NAL Oil & Gas Trust reports fourth quarter and full year 2006 results



    CALGARY, March 2 /CNW/ - NAL Oil & Gas Trust (TSX: NAE.UN) ("NAL" or the
"Trust") today announced its financial and operational results for the fourth
quarter and year ended December 31, 2006. All amounts are in Canadian dollars
unless otherwise stated.

    
    HIGHLIGHTS

    -  In 2006, NAL delivered operating and financial performance that met or
       exceeded expectations. Production volume was within guidance, cash
       flow met expectations, netbacks were above industry average and NAL's
       overall cost structure was lower than 2005 levels. NAL retained a
       sound balance sheet, completed a restructuring of its management
       contract and the capital spending program created positive momentum
       going into 2007.

    -  Production averaged 19,444 barrels of oil equivalent per day in 2006,
       up 2.2 percent from 19,018 in 2005 and within the range of guidance
       (19,200 to 19,800) provided in January 2006. This production level
       represents the highest annual rate in NAL's eleven-year history.
       Production volume mix remained relatively constant at 48 percent crude
       oil, 10 percent natural gas liquids and 42 percent natural gas.

    -  NAL benefited from a five percent increase in year-over-year oil
       prices in 2006, but these higher oil prices were not sufficient to
       offset a 23 percent decrease in natural gas prices. On a barrel of oil
       equivalent basis, realized prices were seven percent lower at $53.98
       per boe in 2006 compared to $58.07 per boe in 2005.

    -  Revenue and funds from operations were relatively unchanged in 2006
       compared to 2005 as higher production volumes largely offset lower
       commodity prices. On a per unit basis, funds from operations were
       lower at $2.88 versus $3.17 due to an increase in the weighted average
       number of units outstanding during the year. During 2006, the Trust
       issued 2.4 million units under its Distribution Reinvestment Program
       (DRIP), raising $41.1 million in new equity at an average price of
       $17.25 per unit, and issued 1.6 million units to an affiliate of the
       Manager at $18.84 per unit as part of the restructuring of the
       management contract.

    -  Net income for full year 2006 was $60.2 million compared to $98.5
       million a year earlier. Excluding a $27.2 million one-time charge
       associated with the management contract restructuring, net income was
       $87.4 million, down eleven percent from a year earlier.

    -  NAL's operating cost for the full year 2006 was $8.31 per boe and came
       in at the low end of the 2006 guidance range due to active cost
       management in a period of rising costs. Similarly, our G&A at $1.54
       per boe was below guidance levels. In addition, as a result of
       management contract restructuring, management fees fell from $1.43 per
       boe in 2005 to $0.19 per boe in 2006 and there will be no management
       fees payable in the future. Operating costs, G&A and management fees
       totaled $10.04 per boe in aggregate in 2006, seven percent lower than
       the $10.79 per boe incurred in 2005. NAL's operating netback was
       $34.40 per boe, including a $0.48 per boe hedging gain.

    -  As to capital expenditures, the Trust spent $124 million in 2006.
       Drilling, completion and production equipment totaled $88 million,
       which contributed to NAL's positive production performance. The Trust
       replaced 3,200 boe per day of production at $27,500 per flowing
       barrel. In addition, NAL invested $25 million in plant, facilities,
       seismic and core area land purchases to add future production and
       reserves, the most significant being the Lacombe/Clive Horseshoe
       Canyon coalbed methane ("CBM") project.

    -  NAL did not make a significant asset or corporate acquisition in 2006,
       so its capital was focused on the conversion of existing reserves and
       positioning for future growth. NAL's three-year average finding,
       development and acquisition cost ("FD&A") per boe, which includes the
       acquisition of Addison Energy Inc. in 2005, was $21.41 proved or
       $18.59 proved plus probable.

    -  NAL ended the year with $223.1 million in net bank debt representing a
       multiple of approximately one times debt-to-funds from operations.
       NAL's solid balance sheet positions the Trust to take advantage of
       acquisition opportunities as they arise.

    -  Regarding tax pools, NAL increased tax pool balances by 25 percent,
       ending 2006 at $495 million vs. $395 million a year earlier.

    -  At the end of 2006, NAL added two experienced members to its senior
       management team who are expected to contribute significantly to our
       future plans. Marlon McDougall joined NAL on December 4, 2006 as Vice
       President of Operations and Keith A. Steeves joined NAL on
       December 11, 2006 as Vice President of Finance. Keith will assume the
       CFO's responsibility at the end of March 2007 when Ross Liland retires
       from NAL.

    OUTLOOK

    -  Moving into 2007, NAL has strong momentum with new production being
       tied-in as follow-on to 2006 capital spending. NAL's outlook for the
       year remains consistent with its guidance announced in December 2006
       and January 2007 with production and cost measures trending towards
       the mid-range.

                                2007 Guidance

             -----------------------------------------------------
              Average total production (boe/d)    18,500 - 19,000
              Capital expenditures                   $106 million
              Operating costs ($/boe)                 8.90 - 9.40
              G&A ($/boe)(1)                          1.75 - 1.95
             -----------------------------------------------------
              (1) Excluding unit-based compensation expense.

    -  As to our future direction, NAL will continue to build on its strong
       historical performance and focus on creating sustainable value through
       the efficient exploitation of its asset base supplemented by
       acquisitions, which add value and deliver future potential. Andrew
       Wiswell, President and CEO summarized the way forward:

       "Our key priorities include delivering targeted production,
       maintaining our very competitive cost structure, improving our capital
       efficiency, and sustaining our industry-recognized safety and
       environmental performance. To deliver these priorities and continue to
       move towards a sustainable model, we will add opportunities through
       the drill bit, partnering and acquisitions, set distributions which
       are responsive to commodity prices, retain a balance sheet which
       allows us to capture opportunities and build a higher tax pool base
       which will serve our unitholders well in the future in any business
       structure."


    SENSITIVITY ANALYSIS

    The estimated impact of changes to commodity prices, production levels,
exchange rates and interest rates on estimated 2007 funds from operations are
summarized below, excluding any effects of hedging.

    -------------------------------------------------------------------------
                                                Funds From Operations
                                      ---------------------------------------
                                                         Amount
    Assumptions                             Change       ($000s)    Per Unit
    -------------------------------------------------------------------------

    Commodity Prices
      WTI oil (US$/bbl)                      $1.00       $2,900        $0.04
      AECO natural gas (Cdn$/Mcf)            $0.50       $7,300        $0.09
    -------------------------------------------------------------------------

    Volume Changes
      Oil                                100 bbl/d       $1,400        $0.02
      Natural gas                      1,000 Mcf/d       $1,800        $0.02
    -------------------------------------------------------------------------

    Exchange Rate
      Cdn$/US$                               $0.01       $1,600        $0.02
    -------------------------------------------------------------------------

    Interest Rate
      Bank prime lending rate                  1.0%      $2,500        $0.03
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    At 8:30 a.m. MST (10:30 a.m. EST) on Friday, March 2, 2007 NAL will hold
    a conference call to discuss its fourth quarter and year-end results.
    Mr. Andrew Wiswell, President and CEO, will host the conference call with
    other members of the Management Team. The call is open to analysts,
    investors, and all interested parties. If you wish to participate, call
    403-398-9531 within the Calgary area or 1-800-733-7571, toll-free across
    North America. The conference will also be accessible by webcast at
    http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=
    1725680.

    A recorded playback of the call will be available until March 9, 2007 by
    dialing 416-640-1917 or 1-877-289-8525, reservation 21218454 followed by
    the number sign.
    -------------------------------------------------------------------------

    When converting natural gas to equivalent barrels of oil (boe) within
    this report, NAL uses the widely recognized standard of 6 thousand cubic
    feet (Mcf) of natural gas to one barrel of oil (bbl). However, boe's may
    be misleading, particularly if used in isolation. A boe conversion ratio
    of 6 Mcf : 1 bbl 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
    (thousands of dollars, except per unit and boe data)
    -------------------------------------------------------------------------
                                          Three Months                  Year
                                     Ended December 31     Ended December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    FINANCIAL

    Gross revenue, net of
     royalties                      $75,694    $95,643   $310,752   $314,006

    Net income (loss)                20,472     30,777   60,198(1)    98,538

    Funds from operations            55,795     65,837    219,776    221,649

    Distributions declared           39,663     41,956    169,589    142,050

    Funds from operations
     per unit                          0.72       0.90       2.88       3.17

    Distributions declared
     per unit                          0.51       0.57       2.22       2.01

    Payout ratio                         71%        64%        77%        64%

    Average number of units
     outstanding (000s)              77,697     73,436     76,350     69,946

    Total assets                   $796,902   $834,883   $796,902   $834,883
    Bank debt, net of working
     capital                        223,061    198,351    223,061    198,351
    Unitholders' equity             456,500    494,490    456,500    494,490

    Costs per boe ($/boe - 6:1):
      Operating                       $7.13      $9.41      $8.31      $8.02
      General and administrative       1.33       1.62       1.54       1.34
      Unit-based incentive
       compensation                   (0.07)      0.33       0.35       0.20
      Management fees                     -       2.27       0.19       1.43

    OPERATING

    Daily production
      Oil (bbl)                       9,700      9,755      9,367      9,399
      Natural gas (Mcf)              47,153     52,340     48,804     46,512
      Natural gas liquids (bbl)       1,958      2,036      1,944      1,867
      Oil equivalent (boe - 6:1)     19,517     20,514     19,444     19,018

    Average pricing, net of
     transportation charges
     and before hedging gains
     and losses
      Liquids:
        WTI (US$/bbl)                 60.21      60.02      66.22      56.56
        NAL average oil (Cdn$/bbl)    58.53      62.16      65.30      62.33
        NAL natural gas liquids
         (Cdn$/bbl)                   43.24      56.29      48.70      49.51

      Natural gas:
        AECO (Cdn$/Mcf)
         - daily spot                  6.90      11.43       6.56       8.77
        AECO (Cdn$/Mcf) - monthly      6.36      11.84       6.98       8.38
        NAL natural gas Western
         Canada (Cdn$/Mcf)             6.84      11.68       6.98       8.97
        NAL natural gas Lake Erie
         (Cdn$/Mcf)                    8.16      14.36       8.09      11.06
        NAL average natural gas
         (Cdn$/Mcf)                    6.96      11.91       7.03       9.16

      NAL oil equivalent
       (Cdn$/boe - 6:1)               49.77      65.52      53.98      58.07

    Average foreign exchange
     rate (Cdn$/US$)                  1.139      1.173      1.134      1.211

    Operating netback before
     hedging gains (losses)
     ($/boe)                          32.48      42.21      33.92      37.49
    Hedging gains (losses)
     ($/boe)                           1.00      (2.37)      0.48      (1.56)
    Operating netback ($/boe)         33.48      39.84      34.40      35.93
    -------------------------------------------------------------------------
    (1) Includes one-time $27.2 million non-cash management contract
        restructuring charge.


    OIL AND GAS RESERVES

    NAL's 2006 year-end reserves were evaluated by McDaniel & Associates
Consultants Ltd. ("McDaniels"), independent engineering consultants in
Calgary, in accordance with National Instrument ("NI") 51-101. At December 31,
2006, the Trust's proved reserves total 40.8 million barrels of oil
equivalent("boe") and proved plus probable ("P+P") reserves amount to 58.2
million boe.
    NAL has a reserves committee, composed entirely of independent directors,
which is responsible for appointing the Trust's independent engineering
consultants and determining the scope of the annual reserves review.

    Some key points regarding NAL's 2006 reserves summary are:

    -  Overall technical revisions were highly positive for Proved reserves
       (+2,588 Mboe) and essentially neutral for P+P reserves (-19 Mboe).
       This demonstrates that our reserves bookings are consistent with
       NI 51-101 guidelines, where the ultimate Proved reserves are a
       conservative estimate, which should increase over time while the
       ultimate P+P reserves represent the best estimate which, in aggregate,
       should have an equal likelihood of being higher or lower than the
       initial estimate.

