q4-11   Q1-12   Q2-12   Q3-12   Q4-12
----------------------------------------------------------------------------
US$ Collar Contracts                                                        
----------------------                                                      
$US WTI Collar Volume                                                       
 (bbl/d)               1,000     200     200     800     800     700     700
Bought Puts - Average                                                       
 Strike Price                                                               
 ($US/bbl)             83.00   90.00   90.00  101.25  101.25  101.43  101.43
Sold Calls - Average                                                        
 Strike Price                                                               
 ($US/bbl)             95.68  100.50  100.50  117.95  117.95  117.66  117.66
US$ Swap Contracts                                                          
----------------------                                                      
$US WTI Swap Volume                                                         
 (bbl/d)               4,900   5,700   5,700     500     500     500     500
Average WTI Swap                                                            
 Price ($US/bbl)       87.39   88.10   88.10  109.60  109.60  109.60  109.60
Total Oil Volume                                                            
 (bbl/d)               5,900   5,900   5,900   1,300   1,300   1,200   1,200
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Two calendar 2011 500 bbl/day 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.

NATURAL GAS               Q2-11   Q3-11   Q4-11   Q1-12  Q2-12  Q3-12  Q4-12
----------------------------------------------------------------------------
Swap Contracts                                                              
------------------------                                                    
AECO Swap Volume (GJ/d)  20,000  21,000  21,000  24,000  5,000  5,000  3,674
AECO Average Price                                                          
 ($Cdn/GJ)                 4.32    3.95    3.95    3.98   4.15   4.15   4.15
Total Natural Gas                                                           
 Volume (GJ/d)           20,000  21,000  21,000  24,000  5,000  5,000  3,674
----------------------------------------------------------------------------
----------------------------------------------------------------------------

For the remainder of 2011, the Corporation has outstanding contracts representing approximately 38 percent of its net crude oil, liquids and natural gas production after royalties. In 2012, the Corporation has outstanding contracts representing approximately 11 percent of its net liquids and natural gas production after royalties.

ROYALTY EXPENSES

Crown, freehold and overriding royalties were $19.8 million for the three months ended March 31, 2011. Expressed as a percentage of gross sales net of transportation costs, before gain/loss on derivative contracts, the net royalty rate was 16.3 percent for the quarter ended March 31, 2011, a decrease from the 16.5 percent experienced in the same period of the previous year.

Royalties decreased to $7.85 per boe for the first quarter of 2011, a decrease of six percent compared to the first quarter of 2010. The decrease is attributable to lower commodity prices on a quarter-over-quarter basis.

On March 11, 2010, the Alberta Government announced measures to improve the Province of Alberta's competitive position in the oil and gas industry. The current royalty framework for natural gas and conventional oil will be modified for all production effective January 1, 2011 and the new royalty curves were announced on May 31, 2010. The current incentive program rate of five percent on new natural gas and conventional oil wells is a permanent feature of the royalty systems. The maximum royalty rate for conventional oil wells is a permanent feature of the royalty system. The maximum royalty rate for conventional oil is reduced at higher price levels from 50 percent to 36 percent.

For the quarter ended March 31, 2011, 43 percent of crude oil and 69 percent of natural gas production was from Alberta.


Royalty Expenses

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Royalties ($000s)                                     19,789         22,599
As % of revenue                                         16.3           16.5
$/boe                                                   7.85           8.34
----------------------------------------------------------------------------
----------------------------------------------------------------------------

OPERATING COSTS

Operating costs averaged $10.81 per boe for the quarter ended March 31,
2011, up four percent from $10.35 per boe for the quarter ended March 31,
2010 and is attributed to lower volumes. Operating costs are expected to
remain within the guidance range of $10.50 - 10.90 per boe for full year
2011.

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Operating costs ($000s)                               27,257         28,070
As a % of revenue                                       22.4           20.5
$/boe                                                  10.81          10.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------

OTHER INCOME

Other income was $0.11 per boe for the first quarter of 2011 compared to
$0.12 per boe in the comparable quarter of 2010. Other income includes gas
processing fees and other miscellaneous income and fees.


                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Other Income                                             281            331
As a % of revenue                                          -              -
$/boe                                                   0.11           0.12
----------------------------------------------------------------------------
----------------------------------------------------------------------------

OPERATING NETBACK

For the quarter ended March 31, 2011, NAL's operating netback, before hedging gains, was $29.38 per boe, a decrease of 10 percent from $32.59 per boe for the quarter ended March 31, 2010. The decrease was due to lower revenues, a result of lower production and lower gas prices, increased operating costs, partially offset by decreased royalty expense. Hedging losses, related to commodity and exchange rate derivative contracts, were $0.34 per boe in the first quarter of 2011, as compared to a gain of $0.63 per boe in 2010, the decrease in 2011 attributable mainly to higher realized crude oil prices.


                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
AVERAGE DAILY PRODUCTION
 Oil (bbl/d)                                          10,411         11,788
 Gas (Mcf/d)                                          89,581         93,328
 NGLs (bbl/d)                                          2,683          2,777
----------------------------------------------------------------------------
Total (boe/d)                                         28,024         30,120

REVENUE(1)
 Oil ($/bbl)                                           82.19          76.43
 Gas ($/Mcf)                                            3.68           5.01
 NGLs ($/bbl)                                          61.61          55.02
----------------------------------------------------------------------------
Total ($/boe)                                          48.27          50.49

ROYALTIES
 Oil ($/bbl)                                           16.16          15.06
 Gas ($/Mcf)                                            0.13           0.42
 NGLs ($/bbl)                                          14.92          12.23
----------------------------------------------------------------------------
Total ($/boe)                                           7.85           8.34

OPERATING EXPENSES
 Oil ($/bbl)                                           16.83          12.79
 Gas ($/Mcf)                                            1.05           1.41
 NGLs ($/bbl)                                          12.71          10.85
----------------------------------------------------------------------------
Total ($/boe)                                          10.81          10.35

OTHER INCOME(2)
 Oil ($/bbl)                                            0.19           0.25
 Gas ($/Mcf)                                            0.01           0.02
 NGLs ($/bbl)                                           0.14           0.18
----------------------------------------------------------------------------
Total ($/boe)                                           0.11           0.16

OPERATING NETBACK, BEFORE HEDGING
 Oil ($/bbl)                                           49.39          48.83
 Gas ($/Mcf)                                            2.51           3.20
 NGLs ($/bbl)                                          34.12          32.12
----------------------------------------------------------------------------
Total ($/boe)                                          29.72          31.96

HEDGING GAINS/(LOSSES)(3)
 Oil ($/bbl)                                           (1.90)         (0.75)
 Gas ($/Mcf)                                            0.11           0.30
 NGLs ($/bbl)                                              -              -
----------------------------------------------------------------------------
Total ($/boe)                                          (0.34)          0.63

OPERATING NETBACK, AFTER HEDGING
 Oil ($/bbl)                                           47.49          48.08
 Gas ($/Mcf)                                            2.62           3.50
 NGLs ($/bbl)                                          34.12          32.12
----------------------------------------------------------------------------
Total ($/boe)                                          29.38          32.59
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation charges.
(2) Excludes interest on notes with MFC and gain on sale of oil and gas
    properties.
(3) Realized hedging gains/losses on commodity and exchange rate derivative
    contracts.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative ("G&A") expenses include direct costs incurred by the Corporation plus the reimbursement of the G&A expenses incurred by NAL Resources Management Limited (the "Manager") on the Corporation's behalf.

For the three months ended March 31, 2011, G&A expenses were $7.4 million, compared with $5.9 million in the comparable quarter of 2010. G&A expense per boe was $2.95 in the quarter, as compared to $2.17 for the same period in 2010.

The year-over-year increase in total G&A of $1.5 million is attributable to higher consulting and information systems costs in the first quarter of 2011.


                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
G&A ($000s)                                            7,431          5,882
($/boe)                                                 2.95           2.17
As % of revenue                                          6.1            4.3
Per share ($)                                           0.05           0.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------

SHARE-BASED INCENTIVE COMPENSATION PLAN

The employees of the Manager are all members of a share-based incentive plan (the "Plan"). The Plan results in employees of the Manager receiving cash compensation based upon the value and overall return of a specified number of notional common shares. The Plan consists of Restricted Share Units ("RSUs") and Performance Share Units ("PSUs"). One third of each RSU grant vests on November 30 in each of the three years after the date of grant. PSUs vest on November 30, three years from the date of grant. Dividends paid on the Corporation's outstanding shares during the vesting period are assumed to be paid on the awarded notional shares and reinvested in additional notional shares on the date of distribution. Upon vesting, the employee of the Manager is entitled to a cash payout based on the share price at the date of vesting of the shares held. In addition, the PSUs have a performance multiplier which is based on the Corporation's performance relative to its peers and may range from zero to two times the market value of the notional shares held at vesting.

During the first quarter of 2011, the Corporation recorded a $0.6 million charge for share-based incentive compensation that reflects the impact of vesting, additional notional shares and an increase in the share price. The share price of the Corporation increased by two percent from $12.95 at December 31, 2010 to $13.23 at March 31, 2011. An increase in share price results in previously accrued amounts being increased.

Share-based incentive compensation remained relatively constant as compared to the first quarter of 2010, from $0.7 million in 2010 to $0.6 million in 2011.

At March 31, 2011, the share price used to determine share-based incentive compensation was $13.23. The closing share price of the Corporation on the Toronto Stock Exchange on May 18, 2011 was $12.40.

The calculation of share-based compensation expense is made at the end of each quarter based on the quarter end share price and estimated performance factors. The compensation charges relating to the shares granted are recognized over the vesting period based on the share price, number of RSUs and PSUs outstanding, and the expected performance multiplier. As a result, the expense recorded in the accounts will fluctuate in each quarter and over time.

At March 31, 2011, the Corporation has recorded a total accumulated liability for share-based incentive compensation in the amount of $6.5 million, of which $4.8 million is recorded as current as it is payable in December 2011, and $1.7 million is long-term as it is payable in December 2012 and December 2013.


Share-Based Compensation

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Share-based compensation ($000s)                         636            686
As % of revenue                                          0.5            0.5
$/boe                                                   0.25           0.25
Per share ($)                                              -              -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

RELATED PARTY TRANSACTIONS

The Corporation continues to be managed by the Manager. The Manager is a wholly-owned subsidiary of Manulife Financial Corporation ("MFC") and also manages NAL Resources Limited ("NAL Resources"), another wholly-owned subsidiary of MFC. NAL Resources and the Corporation maintain ownership interests in many of the same oil and natural gas properties in which NAL Resources is the joint operator. As a result, a significant portion of the net operating revenues and capital expenditures during the year are based on joint amounts from NAL Resources. These transactions are in the normal course of joint operations and are measured using the fair value established through the original transactions with third parties.

The Manager provides certain services to the Corporation and its subsidiary entities pursuant to an administrative services and cost sharing agreement. This agreement requires the Corporation to reimburse the Manager at cost for G&A and share-based compensation expenses incurred by the Manager on behalf of the Corporation calculated on a unit of production basis. The agreement does not provide for any base or performance fees to be payable to the Manager.

The Corporation paid $6.2 million (2010 - $3.6 million) for the reimbursement of G&A expenses during the first quarter. The Corporation also pays the Manager its share of share-based incentive compensation expense when cash compensation is paid to employees under the terms of the Plan, of which $6.8 million was paid in the first quarter of 2011, representing shares that vested on November 30, 2010 (2010 - $6.9 million).

At March 31, 2011 the Corporation owed the Manager $2.1 million for the reimbursement of G&A and had a receivable from NAL Resources of $2.6 million, relating to operating revenue less capital expenditures.

In conjunction with the Reorganization, a partnership that was indirectly owned jointly by the Corporation and MFC was dissolved on December 31, 2010. The Partnership held the assets acquired from the acquisitions of Tiberius and Spear in February 2008. See "Structure of the Business" in this MD&A for more information.

As part of the original structuring of the Partnership in 2008, both the Trust and MFC entered into net profit interest royalty agreements ("NPI") with the Partnership. These agreements entitle each royalty holder to a 49.5 percent interest in the cash flow from the Partnership's reserves.

In addition, in the Partnership there was a note payable to MFC, which was settled on dissolution of the Partnership. At January 1, 2010, the note payable of $8.9 million was included on consolidation of the Partnership, but was effectively eliminated through the non-controlling interest. The note was due on demand, unsecured and bore interest at prime plus three percent.

INTEREST

Interest on bank debt includes the interest rate charge on borrowings, plus a standby fee, a stamping fee and the fee for renewal. Interest on bank debt for the first quarter of 2011 was $3.2 million, an increase of $0.1 million from $3.1 million for the comparable period in 2010. The increase was due to an increase in average debt levels, partially offset by a decrease in effective interest rates. Average outstanding bank debt for the first quarter of 2011 was $259.3 million, $26.8 million higher than the $232.5 million outstanding for the first quarter of 2010. NAL's effective interest rate averaged 5.05 percent during the first quarter of 2011, compared to 5.39 percent during the comparable period in 2010. The decrease in the rate from the first quarter of 2010 is attributable to decreases in the bank fees that are included in debt costs partially offset by increases in interest rates. NAL's interest is calculated based upon a floating rate before the effect of any interest rate swaps.

Interest on convertible debentures represented interest charges of $3.1 million for the three months ended March 31, 2011 and March 31, 2010. The interest includes the interest on the 2007 debentures at 6.75 percent and the interest on the debentures issued in December 2009 at 6.25 percent. Amortization of the debt premium was $0.6 million for the three months ended March 31, 2011. During 2010, the convertible debentures were recorded at fair value resulting in no accretion or amortization in 2010 (refer to "Capital Resources and Liquidity" in this MD&A for further detail).


Interest and Debt

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Interest on bank debt ($000s)(1)                       3,229          3,086
Interest and amortization on convertible debentures
 ($000s)                                               2,549          3,142
----------------------------------------------------------------------------
Total interest ($000)                                  5,778          6,228

Bank debt outstanding at period end ($000s)          255,306        244,695
Convertible debentures at period end ($000s) (2)     198,926        204,362

$/boe:
 Interest on bank debt                                  1.28           1.14
 Interest on convertible debentures                     1.25           1.16
 Amortization on convertible debentures                (0.24)             -
----------------------------------------------------------------------------
 Total interest                                         2.29           2.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes interest rate contract impact.
(2) Debt component of the debentures, as reported on the balance sheet.

CASH FLOW NETBACK

For the quarter ended March 31, 2011, NAL's cash flow netback was $23.60 per
boe, a 15 percent decrease from $27.74 per boe for the comparable period in
2010. The decrease was due to a lower operating netback after hedging,
higher G&A expenses, including share-based incentive compensation, and
higher interest charges.

                            Cash Flow Netback ($/boe)

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Operating netback, after hedging                       29.38          32.59
G&A expenses, including share-based incentive
 compensation                                          (3.20)         (2.42)
Interest on bank debt and convertible debentures(1)    (2.53)         (2.30)
Interest on notes with MFC(2)                              -          (0.04)
Realized loss on interest rate derivative contracts    (0.05)         (0.09)
----------------------------------------------------------------------------
Cash flow netback                                      23.60          27.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes non-cash accretion on convertible debentures.
(2) Reported as other income.


GAIN ON DISPOSITION OF OIL AND GAS PROPERTIES

During the first quarter of 2011 NAL disposed of certain non-core properties
resulting in a gain of $12.5 million (2010 - $11.2 million). The
gain is computed as the difference between sales proceeds and the net book
value.

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Gain on sale of oil and gas properties ($000s)        12,534         11,193
As a % of revenue                                       10.3            8.2
$/boe                                                   4.97           4.13
----------------------------------------------------------------------------
----------------------------------------------------------------------------

DEPLETION, ACCRETION OF ASSET RETIREMENT OBLIGATIONS AND IMPAIRMENT

Depletion of oil and natural gas properties, including the capitalized portion of the asset retirement obligations, and depreciation of equipment is provided for on a unit-of-production basis using estimated proved plus probable reserves volumes.

For the quarter ended March 31, 2011, depletion on property, plant and equipment was $18.40 per boe, three percent higher than the $17.80 per boe for the same period in 2010.

Accretion on asset retirement obligation was $2.5 million for the first quarter in 2011, a seven percent decrease from $2.7 million at the comparable period of 2010 due to disposition of properties.

Impairment in the first quarter of 2011 was $5.2 million compared to no impairment taken in the first quarter of 2010. Impairment is recognized if the carrying amount of PP&E is greater than their recoverable amount, and it is calculated on a cash generating unit basis ("CGU") see "Accounting Policies" section of this MD&A for more information. A CGU is the lowest level at which there are identifiable cash inflows. NAL has determined that it has nine CGUs. The impairment has occurred in natural gas CGUs due to lower gas prices compared to December 31, 2010. Once gas prices recover and the fair value of assets increase, NAL is required to reverse any impairment previously recognized in net income, net of what depletion would have been had the asset not been impaired and increase the carrying value of the CGU to which it relates. The reversal cannot exceed the amount previously written off.

The depletion rate will fluctuate period-over-period depending on the amount and type of capital expenditures and the amount of reserves added.


                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Depletion ($000s)                                     46,412         48,265
 Depletion rate per boe ($)                            18.40          17.80
Accretion of asset retirement obligation ($000s)       2,544          2,701
Impairment ($000s)                                     5,200              -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

TAXES

In the first quarter of 2011, NAL had a deferred income tax reduction of $0.3 million compared to a $2.7 million expense in the corresponding period of the prior year.

As at March 31, 2011, the Corporation's (including all subsidiaries) estimated tax pools available for deduction from future taxable income approximated $1.4 billion, of which approximately 31 percent represented COGPE, 17 percent represented UCC, with the balance represented by CEE, CDE, share issue costs and non-capital loss carry forwards.


Estimated Tax Pools ($ millions)

                                                                December 31,
                                              March 31, 2011           2010
----------------------------------------------------------------------------
Canadian exploration expense                              58             57
Canadian development expense                             417            376
Canadian oil and gas property expense                    432            456
Undepreciated capital costs                              242            251
Other (including loss carry forwards)                    246            279
----------------------------------------------------------------------------
Total estimated tax pools                              1,395          1,419
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Based on current strip prices at March 31, 2011, the Corporation is not expected to be taxable in 2011.

MINORITY INTEREST

The Corporation had recorded a minority interest in respect of the 50 percent ownership interest indirectly held by MFC in the Partnership holding the Tiberius and Spear assets (see "Structure of the Business") for the period ended March 31, 2010. As the Partnership was dissolved December 31, 2010, no minority interest was recorded for the period ended March 31, 2011.

The minority interest presented in the 2010 statement of income has two components: the royalty paid to MFC under the NPI, being a cash payment to the royalty holder, and 50 percent of net income remaining in the Partnership, after NPI expense, attributable to MFC. This share of net income attributable to MFC is a non-cash item.

The minority interest in the consolidated statement of income is comprised of:


                                                Three months ended March 31
                                               -----------------------------
($000s)                                                 2011           2010
----------------------------------------------------------------------------
Net profits interest expense                               -            618
Share of net income attributable to MFC                    -            314
----------------------------------------------------------------------------
                                                           -            932
----------------------------------------------------------------------------
----------------------------------------------------------------------------

NET INCOME

Net income is a measure impacted by both cash and non-cash items. The largest non-cash items impacting the Corporation's net income are depletion, accretion, unrealized gains or losses on derivative contracts gains or losses on disposals of property, plant and equipment, future income taxes and impairment losses/reversals, should these occur.

The loss for the first quarter of 2011 was $1.5 million compared to $50.2 million of net income for the comparable period in 2010. The decrease of $51.7 million was mainly due to decreased revenues net of royalties ($12.5 million), decreased gains on derivative contracts ($41.2 million), increased G&A ($1.5 million), an impairment loss in 2011 of $5.2 million offset by decreased operating costs ($0.8 million), decreased DD&A expense ($1.9 million), a lower tax expense ($3.0 million), a higher gain on disposition in 2011 ($1.3 million) and a fair value adjustment and issuance costs related to convertible debentures in 2010 ($1.0 million).


                                                Three months ended March 31
                                               -----------------------------
($000s)                                                 2011           2010
----------------------------------------------------------------------------
Net income (loss)                                     (1,510)        50,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------

CAPITAL RESOURCES AND LIQUIDITY

The capital structure of the Corporation is comprised of common shares, bank debt and convertible debentures.

As at March 31, 2011, NAL had 147,781,497 common shares outstanding, compared with 147,248,494 common shares as at December 31, 2010. The increase from December 31, 2010 is attributable to 533,003 shares issued under the Corporation's dividend reinvestment plan ("DRIP").

Under the DRIP, shareholders may elect to reinvest dividends or make optional cash payments to acquire common shares from treasury under the DRIP at 95 percent of the average market price with no additional fees or commissions. The operation of the DRIP was reinstated effective with the March distribution payable on April 15, 2009, following suspension of the program in October 2008. Participation in the DRIP averaged 20 percent for this quarter.

As at March 31, 2011, the Corporation had net debt of $528.7 million (net of working capital and other liabilities, excluding derivative contracts and deferred taxes) including the convertible debentures at face value of $194.7 million. Excluding the convertible debentures, net debt was $334.0 million, compared with $310.3 million at December 31, 2010. The increase in net debt, excluding convertible debentures, of $23.7 million during 2011 is attributable to a negative change in working capital of $35.4 million partially offset by decreased bank debt of $11.7 million.

Bank debt outstanding was $255.3 million at March 31, 2011 compared with $267.0 million as at December 31, 2010. Of the $255.3 million outstanding at March 31, 2011, $254.8 million is outstanding under the production facility, and $0.5 million is under the working capital facility.

At the end of the first quarter, the Corporation had a net debt (excluding convertible debentures) to 12 months trailing cash flow ratio of 1.26 times and a total net debt (including convertible debentures) to 12 months trailing cash flow ratio of 2.00 times.

Subsequent to quarter end, the Corporation had its previously approved credit facility amount of $550 million renewed. The credit facility is a fully secured, extendible, revolving facility and will revolve until April 30, 2012 at which time it is extendible for a further 364-day revolving period upon agreement between the Corporation and the bank syndicate. The facility consists of a $535 million production facility and a $15 million working capital facility. The credit facility is fully secured by first priority security interests in all present and after acquired properties and assets of the Corporation and its subsidiary and affiliated entities. The purpose of the facility is to fund property acquisitions and capital expenditures. Principal repayments to the bank are not required at this time. Should principal repayments become mandatory, and in the absence of refinancing arrangements, the Corporation would be required to repay the facility in five equal quarterly installments commencing May 1, 2013.

The Corporation has two series of convertible debentures currently outstanding.

On December 3, 2009, the Corporation issued $115 million principal amount of 6.25 percent convertible unsecured subordinated debentures. Interest on the debentures is paid semi-annually in arrears, on June 30 and December 31, and the debentures are convertible at the option of the holder, at any time, into fully paid common shares at a conversion price of $16.50 per common share. The debentures mature on December 31, 2014 at which time they are due and payable. The debentures are redeemable by the Corporation at a price of $1,050 per debenture on or after January 1, 2013 and on or before December 31, 2013, and at a price of $1,025 per debenture on or after January 1, 2014 and on or before December 31, 2014. On redemption or maturity, the Corporation may opt to satisfy its obligation to repay the principal by issuing common shares. If all of the outstanding debentures were converted at the conversion price, an additional 7.0 million common shares would be required to be issued.

In addition, the Corporation has outstanding $79.7 million principal amount of 6.75 percent convertible extendible unsecured subordinated debentures. Interest on these debentures is paid semi-annually in arrears, on February 28 and August 31, and the debentures are convertible at the option of the holder, at any time, into fully paid common shares at a conversion price of $14.00 per common share. The debentures mature on August 31, 2012 at which time they are due and payable. The debentures are redeemable by the Corporation at a price of $1,050 per debenture on or after September 1, 2010 and on or before August 31, 2011, and at a price of $1,025 per debenture on or after September 1, 2011 and on or before August 31, 2012. On redemption or maturity, the Corporation may opt to satisfy its obligation to repay the principal by issuing common shares. If all of the outstanding debentures were converted at the conversion price, an additional 5.7 million common shares would be required to be issued.

Subsequent to December 30, 2010, the convertible debentures are classified as debt on the balance sheet with a portion of the proceeds allocated to equity, representing the value of the conversion feature. Prior to December 31, 2010, as a trust, the convertible debentures were fair valued with no equity portion. As the debentures are converted to common shares, a portion of the debt and equity amounts are transferred to Share Capital. The debt balance amortizes over time to the principal amount owing on maturity. The amortization of the debt premium and the interest paid to debenture holders are reflected each period as part of the line item "interest and amortization on convertible debentures" in the consolidated statement of income.

The Corporation recognized $0.6 million (2010 - nil) of amortization of the debt premium in the first quarter of 2011.

As at May 19, 2011, the Corporation has 148,188,597 common shares and $194.7 million in convertible debentures outstanding.


Capitalization

                                     March 31,   December 31,      March 31,
                                         2011           2010           2010
----------------------------------------------------------------------------
Shareholders' equity ($000s)          869,962        895,750        887,937

Bank debt ($000s)                     255,306        266,965        244,695
Working capital deficit(1) ($000s)     78,697         43,337         63,760
----------------------------------------------------------------------------
Net debt excluding convertible
 debentures                           334,003        310,302        308,455
Convertible debentures ($000s)(2)     194,744        194,744        194,744
----------------------------------------------------------------------------
Net debt                              528,747        505,046        503,199

Net debt excluding convertible
 debentures to trailing 12-month
 cash flow(3)                            1.26           1.11           1.24
Total net debt to trailing 12-month
 cash flow(3)                            2.00           1.80           2.03
Common shares outstanding (000s)      147,781        147,248        137,881
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Working capital and other liabilities, excludes derivative contracts,
    deferred tax and note with MFC.
(2) Convertible debentures included at face value.
(3) Calculated as net debt divided by funds from operations for the previous
    12 months.

Funds from operations is a non-IFRS measure used by management as an indicator of the Corporation's ability to generate cash from operations. Assuming the Corporation's commodity price and guidance assumptions are attained, dividend levels represent a payout ratio in the range of 40 - 50 percent of funds from operations. The Corporation renewed its bank line of $550 million of which $255 million is drawn at March 31, 2011, leaving available capacity of $295 million.

For 2011, the Corporation expects to continue to benefit from an active hedging program. Currently, the Corporation has in place oil hedges for approximately 52 percent of net forecasted (after royalty) production for 2011. Crude volumes are hedged at an average price of US$87.89 per boe on fixed price contracts. On collared contracts, crude volumes are hedged at an average ceiling price of US$97.06 per boe and at an average floor price of US$85.00 per boe. For natural gas, remaining 2011 hedges total approximately 25 percent of net budgeted production volumes hedged at an average floor price in excess of $4.07 per GJ ($4.29 per Mcf).

NAL's capital program is designed to be scalable and flexible in response to commodity prices and market conditions. For 2011, the Corporation plans for a $200 - 230 million capital program. The Corporation, through the Manager, operates approximately 95 percent of the assets to which the capital program is directed, allowing for significant flexibility over the scale and timing of the program.

Fluctuations in commodity prices, market conditions or potential growth opportunities may make it necessary to adjust forecasted capital expenditures and/or distributions levels.

ASSET RETIREMENT OBLIGATION

At March 31, 2011, the Corporation reported an asset retirement obligation ("ARO") balance of $126.0 million ($149.0 million as at December 31, 2010) for future abandonment and reclamation of the Corporation's oil and gas properties and facilities. The ARO balance was increased by revisions to estimates and $2.5 million from accretion expense, and was reduced by $23.1 million for property dispositions and $2.4 million for actual abandonment and reclamation expenditures incurred during the first quarter. Liabilities incurred to the quarter were offset by revisions to estimates.

VARIABLE INTEREST ENTITIES

NAL has no variable interest entities.

CONTRACTUAL OBLIGATIONS

Joint Venture Agreement:

Effective April 20, 2009, the Corporation and MFC entered into a joint venture agreement with a senior industry partner. The arrangement consists of a three year commitment to spend $50 million to earn an interest in freehold and crown acreage. The Corporation has a 65 percent interest in this agreement and MFC a 35 percent interest and therefore the Corporation's net commitment is $32.5 million. The agreement is exclusive and structured to be extendible for up to an additional six years for a total potential commitment of $150 million ($97.5 million net to the Corporation) to earn an interest in over 150 sections (97.5 net) of freehold and crown acreage. If the capital spending commitments are not met, interests in the freehold and crown acreage will not be earned and the Corporation will not be required to pay unspent commitment amounts to the senior industry partner. As at March 31, 2011, the Corporation had spent $14.0 million under this agreement.

Farm-in Agreement:

Effective August 10, 2009, the Corporation and MFC entered into a farm-in agreement with a senior industry partner. The arrangement consists of a two year initial commitment, with a minimum capital commitment of $40 million in the first year and $57 million in the second year, with an option for a third year, at NAL's election, for an additional $50 million commitment. The Corporation has a 60 percent interest in this agreement and MFC a 40 percent interest. The agreement provides the opportunity to earn an interest in approximately 1,400 gross sections of undeveloped oil and gas rights in Alberta held by the partner. If the capital spending commitments are not met, interest in the acreage will not be earned and the Corporation will not be required to pay any unspent amounts under the Agreement. As at March 31, 2011, the Corporation had spent $36.7 million under this agreement.

Other:

NAL has entered into several contractual obligations as part of conducting day-to-day business. NAL has the following commitments for the next five years:


($000s)                                   2011   2012    2013    2014  2015
----------------------------------------------------------------------------
Office lease(1)                          1,431  2,146   2,132   2,092 2,092
Office lease - Clipper and Breaker(2)    1,473  2,211     364       -     -
Transportation agreement                 3,126  2,352   2,209   1,030   124
Processing agreement(3)                    466    197     184       -     -
Convertible debentures(4)                    - 79,744       - 115,000     -
Bank debt                                    -      - 153,146 102,098     -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total                                    6,496 86,650 158,035 220,220 2,216
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the full amount of office lease commitments, including both
    base rent and operating costs, in relation to the lease held by the
    Manager, of which the Corporation is allocated a pro rata share
    (currently approximately 60 percent) of the expense on a monthly basis.
(2) Represents the full amount of office lease assumed with the acquisitions
    of Clipper and Breaker. MFC will reimburse the Corporation for 50
    percent of the Clipper obligation under the base price adjustment
    clause.
(3) Represents gas processing agreements with take or pay components.
(4) Principal amount.

QUARTERLY INFORMATION

               2011                 2010                        2009
----------------------------------------------------------------------------
($000s, except
 per share
 and production
 amounts)        Q1      Q4      Q3      Q2      Q1     Q4(4)   Q3(4)  Q2(4)
----------------------------------------------------------------------------
Revenue,
 net of
 royalties
 (1)         82,391  85,685 101,258 106,332 136,209   88,165  85,988 60,922
 Per share     0.56    0.58    0.69    0.74    0.99     0.75    0.77   0.60
Cash flow    60,983  72,152  88,400  48,152  68,248   53,060  52,999 63,690
 Per share     0.41    0.49    0.60    0.33    0.50     0.45    0.47   0.63
Funds from
 operations
 (2)         62,997  67,645  65,696  67,848  79,481   62,953  53,766 51,998
 Per share     0.43    0.46    0.45    0.47    0.58     0.53    0.48   0.51
Net income
 (loss)      (1,510)(22,017)  7,430  23,443  50,169    5,634   8,249 (9,407)
 Per share
  basic       (0.01)  (0.15)   0.05    0.16    0.36     0.05    0.07  (0.09)
  diluted     (0.01)  (0.14)   0.05    0.16    0.35     0.05    0.07  (0.09)
Average oil
 equivalent
 production
 (boe/d -
 6:1)        28,024  28,596  29,473  29,609  30,120 25,748(3) 23,418 23,049
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents revenue, net of royalties, plus gain (loss) on derivative
    contracts
(2) Represents cash flow from operating activities prior to the change in
    non-cash working capital items
(3) Includes Breaker volumes effective December 11, 2009.
(4) As computed under previous CGAAP.

DISCLOSURE CONTROLS AND PROCEDURES ("DC&P")

The Chief Executive Officer and the Chief Financial Officer ("certifying officers") have designed DC&P, or caused them to be designed under their supervision, to provide reasonable assurance that all material information required to be disclosed by NAL in its interim filings is processed, summarized and reported within the time periods specified in applicable securities legislation.

INTERNAL CONTROL OVER FINANCIAL REPORTING ("ICFR")

NAL's certifying officers are responsible for establishing and maintaining ICFR, as such term is defined in National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings. The control framework NAL's officers used to design NAL's ICFR is the Internal Control - Integrated Framework (the "COSO Framework") published by The Committee of Sponsoring Organizations of the Treadway Commission ("COSO").

The certifying officers designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes.

There has not been any change in NAL's ICFR during the interim period ended March 31, 2011 that has materially affected, or is reasonably likely to materially affect, NAL's ICFR.

ACCOUNTING POLICIES

The Corporation has prepared its March 31, 2011 Interim Consolidated Financial Statements in accordance with IFRS1, First-time Adoption of International Financial Reporting Standards, and with IAS 34, Interim Financial Reporting, as issued by the IASB. Previously, the Corporation prepared its financial statements in accordance with Canadian GAAP, or previous CGAAP. The adoption of IFRS has not had a material impact on the Corporation's operations and strategic decisions.

The Corporation's IFRS accounting policies are provided in Note 2 to the Interim Consolidated Financial Statements. In addition, Note 14 to the Interim Consolidated Financial Statements presents reconciliations between the Corporation's 2010 previous CGAAP results and the 2010 IFRS results. The reconciliations include the Consolidated Balance Sheets as at January 1, 2010, March 31, 2010 and December 31, 2010, and Consolidated Statement of Earnings, Comprehensive Income, Changes in Shareholders Equity and Cash Flows for the three months ended March 31, 2010 and for the 12 months ended December 31, 2010.

The following discussion explains the significant differences between NAL's previous CGAAP accounting policies and those applied by the Corporation under IFRS. IFRS policies have been retrospectively and consistently applied except where specific IFRS1 optional and mandatory exemptions permitted an alternative treatment upon transition to IFRS for first-time adopters.

The most significant changes to the Corporation's accounting policies relate to the accounting for property, plant and equipment. Under previous CGAAP, NAL followed the Canadian Institute of Chartered Accountants ("CICA") guideline on full cost accounting in which all costs directly associated with the acquisition of, the exploration for, and the development of natural gas and crude oil reserves were capitalized in one cost centre. Costs accumulated within the cost centre were depleted using the unit-of-production method based on proved reserves determined using estimated future prices and costs. Upon transition to IFRS, the Corporation was required to adopt new accounting policies, including exploration and evaluation costs ("E&E") and development and production costs ("D&P").

Under IFRS, E&E costs are those expenditures for an area where technical feasibility and commercial viability has not yet been determined. D&P costs include those expenditures for areas where technical feasibility and commercial viability has been determined.

A) Property, plant and equipment (PP&E) and Exploration and evaluation assets

The Corporation elected to apply the IFRS1 exemption available to entities which followed full cost accounting under previous CGAAP. This exemption permits the total carrying value of PP&E and E&E under IFRS on transition to equal the carrying value under previous CGAAP, subject to an impairment test. In addition, conversion to IFRS requires the allocation of the carrying amount of the full cost pool under previous CGAAP to E&E, and to components and CGUs for PP&E assets. Firstly, E&E assets were recorded at their carrying amount under previous CGAAP. The remaining previous CGAAP carrying amount was then allocated, pro-rata to components (Areas) for D&P assets ("PP&E"), based on proved plus probable reserve values, using the present values at a 10 percent discount rate.

E&E assets are required to be segregated from D&P assets. At January 1, 2010 these assets were $88.1 million, representing their carrying value under previous CGAAP. In order to present PP&E assets in accordance with IFRS, this $88.1 million was reclassified to E&E on NAL's financial statements at January 1, 2010. These assets comprise exploratory undeveloped land and possible reserves assigned as a result of business acquisitions. As at March 31, 2010 and December 31, 2010, NAL's E&E assets were $90.1 million and $63.1 million, respectively.