    -  Additions for Improved Recovery amounted to 1,778 Mboe of P+P
       reserves, representing new reserves added from drilling and other
       development activities over and above the volumes that were previously
       booked. The majority of the capital spending each year is directed
       toward upgrading reserves from Probable to Proved or from Proved
       Undeveloped to Proved Producing, while a smaller portion of the
       capital spending targets new reserves additions.

    -  At December 31, 2006, over 94 percent of NAL's Proved reserves were in
       the Proved Producing category. NAL takes a conservative approach in
       booking undeveloped reserves in the Proved Undeveloped category.

    -  NAL continues to have a high quality asset base, with no heavy oil
       reserves. No reserves write-downs have been required or are
       anticipated as a result of lower commodity prices.

    The following tables summarize NAL's estimated reserves volumes and values
using McDaniels' price forecasts as of January 1, 2007. Gross reserves volumes
are based on the Trust's working interests before deduction of royalties
payable, and exclude any wells or properties in which NAL has only a royalty
interest. Net reserves represent the Trust's working interest reserves after
deducting royalties payable, plus royalty interest reserves.

    -------------------------------------------------------------------------
                       SUMMARY OF OIL AND GAS RESERVES
                           as of December 31, 2006
                          FORECAST PRICES AND COSTS
    -------------------------------------------------------------------------
                                                    RESERVES
                                         LIGHT AND              NATURAL
                                        MEDIUM OIL                GAS
                                      Gross        Net      Gross        Net
    RESERVES CATEGORY                 (Mbbl)     (Mbbl)     (MMcf)     (MMcf)

    PROVED
      Developed Producing            17,734     15,483     99,925     84,485
      Developed Non-Producing           145        129      5,811      5,118
      Undeveloped                       413        382      3,844      3,464
                                  -------------------------------------------
    TOTAL PROVED                     18,291     15,994    109,580     93,067
    PROBABLE                          8,203      7,244     43,046     36,361
                                  -------------------------------------------
    TOTAL PROVED PLUS PROBABLE       26,494     23,238    152,626    129,428
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                    RESERVES
                                        NATURAL GAS              TOTAL
                                          LIQUIDS              BOE (6:1)
                                      Gross        Net      Gross        Net
    RESERVES CATEGORY                 (Mbbl)     (Mbbl)     (Mbbl)     (Mbbl)

    PROVED
      Developed Producing             4,137      3,099     38,525     32,663
      Developed Non-Producing            84         66      1,197      1,048
      Undeveloped                        29         26      1,082        985
                                  -------------------------------------------
    TOTAL PROVED                      4,250      3,191     40,804     34,696
    PROBABLE                          2,032      1,511     17,410     14,815
                                  -------------------------------------------
    TOTAL PROVED PLUS PROBABLE        6,282      4,702     58,214     49,511
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
                  NET PRESENT VALUES OF FUTURE NET REVENUE
                          FORECAST PRICES AND COSTS
    -------------------------------------------------------------------------
                            BEFORE INCOME TAXES, DISCOUNTED AT (percent/year)

    RESERVES CATEGORY                0 %         5 %       10 %       15 %
                                (million $) (million $)(million $)(million $)

    PROVED
      Developed Producing             1,118        882        736        636
      Developed Non-Producing            34         27         23         20
      Undeveloped                        21         16         12          9
                                  -------------------------------------------
    TOTAL PROVED                      1,173        925        771        665
    PROBABLE                            560        352        247        186
                                  -------------------------------------------
    TOTAL PROVED PLUS PROBABLE        1,733      1,277      1,018        851
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The net present values shown are reported before income taxes. It should
    not be assumed that the estimated future net revenue is representative of
    the fair market value of the properties of the Trust. There is no
    assurance that such price and cost assumptions will be attained and
    variances could be material.



    -------------------------------------------------------------------------
              SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
                           as of December 31, 2006

                          FORECAST PRICES AND COSTS
    -------------------------------------------------------------------------
                                     OIL

                                    Edmonton    Cromer Medium    NATURAL GAS
                    WTI Cushing    Par Price    29.3 degrees      AECO Spot
                     Oklahoma   40 degrees API        API           Price
    Year             ($US/bbl)     ($Cdn/bbl)     ($Cdn/bbl)     ($Cdn/MMBtu)

    2007               62.50          70.80          62.20           7.22
    2008               61.20          69.30          60.90           7.43
    2009               59.80          67.70          59.40           7.80
    2010               58.40          66.10          58.00           7.91
    2011               56.80          64.20          56.40           8.12
    2012               58.00          65.60          57.60           8.33
    Thereafter(*)    +2%/year       +2%/year       +2%/year       +2%/year
    -------------------------------------------------------------------------


    --------------------------------------------------------
                   NATURAL GAS      INFLATION      EXCHANGE
                     LIQUIDS          RATES          RATE
                   EDMONTON MIX
    Year            ($Cdn/bbl)     Percent/Year    ($US/Cdn)

    2007               50.80            2.0          0.870
    2008               50.10            2.0          0.870
    2009               49.50            2.0          0.870
    2010               48.60            2.0          0.870
    2011               47.60            2.0          0.870
    2012               48.70            2.0          0.870
    Thereafter(*)    +2%/year           2.0          0.870
    --------------------------------------------------------
    (*) Price escalation rates are approximate.



                              RECONCILIATION OF
                           COMPANY GROSS RESERVES
                          BY PRINCIPAL PRODUCT TYPE

                          FORECAST PRICES AND COSTS
    -------------------------------------------------------------------------
                                                             ASSOCIATED AND
                                   LIGHT AND MEDIUM OIL    NON-ASSOCIATED GAS
    -------------------------------------------------------------------------
                                                Proved                Proved
                                                 Plus                  Plus
                                     Proved    Probable    Proved    Probable
    FACTORS                          (Mbbl)     (Mbbl)     (MMcf)     (MMcf)

    December 31, 2005                19,829     28,455    119,522    166,567

      Improved Recovery                 299      1,178      1,653      2,548
      Technical Revisions             1,530        192      6,168      1,252
      Acquisitions                      123        174         50         73
      Dispositions                      (71)       (86)         0          0
      Production                     (3,419)    (3,419)   (17,813)   (17,813)

    December 31, 2006                18,291     26,494    109,580    152,626
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                    NATURAL GAS LIQUIDS        TOTAL BOE
    -------------------------------------------------------------------------
                                                Proved                Proved
                                                 Plus                  Plus
                                     Proved    Probable    Proved    Probable
    FACTORS                          (Mbbl)     (Mbbl)     (Mboe)     (Mboe)

    December 31, 2005
                                      4,817      7,226     44,566     63,442
      Improved Recovery                 105        175        680      1,778
      Technical Revisions                30       (420)     2,588        (19)
      Acquisitions                        7         10        138        196
      Dispositions                        0          0        (71)       (86)
      Production                       (709)      (709)    (7,097)    (7,097)

    December 31, 2006                 4,250      6,282     40,804     58,214
    -------------------------------------------------------------------------
    

    FINDING AND DEVELOPMENT COSTS

    Finding and Development ("F&D") costs are reported below for Proved and
Proved plus Probable (P+P) reserves, in each case after eliminating the
effects of acquisitions and dispositions as per NI 51-101 guidelines. The
total reserves changes in the Improved Recovery and Technical Revisions
categories of the reconciliation table are used in the F&D calculation.
    The capital spending of $118.8 million used in the F&D calculation for
2006 represents the Trust's total expenditures for drilling, completion and
production equipment, plant and facility costs (including maintenance capital
items that supported our base production volumes and helped maintain our low
operating cost structure), plus seismic and land costs, capitalized G&A and
unit-based incentive costs. The F&D calculation also incorporates changes in
future development costs from the reserves report, as per NI 51-101
guidelines, as some of the changes in reserves estimates each year are a
result of changes in estimated future development capital.
    As shown in the table below, the F&D costs for 2006 were $29.59 per boe
for Proved and $57.95 per boe for P+P reserves. These numbers are higher than
previous years, in part, because capital costs for drilling and completions
increased during 2006 due to high levels of activity within the industry. The
total capital also includes purchases ($7.7 million) of undeveloped land that
has no immediate reserves impact during the year of acquisition but provides
additional drilling opportunities and positions the Trust for reserves
additions in future years. Additionally, a large investment was made in plants
and facilities in Saskatchewan and Central Alberta ($14.6 million), with the
most significant component relating to the coalbed methane development in
Lacombe area. Although these facility investments did not add reserves in
2006, their completion enables the remaining development of wells to occur at
a lower development cost. In addition, a few development projects in Westward
Ho area did not meet expectations for the primary drilling target and were
completed uphole, resulting in lower reserves additions than had been
anticipated.
    The P+P F&D cost for 2006 was particularly affected by a number of
adjustments that were made to Probable reserves and future capital cost
estimates. Minor revisions for base performance were made to the Probable
reserves category in a few properties, along with a reduction to the Probable
NGL reserves for certain former Addison properties to reflect lower estimated
NGL yields. If these performance revisions to the Probable reserves category
were excluded from the calculation, the P+P F&D cost would be more in line
with the Proved number. Additionally, the estimated future capital
requirements related to the development of Probable reserves for some
properties were increased, which had a significant effect on the P+P F&D
calculation for the current year but much less of an impact on the three-year
weighted average cost.
    The F&D calculation for 2006 and the three-year weighted average for 2004
to 2006 are summarized in the tables below. It should be noted that the
aggregate of the development costs incurred during the year and the change in
estimated future development costs generally will not reflect total finding
and development costs related to reserves additions for that year. As such,
the three-year weighted average, with changes tracked over time, is generally
a more useful indicator of capital effectiveness as it relates to reserves
development.
    The weighted average F&D costs for the three-year period from 2004
through 2006 was $23.81 per boe for Proved and $32.38 per boe for Proved plus
Probable reserves. These values reflect the fact that a significant portion of
the Trust's capital spending is directed toward development of reserves that
are booked in the Proved Undeveloped or Probable Undeveloped categories,
meaning that a successful development program results in a transfer of
reserves to the Developed category rather than an addition of new reserves.
The F&D calculation is also highly sensitive to changes in capital costs
relative to estimates used in the reserves report.
    A more representative measure of the Trust's overall capital spending
effectiveness is the three-year average Finding, Development and Acquisition
("FD&A") cost, as provided in the next section, as that metric considers the
effect of the acquisitions and dispositions made during that period.

    
    -------------------------------------------------------------------------
                                    2006
    -------------------------------------------------------------------------
                                                         Change in
                                                         Estimated
                                            Actual        Future
                                           Spending     Development
                                          During 2006      Costs      Total
                                         -------------  -----------  --------
    Capital (M$)      Proved                 118,791     (22,092)     96,699
                      Proved + Probable      118,791     (16,852)    101,939


                                             Improved    Technical
                                             Recovery    Revisions    Total
                                            ----------  -----------  --------
    Reserves (Mboe)   Proved                     680       2,588       3,268
                      Proved + Probable        1,778         (19)      1,759

    F&D ($/boe)       Proved                                          $29.59
                      Proved + Probable                               $57.95
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                           3-YEAR WEIGHTED AVERAGE
    -------------------------------------------------------------------------
                                                         Change in
                                                         Estimated
                                            Actual        Future
                                           Spending     Development
                                         Over 3 Years      Costs      Total
                                        --------------  -----------  --------
    Capital (M$)      Proved                 221,973     (22,538)    199,435
                      Proved + Probable      221,973       5,912     227,885


                                             Improved    Technical
                                             Recovery    Revisions    Total
                                            ----------  -----------  --------
    Reserves (Mboe)   Proved                   3,155       5,220       8,375
                      Proved + Probable        6,982          55       7,037

    F&D ($/boe)       Proved                                          $23.81
                      Proved + Probable                               $32.38
    -------------------------------------------------------------------------
    


    FINDING, DEVELOPMENT AND ACQUISITION COSTS

    A significant part of NAL's business activity in any given year is the
acquisition and, to a lesser degree, the disposition of properties. In order
to provide a more representative measure of the company's total capital
spending as it relates to reserves development, we report the Finding,
Development and Acquisition ("FD&A") costs, which include the effects of
acquisitions and dispositions.
    During 2006, the Trust completed a relatively small number of property
acquisitions and dispositions. The FD&A calculation incorporates all the
components used in the F&D calculation, plus the adjustments to capital
spending and reserves related to the acquisitions and disposition activities
completed during the year, as shown in the table below.
    The FD&A costs for 2006 were $29.35 per boe for Proved and $55.17 per boe
for Proved plus Probable reserves. These numbers are higher than previous
years for the reasons relating to F&D costs discussed earlier. The weighted
average FD&A costs for the three-year period from 2004 through 2006 were
$21.41 per boe for Proved and $18.59 per boe for Proved plus Probable
reserves. These three-year averages provide the most appropriate measure of
the Trust's overall capital spending effectiveness.