Under previous CGAAP these assets were included in the full cost pool as CGAAP PP&E, in accordance with the CICA's full cost accounting guideline. Under IFRS, these costs are initially recorded as E&E, and on determination of technical feasibility and commercial viability of the assets the capitalized costs are then moved to PP&E. Under IFRS, unrecoverable E&E costs and costs incurred prior to obtaining the legal rights to explore are expensed.

B) Capitalized costs - PP&E

Under IFRS, employee costs included in general and administrative charges and share-based compensation charges are capitalized to the extent they are directly attributable to PP&E and E&E. For the year ended December 31, 2010, $9.3 million of such costs are expensed under IFRS that were capitalized under previous CGAAP. For the three months ended March 31, 2010 $1.8 million were expensed that were capitalized under previous CGAAP.

Additionally for the year ended December 31, 2010, lease rentals of $7.7 million were expensed under previous CGAAP, while under IFRS the Corporation has elected to capitalize these amounts. For the three months ended March 31, 2010, $1.8 million has been capitalized.

C) Depreciation and depletion

Under previous CGAAP, depletion was based on NAL's single cost centre, on a unit of production basis using total proved reserves. Costs subject to depletion excluded possible reserve locations and undeveloped land.

Under IFRS, depletion is provided for at a component level, defined as an Area by NAL, on a unit of production basis using total proved plus probable reserves. Costs subject to depletion are D&P assets excluding land under development.

For the year ended December 31, 2010, depletion decreased by $50.6 million from previous CGAAP, primarily as a result of the change in depletion base to proved plus probable reserves. For the three months ended March 31, 2010 depletion decreased by $13.8 million. There was no impact to January 1, 2010 due to the IFRS1 election discussed above.

D) Impairment

Under previous CGAAP, impairment was recognized if the carrying amount exceeded the undiscounted cash flows from proved reserves for NAL's single cost centre. The amount of impairment was then measured as the amount by which the carrying value of the cost centre exceeded the sum of proved plus probable reserves discounted at a risk free rate plus the cost of unproved interests and land, net of impairment. Impairments recognized under previous CGAAP were not reversed.

Under IFRS, an impairment is recognized if the carrying value exceeds the recoverable amount for a cash-generating unit ("CGU"). CGUs are aggregations of areas capable of generating independent cash inflows. If the carrying value of the CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income. Impairments under IFRS are reversed when there has been a subsequent increase in recoverable amounts. Impairment reversals are recognized in net income and the carrying amount of the CGU is increased.

Impairment tests were completed on transition, resulting in no impairment charge to PP&E or E&E at January 1, 2010.

For the year ended December 31, 2010, NAL recognized a $32.8 million impairment loss relating to four gas focused CGUs in Alberta, northeast British Columbia and Ontario. The impairment recognized was based on the difference between the December 31, 2010 net book value of the CGUs and the recoverable amount. The recoverable amount was determined using fair value less costs to sell based on discounted future cash flows of proved plus probable reserves. Under previous CGAAP, these assets were tested as one cost centre with no impairment resulting at December 31, 2010.

E) Gains on dispositions

Under previous CGAAP, gains on dispositions were typically not recognized. Proceeds from dispositions were deducted from the full cost pool unless the deduction resulted in a change to the depletion rate of 20 percent or more, in which case a gain or loss was recorded.

Under IFRS, gains or losses are recorded on dispositions of properties and are calculated as the difference between the proceeds and the net book value of the assets disposed of at the time of disposition. For the year ended December 31, 2010, NAL recognized $17.6 million as gains on disposition under IFRS, compared to no gain recognized under previous CGAAP. Similarly, a gain of $11.2 million was recognized for the three months ended March 31, 2010 under IFRS with no gain recorded under previous CGAAP.

F) Asset Retirement Obligations and Accretion

Under previous CGAAP, the asset retirement obligations were measured at the estimated fair value of the expenditures expected to be incurred. Liabilities were not remeasured to reflect period end discount rates.

Under IFRS, the asset retirement obligation is measured as the best estimate of the expenditure to be incurred and requires the liability to be remeasured using the period end discount rate.

As NAL elected the oil and gas assets IFRS1 exemption, the ARO exemption available to full cost entities was also elected. This exemption allows for the remeasurement of ARO on IFRS transition with the offset to retained earnings. The carrying value under previous CGAAP at December 31, 2009 of $127.9 million was revalued under IFRS, resulting in an opening IFRS balance at January 1, 2010 of $134.4 million. On transition to IFRS, NAL recorded the difference of $6.5 million as an increase to the liability with an offset to retained earnings. At December 31, 2010, the liability was increased by $4.3 million. The adjustments primarily reflect the remeasurement of the obligation using an eight percent discount rate at both dates.

In addition, accretion of the liability is impacted by the change in the recognized amount. For the year ended December 31, 2010, accretion decreased by $1.1 million as compared to previous CGAAP.

G) Other Liabilities and Accounts Payable

The Corporation elected to apply the exemption to restate the liability for share-based compensation on transition with the offset to retained earnings. This is applicable to awards that have not vested prior to January 1, 2010, which applies to all of the outstanding grants at NAL.

The adjustment to the liability for share-based compensation is to reflect a forfeiture rate which was not included under previous CGAAP. On transition to IFRS, the payable was reduced by $0.7 million to reflect the inclusion of a forfeiture rate. For the full year 2010, the expense for share-based compensation increased by $1.5 million due to the expensing of amounts capitalized under previous CGAAP, offset slightly by the inclusion of a forfeiture rate.

H) Convertible Debentures

As a trust, NAL designated its convertible debentures as a financial liability at fair value through profit or loss on transition to IFRS. As at January 1, 2010, the fair value of the convertible debentures was $203.7 million, based on quoted market prices. Under previous CGAAP, the convertible debentures were bifurcated between debt and equity in the amounts of $178.0 million and $12.6 million, respectively at December 31, 2009. The difference between the fair value and CGAAP, carrying value was charged to retained earnings on transition to IFRS.

At each quarter end the debentures were fair valued based on the then prevailing market price with the adjustment taken to income. Any accretion expense previously recognized through income under previous CGAAP was eliminated. On conversion to a corporation on December 31, 2010, the debentures carrying value, which represented the fair value on December 31, 2010, was bifurcated between their debt and equity components, as required under IFRS.

On December 31, 2010, the fair value of the debentures was $204.5 million, which following the corporate conversion was allocated $5.0 million to equity and $199.5 million to debt.

In addition, for the period the debentures were held at fair value through profit and loss any issue costs associated with the debentures were expensed, of which $0.3 million was expensed in 2010. Under previous CGAAP these issue costs were netted against the debt component of the debentures.

I) Minority Interest

The mandatory exception under IFRS1 allows for the prospective application in the accounting for minority interest.

Therefore, the minority interest has only been adjusted under IFRS to reflect the changes to the income statement and net assets of the jointly owned Partnership with MFC (Note 4) as compared to previous CGAAP.

Under IFRS minority interests are presented as part of equity rather than a liability as under previous CGAAP.

J) Deferred Taxes

Under IFRS, NAL is required to record deferred taxes at the trust level at 39 percent, being the tax rate applicable to the undistributed profit of the Trust. Therefore, while a trust, the tax rate was significantly higher under IFRS compared to previous CGAAP, as under previous CGAAP the rate used represented the anticipated rate at time of the temporary difference reversal. On conversion to a corporation, corporate tax rates apply, which resulted in a decrease to previously recorded deferred tax amounts under IFRS at the trust level. Deferred taxes have also been adjusted to reflect the tax effect arising from the difference between IFRS and previous CGAAP as noted above. In addition, the deferred tax impact to share issue costs has been reflected.

Under IFRS, all deferred tax is presented as a long term asset or liability. Under previous CGAAP, future income tax presentation was based on the presentation of the underlying asset or liability.

K) Other Exemptions

Business combinations

NAL elected the exemption not to restate Business Combinations, prior to January 1, 2010, in accordance with IFRS. There were no adjustments required to business combinations prior to January 1, 2010.

The remaining IFRS1 exemptions were not applicable or material to the preparation of NAL's Consolidated Balance Sheet on transition at January 1, 2010.

RECENT PRONONOUNCEMENTS ISSUED

All accounting standards effective for periods beginning on or after January 1, 2011 have been adopted as part of the transition to IFRS. The following new IFRS pronouncements have been issued but are not effective and may have an impact on the Corporation:

As of January 1, 2013, NAL will be required to adopt IFRS 9, Financial Instruments, which is the result of the first phase of the IASB's project to replace IAS 39, Financial Instruments: Recognition and Measurement. The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The adoption of this standard should not have a material impact on NAL's consolidated financial statements.

CRITICAL ACCOUNTING ESTIMATES

Management is required to make judgments, assumptions and estimates in applying its accounting policies and practices, which have a significant impact on the financial results of the Corporation. The preceding discussion outlines the Corporation's significant accounting policies and practices adopted under IFRS. The following discussion outlines the accounting policies and practices involving the use of estimates that are critical to determining NAL's financial results.

Property, plant and equipment and Exploration and evaluation assets

Reserves estimates can have a significant impact on earnings, as they are a key input to the Corporation's depletion calculations and impairment tests. Costs accumulated within each area are depleted using the unit-of-production method based on proved plus probable reserves using estimated future commodity prices and costs. Costs subject to depletion include estimated future costs to be incurred in developing proved and probable reserves. A downward revision in reserves estimates or an increase in estimated future development costs could result in the recognition of a higher depletion charge to net income.

D&P costs, are aggregated into cash-generating units ("CGU") based on their ability to generate largely independent cash flows. If the carrying value of the CGU exceeds the recoverable amount, the cash-generating unit is written down with an impairment recognized in net income. E&E assets are assessed for impairment, together with D&P assets in total, when they are reclassified to property, plant and equipment, and/or if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. If an E&E impairment is indicated when combined with the D&P assets, it is recognized through the statement of income. The recoverable amount of an asset or cash-generating unit is the greater of its fair value less costs to sell and its value in use. Fair value less costs to sell may be determined using discounted future net cash flows of proved and probable reserves using forecast prices and costs. A downward revision in reserves estimates could result in the recognition of impairments charged to net income.

Reversals of impairments are recognized when there has been a subsequent increase in the recoverable amount. In this event, the carrying amount of the asset or cash-generating unit is increased to its revised recoverable amount with an impairment reversal recognized in net income, net of what depletion would have been had the asset not been impaired.

All of NAL's oil and gas reserves and resources are evaluated and reported on by independent qualified reserves evaluators. The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, estimated commodity price forecasts and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. Reserves estimates can be revised upward or downward based on the results of future drilling, testing, production levels and economics of recovery based on cash flow forecasts. Contingent resources are not classified as reserves due to the absence of a commercial development plan that includes a firm intent to develop within a reasonable time frame.

Asset Retirement Obligations

Asset retirement obligations include present obligations where the Corporation will be required to retire tangible long-lived assets such as producing well sites, and natural gas processing plants. The asset retirement obligation is measured at the present value of the expenditure to be incurred. The associated asset retirement cost is capitalized as part of the cost of the related asset. Changes in the estimated obligation resulting from revisions to estimated timing, amount of cash flows or changes in discount rate are recognized as a change in the asset retirement obligation and the related asset retirement cost.

Increases in the estimated asset retirement obligation and costs increase the corresponding charges of accretion and depletion to net income. A decrease in discount rates increases the asset retirement obligation, which increases future accretion charged to net earnings. Actual expenditures incurred are charged against the accumulated asset retirement obligation.

Goodwill

Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment annually at December 31 of each year. Goodwill is currently attributed to the area to which it relates.

To assess impairment, the goodwill carrying amount is compared to the recoverable amount of the aggregated cash-generating units to which the goodwill is allocated. If the carrying amount for the cash-generating unit exceeds the recoverable amount, the associated goodwill is written down with an impairment recognized in net income. Goodwill impairments are not reversed.

The recoverable amount is the greater of the cash-generating unit's fair value less costs to sell and its value in use. Fair value less costs to sell may be determined using discounted future net cash flow of proved and probable reserves using forecast prices and costs. A downward revision in reserves estimates could result in the recognition of a goodwill impairment charge to net income.

Income Taxes

NAL follows the balance sheet method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Current income taxes for the current and prior periods are measured at the amount expected to be recoverable from or payable to the taxation authorities based on the income tax rates enacted or substantively enacted at the end of the reporting period. The deferred income tax assets and liabilities are adjusted to reflect changes in enacted or substantively enacted income tax rates that are expected to apply, with the corresponding adjustment recognized in net income or in shareholders' equity depending on the item to which the adjustment relates.

Tax interpretations, regulations and legislation in the various jurisdictions in which the Corporation subsidiaries operate are subject to change. As such, income taxes are subject to measurement uncertainty and the interpretations can impact net income through the income tax expense arising from the changes in deferred income tax assets or liabilities.

Derivative Financial Instruments

As described in the Risk Management section of this MD&A, derivative financial instruments are used by NAL to manage its exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates.

Derivative financial instruments are recorded at fair value. Instruments are recorded in the balance sheet as either an asset or liability with changes in fair value recognized in net income. Realized gains or losses are presented as the contracts are settled. Unrealized gains and losses are presented at the end of each respective reporting period based on the change in fair value and are recognized in net income. The estimate of fair value of all derivative instruments is based on approximation of the amounts that would be received or paid to settle these instruments at the end of the period, with reference to forward prices, foreign exchange rates and interest rates. The estimated fair value of financial assets and liabilities is subject to measurement uncertainty.

Share-based Compensation

Share-based compensation is recognized over the vesting period, based on the market price of the notional common share at each period end and an expected performance multiplier and forfeiture rate, in the statement of income with a corresponding increase or decrease in liabilities.

Dated: May 19, 2011


Consolidated Balance Sheet
(In thousands of Canadian dollars)
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                                         December 31, 2010  January 1, 2010
                         March 31, 2011           (Note 14)        (Note 14)
----------------------------------------------------------------------------

Assets
 Current assets
  Cash                       $        -         $      821       $    1,604
  Accounts receivable            55,226             57,839           61,631
  Prepaids and other
   receivables                    8,467             14,532           15,663
  Derivative contracts
   (Note 12)                          -                422            6,285
----------------------------------------------------------------------------
                                 63,693             73,614           85,183

 Derivative contracts
 (Note 12)                        1,057                  -            2,461
 Deferred tax asset              41,276             49,380           34,627
 Goodwill                        14,722             14,722           14,722
 Property, plant and
  equipment (Note 5)          1,464,283          1,472,660        1,415,830
 Exploration and
  evaluation assets(Note
  5)                             65,822             63,127           88,122
----------------------------------------------------------------------------
                             $1,650,853         $1,673,503       $1,640,945
----------------------------------------------------------------------------

Liabilities and
 Shareholders' Equity
 Current liabilities
  Accounts payable and
   accrued liabilities          128,792            100,265          110,715
  Note payable                        -                  -            8,907
  Dividends payable to
   shareholders                  10,345             13,252           12,372
  Derivative contracts
   (Note 12)                     31,235              7,819           11,231
----------------------------------------------------------------------------
                                170,372            121,336          143,225

 Bank debt (Note 6)             255,306            266,965          230,713
 Convertible debentures
  (Note 7)                      198,926            199,520          203,730
 Other liabilities (Note
  8)                              3,253              3,012            7,173
 Derivative contracts
  (Note 12)                           -              2,503                -
 Asset retirement
  obligations (Note 10)         126,038            149,015          134,358
 Deferred tax liability          26,996             35,402           51,199
----------------------------------------------------------------------------
                                780,891            777,753          770,398

Shareholders' equity
 Share capital                  897,500            890,777                -
 Unitholders' capital                 -                  -        1,485,421
 Equity component of
  convertible
  debentures(Note 7)              4,973              4,973                -
 Minority interest                    -                  -            3,370
 Deficit                        (32,511)                 -         (618,244)
----------------------------------------------------------------------------
                                869,962            895,750          870,547
----------------------------------------------------------------------------
                             $1,650,853         $1,673,503       $1,640,945
----------------------------------------------------------------------------
Commitments (Note 13)

Common shares
 outstanding (000's)            147,781            147,248          137,471
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Consolidated Statements of Income (loss) and Comprehensive Income (loss)
(In thousands of Canadian dollars, except per share amounts) 
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                                                         Three months ended
                                                                   March 31,
                                                        2011  2010 (Note 14)
Revenue
 Oil, natural gas and liquid sales                $  123,175     $  138,520
 Crown royalties                                     (14,301)       (16,558)
 Freehold and other royalties                         (5,488)        (6,041)
----------------------------------------------------------------------------
                                                     103,386        115,921
 Gain (loss) on derivative contracts (Note 12):
  Realized gain                                         (998)         1,448
  Unrealized gain (loss)                             (20,278)        18,509
----------------------------------------------------------------------------
                                                     (21,276)        19,957
 Other income                                            281            331
----------------------------------------------------------------------------
                                                      82,391        136,209
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Expenses
 Operating                                            27,257         28,070
 Transportation                                        1,423          1,637
 General and administrative                            7,431          5,882
 Share-based incentive compensation                      636            686
 Interest on bank debt                                 3,229          3,086
 Interest and amortization on convertible
  debentures                                           2,549          3,142
 Fair value adjustment on convertible debentures           -            632
 Convertible debenture issue costs                         -            344
 Gain on disposition of property, plant and
  equipment                                          (12,534)       (11,193)
 Impairment of oil and gas assets (Note 5)             5,200              -
 Depletion and depreciation                           46,412         48,265
 Accretion on asset retirement obligations             2,544          2,701
----------------------------------------------------------------------------
                                                      84,147         83,252
----------------------------------------------------------------------------
 Income (loss) before taxes                           (1,756)        52,957

 Current tax expense                                     (56)           (59)
 Deferred tax reduction(expense)                         302         (2,729)
----------------------------------------------------------------------------
 Total tax reduction(expense)                            246         (2,788)
----------------------------------------------------------------------------