    
    -------------------------------------------------------------------------
                                    2006
    -------------------------------------------------------------------------
                                      Change in
                            Actual    Estimated
                           Spending    Future                         Total
                            During   Development  Acquis-  Dispos-  Including
                             2006       Costs     itions   itions      A&D
                           --------- ----------- -------- --------- ---------
    Capital (M$)  Proved     118,791   (22,092)    3,111    (1,940)   97,870
                  Proved +
                   Probable  118,791   (16,852)    3,111    (1,940)  103,110


                                                                      Total
                            Improved  Technical   Acquis-  Dispos-  Including
                            Recovery  Revisions   itions   itions      A&D
                           --------- ----------- -------- --------- ---------
    Reserves      Proved         680     2,588       138       (71)    3,335
    (Mboe)        Proved +
                   Probable    1,778       (19)      196       (86)    1,869

    FD&A ($/boe)  Proved                                              $29.35
                  Proved +
                   Probable                                           $55.17
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                           3-YEAR WEIGHTED AVERAGE
    -------------------------------------------------------------------------
                                      Change in
                            Actual    Estimated
                           Spending    Future                         Total
                             Over    Development  Acquis-  Dispos-  Including
                            3 Years     Costs     itions   itions      A&D
                           --------- ----------- -------- --------- ---------
    Capital (M$)  Proved     242,434     9,082   388,456    (8,141)  631,831
                  Proved +
                   Probable  242,434    48,256   388,456    (8,141)  671,005


                                                                      Total
                            Improved  Technical   Acquis-  Dispos-  Including
                            Recovery  Revisions   itions   itions      A&D
                           --------- ----------- -------- --------- ---------
    Reserves      Proved       3,155     4,629    22,077      (349)   29,512
    (Mboe)        Proved +
                   Probable    6,982       276    29,324      (486)   36,096

    FD&A ($/boe)  Proved                                              $21.41
                  Proved +
                   Probable                                           $18.59
    -------------------------------------------------------------------------
    


    RESERVE LIFE INDEX

    Reserve Life Index ("RLI") is calculated by dividing reserves at
December 31, 2006 by expected annual production for 2007. RLI is useful in
making comparisons between companies but does not accurately represent the
anticipated life of the Trust's reserves. Due to the natural decline of oil
and gas production, the actual producing life of oil and gas properties is
much longer than the RLI calculation would suggest.
    NAL has issued a production guidance range of 18,500 - 19,000 boe per day
for 2007. Using the mid-point of that range - or 18,750 boe per day - NAL's
RLI at December 31, 2006 was 8.5 years for Proved plus Probable reserves, down
slightly from 8.9 years at year-end 2005.

    LAND AND SEISMIC

    At December 31, 2006 NAL owned an average 31.5 percent working interest
in 654,371 gross acres (205,916 net acres) of undeveloped land. Included in
these figures is a large block of non-operated lands in Lake Erie, Ontario in
which the Trust has an average 20.1 percent working interest. Most of NAL's
land is owned in partnership with Manulife Financial, so in total NAL operates
over 80 percent of its production and prospective acreage. Based on an
internal estimate, NAL's undeveloped land and seismic value is approximately
$47.8 million.

    NET ASSET VALUE

    The following net asset value calculations are based on what is generally
referred to as the "produce-out" net present values of the Trust's oil and gas
reserves as evaluated by independent engineering consultants in accordance
with National Instrument 51-101.

    
    -------------------------------------------------------------------------
                                    December 31, 2006     December 31, 2005
    -------------------------------------------------------------------------
                                   Forecast   Constant   Forecast   Constant
    ($000s, except per unit data)  Prices(3)  Prices(4)    Prices     Prices
    -------------------------------------------------------------------------

    Proved plus probable reserves
     (discounted at 10%)          1,017,713    897,171  1,062,520  1,290,508
    Undeveloped land and
     seismic(1)                      47,800     47,800     42,200     42,200
    Working capital (deficiency)     (2,276)    (2,276)    26,066     26,066
    Long-term debt                 (221,790)  (221,790)  (220,519)  (220,519)
    Asset retirement
     obligation(2)                  (34,191)   (37,793)   (31,059)   (35,546)
                                  -------------------------------------------

    Net asset value                 807,256    683,112    879,208  1,102,709
                                  -------------------------------------------

    Units outstanding (000s)         77,971     77,971     73,977     73,977
    NAV per unit                     $10.35      $8.76     $11.88     $14.91
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Internal estimate.
    (2) The Asset Retirement Obligation ("ARO") is calculated based on the
        same methodology that was used to calculate the ARO on NAL's year-end
        financial statements, with the exception that future expected ARO
        costs were discounted at 10 percent. The total discounted ARO of
        $54.0 million and $50.7 million at the respective balance sheets was
        reduced by $19.8 million and $19.6 million under the forecast price
        cases and $16.2 million and $15.1 million under the constant price
        cases, respectively, relating to well abandonment costs that were
        incorporated in the Value of Proved Plus Probable reserves discounted
        at 10 percent pursuant to the forecast and constant price cases
        included in the Trust's oil and gas reserve evaluations.
    (3) McDaniel's price forecasts as of January 1, 2007, reflecting WTI
        US$62.50 and AECO Cdn$7.22 for 2007 trending to WTI US$56.80 and AECO
        Cdn$8.12 in 2011, with a US$/Cdn$ exchange rate of $0.87 over the
        five years.
    (4) Based on December 31, 2006 closing prices as published by McDaniel &
        Associates Consultants Ltd.
    


    MANAGEMENT'S DISCUSSION AND ANALYSIS

    The following discussion and analysis ("MD&A") should be read in
conjunction with the interim consolidated financial statements for the three-
month period ended December 31, 2006 and the audited consolidated financial
statements and MD&A for the years ended December 31, 2006 and December 31,
2005 of NAL Oil & Gas Trust ("NAL" or the "Trust"). It contains information
and opinions on the Trust'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.
    Operating netbacks, cash flow netbacks and funds from operations are not
recognized measures under Canadian generally accepted accounting principles
("GAAP"). Management believes that in addition to net income, operating
netbacks, cash flow netbacks, funds from operations and funds from operations
per unit are useful supplemental measures as they provide an indication of the
results generated by the Trust's principal business activities prior to the
consideration of how those activities are financed. Investors should be
cautioned, however, that these measures should not be construed as an
alternative to net income determined in accordance with GAAP 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. NAL
calculates funds from operations prior to the change in non-cash working
capital related to operating activities, with the per unit amount calculated
using the weighted average units outstanding for the period.

    FORWARD-LOOKING INFORMATION

    This disclosure contains certain forward-looking statements that involve
substantial known and unknown risks and uncertainties, many of which are
beyond NAL's control, including: the impact of general economic conditions in
Canada and in the United States, industry conditions, changes in laws and
regulations including the adoption of new environmental laws and regulations
and changes in how they are interpreted and enforced, increased competition,
the lack of availability of qualified operating or management personnel,
fluctuations in commodity prices, foreign exchange or interest rates, stock
market volatility and fluctuations in market valuations of companies with
respect to announced transactions and the final valuations thereof, and the
ability to obtain required approvals from regulatory authorities. NAL's actual
results, performance or achievement could differ materially from those
expressed in, or implied by, these forward-looking statements and,
accordingly, no assurances can be given that any of the events anticipated by
the forward-looking statements will transpire or occur, or if any of them do
so, what benefits, including the amount of proceeds, that NAL will derive
therefrom.

    DEVELOPMENT ACTIVITIES

    Consistent with our plans, the Trust had an active development program
during the fourth quarter across all of its core areas. At the end of the
fourth quarter, two drilling rigs were still active.
    The Trust participated in the drilling of 49 (28.36 net) wells during the
fourth quarter of 2006 with a success rate of 100 percent. During this period,
the Trust operated 45 (27.65 net) of the wells drilled.

    
                      Fourth Quarter Drilling Activity

    -------------------------------------------------------------------------
                                          Service       Dry &
               Crude Oil   Natural Gas     Wells      Abandoned      Total
              ---------------------------------------------------------------
              Gross   Net  Gross   Net  Gross   Net  Gross   Net  Gross   Net
    -------------------------------------------------------------------------
    Operated
     wells      15   7.89    30  19.76     -      -     -      -    45  27.65
    Non-
     operated
     wells       3   0.40     1   0.31     -      -     -      -     4   0.71
    -------------------------------------------------------------------------
    Total
     wells
     drilled    18   8.29    31  20.07     -      -     -      -    49  28.36
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Southeast Saskatchewan Core Area
    --------------------------------
    With two drilling rigs contracted exclusively for drilling in Southeast
Saskatchewan, this area had an active and successful fourth quarter. A total
of 12 (5.5 net) wells were drilled.
    At Elswick new production facilities were commissioned, providing a
significant addition to our capacity for processing oil and water, which was
required as a result of drilling success earlier in the year. At Nottingham,
one gross (0.33 net); Alida, two gross (0.9 net); Browning, one gross (0.5
net); Star Valley, three gross (1.5 net); Weyburn, three gross (1.5 net);
Midale, one gross (0.5 net); and Midale non-operated, one gross (0.27 net)
horizontal oil producers were drilled.

    Central Alberta Core Area
    -------------------------
    Drilling and recompletion activity during the fourth quarter included
three (1.0 net) Edmonton Sand drills plus two (1.5 net) Mannville and Elkton
recompletions but the majority of activity focused on the behind pipe tie-in
of production identified in the third quarter. This activity included the
construction of a gathering system in the Westward Ho area to increase
capacity for a high rate Viking recompletion (150 bbls/d net) as well as
gathering systems to bring on a number of successful Edmonton Sand completions
in the Sylvan Lake area.

    Gas Focused Core Area
    ---------------------
    NAL's Gas Focused Area is comprised of a majority of the Trust's
properties that exist outside NAL's two geographic core areas - Southeast
Saskatchewan and Central Alberta - and includes Nevis/Lacombe, Brent/Hanna,
Pine Creek, Surmount/Hangingstone and Lake Erie. Although geographically
diverse, these properties are strategically characterized by a focused land
position, a high working interest and future potential concentrated on natural
gas.
    At Hanna, the Trust tied-in 16 (14.73 net) Second White Specks wells in
the fourth quarter. One remaining Second White Specks well (0.93 net) is
expected to be tied-in during the first quarter of 2007. Also, one (1.0 net)
Banff well was tied-in and one (1.0 net) Colony well was drilled and tied-in
during the fourth quarter of 2006. At Brent, one (1.0 net) well was drilled
and is expected to be tied-in during the first quarter of 2007.
    At Lacombe/Clive, 26 (16.8 net) wells were drilled out of a 39-well
program targeting gas from the Horseshoe Canyon Coals. At Lacombe, completions
and construction of the gathering/sales lines commenced in the fourth quarter
but weather and regulatory delays pushed the startup of the project to the
first quarter of 2007. At Clive, four (2.8 net) wells were tied-in during the
fourth quarter. Along with the coalbed methane wells, one (0.7 net) Viking
well will be tied-in during the first quarter of 2007.
    At Wilson Creek, four (2.8 net) Belly River wells were drilled in the
fourth quarter. One well was tied-in during the last quarter of 2006 and the
remaining three were tied-in during the first quarter of 2007. At Willesden
Green, one (0.26 net) well drilled in the fourth quarter is expected to be
tied-in during the first quarter of 2007.
    For the full year, the Trust drilled a total of 191 gross wells (87.55
net) in 2006 with an overall success rate of 98.5 percent.

    
    -------------------------------------------------------------------------
                                          Service       Dry &
               Crude Oil   Natural Gas     Wells      Abandoned      Total
              ---------------------------------------------------------------
              Gross   Net  Gross   Net  Gross   Net  Gross   Net  Gross   Net
    -------------------------------------------------------------------------
    Total
     wells
     drilled    71   27.7   110  57.21     7      2     3   0.64   191  87.55
    -------------------------------------------------------------------------

    CAPITAL EXPENDITURES

    Capital expenditures for the quarter ended December 31, 2006 totaled $34.8
million compared with $26.2 million in the quarter ended December 31, 2005.
For the year ended December 31, 2006 capital expenditures totaled $124.0
million as compared to $73.1 million in the same period in 2005.

                        Capital Expenditures ($000s)

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Drilling, completion and
     production equipment            25,619     20,718     87,901     57,105
    Plant and facilities              4,715      4,039     14,598      8,474
    Seismic                             404      1,072      2,628      2,691
    Land                              2,243        766      7,730      1,205
    Property acquisitions
     (dispositions)                      40     (1,564)     1,171     (1,564)
    -------------------------------------------------------------------------
    Total exploitation and
     development                     33,021     25,031    114,028     67,911
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Office equipment(1)                 772         --      4,080         --
    Capitalized G&A                   1,290        968      4,275      4,537
    Capitalized unit-based
     compensation                      (295)       165      1,659        651
    -------------------------------------------------------------------------
                                      1,767      1,133     10,014      5,188
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total capital expenditures       34,788     26,164    124,042     73,099
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes $2.8 million in assets acquired as part of the management
        agreement restructuring.

    A record $87.9 million was spent in 2006 on drilling, completions and
tie-ins. Although industry costs for development activities were up
substantially in 2006, the Trust participated in a record 87.55 net wells (191
gross wells). The Trust also spent $14.6 million on plant and facilities in
2006, up from $8.5 million a year earlier. This increased level of spending
focused on new Lacombe compression facilities, as well as substantial upgrades
to water handling and storage facilities supporting our Saskatchewan
operations, all of which will support future production.
    NAL made meaningful investments in land and seismic in 2006, focusing on
enhancing the Trust's core areas. Of the $7.7 million spent on land, major
expenditures in the Elswick area of Saskatchewan as well as in Hanna and
Garrington/Westward Ho in Alberta were made. Together with purchases in
Lacombe, Sylvan Lake, Huntoon, and Alida, these investments are focused on
drilling opportunities planned for 2007 and 2008.

    PRODUCTION

    Trust production averaged 19,517 boe/d for the three months ended December
31, 2006, five percent lower than the 20,514 boe/d for the comparable period
in 2005. For the year ended December 31, 2006, production averaged 19,444
boe/d, a two percent increase over 19,018 boe/d a year earlier.

                      Average Daily Production Volumes

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Oil (bbl/d)                       9,700      9,755      9,367      9,399
    Natural gas (Mcf/d)              47,153     52,340     48,804     46,512
    NGL's (bbl/d)                     1,958      2,036      1,944      1,867
    Oil equivalent (boe/d)           19,517     20,514     19,444     19,018
    -------------------------------------------------------------------------

    For the year ended December 31, 2006, the Trust's production weighting was
relatively unchanged from the comparable period in 2005 with oil and natural
gas liquids production representing 58 percent and natural gas 42 percent.

                            Production Weighting

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Oil                                  50%        48%        48%        49%
    Natural gas                          40%        43%        42%        41%
    NGLs                                 10%         9%        10%        10%
    -------------------------------------------------------------------------

    REVENUE AND FUNDS FROM OPERATIONS

    Gross revenue from oil, natural gas and natural gas liquids sales, after
transportation costs and hedging gains, totaled $91.2 million for the three
months ended December 31, 2006, 24 percent lower than the fourth quarter of
2005.
    Revenue decreased year-over-year due to lower production volumes and lower
natural gas prices. Compared to the fourth quarter of 2005, production in the
fourth quarter of 2006 decreased five percent and average commodity prices,
after hedging, decreased by 20 percent.
    For the twelve-month period ended December 31, 2006 gross revenue totaled
$386.5 million, a decrease of one percent from the comparable period in 2005.
This decrease is attributable to a four percent decrease in NAL oil equivalent
pricing after hedging, offset by a two percent increase in production.
    Funds from operations tracked revenues in the fourth quarter of 2006, down
15 percent in total from the fourth quarter 2005 and down 20 percent from
$0.90 to $0.72, on a per unit basis. For the year ended December 31, 2006,
total funds from operations were down one percent and down nine percent on a
per unit basis to $2.88 from $3.17 for 2005.

                      Revenue and Funds From Operations

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Revenue(1) ($000s)               91,172    119,208    386,452    392,244
    $/boe                             50.78      63.16      54.45      56.51
    Funds from operations(2)
     ($000s)                         55,795     65,837    219,776    221,649
    $/boe                             31.07      34.88      30.97      31.93
    $/unit                             0.72       0.90       2.88       3.17
    -------------------------------------------------------------------------
    (1) Oil, natural gas and liquids sales less transportation and after
        hedging.
    (2) Represents cash flow from operating activities prior to the change in
        non-cash working capital items.


                               Average Pricing
                       (net of transportation charges)

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Liquids:
      WTI (US$/bbl)                   60.21      60.02      66.22      56.56
      NAL average oil (Cdn$/bbl)      58.53      62.16      65.30      62.33
      NAL natural gas liquids
       (Cdn$/bbl)                     43.24      56.29      48.70      49.51
      Hedging gains (losses)           1.31      (2.63)      0.33      (2.18)
    Natural Gas (Cdn$/Mcf):
      AECO - daily spot                6.90      11.43       6.56       8.77
      AECO - monthly                   6.36      11.84       6.98       8.38
      NAL Western Canada natural
       gas (Cdn$/Mcf)                  6.84      11.68       6.98       8.97
      NAL Lake Erie natural gas
       (Cdn$/Mcf)                      8.16      14.36       8.09      11.06
      NAL average natural gas          6.96      11.91       7.03       9.16
      Hedging gains (losses)           0.14      (0.44)      0.13      (0.20)
    NAL Oil Equivalent before
     hedging (Cdn$/boe - 6:1)         49.77      65.52      53.98      58.07

    Average Foreign Exchange Rate
     (Cdn$/US$)                       1.139      1.173      1.134      1.211
    -------------------------------------------------------------------------
    

    OIL MARKETING

    NAL sells its crude oil based on refiners' posted prices at Edmonton,
Alberta and Cromer, Manitoba adjusted for transportation and quality of crude
oil at each field battery. The refiners' posted prices are influenced by the
West Texas Intermediate ("WTI") benchmark price, transportation costs,
exchange rates and the supply/demand situation of particular crude oil quality
streams during the year.
    NAL's average crude oil price per barrel, net of transportation costs,
was $58.53 for the fourth quarter of 2006, as compared to $62.16 for the
comparable quarter in 2005. This decrease of six percent is attributable to a
three percent wider differential between WTI and Edmonton posted prices and a
three percent decrease in the Cdn$/US$ exchange rate.
    For the year ended December 31, 2006, NAL's average oil price was
$65.30/bbl as compared to $62.33/bbl in 2005, an increase of five percent.
This increase was attributable to a 17 percent increase in WTI, offset by a
six percent decrease in the Cdn$/US$ exchange rate and a lower market
differential.
    Natural gas liquids prices averaged $43.24/bbl in the fourth quarter,
less than the $56.29 realized in the fourth quarter of 2005. For the twelve-
month period ending December 31, natural gas liquids pricing averaged
$48.70/bbl, two percent lower than the $49.51 realized in the comparable
period in 2005. Pricing for natural gas liquids is linked to crude oil pricing
with some seasonal impacts.

    NATURAL GAS MARKETING

    Approximately 92 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 eight percent tied to NYMEX or other indexed
referenced prices. Eight percent of the Trust's natural gas sales is produced
from its Lake Erie property and receives a higher price due to close proximity
to the Ontario and northeastern U.S. markets.
    For the three months ended December 31, 2006, the Trust's gas sales
averaged $6.96/Mcf as compared to $11.91 for the comparable quarter in 2005, a
decrease of 42 percent. The quarter-over-quarter decrease in gas prices was
attributable to the 40 percent decrease in the benchmark AECO price. Natural
gas sales from the Lake Erie property averaged $8.16/Mcf in the fourth quarter
of 2006, compared to $14.36/Mcf in 2005, a decrease of 43 percent.
    For the year ended December 31, 2006, NAL's average gas price was
$7.03/Mcf as compared to $9.16/Mcf in 2005, a decrease of 23 percent. The 23
percent decrease in the year-to-date average gas price compares to a 25
percent decrease in the AECO daily spot price, year-over-year. This lower
decrease is due to the higher price realized from Lake Erie gas sales and also
from marketing a portion of our gas on a monthly basis. During 2006, the AECO
monthly price exceeded the daily spot price by an average of six percent, with
the majority of the differential occurring in the first quarter.

    RISK MANAGEMENT

    NAL employs risk management practices to assist in managing cash flows
and support capital programs and distributions. NAL's management is authorized
to hedge up to 50 percent of its annual net production. NAL's hedging programs
tend to be scaled-in over time using a combination of swaps and collars.
During the fourth quarter of 2006, NAL had several financial WTI oil contracts
and AECO natural gas contracts in place, which are described below.
    For the oil contracts, settlements are made monthly based on the average
monthly WTI price. NAL has used a combination of costless three-way options,
costless collar contracts and swaps to hedge oil production.
    During the fourth quarter of 2006, an average of 4,263 bbls/d of crude
oil was hedged, resulting in a realized gain of $1,169,745 and increasing
realized crude oil prices for the quarter by $1.31/bbl. In addition,
7,304 GJ/d of natural gas were hedged, resulting in a realized gain of
$628,616 and increasing average natural gas prices for the quarter by
$0.14/Mcf. In contrast, hedging contracts in place during the fourth quarter
of 2005 negatively affected realized crude oil prices by $2.63/bbl and natural
gas prices by $0.44/Mcf or $4.5 million in aggregate.
    For the year ended December 31, 2006 an average of 3,244 bbls/d of crude
oil was hedged, resulting in a realized gain of $1,157,573 increasing realized
crude oil prices for the period by $0.33/bbl. In addition, 3,337 GJ/d of
natural gas were hedged resulting in a realized gain of $2,217,152 and
increasing natural gas prices for the period by $0.13/Mcf. Hedging contracts
in place for the corresponding period in 2005 negatively affected crude oil
prices by $2.18/bbl and natural gas prices by $0.20/Mcf resulting in a total
hedging loss of $10.9 million.

    
    For 2007, NAL has the following hedges outstanding:

                               Hedging Summary

    -------------------------------------------------------------------------
    Crude Oil                              Natural Gas
    -------------------------------------------------------------------------
    Swap (bbls/d)               1,150      Swap (GJ/d)                 6,630
    $US/bbl                    $67.70      $Cdn/GJ                     $7.15

    Collars (bbls/d)            1,148      Collars (GJ/d)              9,000
    $US/bbl           $64.68 - $73.78      $Cdn/GJ             $6.61 - $8.48

    Total (bbls/d)              2,298      Total (GJ/d)               15,630
    -------------------------------------------------------------------------

    The details of NAL's hedging position are set out in Note 12 to the
accompanying Consolidated Financial Statements.
    NAL has designated these derivatives as accounting hedges under the
Canadian Institute of Chartered Accountants (the "CICA") accounting guideline
AcG13 and, accordingly, has not recorded the fair value of these instruments
in the consolidated financial statements as at December 31, 2006. As at
December 31, 2006 the unrealized fair value of these hedges was a gain of $4.5
million.