----------------------------------------------------------------------------
Net income (loss) and comprehensive income (loss) $   (1,510)    $   50,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Attributable to:
 Equity holders of the Corporation                $   (1,510)    $   49,237
 Minority interest                                         -            932
----------------------------------------------------------------------------
 Net income (loss) and comprehensive income
  (loss)                                          $   (1,510)    $   50,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) per share (Note 11)
 Basic                                                 (0.01)          0.36
 Diluted                                               (0.01)          0.35
----------------------------------------------------------------------------

Weighted average shares outstanding (000s)           147,534        137,660
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Consolidated Statements of Cash Flows
(In thousands of Canadian dollars)
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                                                         Three months ended
                                                                   March 31
                                                        2011  2010 (Note 14)
----------------------------------------------------------------------------

Operating Activities
 Net income (loss)                                 $  (1,510)     $  49,237
 Items not involving cash:
  Depletion and depreciation                          46,412         48,265
  Accretion on asset retirement obligations            2,544          2,701
  Unrealized loss (gain) on derivative contracts      20,278        (18,509)
  Gain on disposition of property, plant and
   equipment                                         (12,534)       (11,193)
  Fair value adjustment on convertible debentures          -            632
  Deferred tax expense (recovery)                       (302)         2,729
  Minority interest                                        -            314
  Lease amortization                                    (432)          (376)
  Impairment of oil and gas assets                     5,200              -
  Interest expense and amortization on convertible
   debentures                                          5,778          6,228
  Debenture issue costs                                    -            344
 Abandonment and reclamation                          (2,437)          (891)
 Change in non-cash working capital                   (2,014)       (11,233)
----------------------------------------------------------------------------
                                                      60,983         68,248
----------------------------------------------------------------------------

Financing Activities
 Dividends paid to shareholders                      (27,185)       (31,969)
 Increase (decrease) in bank debt                    (11,659)        13,982
 Issue of shares, net of issue costs                       -           (155)
 Convertible debenture issue costs                         -           (344)
 Interest expense                                     (5,684)        (6,796)
 Change in non-cash working capital                     (688)           568
----------------------------------------------------------------------------
                                                     (45,216)       (24,714)
----------------------------------------------------------------------------

Investing Activities
 Property, plant and equipment expenditures          (80,781)       (79,283)
 Exploration and evaluation expenditures              (2,789)        (2,013)
 Proceeds from dispositions                           27,090         14,676
 Disposition of Spearpoint                                 -           (309)
 Change in non-cash working capital                   39,892         26,833
----------------------------------------------------------------------------
                                                     (16,588)       (40,096)
----------------------------------------------------------------------------

Increase (decrease) in cash                             (821)         3,438
Cash, beginning of period                                821          1,604
----------------------------------------------------------------------------
Cash, end of period                                $       -      $   5,042
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


Consolidated Statements of Changes in Equity
(In thousands of Canadian dollars) 
(unaudited)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                                                                     Equity
                                                                  component
                                                                         of
                                           Number Shareholders  convertible
                                        of Shares       Equity   debentures
----------------------------------------------------------------------------
Balance at January 1, 2010                137,471   $1,485,421      $     -
Net income before minority interest             -            -            -
Net income attributable to minority
interest                                        -            -            -
Less issue costs (net of tax of $54)            -         (155)           -
Issued from Distribution Reinvestment
 Plan                                         410        5,179            -
Dividends declared                                           -            -
----------------------------------------------------------------------------
Balance at March 31, 2010                 137,881   $1,490,445            -
Net income before minority interest             -            -            -
Equity offering                             7,550      100,038            -
Issue costs (net of tax of $1,692)              -       (4,869)           -
Issued from Distribution Reinvestment
 Plan                                       1,817       20,159            -
Dividends declared                              -            -            -
Dissolution of partnership                      -            -            -
Reclassification of deficit to share
 capital (Note 1)                               -     (714,996)           -
Equity component of convertible
 debentures on conversion to corporation        -            -        4,973
----------------------------------------------------------------------------
Balance at December 31, 2010              147,248      890,777        4,973
Net loss                                        -            -            -
Issued from Distribution Reinvestment
 Plan                                         533        6,723            -
Dividends declared                              -            -            -
----------------------------------------------------------------------------
Balance at March 31, 2011                 147,781   $  897,500      $ 4,973
----------------------------------------------------------------------------
----------------------------------------------------------------------------


                                                       Minority       Total
                                              Deficit  interest      Equity
----------------------------------------------------------------------------

Balance at January 1, 2010                  $(618,244)  $ 3,370  $  870,547
Net income before minority interest            50,169         -      50,169
Net income attributable to minority
 interest                                        (932)      314        (618)
Less issue costs (net of tax of $54)                -         -        (155)
Issued from Distribution Reinvestment
 Plan                                               -         -       5,179
Dividends declared                            (37,185)        -     (37,185)
----------------------------------------------------------------------------
Balance at March 31, 2010                   $(606,192)  $ 3,684  $  887,937
Net income before minority interest             9,788         -       9,788
Equity offering                                     -         -     100,038
Issue costs (net of tax of $1,692)                  -         -      (4,869)
Issued from Distribution Reinvestment
 Plan                                               -         -      20,159
Dividends declared                           (118,592)        -    (118,592)
Dissolution of partnership                          -    (3,684)     (3,684)
Reclassification of deficit to share
 capital (Note 1)                             714,996         -           -
Equity component of convertible
 debentures on conversion to corporation            -         -       4,973
----------------------------------------------------------------------------
Balance at December 31, 2010                        -         -     895,750
Net loss                                       (1,510)        -      (1,510)
Issued from Distribution Reinvestment
 Plan                                               -         -       6,723
Dividends declared                            (31,001)        -     (31,001)
----------------------------------------------------------------------------
Balance at March 31, 2011                   $ (32,511)  $     -  $  869,962
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.

Notes to the consolidated interim financial statements

Three months ended March 31, 2011

(Tabular amounts in thousands of Canadian dollars, except per share amounts)

(unaudited)

1) NATURE OF OPERATIONS AND STRUCTURE OF THE CORPORATION

NAL Energy Corporation ("NAL" or the "Corporation") is engaged in the exploration for, and the development and production of natural gas, natural gas liquids and crude oil in Western Canada. The Corporation resulted from a reorganization effective December 31, 2010 as part of a Plan of Arrangement involving, among others, NAL Oil & Gas Trust (the "Trust"), the Corporation, and the security holders of the Trust ("Reorganization").

Pursuant to the Reorganization, the Trust was restructured from an open-ended unincorporated trust to NAL Energy Corporation, a publicly traded exploration and development corporation. Unitholders of the Trust received one common share of the Corporation for each trust unit held. The Corporation and its subsidiaries now carry on the business formerly carried on by the Trust and its subsidiaries. The outstanding convertible debentures of the Trust were assumed by NAL and are now convertible into common shares of the Corporation, rather than trust units of the Trust, with the same terms and conditions as those previously agreed to by the Trust.

Pursuant to the Reorganization, share capital was reduced by the amount of the deficit of the Trust on December 31, 2010.

The Reorganization to a corporation has been accounted for on a continuity of interest basis and accordingly, the consolidated financial statements for 2010 and 2011 reflect the financial position, results of operations and cash flows as if the Corporation had carried on the business formerly carried on by the Trust.

References to NAL or the Corporation in these financial statements for periods prior to December 31, 2010 are references to the Trust and for periods after December 30, 2010 are references to NAL Energy Corporation. Additionally, NAL or the Corporation refers to shares, shareholders, and dividends which are comparable to units, unitholders and distributions previously under the Trust.

The Corporation, as with the Trust, continues to be managed by NAL Resources Management Limited (the "Manager"). The Manager is a wholly-owned subsidiary of Manulife Financial Corporation ("MFC") and manages, on their behalf, NAL Resources Limited ("NAL Resources"), another wholly-owned subsidiary of MFC. NAL Resources and the Corporation maintain ownership interests in many of the same oil and natural gas properties. NAL Resources operates these properties on behalf of the Corporation and MFC. As a result, a significant portion of the net operating revenues and capital expenditures represent joint operations amounts from NAL Resources. These transactions are in the normal course of joint operations and are based on the original exchange amounts established through transactions with third parties.

The interim consolidated financial statements were authorized for issue by the Board of Directors on May 19, 2011.

2) SUMMARY OF ACCOUNTING POLICIES

(a) Conversion to International Financial Reporting Standards ("IFRS") and Statement of Compliance

These are the Corporation's first IFRS consolidated interim financial statements as at March 31, 2011, including 2010 comparative periods. They comprise the initial period of the Corporation's annual audited financial statements to be issued under IFRS at December 31, 2011. As a result these interim consolidated financial statements have been prepared in accordance with IFRS1 "First-time Adoption of International Financial Reporting Standards" ("IFRS1") and IAS34 "Interim Financial Reporting". The consolidated interim financial statements do not include all of the information required for full annual financial statements.

An explanation of how the transition to IFRS has affected the reported financial position, financial performance and cash flows of the Corporation is provided in Note 14. That note includes reconciliations as at January 1, 2010, as at and for the three months ended March 31, 2010 and as at and for the year ended December 31, 2010.

(b) Basis of Presentation

The Corporation's consolidated financial statements are stated in Canadian dollars, which is the Corporation's functional currency, and include the accounts of the Corporation and its subsidiary entities. The Corporation and its subsidiary entities are all incorporated in Canada. All inter-entity transactions and balances have been eliminated. The accounting policies set out below have been applied consistently to all periods presented in these consolidated condensed interim financial statements. They have also been applied in preparing an opening IFRS statement of financial position as at January 1, 2010 for the purposes of the transition to IFRS, as required by IFRS1.

(c) Basis of Measurement

The consolidated financial statements have been prepared on the historical cost basis except for the following:

- Convertible Debentures were classified as financial liabilities at fair value through profit and loss until conversion to a corporation. Subsequent to the Reorganization, the convertible debentures were bifurcated between debt and equity, with the bond premium amortized over the period to maturity. The equity portion is carried at the historic carrying amount determined at the time of Reorganization, subject to any debenture conversions.

- Derivative contracts are classified at fair value through profit and loss.

The methods used to measure fair values are discussed within the notes to which they relate.

(d) Use of Estimates and Judgments

The preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected.

Reserve estimates including production profiles, future development costs, and discount rates are a critical part of many of the estimated amounts and calculations contained in the financial statements. These estimates are verified by third party professional engineers, who work with information provided by the Corporation to establish reserve determinations. These determinations are updated at least on an annual basis, and more frequently as significant business combinations take place.

Significant areas of estimation, uncertainty and critical judgments in applying accounting policies that impact the amounts recognized in the interim consolidated financial statements include:

- Impairment testing - estimates of reserves, future commodity prices, future costs, production profiles, discount rates, and market value of land.

- Depletion and depreciation - oil and natural gas reserves, including future prices, costs and reserve base to use on calculation of depletion.

- Asset Retirement Obligations ("ARO") - estimates relating to amounts, likelihood, timing, inflation and discount rates.

- Share-based Compensation - forfeiture rates and performance factors.

- Derivatives - expected future oil and natural gas prices and expected volatility in these prices, expected interest rates, expected future foreign exchange rates.

- Deferred Tax - estimates of reversal of temporary differences, tax rates substantively enacted, and likelihood of assets being realized.

- Provisions and Contingencies - estimates relating to onerous contracts, including discount rates associated with long term contracts.

(e) Basis of Consolidation

Subsidiaries are entities controlled by the Corporation. Control exists when the Corporation has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that are currently exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated interim financial statements from the date that control commences until the date that control ceases.

The purchase method of accounting is used to account for acquisitions of subsidiaries and assets that meet the definition of a business under IFRS. The cost of an acquisition is measured at the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the cost of acquisition over the fair value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognized immediately in the income statement.

(f) Joint Operations

Many of the Corporation's oil and natural gas activities involve jointly controlled assets. The consolidated interim financial statements include the Corporation's share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs.

(g) Financial Instruments

A financial instrument is any contract that gives rise to a financial asset of one entity and to a financial liability or equity instrument of another entity. Upon initial recognition, all financial instruments, including derivatives, are recognized on the balance sheet at fair value. Subsequent measurement is then dependent on the financial instruments being classified into one of five categories: Financial liabilities or financial assets at fair value through profit or loss, held to maturity investments, loans and receivables, available for sale financial assets; or other financial liabilities.

The Corporation will assess at each reporting period whether a financial asset is impaired. An impairment loss, if any, is included in net income.

Transaction costs are frequently attributable to the issue of a financial asset or liability. For financial assets or liabilities measured at fair value through profit and loss, these costs are expensed. For all other financial assets and liabilities, these costs are netted in the initial carrying amount recorded.

(i) Non-derivative financial instruments

Non-derivative financial instruments comprise cash and cash equivalents, accounts and other receivables, accounts payable and accrued liabilities, dividends payable to shareholders, notes payable, convertible debentures and bank debt. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit and loss, any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured as described below.

Cash and cash equivalents comprises cash on hand, term deposits held with banks, other short-term highly liquid investments with original maturities of three months or less. The Corporation has classified cash and cash equivalents and accounts and other receivables as loans and receivables, which are measured at amortized cost less any impairment losses. Accounts payable and accrued liabilities, dividends payable to shareholders, notes payable and bank debt are classified as other financial liabilities which are measured at amortized cost, which is determined using the effective interest method.

As a Trust, the convertible debentures were considered to contain an embedded derivative related to the conversion feature. On transition to IFRS, an election was made to treat the convertible debentures as a whole as a financial liability at fair value through profit and loss, based on the debenture market value as at the reporting date. On Reorganization, the embedded equity feature ceased to be a derivative and the Company ceased to fair value the convertible debentures as a whole, and the equity feature had to be bifurcated. Therefore, the fair value of the convertible debenture was determined at that time, with the debt and equity then recorded separately. Subsequent to the Reorganization, the equity portion is recorded at its assigned cost and the debt portion is recorded at amortized cost.

(ii) Derivative financial instruments

The Corporation has entered into certain financial derivative contracts in order to manage exposure to market risks from fluctuations in commodity prices, foreign exchange and interest rates. These instruments are not used for trading or speculative purposes. The Corporation has not designated its financial derivative contracts as effective accounting hedges, and thus not applied hedge accounting, even though the Corporation considers all derivative contracts to be effective economic hedges. As a result, all financial derivative contracts are classified as fair value through profit or loss and are recorded on the balance sheet at fair value. Proceeds and costs realized from holding the derivative contracts are recognized in net income at the time each transaction under a contract is settled. The fair value of derivative contracts is based on an approximation of the amounts that would be received or paid to settle these instruments at the end of the period, with reference to forward prices, foreign exchange rates and interest rates.

The Corporation applies trade date accounting for the recognition of a purchase or sale of short term investments and derivative contracts.

(iii) Unitholder's equity/share capital

The Trust's units are classified as equity. Incremental costs directly attributable to the issue of trust units were recognized as a deduction from equity, net of any tax effects.

Shares of the Corporation are classified as equity and are presented at cost net of transaction costs, and any tax effects.

(iv) Impairment of Financial Assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired, namely if one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.

All impairment losses are recognized in profit or loss.

An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost, the reversal is recognized in profit or loss.

(h) Property, Plant and Equipment and Exploration and Evaluation Assets

(i) Recognition and measurement

Exploration and Evaluation ("E&E") expenditures:

Pre-license costs ("Pre-E&E"), or costs incurred before acquiring legal rights to explore are recognized in the statement of income as incurred. Once a legal right to explore has been established, but before technical feasibility and commercial viability has been determined, costs are capitalized as E&E. E&E expenditures can include the costs of acquiring licenses on exploratory lands or assigned values on business acquisitions for possible reserves.

The technical feasibility and commercial viability of extracting oil and natural gas resources is generally considered to be determinable when proved and/or probable reserves exist. Upon determination of technical feasibility and commercial viability, intangible E&E assets are first tested for impairment, and then moved to Development and Production assets.

In addition, exploration and evaluation assets are assessed for impairment when facts and circumstances suggest that the carrying amount exceeds the recoverable amount.

Development and Production ("D&P") costs:

Items of property, plant and equipment ("PP&E"), which include oil and natural gas development and production assets, are measured at cost, including asset retirement costs, less accumulated depletion and depreciation and accumulated net impairment losses.

D&P costs are accumulated on an Area basis and are grouped into cash generating units ("CGUs) for impairment testing. CGUs are the smallest group of assets that generate independent cash flows. NAL has defined nine CGUs.

Gains and losses on disposition of property, plant and equipment, property swaps and farm-outs are recorded. Gains and losses are determined by comparing the proceeds from disposal or fair value of the asset received with the disposed amount of carrying amount of PP&E and ARO and are recognized in the Statement of Income.

(ii) Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

(iii) Depletion and depreciation

The net carrying value of D&P assets is depleted on a unit of production basis on proved and probable reserves, using estimated future prices and cost, and taking into account estimated future development costs. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually.

Depletion is calculated at a "component" level, which is defined as those parts of assets with similar characteristics that are significant in relation to the total cost of the asset. For the Corporation, components relating to D&P assets are consistent with the areas determined by management.

Depreciation methods, useful lives, and residual values are reviewed at each reporting date.

(iv) Impairment

The carrying amounts of the Corporation's D&P assets are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset's recoverable amount is estimated. Goodwill is allocated to CGUs on acquisition and for these CGUs, impairment is tested each year end, or more frequently if indications of impairment exist.

E&E assets are assessed for impairment, together with D&P assets in total, when they are reclassified to property, plant and equipment, and/or if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. If an E&E impairment is indicated when combined with the D&P assets, it is recognized through the statement of income.

For the purpose of impairment testing, D&P assets are grouped together into CGUs. The recoverable amount of a CGU is the greater of its value in use and its fair value less costs to sell. CGUs are reviewed annually for reasonableness and continued applicability, or on a more frequent basis should conditions change that would materially impact classification.

In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves.

Fair value less costs to sell is generally determined as the current market bid price, when an active market exists. The intent is that this represents what a market participant would pay to acquire control of the CGU.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in the statement of income. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the unit on a pro rata basis.