    ROYALTY EXPENSES

    Crown, freehold and overriding royalties, net of Alberta Royalty Tax
Credit ("ARTC"), were $18.3 million for the three months ended December 31,
2006. Expressed as a percentage of gross sales, before hedging and
transportation costs, the net royalty rate was 20.3 percent for the quarter
ended December 31, 2006, down slightly from 21.1 percent experienced in the
comparable period the previous year.
    On a year-to-date basis, royalties were $83.3 million, down from $87.2
million in the comparable period of 2005. Expressed as a percentage of gross
sales the royalty rate is consistent year-over-year at 21.6 percent for 2006
as compared to 21.5 percent in the prior year.

                              Royalty Expenses

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Net royalties ($000s)            18,258     26,248     83,332     87,188
    As % of revenue(1)                 20.3       21.1       21.6       21.5
    $/boe                             10.17      13.91      11.74      12.56
    -------------------------------------------------------------------------
    (1) Oil, natural gas and liquids sales before transportation and hedging.

    OPERATING COSTS

    For the quarter ended December 31, 2006, operating costs averaged $7.13
per boe, a 24 percent decrease from the $9.41 per boe for the quarter ended
December 31, 2005. The fourth quarter of 2005 included upward adjustments to
various costs that were accrued earlier in the year. Conversely, the fourth
quarter of 2006 includes several downward adjustments for activity from
earlier in 2006 that cost less than estimated. For the full year 2006,
operating costs averaged $8.31 per boe compared to $8.02 for 2005, an increase
of four percent. The Trust assets are characterized by high working interest
operated processing facilities and as such have a significant (80 percent
plus) fixed operating cost component. Although competitive industry conditions
had significant impact on the Trust's cost base in 2006, a continuous and
aggressive optimization program by our field operations staff yielded savings
of $1.2 million for the full year. The Trust continues to compare favorably to
trust industry averages for operating expenses.

                               Operating Costs

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Operating costs ($000s)          12,796     17,767     58,964     55,682
    As % of revenue                    14.0       14.9       15.3       14.2
    $/boe                              7.13       9.41       8.31       8.02
    -------------------------------------------------------------------------

    OPERATING NETBACK

    For the quarter ended December 31, 2006, NAL's operating netback, before
hedging gains, was $32.48 per boe, a decrease of 23 percent from $42.21 for
the quarter ended December 31, 2005, primarily attributable to lower natural
gas prices.
    For the twelve-month period ended December 31, 2006, the operating netback
before hedging was $33.92 per boe, a decrease of ten percent from the
comparable period of 2005, the decrease driven primarily by year-over-year
lower natural gas prices.

                          Operating Netback ($/boe)

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Revenue(1)                        49.78      65.53      53.97      58.07
    Royalties, net                   (10.17)    (13.91)    (11.74)    (12.56)
    Operating expenses                (7.13)     (9.41)     (8.31)     (8.02)
                                  -------------------------------------------
    Operating netback, before
     hedging                          32.48      42.21      33.92      37.49
    Hedging gains (losses)             1.00      (2.37)      0.48      (1.56)
                                  -------------------------------------------
    Operating netback, after
     hedging                          33.48      39.84      34.40      35.93
    -------------------------------------------------------------------------
    (1) Oil, natural gas and liquids sales less transportation.

    GENERAL AND ADMINISTRATIVE EXPENSES

    General and administrative ("G&A") expenses include direct costs incurred
by the Trust plus the reimbursement of the Manager's G&A expenses incurred on
the Trust's behalf.
    For the three months ended December 31, 2006, G&A expenses were $2.4
million, compared with $3.0 million in the comparable quarter in 2005. In
addition, $1.3 million of G&A costs relating to exploitation and development
activities were capitalized in the fourth quarter of 2006 compared with $1.0
million in the fourth quarter of 2005.
    For the year ended December 31, 2006, total G&A has increased ten percent
to $15.2 million from $13.8 million. In 2006, $4.3 million of G&A costs
relating to exploitation and development activities were capitalized, compared
with $4.5 million in 2005. G&A expenses increased to $10.9 million in 2006
compared with $9.3 million in 2005.
    The increase in total G&A costs in 2006 was primarily due to increased
compensation costs necessary to continue to attract and retain qualified
personnel in a highly competitive market, one time costs associated with the
special meeting to approve the restructuring of the management contract, and
costs associated with the simplification of the trust structure undertaken
during the year.

                     General and Administrative Expenses

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    G&A expenses ($000s)              2,395      3,049     10,946      9,295
    Capitalized G&A ($000s)           1,290        968      4,275      4,537
                                  -------------------------------------------
    Total G&A ($000s)                 3,685      4,017     15,221     13,832
    Expensed G&A costs:
      As % of revenue                   2.6        2.6        2.8        2.4
      $/boe                            1.33       1.62       1.54       1.34
      Per Trust unit ($)               0.03       0.04       0.14       0.13
    -------------------------------------------------------------------------

    UNIT-BASED INCENTIVE COMPENSATION PLAN

    In January 2006, the Board of Directors approved a revised unit-based
incentive plan (the "Plan") for all employees of the Manager. Under the Plan,
employees receive cash compensation based upon the value and overall return of
a specified number of awarded notional Trust units. Distributions paid on the
Trust's outstanding units during the vesting period are assumed to be
reinvested in notional units on the date of distribution.
    The first payment under the previous plan was made in December 2005, the
charge for which was accrued throughout the year and of which $1,415,000 was
charged to income and $651,000 capitalized in 2005. During the fourth quarter
of 2005, $628,000 was charged to income and $165,000 was capitalized. With the
expansion of the Plan and the introduction of the annual vesting provision for
the RTU's in 2006, the Trust has commenced to record its share of the value
associated with the notional units in its accounts over the vesting period.
    The compensation charges relating to the units granted are recognized over
the vesting period based on the number of notional units outstanding, the
Trust's unit price and an expected performance multiplier. As a result, the
expense recorded in the accounts will fluctuate from period to period.
    During the fourth quarter of 2006, the Trust recorded a reduction in unit-
based incentive compensation charges in the total amount of $426,000, of which
$131,000 was reflected in unit-based compensation expense and $295,000 was
deducted from capitalized unit-based compensation relating to exploitation and
development personnel. The reduction in unit-based compensation expense in the
fourth quarter is a reflection of the significant decrease in the Trust's unit
price following the October 31, 2006 announcement by the Federal Government of
their intention to tax income trusts.
    On a year-to-date basis, the Trust has recorded $4.2 million of unit-
based incentive compensation charges in its accounts, of which $2.5 million
has been charged to income and $1.7 million has been capitalized. Of the $4.2
million, $2.2 million was paid in January 2007 and $1.0 million is expected to
be paid in December 2007. The balance represents the long-term portion of the
Trust's estimated liability for the unit-based incentive plan as at
December 31, 2006. This amount is payable in December 2008 and 2009.

                           Unit-Based Compensation

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Unit-based compensation:
      Expensed ($000s)                 (131)       628      2,495      1,415
      Capitalized ($000s)              (295)       165      1,659        651
                                  -------------------------------------------
    Total unit-based compensation
     ($000s)                           (426)       793      4,154      2,066
    Expensed unit-based
     compensation:
      As % of revenue                  (0.1)       0.5        0.6        0.4
      $/boe                           (0.07)      0.33       0.35       0.20
      Per trust unit ($)               0.00       0.01       0.03       0.02
    -------------------------------------------------------------------------

    MANAGEMENT CONTRACT AND FEES

    The Trust is managed by NAL Resources Management Limited (the "Manager").
The Manager is a wholly-owned subsidiary of Manulife Financial Corporation
("MFC") and also manages, on their behalf, NAL Resources Limited ("NAL
Resources"), another wholly-owned subsidiary of MFC. NAL Resources and the
Trust maintain ownership interests in many of the same oil and natural gas
properties in which NAL Resources is the joint venture operator. As a result,
a significant portion of the net operating revenues and capital expenditures
represent joint venture amounts from NAL Resources. These transactions are in
the normal course of joint venture operations and are based on the original
transactions with third parties.
    The Manager provides certain services to the Trust pursuant to the
Management Contract for which, prior to January 1, 2006, the Trust was
required to pay a monthly base management fee equal to three percent of its
net production revenue and a quarterly performance fee based on the Trust's
overall return compared to the S&P/TSX Capped Energy Trust Index. Such fees
amounted to $4.3 million for the quarter ended December 31, 2005 and $10.0
million for the year ended December 31, 2005. In addition, the Trust paid $1.3
million (2005 - $1.9 million) for the reimbursement of G&A expenses incurred
by the Manager on behalf of the Trust pursuant to the Management Contract for
the fourth quarter of 2006, and $6.6 million (2005 - $7.0 million) for 2006.
The Trust also pays the Manager its share of unit-based incentive compensation
expense when cash compensation is paid to employees under the terms of the
Plan (2006 - $2.2 million; 2005 - $2.1 million).
    On May 31, 2006 the Trust's unitholders approved the restructuring of the
Management Contract with the Manager. Under the restructuring, the Trust
agreed to pay a one-time $30 million restructuring fee in exchange for the
elimination of any further base and performance management fees payable by the
Trust and for the acquisition of a 50 percent ownership in the Manager's
administrative capital assets, effective January 1, 2006. In payment of the
Restructuring Fee, the Trust issued, to an affiliate of the Manager, 1,592,357
units of the Trust at a price of $18.84 per unit. The subscription price was
based on the weighted average trading price of the Trust units over the five
consecutive trading days ending on the third trading day preceding March 1,
2006, the date of the agreement.
    Of the $30 million Restructuring Fee, $2.8 million has been allocated to
the administrative assets acquired and capitalized as Property, Plant and
Equipment. The balance of $27.2 million, representing the elimination of
future management and performance fees, has been recorded as a non-cash charge
to income. During 2006, the Trust paid an interim management fee of $250,000
per month in the first quarter and $300,000 per month in the second quarter up
to the closing of the restructuring transaction on May 31, 2006.

                               Management Fees

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Base management fees ($000s)          -      2,142      1,350      7,816
    Performance fees ($000s)              -      2,142         --      2,142
    -------------------------------------------------------------------------
    Total management fees                 -      4,284      1,350      9,958
    As % of revenue                       -        3.6        0.4        2.5
    $/boe                                 -       2.27       0.19       1.43
    Per trust unit ($)                    -       0.06       0.02       0.14
    -------------------------------------------------------------------------

    INTEREST

    Interest expense includes charges on bank borrowings plus standby fees on
the unused portion of the bank credit facility. NAL's average outstanding bank
debt for the fourth quarter of 2006 was $213.9 million, as compared to $229.1
million for the fourth quarter of 2005. NAL's effective interest rate averaged
5.06 percent in 2006, compared with 4.54 percent in the fourth quarter of
2005.
    For the year ended December 31, 2006 NAL's average outstanding debt was
$203.2 million, as compared to $233.7 million for the corresponding period in
2005. NAL's effective interest rate in 2006 averaged 4.83 percent compared
with 4.40 percent in 2005.
    The lower outstanding bank debt during 2006 resulted in lower interest
charges for the year compared to fiscal 2005. Higher interest rates in 2006
resulted in higher interest charges in the fourth quarter compared with the
corresponding period in 2005.

                       Interest and Bank Debt ($000s)

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Interest on bank debt             2,759      2,651      9,963     10,372
    Bank debt outstanding at
     period end                     220,785    220,519    220,785    220,519
    Net bank debt outstanding at
     period end(1)                  223,061    198,351    223,061    198,351
    Net bank debt-to-funds from
     operations ratio                  1.01       0.89       1.01       0.89
    -------------------------------------------------------------------------
    (1) Net bank debt is bank debt net of working capital.

    CASH FLOW NETBACK

    For the quarter ended December 31, 2006, NAL's cash flow netback was
$30.68 per boe, a ten percent decrease from $34.21 for the comparable period
in 2005. The decrease is primarily due to lower operating netbacks in 2006
that are partially offset by the elimination of management fee charges for the
period, compared to a $2.27 per boe charge in the corresponding period of
2005.
    For the year ended December 31, 2006, NAL's cash flow netback decreased
two percent to $30.92 compared to $31.47 in 2005. The decrease is primarily
attributable to lower operating netbacks offset by lower management fees in
2006 following the restructuring of the management agreement.

                          Cash Flow Netback ($/boe)

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Operating netback, after
     hedging                          33.48      39.84      34.40      35.93
    Management fees                      --      (2.27)     (0.19)     (1.43)
    G&A expenses                      (1.33)     (1.62)     (1.54)     (1.34)
    Unit-based incentive
     compensation                      0.07      (0.33)     (0.35)     (0.20)
    Interest                          (1.54)     (1.41)     (1.40)     (1.49)
                                  -------------------------------------------
    Cash flow netback                 30.68      34.21      30.92      31.47
    -------------------------------------------------------------------------

    DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATION
    (DDA)

    Depletion of oil and natural gas properties, including the capitalized
portion of the asset retirement obligation, and depreciation of equipment is
provided for on a unit-of-production basis using estimated proved reserves
volumes.
    For the quarter ended December 31, 2006, depletion on property, plant and
equipment and accretion on the asset retirement obligation increased by 6
percent over the comparable period in 2005 due to a 12 percent increase in the
DDA rate per boe of production partially offset by a five percent decrease in
production volumes.
    For the year ended December 31, 2006 depletion and accretion increased by
12 percent over the comparable period due to a two percent increase in
production and a nine percent increase in the DDA rate per boe of production.

               Depletion, Depreciation and Accretion Expenses

    -------------------------------------------------------------------------
                                    Three Months Ended            Year Ended
                                           December 31           December 31
                                  -------------------------------------------
                                       2006       2005       2006       2005
    -------------------------------------------------------------------------
    Depletion and depreciation
     ($000s)                         35,725     33,608    133,079    118,961
    Accretion of asset retirement
     obligation ($000s)               1,258      1,197      4,984      4,582
    -------------------------------------------------------------------------
    Total DDA ($000s)                36,983     34,805    138,063    123,543
    DDA rate per boe ($)              20.60      18.44      19.45      17.80
    -------------------------------------------------------------------------

    TAXES

    Taxes include provincial capital taxes relating to the Trust and its
subsidiary companies.
    In the fourth quarter of 2006, NAL had a future income tax recovery of
$262,000 compared with a provision of $1.2 million in the corresponding period
of the prior year.
    For the year, NAL had a future income tax recovery of $1.2 million in 2006
compared to a provision of $2.5 million in 2005.
    The Trust is a taxable entity and files a trust income tax return
annually. The Trust's taxable income consists of royalty income, distributions
from a subsidiary trust and interest and dividends from other subsidiaries,
less deductions for the Trust's G&A expenses, resource allowance, Canadian Oil
and Gas Property Expense ("COGPE"), and trust unit issue costs. In addition,
Canadian Exploration Expense ("CEE"), Canadian Development Expense ("CDE") and
Undepreciated Capital Cost ("UCC") are incurred and deducted by the Trust's
subsidiaries. The Trust is taxable only on remaining income, if any, that is
not distributed to unitholders. The Trust does not expect to incur any cash
income taxes in 2007.
    The following tax pools are available to the Trust and subsidiaries
(subject to assessment by income tax authorities) for future use as deductions
from taxable income:

         --------------------------------------------------------
                                               2006         2005
         --------------------------------------------------------
          Intangible resource pools        $323,818     $268,575
          Undepreciated capital cost        149,383      102,983
          Unit issue costs                    9,437       14,144
          Non-capital losses                 11,495        9,765
         --------------------------------------------------------
          Total tax pools                  $494,133     $395,467
         --------------------------------------------------------
         --------------------------------------------------------

    On December 21, 2006, the Minister of Finance released for comment draft
legislation concerning the taxation of certain publicly traded trusts. The
legislation reflects proposals originally announced by the Minister on
October 31, 2006. Under the proposed legislation, distributions to unitholders
will not be deductible by publicly traded income trusts and, as a result, the
Trust will be taxed on its income similar to corporations. The proposed rules,
if passed into law, would be applicable commencing in 2011. However, if the
proposed legislation is implemented, the Trust would be required to recognize
in its accounts, in the period in which the change is substantially enacted,
future income taxes on temporary differences in the Trust.