An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

(i) Goodwill

Goodwill arising through a business combination is assigned at the time acquired, to a cash generating unit or units that are expected to benefit from the synergies of the combination. It is measured at cost less accumulated impairment losses. No amortization is recorded for goodwill.

Acquisitions prior to January 1, 2010:

As part of its transition to IFRS, the Corporation elected to restate only those business combinations that occurred on or after January 1, 2010. In respect of acquisitions prior to January 1, 2010, goodwill represents the amount recognized under the Corporation's previous accounting framework, previous CGAAP.

Acquisitions on or after January 1, 2010:

For acquisitions on or after January 1, 2010, goodwill represents the excess of the cost of the acquisition over the net fair value of the identifiable assets, liabilities and contingent liabilities of the acquiree. When the excess is negative, it is recognized immediately in profit for loss.

(j) Share-Based Incentive Compensation

The Manager has established a share-based incentive compensation plan (the "Plan") for all employees. Under the Plan, employees receive cash compensation based upon the value and overall return of a specified number of awarded notional common shares on a fixed vesting date. The notional common shares are in the form of Restricted Share Units ("RSUs") and Performance Share Units ("PSUs"). Dividends paid on the Corporation's outstanding common shares during the vesting period are assumed to be reinvested in the awarded notional common shares on the date of dividend. Compensation expense incorporates the common share price and the number of RSUs and PSUs outstanding at each period end. In addition, for the PSUs there is a performance multiplier which is based on the Corporation's performance relative to its peers and may range from zero to two times the value of the notional common shares held at vesting.

Compensation expense is recognized over the vesting period and is determined based on the market price of the notional common shares at each period end and an expected performance multiplier with a corresponding increase or decrease in liabilities. Classification between current liabilities and long-term liabilities is dependent on the expected payout date.

The Corporation charges the accrued compensation amounts relating to head office employees to general and administrative expenses.

The Corporation has incorporated an estimated forfeiture rate for common shares that will not vest, that is adjusted to reflect the actual number of awards that vest.

(k) Provisions

A provision is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

(i) Asset Retirement Obligations

The Corporation's activities give rise to dismantling, decommissioning and site disturbance re-mediation activities. Provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.

Asset retirement obligations are measured at the present value of management's best estimate of expenditure required to settle the present obligation at the balance sheet date. The discount rate applied is the credit adjusted risk free rate. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time, changes in the estimated future cash flows underlying the obligation, and the discount rate applied is adjusted to the current applicable rate as at each reporting period. The increase in the provision due to the passage of time is recognized as accretion of asset retirement obligations whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the retirement obligations are charged against the provision to the extent the provision was established.

(ii) Onerous Contracts

A provision for onerous contracts is recognized by the Corporation when the expected benefits to be derived from a contract are lower than the unavoidable cost of meeting its obligations under the contract. The provision is measured at the present value of the lower of the expected cost of terminating the contract and the expected net costs of continuing with the contract. Before a provision is established, the Corporation recognizes any impairment loss on associated assets, if applicable.

(l) Revenue Recognition

Revenues from the sale of petroleum and natural gas are recorded when title passes to the purchaser and if collection is reasonably assured.

(m) Income Tax

The Corporation is a taxable entity under the Income Tax Act (Canada).

As a Trust, the organization was a taxable entity under the Income Tax Act (Canada) and until 2011 was taxable only on income that was not distributed or distributable to unitholders, provided that the Trust continued to adhere to the transition rules provided for under the Federal legislation. The Trust met the criteria qualifying for income tax treatment permitting a tax deduction for distributions paid to the unitholders in addition to other deductions available in the Trust until its conversion to a Corporation on December 31, 2010.

Current and deferred tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, with the intent to settle current tax liabilities and assets on a net basis or the tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

(n) Basic and Diluted per Share Calculation

Basic per share amounts are calculated by dividing net income by the weighted average number of common shares outstanding. Diluted net income per share is calculated using the "if converted method" to determine the dilutive effects of the convertible debentures. Dilutive shares are arrived at by taking the weighted average shares and the shares issuable on conversion of the convertible debentures, giving effect to the potential dilution that would occur had conversion occurred at the beginning of the period or on issuance of the convertible instrument, whichever is later. Interest and accretion on convertible debentures is added back to net income, net of tax in calculating diluted net income per share/unit.

3) NEW IFRS STANDARDS

The International Accounting Standards Board ("IASB") has issued certain new accounting standards and interpretations that are expected to have minimal impact to the Corporation's financial statements.

The Corporation has reviewed new and revised accounting pronouncements that have been issued but are not yet effective and determined that the following may have an impact on the Corporation:

As at January 1, 2013, NAL will be required to adopt IFRS 9, "Financial Instruments", which is the result of the first phase of the IASB's project to replace IAS 39, "Financial Instruments: Recognition and Measurement". The new standard replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The adoption of this standard should not have a material impact on NAL's consolidated financial statements.

4) RELATED PARTY TRANSACTIONS

NAL has several subsidiaries within its corporate structure. Two active entities hold the working interests in the oil and gas properties being NAL Petroleum Ltd. ("ACE") and Addison Energy Limited Partnership ("Addison"). The partners of Addison are ACE and NAL.

In addition, there are several inactive subsidiaries, namely, NAL Canada West Inc., NAL Properties Inc., Startech Energy and NAL Energy Inc.

The Corporation is managed by the Manager. The Manager is a wholly-owned subsidiary of MFC and also manages on their behalf NAL Resources, another wholly-owned subsidiary of MFC.

The Manager continues to provide certain services to the Corporation pursuant to an Administrative Services and Cost Sharing Agreement. This agreement requires the Corporation to reimburse the Manager, at cost, for general and administrative ("G&A") expenses incurred by the Manager on behalf of the Corporation. The Corporation paid $6.2 million (2010 - $3.6 million) for the reimbursement of G&A expenses during the first quarter. The Corporation also pays the Manager its portion of share-based compensation expense when cash compensation is paid to employees under the terms of the Manager's incentive compensation plans, of which $6.8 million has been paid in the first three months of 2011 relating to notional shares that vested on November 30, 2010 (2010 - $6.9 million).

In conjunction with the Reorganization, a partnership that was jointly owned by the Corporation and MFC was dissolved on December 31, 2010. This Partnership held the assets acquired from the acquisitions of Tiberius and Spear in February 2008.

Prior to December 31, 2010 the Corporation, by virtue of being the owner of the general partner of the Partnership, was required to consolidate the results of the Partnership into its financial statements on the basis that the Corporation had control over the Partnership. The Corporation had recorded a minority interest in respect of the 50 percent ownership held by MFC. As a result of the Partnership dissolution on December 31, 2010, the Corporation only reflects its proportionate share of the Partnership's assets, liabilities, revenues and expenses in the March 31, 2011 financial statements. Accordingly at March 31, 2011 and December 31, 2010, no minority interest was reflected on the balance sheet. For the three months ended March 31, 2010, the minority interest in the statement of income is comprised of:


                                                Three months ended March 31
                                                        2011           2010
----------------------------------------------------------------------------
Net profits interest expense                         $     -        $   618
Share of net income attributable to MFC                    -            314
----------------------------------------------------------------------------
                                                     $     -        $   932
----------------------------------------------------------------------------
----------------------------------------------------------------------------

As a part of the original structuring of the Partnership in 2008, both the Corporation and MFC entered into net profit interest royalty agreements with the Partnership. These agreements entitled each royalty holder to a 49.5 percent interest in the cash flow from the Partnership's reserves.

In addition, in the Partnership there was a note payable to MFC, which was settled on dissolution. At January 1, 2010, the note payable of $8.9 million was included on consolidation of the Partnership, but was effectively eliminated through the non-controlling interest. The note was due on demand, unsecured and bore interest at prime plus three percent.

The following amounts are due to and from related parties as at March 31, 2011 and December 31, 2010 and have been included in prepaids and other receivables, accounts payable and accrued liabilities and note payable on the balance sheet:


                                                    March 31,   December 31,
                                                        2011           2010
----------------------------------------------------------------------------
Due from (to) NAL Resources Limited                  $ 2,556        $ 8,149
Due to NAL Resources Management Limited               (2,094)        (8,705)
Due (to) from Manulife Financial Corporation              34           (265)
----------------------------------------------------------------------------
                                                     $   496        $  (821)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


5) PROPERTY, PLANT AND EQUIPMENT AND EXPLORATION AND EVALUATION ASSETS

(i) Property, Plant and Equipment ("PP&E")

                                                Three months ended March 31
                                                        2011           2010
----------------------------------------------------------------------------

Gross cost
Opening balance, beginning of period               1,673,359    $ 1,415,830
Additions                                             80,781         79,592
Asset retirement cost additions and revisions           (414)         3,169
Disposals                                            (41,442)        (3,686)
Transfers from evaluation and exploration
 assets                                                   94              -
----------------------------------------------------------------------------
                                                 $ 1,712,378    $ 1,494,905
----------------------------------------------------------------------------

Accumulated depletion and impairment losses
Opening balance, beginning of period                 200,699    $         -
Disposals                                             (4,216)             -
Depletion for the period                              46,412         48,265
Impairment losses                                      5,200              -
----------------------------------------------------------------------------
                                                 $   248,095    $    48,265
----------------------------------------------------------------------------

Net book value
Opening balance, beginning of period             $ 1,472,660    $ 1,415,830
Additions                                             80,367         82,761
Depletion for the period                             (46,412)       (48,265)
Disposals                                            (37,226)        (3,686)
Transfers from evaluation and exploration
 assets                                                   94              -
Impairment losses                                     (5,200)             -
Reversal of impairment losses                              -              -
----------------------------------------------------------------------------
                                                 $ 1,464,283    $ 1,446,640
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The calculation of first quarter depletion included future development costs for proved plus probable reserves of $419.1 million (2010 - $404.2 million). Undeveloped land amounting to $48.8 million (2010 - $51.0 million) is included in PP&E assets and has not been included in the depletable base while development activity is completed on this development acreage.


(ii) Exploration and evaluation assets

                                                Three months ended March 31
                                                        2011           2010
----------------------------------------------------------------------------

Net book value
Opening balance, beginning of period             $    63,127    $    88,122
Additions                                              2,789          2,013
Transfers to PP&E                                        (94)             -
----------------------------------------------------------------------------
                                                 $    65,822    $    90,135
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(iii) Impairment of oil and gas assets

During the first three months of 2011, impairment losses of $5.2 million were recorded and reported as impairment of oil and gas assets in the statement of income. The impairment related to D&P assets was calculated using the fair value less costs to sell approach, which was based on the engineering report, using future prices as at April 1, 2011 and future costs, discounted at a rate commensurate with market transactions.

These impairment losses were recognized in three natural gas CGUs, which have no goodwill assigned, and were the result of a further reduction in forward natural gas prices as estimated by the Corporation's independent engineers.

6) BANK DEBT

The Corporation maintains a fully secured, extendible, revolving term credit facility with a syndicate of Canadian chartered banks and one U.S. based lender. The facility consists of a $535 million production facility and a $15 million working capital facility. The total amount of the facility is determined by reference to a borrowing base. The borrowing base is calculated by the bank syndicate and is based on the net present value of the Corporation's oil and gas reserves and other assets. Given that the borrowing base is dependent on the Corporation's reserves and future commodity prices, lending limits are subject to change on renewal.

The credit facility is fully secured by first priority security interests in all existing and future acquired properties and assets of the Corporation and its subsidiary and affiliated entities. The facility will revolve until April 30, 2012 at which time it may be extended for a further 364-day revolving period upon agreement between the Corporation and the bank syndicate. If the credit facility is not extended in April 2012, the amounts outstanding at that time will be converted to a two-year term loan. The term loan will be payable in five equal quarterly installments commencing May 1, 2013.

Amounts are advanced under the credit facility in Canadian dollars by way of prime interest rate based loans and by issues of bankers' acceptances and in U.S. dollars by way of U.S. based interest rate and Libor based loans. The interest charged on advances is at the prevailing interest rate for bankers' acceptances, Libor loans, lenders' prime or U.S. base rates plus an applicable margin or stamping fee. The applicable margin or stamping fee, if any, varies based on the consolidated debt-to-cash flow ratio of the Corporation. As at March 31, 2011 and December 31, 2010 all amounts outstanding were in Canadian dollars.

On March 31, 2011 the effective interest rate on amounts outstanding under the credit facility was 5.05 percent (2010 - 3.33 percent). The Corporation's interest charge includes this fixed interest rate component, plus a standby fee, a stamping fee and the fee for renewal.

7) CONVERTIBLE DEBENTURES

Prior to the Reorganization, the convertible debentures were recorded at fair value and classified as debt. On conversion to a Corporation on December 31, 2010, the fair value of the convertible debentures at that date was bifurcated between debt and equity. As a result, $5.0 million of debt was re-classified as equity, with the remaining debt premium to be amortized into income over the term to maturity.


The following table reconciles the principal amount, debt component and
equity component of the convertible debentures:

                              Three months ended                 Year ended
                                  March 31, 2011          December 31, 2010
----------------------------------------------------------------------------
                          6.25%    6.75%   Total     6.25%    6.75%   Total
----------------------------------------------------------------------------
Principal, beginning
 of period             115,000   79,744  194,744  115,000   79,744  194,744
Issued during period         -        -        -        -        -        -
----------------------------------------------------------------------------
Principal, end of
 period                115,000   79,744  194,744  115,000   79,744  194,744
----------------------------------------------------------------------------

Debt component,
 beginning of period   116,506   83,014  199,520  119,600   84,130  203,730
Issued during period         -        -        -        -        -        -
Premium amortization       (94)    (500)    (594)       -        -        -
Fair value adjustment
 to Dec 30, 2010             -        -        -    1,161     (398)     763
Reclassification to
 equity                      -        -        -   (4,255)    (718)  (4,973)
----------------------------------------------------------------------------
Debt component, end of
 period                116,412   82,514  198,926  116,506   83,014  199,520
----------------------------------------------------------------------------

Equity component,
 beginning of period     4,255      718    4,973        -        -        -
Reclassification from
 debt                        -        -        -    4,255      718    4,973
Issued during period         -        -        -        -        -        -
----------------------------------------------------------------------------
Equity component, end
 of period               4,255      718    4,973    4,255      718    4,973
----------------------------------------------------------------------------
----------------------------------------------------------------------------


8) OTHER LIABILITIES

                                                    March 31,   December 31,
                                                        2011           2010
----------------------------------------------------------------------------
Share-based incentive compensation (Note 9)           $1,686         $1,009
Excess office lease obligation (1)                    $1,567         $2,003
----------------------------------------------------------------------------
                                                      $3,253         $3,012
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the present value of the long-term portion of the office
    lease obligation, in excess of a sub-lease, assumed on the acquisition
    of Alberta Clipper Energy Inc. and Breaker Energy Ltd. MFC will
    reimburse the Corporation for 50 percent of the Alberta Clipper
    obligation of $0.7 million under a base price adjustment clause.

9) SHARE-BASED INCENTIVE COMPENSATION PLAN

The Manager has a long term incentive plan under which employees receive cash compensation based upon the value and overall return of a specified number of awarded notional shares on a fixed vesting date. The notional share grants are in the form of Restricted Share Units ("RSUs") and Performance Share Units ("PSUs"). One third of each RSU grant vests on November 30 in each of the three years after the date of grant. PSUs vest on November 30, three years after the date of grant.

Pursuant to the Reorganization, all previously issued Restricted Trust Units and Performance Trust Units were amended such that instead of them representing one notional unit they represent one notional share on the same terms and continue to be governed by the same terms under the Plan.

The Corporation recorded total share based compensation expense of $0.6 million in the first three months of 2011 ($0.7 million was expensed through earnings for the three months ended March 31, 2010). The compensation expense was based on the March 31, 2011 share price of $13.23 (March 31, 2010 - $12.95), accrued dividends, performance factors and the estimated number of shares vesting on maturity.

A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of shares that vested. Forfeiture rates incorporated in the calculations are 10 percent for a one year vest, 15 percent for a two year vest and 20 percent for a three year vest.

The Corporation has a deferred share unit plan ("DSU") under which directors of the Corporation receive cash compensation based upon the value and the overall return of a specified number of notional shares. The notional shares vest on retirement of the director.


The following table reconciles the change in total accrued share-based
incentive compensation relating to the plan:

                                          Three months ended     Year ended
                                                    March 31,   December 31,
                                                        2011           2010
----------------------------------------------------------------------------
Balance, beginning of period                        $ 13,209       $ 15,759
Increase in liability                                    636          4,545
Cash payout, relating to shares vested(1)             (7,386)        (7,095)
----------------------------------------------------------------------------
Balance, end of period                              $  6,459       $ 13,209
----------------------------------------------------------------------------
Current portion of liability(2)                     $  4,773       $ 12,200
----------------------------------------------------------------------------
Long-term liability(3)                              $  1,686       $  1,009
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes cash payout under Directors' DSU plan of $0.5 million (December
    31, 2010 - $0.3 million).
(2) Included in accounts payable and accrued liabilities.
(3) Included in other liabilities.


The following table sets forth a reconciliation of the Corporation's
incentive plan activity for the quarter ended March 31, 2011 and 2010.

                                                        2011
----------------------------------------------------------------------------
                                    Number of      Number of
                                   Restricted    Performance 
                                       Shares         Shares          Total 
----------------------------------------------------------------------------
Balance, beginning of quarter         122,482        543,011        665,493
Allocation rate change(1)              (6,859)       (30,407)       (37,266)
Issued                                188,885        180,724        369,609
Exercised                                   -              -              -
Forfeited                              (2,901)        (8,569)       (11,470)
----------------------------------------------------------------------------
Balance, end of quarter               301,607        684,759        986,366
----------------------------------------------------------------------------
Exercisable, end of quarter                 -              -              -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Allocation rate change reflects change in proportion of expenses charged
    to the Corporation from the Manager based on relative production of the
    Corporation and MFC.