    CAPITAL RE

SOURCES AND LIQUIDITY The capital structure of the Trust is comprised of Trust units and bank debt. As at December 31, 2006, NAL had 77,971,268 units outstanding, compared with 73,977,021 units at December 31, 2005. The increase from December 31, 2005 is attributable to 2.4 million units issued under the distribution reinvestment program ("DRIP") and 1.6 million units issued in connection with the restructuring of the Management Agreement. For the year ended December 31, 2006, the distribution reinvestment and premium distribution reinvestment ("Premium DRIP") plans resulted in 2,401,890 units being issued at an average price of $17.25 per unit for total proceeds of $41.4 million. Unitholders electing to reinvest distributions or make optional cash payments to acquire trust units from treasury under the DRIP may do so at 95 percent of the average market price with no additional fees or commissions. The Premium DRIP allows unitholders to exchange such units for a cash payment, from the plan broker, equal to 102 percent of the monthly distribution. The combined participation in these programs has resulted in the reinvestment of approximately 24.2 percent of monthly distributions over the past year. On March 10, 2006, the Trust announced the suspension of the Premium DRIP, which resulted in a significant reduction in the reinvestment participation rate commencing with the distribution payable in April 2006. The participation rate in the regular DRIP averaged 18.8 percent over the three months ended December 31, 2006. The Trust continues to monitor the participation in these plans in conjunction with its capital requirements. As at December 31, 2006, the Trust had bank debt of $223.1 million (net of working capital) compared with $198.4 million at December 31, 2005. At the end of the fourth quarter, the Trust had a net bank debt-to-equity ratio of 0.49 and a net bank debt-to-twelve months trailing funds from operations ratio of 1.01. The Trust maintains a $300 million fully secured, extendible, revolving credit facility. The credit facility revolves until April 26, 2007, at which time it is extendible for a further 364-day revolving period upon agreement between the Trust and the bank syndicate. The facility consists of a $290 million production facility and a $10 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 Trust 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 Trust would be required to repay the facility in four equal quarterly installments commencing April 2008. Total bank debt amounted to $220.8 million at December 31, 2006 compared with $220.5 million as at December 31, 2005. Of the debt outstanding at December 31, 2006, $219.0 million was outstanding under the production facility and $1.8 million under the working capital facility. Year-End Capitalization ------------------------------------------------------------------------- 2006 2005 ------------------------------------------------------------------------- Trust unit equity ($000s) 456,500 494,490 Bank debt ($000s) 220,785 220,519 Net bank debt ($000s)(1) 223,061 198,351 Net bank debt-to-equity 0.49 0.40 Net bank debt-to-trailing 12 months funds from operations 1.01 0.89 Units outstanding (000s) 77,971 73,977 ------------------------------------------------------------------------- (1) Net bank debt is bank debt net of working capital. The Trust anticipates that, subject to fluctuations in commodity prices, it will continue to have adequate liquidity to fund planned capital spending during 2007 through a combination of funds from operations, funds received from its distribution reinvestment program and bank borrowings. ASSET RETIREMENT OBLIGATION At December 31, 2006, the Trust reported an Asset Retirement Obligation ("ARO") balance of $65.6 million ($61.9 million at December 31, 2005) for future abandonment and reclamation of the Trust's oil and gas properties and facilities. The ARO balance was increased by accretion expense of $5.0 million and liabilities incurred of $3.1 million in 2006 ($4.6 million and $23.4 million, respectively, in 2005) and reduced by $4.4 million for actual abandonment and environmental expenditures in 2006 ($3.0 million in 2005). The liabilities incurred in 2005 were primarily due to the liability associated with the additional properties acquired with the acquisition of Addison Energy Inc. DISTRIBUTIONS TO UNITHOLDERS The Trust sets distributions based upon commodity prices, financial market conditions, internal capital investment opportunities and the resulting impact on taxability and payout ratios. The Trust develops an annual forecast, which is updated regularly by management. The Board sets distributions at a level it believes will be sustainable for a period of time and formally reviews distribution levels quarterly. In November 2006, as a result of lower commodity prices, the Board of Directors decided to reduce monthly distributions from $0.19 to $0.16 per unit, reversing the $0.03 per unit distribution increase introduced in October 2005 in response to higher commodity prices. This reduced rate was implemented effective with the distribution paid in December 2006. This reduction allows the Trust to retain an incremental $2.3 million per month or $27.7 million on an annual basis. The lower distribution will allow the Trust to maintain an effective capital expenditure budget and create additional tax pools for the Trust. This action will also lower the payout ratio and retain the Trust's very competitive debt level to position it to take advantage of opportunities to add assets in the future. For the three months ended December 31, 2006, funds from operations amounted to $55.8 million compared with $65.8 million for the three months ended December 31, 2005. NAL declared cash distributions of $39.7 million ($0.51 per unit) in the fourth quarter of 2006 as compared to $42.0 million ($0.57 per unit) in the fourth quarter of 2005. This represented a 71 percent payout ratio in 2006, compared with the 64 percent payout ratio in the comparable quarter in 2005. The payout ratio in the fourth quarter of 2006 decreased from the 81 percent experienced in the third quarter due to the lower distribution rate in the fourth quarter. The weighted average number of units outstanding during the fourth quarter of 2006 increased by six percent to 77.7 million from 73.4 million in 2005. For the year ended December 31, 2006 funds from operations were $219.8 million compared with $221.6 million for the comparable period in 2005. NAL declared cash distributions of $169.6 million ($2.22 per unit) in this period as compared to $142.1 million ($2.01 per unit) in 2005. This represented a 77 percent payout ratio for fiscal 2006 compared to 64 percent in 2005. Distributions ------------------------------------------------------------------------- Three Months Ended Year Ended December 31 December 31 ------------------------------------------- 2006 2005 2006 2005 ------------------------------------------------------------------------- Funds from operations ($000s) 55,795 65,837 219,776 221,649 Distributions declared ($000s) 39,663 41,956 169,589 142,050 Funds from operations per unit(1) 0.72 $0.90 2.88 $3.17 Distributions declared per unit 0.51 $0.57 2.22 $2.01 Weighted average units outstanding ($000s) 77,697 73,436 76,350 69,946 ------------------------------------------------------------------------- (1) Based on weighted average units outstanding. VARIABLE INTEREST ENTITIES NAL has no variable interest entities. CONTRACTUAL OBLIGATIONS 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) 2007 2008 2009 2010 2011 ------------------------------------------------------------------------- Office lease(1) 2,734 2,580 2,580 2,365 Transportation agreement 716 716 80 - - Processing agreement(2) 491 469 446 428 414 Drilling rigs(3) 1,975 494 - - - Retention bonus(4) 938 938 - - - ------------------------------------------------------------------------- (1) Represents the full amount of office lease commitments, both base rent and operating costs, held by the Manager, of which the Trust is allocated a pro rata share (currently approximately 53 percent) of the expense on a monthly basis. (2) Represents a gas processing agreement with a take or pay arrangement. (3) Represents the Trust's share of the minimum payments required under drilling rig contracts held by NAL Resources. (4) Represents the Trust's share of the expected future payments under a staff retention program. QUARTERLY INFORMATION ------------------------------------------------------------------------- 2006 ------------------------------------------------------------------------- ($000s, except per unit and production amounts) Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Revenue, net of royalties 75,694 75,798 77,988 81,272 Per unit 0.97 0.98 1.03 1.08 Funds from operations(1) 55,795 54,107 52,210 57,664 Per unit 0.72 0.70 0.69 0.77 Net income (loss)(2) 20,472 20,473 (5,357) 24,610 Per unit 0.26 0.27 (0.07) 0.33 Average oil equivalent production (boe/d - 6:1) 19,517 19,079 19,012 20,181 ------------------------------------------------------------------------- ------------------------------------------------------------------------- 2005 ------------------------------------------------------------------------- ($000s, except per unit and production amounts) Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Revenue, net of royalties 95,643 85,613 71,482 61,268 Per unit 1.30 1.18 1.00 0.98 Funds from operations(1) 65,837 62,442 49,881 43,489 Per unit 0.90 0.86 0.70 0.69 Net income (loss) 30,777 31,710 20,804 15,247 Per unit 0.42 0.44 0.29 0.24 Average oil equivalent production (boe/d - 6:1) 20,514 19,710 18,349 17,457 ------------------------------------------------------------------------- (1) Represents cash flow from operating activities prior to the change in non-cash working capital items. (2) Includes non-cash management restructuring fee of $27.2 million in Q2. FINANCIAL REPORTING DISCLOSURE CONTROLS Management has evaluated the effectiveness of the Trust's financial reporting disclosure controls and procedures as at December 31, 2006 and has concluded that such financial reporting disclosure controls and procedures were effective as at that date. CHANGES TO INTERNAL CONTROL OVER FINANCIAL REPORTING There were no changes to the Trust's internal control over financial reporting since September 30, 2006 that have materially affected, or are reasonably likely to materially affect, the Trust's internal control over financial reporting. CRITICAL ACCOUNTING ESTIMATES The significant accounting policies used by NAL are disclosed in the notes to NAL's December 31, 2006 audited consolidated financial statements. Certain accounting policies require that management make appropriate decisions when formulating estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The following discusses such accounting policies and is included in this MD&A to assist investors in assessing the critical accounting policies and practices of NAL and the likelihood of materially different results being reported. The Manager reviews the estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates. The following assessment of significant accounting estimates is not meant to be exhaustive. NAL might realize different results from the application of new accounting standards published, from time to time, by various regulatory bodies. Proved Oil and Gas Reserves --------------------------- Under National Instrument 51-101 ("NI 51-101"), "proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable (it is possible that the actual remaining quantities recovered will exceed the estimated proved reserves). In accordance with this definition, the level of certainty targeted by the reporting company should result in at least a 90 percent probability at a company aggregate level that the quantities actually recovered will equal or exceed the estimated reserves. There was no such consideration of probability under previous reporting rules. In the case of "probable" reserves, which are less certain to be recovered than proved reserves, NI 51-101 states that it must be equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable ("P+P") reserves. As for certainty, in order to report reserves as P+P, the reporting company must believe that there is at least 50 percent probability at a company aggregate level that the quantities actually recovered will equal or exceed the sum of the estimated P+P reserves. The implementation of NI 51-101 has resulted in a more rigorous and uniform standardization of reserve evaluation. The oil and gas reserve estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in NAL's plans. The effect of changes in proved oil and gas reserves on the financial results and position of NAL is described under the heading "Full Cost Accounting for Oil and Gas Activities ("Ceiling Test")". Depletion Expense ----------------- NAL uses the full cost method of accounting for exploration and development activities. In accordance with this method of accounting, all costs associated with exploration and development are capitalized whether or not the activities funded were successful. The aggregate of net capitalized costs and estimated future development costs is amortized using the unit of production method based on estimated proved oil and gas reserves. An increase in estimated proved oil and gas reserves would result in a corresponding reduction in depletion expense. A decrease in estimated future development costs would result in a corresponding reduction in depletion expense. Impairment of Property, Plant & Equipment ----------------------------------------- NAL is required to review the carrying value of all property, plant and equipment, including the carrying value of oil and gas assets, for potential impairment. Impairment is indicated if the carrying value of the long-lived oil and gas asset is not recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the property, plant and equipment is charged to earnings. Fair Value of Derivative Instruments ------------------------------------ Periodically NAL utilizes financial derivatives to manage market risk. The purpose of the hedge is to provide an element of stability to NAL's cash flow in a volatile environment. NAL discloses the fair value of open hedging contracts as at the end of a reporting period. Asset Retirement Obligation --------------------------- NAL is required to recognize and measure liabilities associated with capital assets. A liability is recognized equal to the discounted fair value of the obligation in the period in which the asset is recorded with an equal offset to the carrying amount of the asset. The liability then accretes to its fair value with the passage of time. Management is required to estimate the timing and future costs to settle liabilities. Legal, Environmental Remediation and Other Contingent Matters ------------------------------------------------------------- NAL is required to determine whether a loss is probable based on judgment and interpretation of laws and regulations and whether the loss can reasonably be estimated. When the loss is determined, it is charged to earnings. NAL's management must continually monitor known and potential contingent matters and make appropriate provisions by charges to earnings when warranted by circumstance. Income Tax Accounting --------------------- The determination of NAL's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessments after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management. NEW ACCOUNTING POLICY Unit-Based Incentive Compensation Accounting Policy --------------------------------------------------- In January 2006, the Board of Directors approved a revised unit-based incentive plan (the "Plan") for all employees of the Manager, under which employees will receive cash compensation based upon the value and overall return of a specified number of awarded notional Trust units. The first payment under the previous plan was made in December 2005. With the expansion of the Plan and the introduction of an annual vesting provision in 2006, the Trust has commenced to record its share of the value associated with the notional units in its accounts over the vesting period. The accounting policy for the Plan is more fully described in Note 2 to the accompanying consolidated financial statements for the year ended December 31, 2006. FUTURE ACCOUNTING CHANGES Financial Instruments, Other Comprehensive Income, Hedges --------------------------------------------------------- The CICA issued new accounting standards effective for fiscal year ends beginning on or after October 1, 2006. The standards address how and at what amount financial assets, financial liabilities and non-financial derivatives are to be recognized on the balance sheet and how the gains and losses are to be presented. An additional financial statement ("Other Comprehensive Income") will be required. Under the new standards the Trust will no longer designate its hedging contracts as "hedges". Effective January 1, 2007, these contracts will be reported at fair value on the balance sheet with any related unrealized gains and losses recognized in income of the period. The Trust is currently reviewing the impact of other provisions in the new standards on the consolidated financial statements. Dated: March 1, 2007 CONSOLIDATED BALANCE SHEETS (thousands of dollars) (audited) ---------------------------- As at As at December 31, December 31, 2006 2005 ---------------------------- Assets Current assets Cash and cash equivalents $6,295 $1,124 Accounts receivable and other 44,467 79,010 ------------------------------------------------------------------------- 50,762 80,134 Reclamation reserve (Note 5) - 3,898 Future income tax asset (Note 11) 3,345 2,136 Property, plant and equipment, net (Note 6) 742,795 748,715 ------------------------------------------------------------------------- $796,902 $834,883 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Liabilities and Unitholders' Equity Current liabilities Accounts payable and accrued liabilities $40,563 $43,910 Distributions payable to unitholders 12,475 14,056 ------------------------------------------------------------------------- 53,038 57,966 Bank debt (Note 8) 220,785 220,519 Unit-based incentive compensation (Note 9) 1,005 - Asset retirement obligations (Note 7) 65,574 61,908 ------------------------------------------------------------------------- 340,402 340,393 Unitholders' equity (Note 10) Unitholders' capital 824,986 753,585 Deficit (368,486) (259,095) ------------------------------------------------------------------------- 456,500 494,490 ------------------------------------------------------------------------- $796,902 $834,883 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Commitments (Note 13) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Units outstanding (000s) 77,971 73,977 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT (thousands of dollars, except per unit amounts) (unaudited) ------------------------------------------ Three Months Ended Year Ended December 31 December 31 ------------------------------------------------------------------------- 2006 2005 2006 2005 ------------------------------------------ Revenue Oil, natural gas and liquids sales(1) $91,792 $119,995 $388,999 $395,147 Royalty and other income 2,160 1,896 5,085 6,047 Crown royalties, net of ARTC (13,156) (20,099) (61,570) (65,167) Freehold and other royalties (5,102) (6,149) (21,762) (22,021) ------------------------------------------------------------------------- 75,694 95,643 310,752 314,006 ------------------------------------------------------------------------- Expenses Operating 12,796 17,767 58,964 55,682 Transportation costs 620 787 2,547 2,903 General and administrative 2,395 3,049 10,946 9,295 Unit-based incentive compensation (Note 9) (131) 628 2,495 1,415 Management fees (Note 3) - 4,284 1,350 9,958 Restructuring fee (Note 3) - - 27,299 - Interest on bank debt 2,759 2,651 9,963 10,372 Depletion, depreciation and amortization 35,725 33,608 133,079 118,961 Accretion on asset retirement obligations 1,258 1,197 4,984 4,582 ------------------------------------------------------------------------- 55,422 63,971 251,627 213,168 ------------------------------------------------------------------------- Income before taxes 20,272 31,672 59,125 100,838 ------------------------------------------------------------------------- Income and capital taxes (provision) recovery (62) 340 (136) 240 Future income tax recovery (provision) 262 (1,235) 1,209 (2,540) ------------------------------------------------------------------------- Total