                                                        2010
                              ----------------------------------------------
                                    Number of      Number of 
                                   Restricted    Performance
                                       Shares         Shares          Total
----------------------------------------------------------------------------
Balance, beginning of quarter         295,121        670,030        965,151
Allocation rate change(1)              28,990         65,818         94,808
Issued                                  9,866          2,466         12,332
Exercised                            (106,237)             -       (106,237)
Forfeited                              (5,083)       (21,600)       (26,683)
----------------------------------------------------------------------------
Balance, end of quarter               222,657        716,714        939,371
----------------------------------------------------------------------------
Exercisable, end of quarter                 -              -              -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Allocation rate change reflects change in proportion of expenses charged
    to the Corporation from the Manager based on relative production of the
    Corporation and MFC.


10) ASSET RETIREMENT OBLIGATIONS

The following table reconciles the Corporation's asset retirement
obligations.

                                          Three months ended     Year ended
                                                    March 31,   December 31,
                                                        2011           2010
----------------------------------------------------------------------------
Balance, beginning of period                        $149,015       $134,358
Accretion expense                                      2,544         11,006
Revisions to estimates                                  (910)             -
Liabilities incurred                                     496          4,515
Liabilities acquired                                       -          6,797
Liabilities disposed                                 (22,670)        (1,044)
Liabilities settled                                   (2,437)        (6,617)
----------------------------------------------------------------------------
Balance, end of period                              $126,038       $149,015
----------------------------------------------------------------------------
----------------------------------------------------------------------------

NAL's estimated credit-adjusted risk-free rate of eight percent (2010 - eight percent) and an inflation rate of two percent (2010 - two percent) were used to calculate the present value of the asset retirement obligations.

11) NET INCOME (LOSS) PER SHARE

Basic net income (loss) per share is calculated using the weighted average number of shares outstanding. The calculation of diluted net income per share includes the weighted average shares potentially issuable on the conversion of the convertible debentures. For the three months ended March 31, 2011, the shares potentially issuable on the conversion of the convertible debentures are anti-dilutive and are therefore excluded from the calculation. Total weighted average shares issuable on conversion of the convertible debentures and excluded from the diluted net income per share calculation for the three months ended March 31, 2011 was 12,665,697, as they were anti-dilutive. For the three months ended March 31, 2010, 12,665,697 common shares were included in the diluted earnings per share calculation as they were dilutive. As at March 31, 2011, the total convertible debentures outstanding were immediately convertible to 12,665,697 shares (March 31, 2010 - 12,665,697).

12) FINANCIAL RISK MANAGEMENT

Overview

The Corporation has exposure to the following risks from its use of financial instruments: credit risk, liquidity risk and market risk.

This note presents information about the Corporation's exposure to each of the above risks, the Corporation's objectives, policies and processes for measuring and managing risk, and the Corporation's management of capital. Certain other quantitative disclosures are included throughout these financial statements.

The Board of Directors has the responsibility to understand the principal risks of the business and to achieve a proper balance between the risks incurred and the potential return to shareholders. The Board of Directors has oversight for ensuring systems are in place which effectively monitor and manage those risks with a view to the long term viability of the Corporation.

Credit risk

Credit risk is the risk of financial loss to the Corporation if a customer or counterparty to a financial instrument fails to meet its contractual obligations, and arises principally from the Corporation's receivables. The Corporation is managed by the Manager. The Manager is a wholly-owned subsidiary of MFC and manages on its behalf NAL Resources, another wholly-owned subsidiary of MFC. NAL Resources and the Corporation maintain ownership interests in many of the same oil and natural gas properties in which NAL Resources is the operator. As a result, a significant portion of the Corporation's net operating revenues represent joint operations from NAL Resources. Accordingly, accounts receivable include amounts due from NAL Resources for oil, natural gas and natural gas liquids sales. Oil and gas marketing is conducted by the Manager on behalf of the Corporation and NAL Resources, generally with large creditworthy purchasers, for which the Corporation views the credit risk as low. NAL Resources, and ultimately the Corporation, has not historically experienced any collection issues with their oil and gas marketers. The Manager does not obtain collateral from oil and natural gas marketers.

Cash and cash equivalents, when outstanding, consist of cash bank balances and short-term deposits maturing in less than 90 days. Derivative contracts consist of commodity contracts and foreign exchange rate contracts denominated in U.S. dollars for periods of up to two years and interest rate contracts for periods of up to five years. The Corporation manages the credit exposure related to short-term investments and derivative contracts by dealing with established counter-parties with high credit ratings and monitors all investments, avoiding complex investment vehicles with higher risks such as asset backed commercial paper. All derivative contract counterparties are Canadian chartered banks in NAL's lending syndicate.

NAL management has reviewed its existing credit policy and has implemented more regular reviews of purchasers to ensure credit worthiness given the current market conditions.

The carrying amounts of cash, accounts and other receivables and derivatives represent the maximum credit exposure.

The Corporation considers all amounts greater than 90 days to be past due. Generally, the Corporation does not have amounts past due, due to receiving a significant portion of net operating revenues from NAL Resources. No receivables were past due as at March 31, 2011 and March 31, 2010.

Liquidity risk

Liquidity risk is the risk that the Corporation will not be able to meet its financial obligations as they are due. The Corporation manages liquidity by ensuring, as far as possible, that it will have sufficient liquidity under both normal and stressed conditions.

The Corporation requires significant cash to fund capital programs necessary to maintain or increase production and develop reserves, to acquire strategic oil and gas assets, to repay maturing debt and to pay dividends.

The Corporation's capital programs are funded principally by internally generated cash flows and undrawn committed borrowing facilities. The Corporation also hedges a portion of its production to protect cash flow in the event of commodity price declines. To support the capital spending program, the Corporation maintains a fully secured, extendible, revolving term credit facility, as outlined in Note 6.

The Corporation prepares annual capital expenditure budgets, which are regularly monitored and updated as necessary. As well, the Manager utilizes authorizations for expenditures on both operated and non-operated projects. Furthermore, the Manager operates a high percentage of the Corporation's properties, which allows for significant control over future expenditures.

The Corporation's non-derivative financial liabilities include its accounts payable and accrued liabilities, dividends payable to shareholders, bank debt and convertible debentures. The Corporation's derivative financial liabilities include its commodity contracts. The following table outlines cash flows associated with the maturities of the Corporation's financial liabilities.


The following are the contractual maturities of financial liabilities as at
March 31, 2011.

Non-Derivative Financial            less than
 Liability                             1 Year    1 - 2 Years    2 - 5 Years
----------------------------------------------------------------------------
Accounts payable and accrued
 liabilities                        $ 128,792      $       -      $       -
Dividends payable to
 shareholders                          10,345              -              -
Bank debt, principal                        -              -        255,306
Convertible debentures,
 principal                                  -         79,744        115,000
----------------------------------------------------------------------------
Total                               $ 139,137      $  79,744      $ 370,306
----------------------------------------------------------------------------
----------------------------------------------------------------------------


                                    less than
Derivative Financial Liability         1 Year    1 - 2 Years    2 - 5 Years
----------------------------------------------------------------------------
Commodity contracts                 $  31,235      $       -      $       -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Market risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Corporation's net income or the value of financial instruments.

Foreign currency exchange rate risk

Foreign currency exchange rate risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Corporation's oil and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for oil and natural gas are impacted by changes in the exchange rate between the Canadian and U.S. dollar.

NAL's management has authorization from the Board to fix the exchange rate on up to 50 percent of the Corporation's U.S. dollar exposure for periods of up to 24 months.


NAL has the following Canadian dollar / U.S. dollar foreign exchange option
contracts outstanding.

----------------------------------------------------------------------------
Fixed      Notional
 Rate      (US) per                                            Counterparty
 (CAD/USD)    month                           Term            Floating Rate
----------------------------------------------------------------------------
1.05        $2.0 MM    Apr 1, 2011 to Dec 31, 2011     BofC Monthly Average 
                                                                  Noon Rate
1.0608      $0.5 MM    Apr 1, 2011 to Dec 31, 2011     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.

----------------------------------------------------------------------------
Option                                                              Monthly
 Payout         Notional                                            Premium
 Range          (US) per                             Counterparty  Received
 (CAD/USD)         month              Term          Floating Rate      (CAD)
----------------------------------------------------------------------------
$0.93 - $1.01    $3.0 MM    May 1, 2011 to   BofC Monthly Average      $60K
                              Dec 31, 2011              Noon Rate
$0.93 - $1.01    $2.0 MM    Jan 1, 2012 to   BofC Monthly Average      $40K
                              Jun 30, 2012              Noon Rate
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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.


----------------------------------------------------------------------------
Option Fixing       Notional
 Range                   (US)                                  Counterparty
 (CAD/USD)         per month               Term               Floating Rate
----------------------------------------------------------------------------
$0.94 - $1.06        $0.5 MM     Apr 1, 2011 to        BofC Monthly Average
                                   Dec 31, 2011                   Noon Rate
$0.95 - $1.07        $0.5 MM     Apr 1, 2011 to        BofC Monthly Average
                                   Dec 31, 2011                   Noon Rate
$0.94 - $1.08        $0.5 MM     Apr 1, 2011 to        BofC Monthly Average
                                   Dec 31, 2011                   Noon Rate
$0.95 - $1.04        $0.5 MM     Apr 1, 2011 to        BofC Monthly Average
                                   Dec 31, 2011                   Noon Rate
$0.95 - $1.0125      $0.5 MM     Apr 1, 2011 to        BofC Monthly Average
                                   Jun 30, 2012                   Noon Rate
$0.95 - $1.0138      $1.0 MM     Apr 1, 2011 to        BofC Monthly Average
                                   Jun 30, 2012                   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 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.


----------------------------------------------------------------------------
Option
 Fixing            Notional
 Range                  (US)                                   Counterparty
 (CAD/USD)        per month                 Term              Floating Rate
----------------------------------------------------------------------------
$1.05 - $1.15       $1.0 MM       Apr 1, 2011 to       BofC Monthly Average 
                                    Dec 31, 2011                  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.

The fair value of foreign exchange derivative contracts has been included on the balance sheet with changes in the fair value reported separately on the statement of income as unrealized gain (loss). As at March 31, 2011, if exchange rates had strengthened by $0.01, with all other variables held constant, net income for the period would have been $0.7 million higher, due to changes in the fair value of the derivative contracts. An equal and opposite effect would have occurred to net income had exchange rates been $0.01 weaker.

Commodity price risk

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by not only the relationship between the Canadian and U.S. dollar, but also macroeconomic events that dictate the levels of supply and demand. The Corporation has attempted to mitigate commodity price risk by entering into financial derivative contracts. The Corporation's policy is to enter into commodity contracts to a maximum of 60 percent of forecasted, net of royalty, production volumes for a period of up to two years.


NAL has the following commodity risk derivative contracts outstanding:

CRUDE OIL                   Q2-11  Q3-11  Q4-11  Q1-12  Q2-12  Q3-12  Q4-12
----------------------------------------------------------------------------
US$ Collar Contracts
$US WTI Collar Volume
 (bbl/d)                    1,000    200    200    800    800    700    700
Bought Puts - Average
 Strike Price ($US/bbl)     83.00  90.00  90.00 101.25 101.25 101.43 101.43
Sold Calls - Average
 Strike Price ($US/bbl)     95.68 100.50 100.50 117.95 117.95 117.66 117.66

US$ Swap Contracts
$US WTI Swap Volume
 (bbl/d)                    4,900  5,700  5,700    500    500    500    500
Average WTI Swap Price
 ($US/bbl)                  87.39  88.10  88.10 109.60 109.60 109.60 109.60

Total Oil Volume (bbl/d)    5,900  5,900  5,900  1,300  1,300  1,200  1,200
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Two calendar 2011 500 bbl/d 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.


NATURAL GAS                 Q2-11  Q3-11  Q4-11  Q1-12  Q2-12  Q3-12  Q4-12
----------------------------------------------------------------------------
Swap Contracts
---------------
AECO Swap Volume (GJ/d)    20,000 21,000 21,000 24,000  5,000  5,000  3,674
AECO Average Price
 ($Cdn/GJ)                   4.32   3.95   3.95   3.98   4.15   4.15   4.15

Total Natural Gas Volume
 (GJ/d)                    20,000 21,000 21,000 24,000  5,000  5,000  3,674
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The fair value of commodity derivative contracts has been included on the balance sheet with changes in the fair value reported separately on the statement of income as unrealized gain (loss). As at March 31, 2011, if oil and natural gas liquids prices had been $1.00 per barrel lower and natural gas prices $0.10 per Mcf lower, with all other variables held constant, net income for the period would have been $1.9 million higher, due to changes in the fair value of the derivative contracts. An equal and opposite effect would have occurred to net income had oil and natural gas liquids prices been $1.00 per barrel higher and natural gas $0.10 per Mcf higher.

Interest rate risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Corporation is exposed to interest rate fluctuations on its bank debt, which bears a floating rate of interest. The Corporation has attempted to mitigate interest rate risk by entering into derivative contracts.

The contracts have a combined notional debt amount of $139 million and require NAL to make fixed quarterly payments. In exchange, the counterparties are required to pay the Corporation a floating rate of interest based on the average rate for Canadian dollar bankers' acceptances. The Corporation's interest charge includes this fixed interest rate component plus a standby fee, a stamping fee and the fee for renewal. The Corporation's policy is to enter into interest rate swap contracts to fix the interest rate on up to 50 percent of outstanding bank debt for periods of up to five years.


NAL has the following interest rate derivative contracts outstanding:

----------------------------------------------------------------------------
                Remaining       Amount  Corporation            Counterparty
INTEREST RATE        Term   (Cdn$MM)(1)  Fixed Rate           Floating Rate
----------------------------------------------------------------------------
Swaps-floating   Apr 2011 -      $39.0       1.5864%  CAD-BA-CDOR (3 months)
 to fixed        Dec 2011
Swaps-floating   Apr 2011 -      $22.0       1.3850%  CAD-BA-CDOR (3 months)
 to fixed        Jan 2013
Swaps-floating   Apr 2011 -      $22.0       1.5100%  CAD-BA-CDOR (3 months)
 to fixed        Jan 2014
Swaps-floating   Apr 2011 -      $14.0       1.8750%  CAD-BA-CDOR (3 months)
 to fixed        Mar 2013
Swaps-floating   Apr 2011 -      $14.0       1.9850%  CAD-BA-CDOR (3 months)
 to fixed        Mar 2014
Swaps-floating   Apr 2011 -      $14.0       1.8500%  CAD-BA-CDOR (3 months)
 to fixed        Mar 2013
Swaps-floating   Apr 2011 -      $14.0       1.9300%  CAD-BA-CDOR (3 months)
 to fixed        Mar 2014
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Notional debt amount

The fair value of interest rate derivative contracts has been included on the balance sheet with changes in the fair value reported separately on the statement of income as unrealized gain (loss). As at March 31, 2011, if interest rates had been one percent lower, with all other variables held constant, net income for the year would have been $2.9 million lower, due to changes in the fair value of the derivative contracts. An equal and opposite effect would have occurred to net income had interest rates been one percent higher.

Fair Value of Financial Instruments

The carrying amount of the Corporation's financial instruments, including accounts receivable, accounts payable and accrued liabilities, and dividends payable to shareholders, approximate their fair value due to their short term to maturity.

The Corporation's bank debt and cash bear interest at floating market rates and, accordingly, the fair market value approximates the carrying amount.

The fair value of the Corporation's convertible debentures is based on quoted and observable market values, which is used to mark-to-market the convertible debentures within the financial statements. On conversion to a Corporation, the convertible debentures are no longer fair valued. The mark-to-market on the convertible debentures is included in the December 31, 2010 convertible debenture total of $199,520.

Other liabilities include share-based compensation liabilities as well as excess office lease obligations.

Share-based compensation liabilities are recorded at fair value and are based upon the outstanding shares, valued at the Corporation's share price at the reporting date, performance factors and the number of shares vesting on maturity and estimated forfeitures.

The excess office lease obligation represents the present value of the long-term portion of office lease obligations, in excess of sub-leases, assumed on previous business acquisitions.

Derivative commodity contracts are recorded at fair value on the balance sheet as current or long-term, assets or liabilities, based on their fair values on a contract-by-contract basis. The fair value of commodity contracts is determined as the difference between the contracted prices and published forward curves (ranging from US$105.10 per barrel to US$108.35 per barrel for oil and $3.59 per GJ to $4.12 per GJ for natural gas) as of the balance sheet date, using the remaining contracted oil and natural gas volumes with option contracts also including an element of volatility. The fair value of the interest rate swaps is determined by discounting the difference between the contracted interest rate and forward bankers' acceptances rates (ranging from 0.956 percent to 2.192 percent) as of the balance sheet date, using the notional debt amount and outstanding term of the swap. The fair value of the exchange rate derivatives is calculated as the discounted value of the difference between the contracted exchange rate and the market forward exchange rates (ranging from 0.9684 to 0.9813) as of the balance sheet date, using the notional U.S. dollar amount and outstanding term of the swap. The fair value of the derivative contracts is as follows:


                                                    March 31,   December 31,
                                                        2011           2010
----------------------------------------------------------------------------
Fair value of commodity contracts                  $ (34,979)     $ (13,717)
Fair value of interest rate swaps                      1,012            706
Fair value of foreign exchange rate swaps              3,789          3,111
----------------------------------------------------------------------------
                                                   $ (30,178)     $  (9,900)
----------------------------------------------------------------------------
----------------------------------------------------------------------------


The gain/(loss) on derivative contracts is as follows:

Gain / (Loss) on Derivative Contracts

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Unrealized gain (loss):
 Crude oil contracts                               $ (21,318)         1,546
 Natural gas contracts                                    56         15,021
 Interest rate swaps                                     306            191
 Exchange rate swaps                                     678          1,751
----------------------------------------------------------------------------
Unrealized gain (loss)                               (20,278)        18,509
Realized gain (loss):
 Crude oil contracts                                  (3,127)        (2,082)
 Natural gas contracts                                   916          2,497
 Interest rate swaps                                    (129)          (257)
 Exchange rate swaps                                   1,342          1,290
----------------------------------------------------------------------------
Realized gain (loss)                                    (998)         1,448
----------------------------------------------------------------------------
Gain (loss) on derivative contracts                $ (21,276)     $  19,957
----------------------------------------------------------------------------
----------------------------------------------------------------------------


These contracts are presented on the balance sheet as short term / long
term, assets and liabilities as follows:

                                                    March 31,   December 31,
                                                        2011           2010
----------------------------------------------------------------------------
Current unrealized loss on derivative
 contracts                                         $ (31,235)     $  (7,819)
Current unrealized gain on derivative
 contracts                                                 -            422
----------------------------------------------------------------------------
Current unrealized loss on derivative
 contracts                                         $ (31,235)        (7,397)
Long term unrealized gain on derivative
 contracts                                             1,057              -
Long term unrealized loss on derivative
 contracts                                                 -         (2,503)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net fair value of derivative contracts             $ (30,178)     $  (9,900)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

As at March 31, 2011, the total fair value of derivative contracts was a net liability of $30.2 million (December 31, 2010 - net liability of $9.9 million). The change in the fair value for the quarter ended March 31, 2011 of $20.3 million has been recognized as an unrealized loss in the statement of income (year ended December 31, 2010 - $7.4 million unrealized loss).


The following table reconciles the movement in the fair value of the
Corporation's derivative contracts:

                                                Three months ended March 31
                                               -----------------------------
                                                        2011           2010
----------------------------------------------------------------------------
Unrealized (loss), beginning of period             $  (9,900)     $  (2,485)
Unrealized (loss) gain, end of period                (30,178)        16,024
----------------------------------------------------------------------------
Unrealized (loss) gain for the period                (20,278)        18,509
Realized gain (loss) in the period                      (998)         1,448
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gain (loss) on derivative contracts                $ (21,276)     $  19,957
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The financial instruments carried at fair value, being the derivative contracts, are required to be classified into a hierarchy that prioritizes the inputs used to measure the fair value. The three levels of the fair value hierarchy are:

Level 1: Unadjusted quoted prices in active markets for identical assets or liabilities;

Level 2: Inputs other than quoted prices that are observable for the asset or liability either directly or indirectly; and

Level 3: Inputs that are not based on observable market data.

Fair values are classified as Level 1 when the related derivative is actively traded and a quoted price is available. If different levels of inputs are used to measure a financial instrument's fair value, the classification within the hierarchy is based on the lowest level input that is significant to the fair value measurement. The following table illustrates the classification of the financial instruments within the fair value hierarchy as at March 31, 2011:


----------------------------------------------------------------------------
                                  Assets at fair value as at March 31, 2011
                                 -------------------------------------------
                                      Level 1   Level 2   Level 3     Total
----------------------------------------------------------------------------
Foreign exchange rate contracts             -     3,789         -     3,789
Interest rate contracts                     -     1,012         -     1,012
----------------------------------------------------------------------------
                                            -     4,801         -     4,801
----------------------------------------------------------------------------
----------------------------------------------------------------------------

----------------------------------------------------------------------------
                                        Liabilities at fair value as at
                                                March 31, 2011
                                 -------------------------------------------
                                      Level 1   Level 2   Level 3     Total
----------------------------------------------------------------------------
Crude oil contracts                         -    34,979         -    34,979
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Capital Management

The Corporation's policy is to maintain a strong and flexible capital base to ensure that dividend levels are sustainable, while at the same time providing the flexibility to take advantage of operational and acquisition opportunities.

The Corporation manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying oil and natural gas assets. The Corporation considers its capital structure to include common shares, bank debt, convertible debentures, other liabilities, and working capital (excluding derivative contracts and future income tax) as shown below. In order to maintain or adjust its capital structure, the Corporation may adjust the amount of dividends paid to shareholders, issue new shares, adjust its capital spending to modify debt levels, or suspend/resume its DRIP programs.

The Corporation monitors its capital based on the ratio of its net debt to 12 months trailing funds from operations. This ratio, which is a non-GAAP measure, is calculated as net debt as a proportion of funds from operations for the previous 12 months. Funds from operations is defined as cash flow from operating activities prior to the change in non-cash working capital. Net debt is defined as bank debt, plus convertible debentures at face value, plus working capital (excluding derivative contracts and future income tax balances and including other liabilities). Net debt is measured with and without convertible debentures. The Corporation's strategy is to maintain a conservative net debt to 12 month trailing funds from operations as compared to other oil and gas companies, both before and after taking into account the convertible debentures. The Corporation will, for the appropriate opportunity, increase its debt to funds from operations ratio above the Corporation's average. In order to facilitate the management of this ratio, the Corporation prepares an annual budget which is approved by the Board of Directors. On a monthly basis a reforecast for the year is prepared based on updated commodity prices, results of operational activity and other events. The monthly forecast is provided to the Board of Directors.

As at March 31, 2011, the Corporation had a total net debt to 12 months trailing funds from operations ratio of 2.00 (March 31, 2010 - 2.03), as calculated in the table below. The increase in the net debt to 12 months trailing funds from operations ratio in 2011 is attributable to a relatively higher total net debt increase compared to the increase in funds from operations.

The Corporation has no restrictions on the issuance of common shares.

There has been no change in the approach to capital management during the first quarter of 2011.


Capitalization

                                     March 31,   December 31,      March 31,
                                         2011           2010           2010
----------------------------------------------------------------------------
Shareholders' equity ($000s)          869,962        895,750        887,937

Bank debt ($000s)                     255,306        266,965        244,695
Working capital deficit(1) ($000s)     78,697         43,337         63,760
----------------------------------------------------------------------------
Net debt excluding convertible
 debentures                           334,003        310,302        308,455
Convertible debentures ($000s)(2)     194,744        194,744        194,744
----------------------------------------------------------------------------
Net debt                              528,747        505,046        503,199

Net debt excluding convertible
 debentures to trailing 12-month
 cash flow(3)                            1.26           1.11           1.24
Total net debt to trailing
 12-month cash flow(3)                   2.00           1.80           2.03
Common shares outstanding (000s)      147,781        147,248        137,881
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Working capital and other liabilities, excludes derivative contracts,
    deferred tax and note with MFC.
(2) Convertible debentures included at face value.
(3) Calculated as net debt divided by funds from operations for the previous
    12 months.

13) COMMITMENTS

(i) Joint Venture Agreement

Effective April 20, 2009, the Corporation and MFC entered into a joint venture agreement with a senior industry partner. The arrangement consists of a three year commitment to spend $50 million on or before August 31, 2012, that provides the Corporation and MFC an opportunity to earn an interest in freehold and crown acreage. The Corporation has a 65 percent interest in this agreement and MFC a 35 percent interest. The three year commitment to the Corporation is $32.5 million. The agreement is exclusive and structured to be extendible for up to an additional six years for a total potential commitment of $150 million ($97.5 million net to the Corporation) to earn an interest in over 150 (97.5 net) sections of freehold and crown acreage. If the capital spending commitments are not met, interests in the freehold and crown acreage will not be earned and the Corporation will not be required to pay unspent commitment amounts under the arrangement. As at March 31, 2011, the Corporation has spent $14.0 million under this agreement.

(ii) Farm-in Agreement

Effective August 10, 2009, the Corporation and MFC entered into a farm-in agreement with a senior industry partner. The arrangement consists of a two year initial commitment, with a minimum capital commitment of $40 million in the first year and $57 million in the second year, with an option for a third year, at NAL's election, for an additional commitment of $50 million. The Corporation has a 60 percent interest in this agreement and MFC a 40 percent interest. The agreement provides the opportunity to earn an interest in approximately 1,400 gross sections of undeveloped oil and gas rights in Alberta held by the partner. If the capital spending commitments are not met, interest in the acreage will not be earned and the Corporation will not be required to pay any unspent amounts. As at March 31, 2011, the Corporation has spent $36.7 million under this agreement and met its first year commitment.

(iii) Other

NAL has entered into several contractual obligations as part of conducting day-to-day business. NAL has the following commitments for the next five years:


----------------------------------------------------------------------------
($000s)                        2011      2012      2013      2014      2015
----------------------------------------------------------------------------
Office lease(1)            $  1,431  $  2,146  $  2,132  $  2,092  $  2,092
Office lease - Clipper
 and Breaker(2)               1,473     2,211       364         -         -
Transportation agreement      3,126     2,352     2,209     1,030       124
Processing agreements(3)        466       197       184         -         -
Convertible debentures(4)         -    79,744         -   115,000         -
Bank debt                         -         -   153,146   102,098         -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total                      $  6,496  $ 86,650  $158,035  $220,220  $  2,216
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Represents the Corporation's share of office lease commitments,
    including both base rent and operating costs, in relation to the lease
    held by the Manager, of which the Corporation is allocated a pro rata
    share (currently approximately 60 percent) of the expense on a monthly
    basis.
(2) Represents the full amount of the office leases assumed with the
    acquisitions of Clipper and Breaker. MFC will reimburse the Corporation
    for 50 percent of the Clipper obligation under the base price adjustment
    clause.
(3) Represents gas processing agreements with take or pay components.
(4) Principal amount.

14) TRANSITION TO INTERNATIONAL FINANCIAL REPORTING STANDARDS ("IFRS")

As stated in Note 2, these interim consolidated financial statements are the first set of financial statements presented by the Corporation in accordance with Canadian generally accepted accounting principles for publicly accountable enterprises (being IFRS as adopted by the Canadian AcSB). Accordingly, these interim consolidated financial statements have been prepared in accordance with IFRS1, "First- time adoption of International Financial Reporting Standards" and with IAS 34,. "Interim Reporting" as issued by the IASB. Previously the Corporation prepared its consolidated financial statements in accordance with previous Canadian GAAP ("CGAAP"). The accounting policies as set out in Note 2 outline the basis for the preparation of these financial statements.

IFRS1 requires the presentation of comparative information as at the January 1, 2010 transition date and subsequent comparative periods as well as the consistent and retroactive application of IFRS accounting policies. To assist with the transition, IFRS1 outlines certain mandatory exceptions and optional exemptions that NAL could elect to eliminate the need for retroactive application of standards in certain circumstances.

In preparing the opening IFRS balance sheet, the Corporation has adjusted amounts reported previously in financial statements prepared in accordance with previous CGAAP. Reconciliations of previous CGAAP to IFRS as required by IFRS1 are set out in the tables which follow. A summary of the significant policy changes and exemptions are discussed in the notes that follow the reconciliations.


Reconciliation of Equity at January 1, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                        January 1, 2010                     January 1, 2010
                        as stated under                         as restated
                                  CGAAP  Adjustments  Notes      under IFRS
----------------------------------------------------------------------------

Assets
 Current assets
  Cash                      $     1,604  $         -            $     1,604
  Accounts receivable            61,631            -                 61,631
  Prepaids and other
   receivables                   15,663            -                 15,663
  Derivative contracts            6,285            -                  6,285
  Future income tax                                        
   assets                         3,132       (3,132)      J              -
----------------------------------------------------------------------------
                                 88,315       (3,132)                85,183

  Derivative contracts            2,461            -                  2,461
  Goodwill                       14,722            -                 14,722
  Deferred tax asset                  -       34,627      J          34,627
  Property, plant and                                      
   equipment                  1,503,952      (88,122)     A       1,415,830
  Exploration and                                          
   evaluation assets                  -       88,122      A          88,122
----------------------------------------------------------------------------
                            $ 1,609,450  $    31,495            $ 1,640,945
----------------------------------------------------------------------------

Liabilities and
 Shareholders' Equity
 Current liabilities
  Accounts payable and                                     
   accrued liabilities      $   110,897  $      (182)     G     $   110,715
  Note payable                    8,907            -                  8,907
  Dividends payable to
   shareholders                  12,372            -                 12,372
  Derivative contracts           11,231            -                 11,231
----------------------------------------------------------------------------
                                143,407         (182)               143,225

 Bank debt                      230,713            -                230,713
 Convertible debentures         177,977       25,753      H         203,730
 Other liabilities                7,643         (470)     G           7,173
 Asset retirement                                         
  obligations                   127,872        6,486      F         134,358
 Deferred income tax                                      
  liability                      24,778       26,421      J          51,199
 Minority interest                2,868       (2,868)     I               -
----------------------------------------------------------------------------
                                715,258       55,140                770,398
Shareholders' equity
 Share capital                1,482,029        3,392      J       1,485,421
 Equity component of                                      
  convertible debentures         12,628      (12,628)     H               -
 Minority interest                    -        3,370      I           3,370
 Deficit                       (600,465)     (17,779)              (618,244)
----------------------------------------------------------------------------
                                894,192      (23,645)               870,547
----------------------------------------------------------------------------
                            $ 1,609,450  $    31,495            $ 1,640,945
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Reconciliation of Equity at March 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                         March 31, 2010                      March 31, 2010
                              as stated                         as restated
                            under CGAAP  Adjustments  Notes      under IFRS
----------------------------------------------------------------------------

Assets
 Current assets
  Cash                      $     5,042  $         -            $     5,042
  Accounts receivable            51,255            -                 51,255
  Prepaids and other
   receivables                   11,301            -                 11,301
  Derivative contracts           24,714            -                 24,714
----------------------------------------------------------------------------
                                 92,312            -                 92,312

  Derivative contracts            2,652            -                  2,652
  Goodwill                       14,722            -                 14,722
  Deferred tax asset                  -       35,847      J          35,847
  Property, plant and                                  
   equipment                  1,511,167      (64,527) A - F      1,446,640
  Exploration and                                          
   evaluation assets                  -       90,135      A         90,135
----------------------------------------------------------------------------
                            $ 1,620,853  $    61,455            $ 1,682,308
----------------------------------------------------------------------------

Liabilities and
 Shareholders' Equity
 Current liabilities
  Accounts payable and                                    
   accrued liabilities      $   111,495         (135)     G     $   111,360
  Note payable                    8,331            -                  8,331
  Dividends payable
   to shareholders               12,409            -                 12,409
  Derivative contracts           11,342            -                 11,342
  Deferred tax                                            
   liability                      1,665       (1,665)     J               -
----------------------------------------------------------------------------
                                145,242       (1,800)               143,442

 Bank debt                      244,695            -                244,695
 Convertible debentures         178,624       25,738      H         204,362
 Other liabilities                8,135         (546)     G           7,589
 Asset retirement                                         
  obligations                   131,917        7,219      F         139,136
 Deferred income tax                                      
  liability                      17,818       37,329      J          55,147
 Minority interest                3,042       (3,042)     I               -
----------------------------------------------------------------------------
                                729,473       64,898                794,371
Shareholders' equity
 Share capital                1,487,053        3,392      J       1,490,445
 Equity component of                                      
  convertible debentures         12,628      (12,628)     H               -
 Minority interest                    -        3,684      I           3,684
 Deficit                       (608,301)       2,109               (606,192)
----------------------------------------------------------------------------
                                891,380       (3,443)               887,937
----------------------------------------------------------------------------
                            $ 1,620,853  $    61,455            $ 1,682,308
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Reconciliation of Equity at December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                            December 31,                        December 31,
                                2010 as                             2010 as
                                 stated                            restated
                            under CGAAP  Adjustments  Notes      under IFRS
----------------------------------------------------------------------------

Assets
 Current assets
  Cash                      $       821  $         -            $       821
  Accounts receivable            57,839            -                 57,839
  Prepaids and other
   receivables                   14,532            -                 14,532
  Derivative contracts              422            -                    422
  Future income tax                                       
   assets                         3,830       (3,830)     J               -
----------------------------------------------------------------------------
                                 77,444       (3,830)                73,614
  Deferred tax asset             17,152       32,228      J          49,380
  Goodwill                       14,722            -                 14,722
  Property, plant and                                  
   equipment                  1,503,546      (30,886) A - F       1,472,660
  Exploration and                                          
   evaluation assets                  -       63,127      A          63,127
----------------------------------------------------------------------------
                              1,612,864       60,639              1,673,503
----------------------------------------------------------------------------

Liabilities and
 Shareholders' Equity
 Current liabilities
  Accounts payable and                                     
   accrued liabilities          100,837         (572)     G         100,265
  Note payable                        -            -                      -
  Dividends payable to
   shareholders                  13,252            -                 13,252
  Derivative contracts            7,819            -                  7,819
----------------------------------------------------------------------------
                                121,908         (572)               121,336

 Bank debt                      266,965            -                266,965
 Convertible debentures         181,672       17,848      H         199,520
 Other liabilities                3,057          (45)     G           3,012
 Derivative contracts             2,503            -                  2,503
 Asset retirement                                         
  obligations                   144,738        4,277      F         149,015
 Deferred tax liability               -       35,402      J          35,402
----------------------------------------------------------------------------
                                720,843       56,910                777,753
Shareholders' equity
 Share capital                  879,393       11,384      J         890,777
 Equity component of                                      
  convertible debentures         12,628       (7,655)     H           4,973
 Deficit                              -            -                      -
----------------------------------------------------------------------------
                                892,021        3,729                895,750
----------------------------------------------------------------------------
                            $ 1,612,864  $    60,639            $ 1,673,503
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Reconciliation of Net Income for the three months ended March 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                           Three months                        Three months
                                  ended                               ended
                         March 31, 2010                      March 31, 2010
                              as stated                         as restated
                            under CGAAP  Adjustments  Notes      under IFRS
----------------------------------------------------------------------------

Revenue
 Oil, natural gas and
  liquid sales              $   138,520  $         -            $   138,520
 Crown royalties               (17,105)         547      B        (16,558)
 Freehold and other
  royalties                      (6,041)           -                 (6,041)
----------------------------------------------------------------------------
                                115,374          547                115,921

Gain on derivative
 contracts:
 Realized gain                    1,448            -                  1,448
 Unrealized gain                 18,509            -                 18,509
----------------------------------------------------------------------------
                                 19,957            -                 19,957
 Other income                       331            -                    331
----------------------------------------------------------------------------
                                135,662          547                136,209
----------------------------------------------------------------------------

Expenses
 Operating                       29,304       (1,234)     B          28,070
 Transportation                   1,637            -                  1,637
 General and                                              
  administrative                  4,359        1,523      B           5,882
 Share-based incentive                                    
  compensation                      439          247      B             686
 Interest on bank debt            3,086            -                  3,086
 Interest and accretion                                   
  on convertible debentures       4,133         (991)     H           3,142
 Fair value adjustment                                    
  on convertible debentures           -          632      H             632
 Convertible debenture                                    
  issue costs                         -          344      H             344
 Gain on disposition of
  property, plant and
  equipment                           -      (11,193)     E         (11,193)
 Depletion and                                            
  depreciation                   62,036      (13,771)     C          48,265
 Accretion on asset                                       
  retirement obligations          2,631           70      F           2,701
----------------------------------------------------------------------------
                                107,625      (24,373)                83,252
----------------------------------------------------------------------------
 Income before taxes             28,037       24,920                 52,957

 Current tax expense                (59)           -                    (59)
 Deferred tax reduction                                   
  (expense)                       2,163       (4,892)     J          (2,729)
----------------------------------------------------------------------------
 Total tax reduction
 (expense)                        2,104       (4,892)                (2,788)
----------------------------------------------------------------------------
 Net income and
  comprehensive income      $    30,141  $    20,028            $    50,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Attributable to:
 Equity holders of the
  Corporation               $    29,349  $    19,888            $    49,237
 Minority interest                  792          140                    932
----------------------------------------------------------------------------
 Net income and
  comprehensive income      $    30,141  $    20,028            $    50,169
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income per share
 Basic                      $      0.21  $      0.15            $      0.36
 Diluted                    $      0.21  $      0.14            $      0.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Reconciliation of Net Income for the year ended December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                             Year ended                          Year ended
                            December 31,                        December 31,
                                   2010                                2010
                              as stated                         as restated
                            under CGAAP  Adjustments  Notes      under IFRS
----------------------------------------------------------------------------

Revenue
 Oil, natural gas and
  liquid sales              $   497,538  $         -            $   497,538
 Crown royalties                (65,032)       2,132      B         (62,900)
 Freehold and other
  royalties                     (23,585)           -                (23,585)
----------------------------------------------------------------------------
                                408,921        2,132                411,053

Gain (loss) on
 derivative contracts:
 Realized gain                   24,446            -                 24,446
 Unrealized loss                 (7,415)           -                 (7,415)
----------------------------------------------------------------------------
                                 17,031            -                 17,031
 Other income                     1,403            -                  1,403
----------------------------------------------------------------------------
                                427,355        2,132                429,487
----------------------------------------------------------------------------

Expenses
 Operating                      117,523       (5,612)     B         111,911
 Transportation                   6,501            -                  6,501
 General and                                              
  administrative                 16,393        7,821      B          24,214
 Share-based incentive                                    
  compensation                    3,170        1,462      B           4,632
 Corporate conversion
  costs                           1,483            -                  1,483
 Interest on bank debt           11,794            -                 11,794
 Interest and accretion                                   
  on convertible debentures      16,562       (4,041)     H          12,521
 Fair value adjustment                                    
  on convertible debentures           -          763      H             763
 Convertible debenture                                    
  issue costs                         -          345      H             345
 Gain on disposition
  of property, plant and
  equipment                           -      (17,596)     E         (17,596)
 Depletion and                                            
  depreciation                  251,343      (50,556)     C         200,787
 Impairment of oil and                                    
  gas assets                          -       32,804      D          32,804
 Accretion on asset                                       
  retirement obligations         12,112       (1,106)     F          11,006
----------------------------------------------------------------------------
                                436,881      (35,716)               401,165
----------------------------------------------------------------------------
 Income (loss) before
  taxes                          (9,526)      37,848                 28,322

 Current tax recovery               782            -                    782
 Deferred tax reduction          41,154      (11,233)     J          29,921
----------------------------------------------------------------------------
 Total tax expense               41,936      (11,233)                30,703

----------------------------------------------------------------------------
 Net income and
  comprehensive income      $    32,410  $    26,615            $    59,025
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Net income per share
 Basic                      $      0.23  $      0.18            $      0.41
 Diluted                    $      0.23  $      0.18            $      0.41
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Reconciliation of Cash Flows for the three months ended March 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                           Three months                        Three months
                                  ended                               ended
                         March 31, 2010                      March 31, 2010
                              as stated                         as restated
                            under CGAAP  Adjustments  Notes      under IFRS
----------------------------------------------------------------------------

Operating Activities
 Net income                 $    29,349       19,888            $    49,237
 Items not including
  cash:
  Depletion and                                           
   depreciation                  62,036      (13,771)     C          48,265
  Accretion on asset                                      
   retirement obligations         2,631           70      F           2,701
  Unrealized loss (gain)
   on derivative contracts      (18,509)           -                (18,509)
  Gain on disposition of
   property, plant and
   equipment                          -      (11,193)     E         (11,193)
  Fair value adjustment                                   
   on convertible
   debentures                         -          632      H             632
  Deferred tax                                            
   (reduction) expense           (2,163)       4,892      J           2,729
  Non-controlling                                         
   interest                         174          140      I             314
  Lease amortization               (376)           -                   (376)
  Interest expense                    -        6,228                  6,228
  Convertible debenture
   issue costs                        -          344                    344
  Non-cash accretion
   expense on convertible
   debentures                       991         (991)     H               -
 Abandonment and
  reclamation                      (891)           -                   (891)
----------------------------------------------------------------------------
                                 73,242        6,239                 79,481
 Change in non-cash
  working capital                (9,594)      (1,639)               (11,233)
----------------------------------------------------------------------------
                                 63,648        4,600                 68,248
----------------------------------------------------------------------------

Financing Activities
 Distributions paid to
  shareholders                  (31,969)           -                (31,969)
 Increase in bank debt           13,982            -                 13,982
 Issue of shares, net
  of issue costs                   (155)           -                   (155)
 Convertible debenture
  issue costs                      (344)           -                   (344)
 Interest expense                     -       (6,796)                (6,796)
 Change in non-cash
  working capital                     -          568                    568
----------------------------------------------------------------------------
                                (18,486)      (6,228)               (24,714)
----------------------------------------------------------------------------

Investing Activities
 Additions to property,
  plant and equipment           (78,319)        (964)               (77,283)
 Additions to
  exploration and
  evaluation assets                   -       (2,013)                (2,013)
 Property acquisitions           (1,974)       1,974                      -
 Proceeds from
  dispositions                   14,676            -                 14,676
 Disposition of
  Spearpoint                       (309)           -                   (309)
 Change in non-cash
  working capital                24,202        2,631                 26,833
----------------------------------------------------------------------------
                                (41,724)       1,628                (40,096)
----------------------------------------------------------------------------

Increase in cash                  3,438            -                  3,438
Cash, beginning of
 period                           1,604            -                  1,604
----------------------------------------------------------------------------
Cash, end of period         $     5,042  $         -            $     5,042
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Reconciliation of Cash Flows for the year ended December 31, 2010
----------------------------------------------------------------------------
----------------------------------------------------------------------------

                             Year ended                          Year ended
                            December 31,                        December 31,
                                   2010                             2010 as
                              as stated                            restated
                            under CGAAP  Adjustments  Notes      under IFRS
----------------------------------------------------------------------------

Operating Activities
 Net income                 $    32,410       26,615            $    59,025
 Items not including
  cash:
  Depletion and                                           
   depreciation                 251,343      (50,556)     C         200,787
  Accretion on asset                                      
   retirement obligations        12,112       (1,106)     F          11,006
  Unrealized loss (gain)
   on derivative contracts        7,415            -                  7,415
  Gain on disposition of
   property, plant and
   equipment                          -      (17,596)     E         (17,596)
  Fair value adjustment                                   
   on convertible
   debentures                         -          763      H             763
  Impairment of oil and
   gas properties                     -       32,804                 32,804
  Deferred tax                                             
   (reduction) expense          (41,154)      11,233      J         (29,921)
  Lease amortization             (1,655)           -                 (1,655)
  Interest expense                    -       24,315                 24,315
  Convertible debenture
   issue costs                        -          345                    345
  Non-cash accretion
   expense on convertible
   debentures                     4,040       (4,040)     H               -
 Abandonment and
  reclamation                    (6,617)           -                 (6,617)
----------------------------------------------------------------------------
                                257,894       22,777                280,671
 Change in non-cash
  working capital                (3,754)          35                 (3,719)
----------------------------------------------------------------------------
                                254,140       22,812                276,952
----------------------------------------------------------------------------

Financing Activities
 Distributions paid to
  shareholders                 (129,559)           -               (129,559)
 Increase in bank debt           36,252            -                 36,252
 Issue of shares, net
  of issue costs                 94,466            -                 94,466
 Convertible debenture
  issue costs                      (345)           -                   (345)
 Interest expense                     -      (29,044)               (29,044)
 Change in non-cash
  working capital                     -        4,729                  4,729
----------------------------------------------------------------------------
                                    814      (24,315)               (23,501)
----------------------------------------------------------------------------

Investing Activities
 Additions to property,
  plant and equipment          (203,038)     (41,118)              (244,156)
 Additions to
  exploration and
  evaluation assets                   -      (25,986)               (25,986)
 Property acquisitions          (68,607)      68,607                      -
 Proceeds from
  dispositions                   22,178            -                 22,178
 Acquisition of Breaker            (901)           -                   (901)
 Disposition of
  Spearpoint                       (309)           -                   (309)
 Change in non-cash
  working capital                (4,968)           -                 (4,968)
----------------------------------------------------------------------------
                               (255,645)       1,503               (254,142)
----------------------------------------------------------------------------

(Decrease) Increase in
 cash                              (691)                               (691)
Cash, beginning of year           1,604                               1,604
Dissolution of partnership          (92)                                (92)
----------------------------------------------------------------------------
Cash, end of year           $       821  $         -            $       821
----------------------------------------------------------------------------
----------------------------------------------------------------------------

A) Property, plant and equipment (PP&E) and Exploration and evaluation assets (E&E)

The Corporation elected to apply the IFRS1 exemption available to entities which followed full cost accounting under previous CGAAP. This exemption permits the total carrying value of PP&E and E&E under IFRS on transition to equal the carrying value under previous CGAAP, subject to an impairment test. In addition, conversion to IFRS requires the allocation of the carrying amount of the full cost pool under previous CGAAP to E&E, and to components and CGUs for PP&E assets. Firstly, E&E assets were recorded at the carrying amount under previous CGAAP. The remaining previous CGAAP carrying amount was then allocated, pro-rata to components (Areas) for D&P assets ("PP&E"), based on proved plus probable reserve values, using the present values at a 10 percent discount rate.

Impairment tests were completed on transition, resulting in no impairment charge to PP&E or E&E at January 1, 2010.

E&E assets are required to be segregated from D&P assets. At January 1, 2010 these assets were $88.1 million, representing their carrying value under previous CGAAP. These assets comprise possible reserves assigned as a result of business acquisitions. As at March 31, 2010 and December 31, 2010, NAL's E&E assets were $90.1 million and $63.1 million, respectively.

Under previous CGAAP these assets were included in the full cost pool as PP&E, in accordance with the CICA's full cost accounting guideline. Under IFRS, these costs are initially recorded as E&E, on determination of technical feasibility and commercial viability of the assets the capitalized costs are moved to PP&E.

B) Capitalized costs - PP&E

Under IFRS, employee costs included in general and administrative charges and share-based compensation charges are capitalized to the extent they are directly attributable to PP&E and E&E. The Corporation has adjusted its capitalization policy to comply with IFRS. For the year ended December 31, 2010, $9.3 million of such costs are expensed under IFRS that were originally capitalized under previous CGAAP. For the three months ended March 31, 2010 $1.8 million were expensed.

Additionally for the year ended December 31, 2010, lease rentals of $7.7 million were expensed under previous CGAAP, while under IFRS the Corporation has elected to capitalize these amounts. For the three months ended March 31, 2010, $1.9 million has been capitalized.

C) Depreciation and depletion

Under previous CGAAP, depletion was based on NAL's single cost centre, on a unit of production basis using total proved reserves. Costs subject to depletion excluded possible reserve locations and undeveloped land.

Under IFRS, depletion is provided for at a component level, defined as an Area by NAL, on a unit of production basis using total proved plus probable reserves. Costs subject to depletion are D&P assets excluding land under development.

For the year ended December 31, 2010, depletion decreased by $50.6 million from previous CGAAP, primarily a result of the change in depletion base to proved plus probable reserves. For the three months ended March 31, 2010 depletion decreased by $13.8 million. There was no impact to January 1, 2010 due to the IFRS1 election discussed above.

D) Impairment

Under previous CGAAP, impairment was recognized if the carrying amount exceeded the undiscounted cash flows from proved reserves for NAL's single cost centre. The amount of impairment was then measured as the amount by which the carrying value of the cost centre exceeded the sum of proved plus probable reserves discounted at a risk free rate plus the cost of unproved interests and land, net of impairment. Impairments recognized under previous CGAAP were not reversed.

Under IFRS, an impairment is recognized if the carrying value exceeds the recoverable amount for a cash-generating unit ("CGU"). If the carrying value exceeds the recoverable amount of the CGU, the CGU is written down with an impairment recognized in net income. Impairments under IFRS are reversed when there has been a subsequent increase in recoverable amounts. Impairment reversals are recognized in net income and the carrying amount of the CGU is increased.

For the year ended December 31, 2010, NAL recognized a $32.8 million impairment loss relating to gas focused CGUs in Alberta, northeast British Columbia and Ontario. The impairment recognized was based on the difference between the December 31, 2010 net book value of the CGUs and the recoverable amount. The recoverable amount was determined using fair value less costs to sell based on discounted future cash flows of proved plus probable reserves. Under previous CGAAP, these assets were included in the one cost centre, which was not impaired at December 31, 2010.

E) Gains on dispositions

Under previous CGAAP, gains on dispositions were typically not recognized. Proceeds from dispositions were deducted from the full cost pool unless the deduction resulted in a change to the depletion rate of 20 percent or more, in which case a gain or loss was recorded.

Under IFRS, gains or losses are recorded on dispositions of properties and are calculated as the difference between the proceeds and the net book value of the assets disposed of at the point of disposition. For the year ended December 31, 2010, NAL recognized $17.6 million as gains on disposition, compared to no gain recognized under previous CGAAP. A gain of $11.2 million was recognized for the three months ended March 31, 2010.

F) Asset Retirement Obligations and Accretion

Under previous CGAAP, the asset retirement obligations were measured at the estimated fair value of the expenditures expected to be incurred. Liabilities were not remeasured to reflect period end discount rates.

Under IFRS, the asset retirement obligation is measured as the best estimate of the expenditure to be incurred and requires the liability to be remeasured using the period end discount rate.

As NAL elected the oil and gas assets IFRS1 exemption, the ARO exemption available to full cost entities was also elected. This exemption allows for the remeasurement of ARO on IFRS transition with the offset to retained earnings. The carrying value under previous CGAAP at December 31, 2009 of $127.9 million was revalued under IFRS, resulting in an opening IFRS balance at January 1, 2010 of $134.4 million. On transition to IFRS, NAL recorded the difference of $6.5 million as an increase to the liability with an offset to retained earnings. At December 31, 2010, the liability was increased by $4.3 million. The adjustments primarily reflect the remeasurement of the obligation using an 8% discount rate at both dates.

In addition, accretion of the liability is impacted by the change in the recognized amount. For the year ended December 31, 2010, accretion decreased by $1.1 million as compared to previous CGAAP.

G) Other Liabilities and Accounts Payable

The adjustment to the liability for share-based compensation is to reflect a forfeiture rate which was not included under previous CGAAP. On transition to IFRS, the payable was reduced by $0.7 million to reflect the inclusion of a forfeiture rate. For the full year 2010, the expense for share-based compensation increased by $1.5 million due to the expensing of amounts capitalized under previous CGAAP, offset slightly by the inclusion of a forfeiture rate.

H) Convertible Debentures

As a trust, NAL designated its convertible debentures as a financial liability at fair value through profit or loss on transition. As at January 1, 2010, the fair value of the Corporation's convertible debentures was $203.7 million, based on quoted market prices. Under previous CGAAP, the convertible debentures were bifurcated between debt and equity in the amounts of $178.0 million and $12.6 million, respectively at December 31, 2009. The difference between the fair value and CGAAP carrying value was charged to retained earnings on transition.

At each quarter end, the convertible debentures were fair valued based on the then prevailing market price with the adjustment taken to income. Any accretion expense previously recognized through income under previous CGAAP was eliminated. On conversion to a corporation, on December 31, 2010, the convertible debentures carrying value, which represented the fair value on December 31, 2010, was bifurcated between their debt and equity components, as required under IFRS.

On December 31, 2010, the fair value of the convertible debentures was $204.5 million, which following the corporate conversion was allocated $5.0 million to equity and $199.5 million to debt.

In addition, for the period the convertible debentures were held at fair value through profit and loss any issue costs associated with the convertible debentures were expensed, of which $0.3 million was expensed in 2010. Under previous CGAAP these issue costs were netted against the debt component of the convertible debentures.

I) Minority Interest

The mandatory exception under IFRS1 allows for the prospective application in the accounting for a minority interest.

Therefore, the minority interest has only been adjusted under IFRS to reflect the changes to the income statement and net assets of the jointly owned Partnership with MFC (Note 4) as compared to previous CGAAP.

Under IFRS, minority interests are presented as part of equity rather than a liability as under previous CGAAP.

J) Deferred Taxes

Under IFRS, NAL is required to record deferred taxes at the Trust level at 39 percent, being the tax rate applicable to the undistributed profit of the Trust. Therefore, while a trust, the tax rate was significantly higher under IFRS compared to previous CGAAP, as under previous CGAAP the rate used represented the anticipated rate at time of the temporary difference reversal. On conversion to a corporation, corporate tax rates apply, which resulted in a decrease to previously recorded deferred tax amounts under IFRS at the trust level. Deferred taxes have also been adjusted to reflect the tax effect arising from the difference between IFRS and previous CGAAP as noted above. In addition, the deferred tax impact to share issue costs has been reflected.

Under IFRS, all deferred tax is presented as a long-term asset or liability. Under previous CGAAP, future income tax presentation was based on the presentation of the underlying asset or liability.

K) Other Exemptions

Business combinations

NAL elected the exemption not to restate business combinations, prior to January 1, 2010, in accordance with IFRS. There were no adjustments required to business combinations prior to January 1, 2010.

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