income and capital taxes (Note 11) 200 (895) 1,073 (2,300) ------------------------------------------------------------------------- Net income 20,472 30,777 60,198 98,538 Deficit, beginning of period (349,295) (247,915) (259,095) (215,583) Distributions declared (Note 10) (39,663) (41,957) (169,589) (142,050) ------------------------------------------------------------------------- Deficit, end of period $(368,486) $(259,095) $(368,486) $(259,095) ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net income per Trust unit $0.26 $0.42 $0.79 $1.41 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Weighted average units outstanding (000s) 77,697 73,436 76,350 69,946 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (1) After hedging. See accompanying notes CONSOLIDATED STATEMENTS OF CASH FLOWS (thousands of dollars) (unaudited) ------------------------------------------ Three Months Ended Year Ended December 31 December 31 ------------------------------------------ 2006 2005 2006 2005 ------------------------------------------ Operating Activities Net income $20,472 $30,777 $60,198 $98,538 Items not involving cash: Depletion, depreciation and amortization 35,725 33,608 133,079 118,961 Accretion on asset retirement obligations 1,258 1,197 4,984 4,582 Future income tax provision (recovery) (262) 1,235 (1,209) 2,540 Restructuring fee - - 27,159 - Abandonment and environmental expenditures (1,398) (980) (4,435) (2,972) Decrease (increase) in non-cash working capital (7,117) 6,626 18,669 (26,364) ------------------------------------------------------------------------- 48,678 72,463 238,445 195,285 ------------------------------------------------------------------------- Financing Activities Distributions paid to unitholders (41,899) (39,557) (171,170) (136,484) Issue of Trust units, net of issue costs 7,874 17,690 41,401 276,964 Increase (decrease) in bank debt 12,592 (18,281) 266 126,819 Decrease (increase) in non-cash working capital 186 (3,133) 2,241 (3,133) ------------------------------------------------------------------------- (21,247) (43,281) (127,262) 264,166 ------------------------------------------------------------------------- Investing Activities Acquisition of Addison Energy Inc. - - - (387,215) Additions to property, plant and equipment (34,788) (25,514) (121,201) (73,099) Reclamation reserve 4,294 (138) 3,898 (464) Decrease (increase) in non-cash working capital 2,169 (6,282) 11,291 1,340 ------------------------------------------------------------------------- (28,325) (31,934) (106,012) (459,438) ------------------------------------------------------------------------- Increase (decrease) in cash (894) (2,752) 5,171 13 Cash and cash equivalents, beginning of period 7,189 3,876 1,124 1,111 ------------------------------------------------------------------------- Cash and cash equivalents, end of period $6,295 $1,124 $6,295 $1,124 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Supplementary disclosure of cash flow information: Cash paid during the period for: Interest $2,726 $2,621 $9,816 $10,287 Taxes (recovery) $62 $(340) $136 $(240) ------------------------------------------------------------------------- See accompanying notes NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS Year ended December 31, 2006 (Tabular amounts in thousands of dollars, except per unit amounts) The financial results for the three months ended December 31, 2006 have not been separately reviewed by the external auditors. 1. STRUCTURE OF THE TRUST The Trust is an open-end investment trust formed under the laws of the Province of Alberta. Operations commenced on May 9, 1996. The principal undertakings of the Trust are to indirectly acquire and hold, through its direct and indirect wholly owned subsidiaries, interests in oil and natural gas properties and to distribute the net cash proceeds to its Unitholders. The Trust is 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 Trust 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 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 transactions with third parties. Effective May 31, 2006 the terms of the management contract were restructured, resulting in the elimination of management fees and performance fees while retaining the recovery of the general and administrative costs incurred on behalf of the Trust, see Note 3. 2. SUMMARY OF ACCOUNTING POLICIES Basis of Presentation The Trust's financial statements have been prepared in accordance with Generally Accepted Accounting Principles ("GAAP") in Canada and they include the accounts of the Trust and its subsidiaries, trusts and partnerships, which are wholly owned. All inter-entity transactions and balances have been eliminated. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimated. In particular, the amounts recorded for depletion and depreciation of property, plant and equipment and for asset retirement obligations are based on estimates of reserves and future costs. The amounts recorded for unit-based compensation are based on estimates of unit price and performance factors. The ceiling test calculation is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and may impact the consolidated financial statements of future periods. Property, Plant and Equipment The Trust follows the full cost method of accounting for petroleum and natural gas properties, whereby all costs of acquiring petroleum and natural gas properties and related development costs are capitalized and accumulated in one cost centre. Such costs include land acquisition, geological and geophysical expenditures, costs of drilling both productive and non-productive wells, related plant and production equipment costs and related overhead charges. Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless such sale would alter the depletion rate by 20% or more. Depletion of oil and natural gas properties and depreciation of equipment is calculated using the unit of production method based on total proven reserves before royalties. Natural gas reserves are converted to barrels of oil equivalent based on relative energy content (6:1). Oil and natural gas assets are evaluated in each reporting period to determine that the carrying amount in a cost centre is recoverable and does not exceed the fair value of the properties in the cost centre. The carrying amount of property, plant and equipment is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves exceeds the carrying amount. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves. The cash flows are estimated using expected future commodity prices and costs and discounted using a risk-free rate. Asset Retirement Obligation The Trust recognizes the fair value of an asset retirement obligation in the period in which it is incurred, on a discounted basis, with a corresponding increase to the carrying amount of property, plant and equipment. The asset recorded is depleted on a unit of production basis over the life of the reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to income in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost could also result in an increase or decrease to the obligation. Actual costs incurred upon settlement of the retirement obligation are charged against the obligation to the extent of the liability recorded. Income Taxes The Trust is a taxable entity under the Canadian Income Tax Act and is taxable only on income that is not distributed or distributable to unitholders. The Trust meets 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. In addition, the Trust is exempt from future income taxes because it is contractually committed to distribute all of its income to its unitholders. Ventures Trust, a subsidiary of the Trust, is also exempt from future income taxes because it is contractually committed to distribute all of its tax-exempt income to the Trust who ultimately distributes the income to the unitholders. The Trust follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported in the Trust's subsidiaries financial statements and their respective tax bases, using substantially enacted income tax rates. The effect of a change in income tax rates on future income tax liabilities and assets is recognized in income in the period that the change occurs. Joint Operations Substantially all of the development and production activities are conducted jointly with others and, accordingly, these financial statements reflect only the Trust's proportionate interest in such activities. Financial Instruments The Trust uses, from time to time, derivative financial instruments to manage exposure related to changes in oil and natural gas commodity prices. They are not used for trading or speculative purposes. The Trust formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or anticipated transactions. The Trust also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. For cash flow hedges, effectiveness is achieved if the changes in the cash flows of the derivative substantially offset the changes in the cash flows of the hedged position and the timing of the cash flows is similar. Effectiveness for fair value hedges is achieved if the fair value of the derivative substantially offsets changes in the fair value attributable to the hedged item. In the event that a derivative does not meet the designation or effectiveness criterion, the Trust applies the fair value method of accounting by recording an asset or liability on the consolidated balance sheet and recognizing changes in the fair value of the instruments in the current period income statement. If a derivative that qualifies as a hedge is settled early, the gain or loss at settlement is deferred and recognized when the gain or loss on the hedged transaction is recognized. Realized gains or losses on changes in oil and natural gas commodity prices are recognized in income in the same period and in the same financial statement category as the income or expense arising from corresponding commodity hedge contract. Revenue Recognition Revenues from the sale of petroleum and natural gas are recorded when title passes to the purchaser. Unit-Based Incentive Compensation The Manager has established a unit-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 Trust units on a fixed vesting date. The notional unit grants are in the form of Restricted Trust Units ("RTU's") and Performance Trust Units ("PTU's"). Distributions paid on the Trust's outstanding units during the vesting period are assumed to be reinvested in the awarded notional units on the date of distribution. The compensation incorporates the Trust unit price and the number of RTU's and PTU's outstanding at each period end. In addition, for the PTU's, there is a performance multiplier which is based on the Trust's performance relative to its peers and may range from zero to two times the value of the notional units held at vesting. RTU's vest one third on November 30 in each of three years after grant date. PTU's vest at the end of three years. Compensation expense is recognized over the vesting period and is determined based on the intrinsic value of the notional units at each period end and an expected performance multiplier with a corresponding increase or decrease in liabilities. Classification between accrued liabilities and other long-term liabilities is dependent on the expected payout date. The Trust charges the accrued compensation amounts relating to head office employees to general and administrative expenses, the amounts relating to field staff to operating costs, and the amounts relating to exploitation and development personnel to property, plant and equipment. The Trust has not incorporated an estimated forfeiture rate for performance units that will not vest and accounts for actual forfeitures as they occur. Comparative Figures Certain comparative figures have been reclassified to conform to current period presentation. 3. RELATED PARTY TRANSACTIONS The Manager provides certain services pursuant to the Management Contract for which, prior to January 1, 2006, the Trust was required to pay a monthly base management fee equal to three percent of its net production revenue and a quarterly performance fee based on the Trust's overall return compared to the S&P/TSX Capped Energy Trust Index. Such fees amounted to $9,958,000 for the year ended December 31, 2005. On May 31, 2006 the Trust's unitholders approved the restructuring of the Management Contract with the Manager. Under the restructuring, the Trust agreed to pay a one-time $30 million restructuring fee in exchange for the elimination of any further base and performance management fees payable by the Trust and the acquisition of a 50 percent ownership in the Manager's administrative capital assets, effective January 1, 2006. In payment of the Restructuring Fee, the Trust issued, to an affiliate of the Manager. 1,592,357 units of the Trust at a price of $18.84 per unit. The subscription price was based on the weighted average trading price of the Trust units over the five consecutive trading days ending on the third trading day preceding March 1, 2006, the date of the agreement. Of the $30 million Restructuring Fee, $2.8 million has been allocated to the administrative assets acquired and capitalized as Property, Plant and Equipment. The balance of $27.2 million, representing the elimination of future management and performance fees, has been recorded as a non-cash charge to income. During 2006, the Trust paid an interim management fee of $1,350,000 up to the closing of the restructuring transaction on May 31, 2006. In addition, the Trust paid $6.6 million (2005 - $7.0 million) for the reimbursement of G&A expenses incurred by the Manager on behalf of the Trust pursuant to the Management Contract. The Trust also pays the Manager its share of unit-based incentive compensation expense when cash compensation is paid to employees under the terms of the Plan (2006 - $2.2 million; 2005 - $2.1 million). The following amounts are due to and from related parties as at December 31 and have been included in accounts receivable and accounts payable and accrued liabilities on the balance sheet: --------------------------------------------------------------------- 2006 2005 --------------------------------------------------------------------- Due (to) from NAL Resources Limited $1,478 $14,326 Due to NAL Resources Management Limited $(3,718) $(4,598) --------------------------------------------------------------------- 4. CORPORATE ACQUISITION Effective February 10, 2005 the Trust acquired all of the issued and outstanding shares of Addison Energy Inc. ("Addison") for consideration of $388.7 million. The allocation of the purchase price and consideration paid was as follows: --------------------------------------------------------------------- Net assets acquired: --------------------------------------------------------------------- Cash $1,527 Working capital 2,729 Asset retirement obligations (22,974) Property, plant and equipment 407,460 --------------------------------------------------------------------- Total net assets acquired $388,742 --------------------------------------------------------------------- --------------------------------------------------------------------- --------------------------------------------------------------------- Consideration --------------------------------------------------------------------- Cash $386,461 Related fees and expenses 2,281 --------------------------------------------------------------------- Cost of acquisition $388,742 --------------------------------------------------------------------- --------------------------------------------------------------------- The fair value of the property, plant and equipment and asset retirement obligations reflects the Trust's 70 percent remaining interest in the Addison properties following the disposal of a 30 percent interest to Manulife Financial Corporation ("MFC"). The Trust received $165 million in cash from MFC, representing its 30 percent share of the cost of the Addison properties, which has been offset against the cost of the acquisition in the above purchase equation. The consolidated financial statements incorporate the operations of Addison effective February 10, 2005. 5. RECLAMATION RESERVE During 2006 certain amendments were made to a royalty agreement involving the business of the Trust, which had provided for the establishment of a reserve ("Reclamation Reserve") to assist in funding future asset retirement obligations. Under the terms of the amended royalty agreement, the requirement for the Reclamation Reserve has been eliminated and, accordingly, the funds in the reserve have been transferred to the general working capital of the Trust. The Trust continues to pay ongoing abandonment and reclamation expenditures from its cash flow from operating activities. 6. PROPERTY, PLANT AND EQUIPMENT ("PP&E") --------------------------------------------------------------------- Net book value as at December 31: 2006 2005 --------------------------------------------------------------------- Oil and natural gas properties, at cost $1,293,854 $1,166,695 Less: Accumulated depletion and depreciation (551,059) (417,980) --------------------------------------------------------------------- $742,795 $748,715 --------------------------------------------------------------------- --------------------------------------------------------------------- During 2006, the Trust capitalized $4.3 million (2005 - $4.5 million) of general and administrative costs and $1.7 million of unit-based incentive compensation expense (2005 - $0.7 million) that were directly related to exploitation and development programs. No property costs have been excluded from the depletion and depreciation calculation. The Trust performed a ceiling test calculation at December 31, 2006 in accordance with CICA AcG16 to assess the recoverable value of property, plant and equipment. The oil and gas future prices are based on the January 1, 2007 commodity price forecast of our independent reserve evaluators, adjusted for commodity differentials specific to the Trust. The following table summarizes the benchmark prices used in the ceiling test calculation. Based on these assumptions, the undiscounted value of future net reserves from the Trust's proved reserves exceeded the carrying value of property, plant and equipment as at December 31, 2006. US$/Cdn$ WTI Oil Exchange WTI Oil AECO Gas Year (US$/bbl) Rate (Cdn$/bbl) (Cdn$/GJ) --------------------------------------------------------------------- 2007 62.50 0.870 71.84 6.85 2008 61.20 0.870 70.34 7.05 2009 59.80 0.870 68.74 7.40 2010 58.40 0.870 67.13 7.50 2011 56.80 0.870 65.29 7.70 --------------------------------------------------------------------- Remainder(1) 2% 0.870 2% 2% 1) Percentage change represents the change in each year after 2011 to the end of the reserve life. 7. ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligation was estimated by the Manager based on the Trust's net ownership interests in oil and natural gas assets including well sites, gathering systems and processing facilities, estimated costs to remediate, reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. NAL has estimated the net present value of its asset retirement obligations to be $65.6 million as at December 31, 2006 based on a total undiscounted amount of cash flows required to settle its asset retirement obligations of $165.2 million (2005 - $161.8 million). These costs are expected to be made over the next 46 years with the majority of the costs incurred between 2007 and 2033. NAL's credit-adjusted risk-free rate of 8 percent (2005 - 8 percent) and an inflation rate of 2.0 percent (2005 - 1.5 percent) were used to calculate the present value of the asset retirement obligations. The following table reconciles the Trust's asset retirement obligations. --------------------------------------------------------------------- 2006 2005 --------------------------------------------------------------------- Balance, beginning of year $61,908 $36,924 Accretion expense 4,984 4,582 Liabilities incurred 3,117 23,374 Liabilities settled (4,435) (2,972) --------------------------------------------------------------------- Balance, end of year $65,574 $61,908 --------------------------------------------------------------------- --------------------------------------------------------------------- 8. BANK DEBT --------------------------------------------------------------------- 2006 2005 --------------------------------------------------------------------- Production loan facility $219,000 $219,000 Working capital facility 1,785 1,519 --------------------------------------------------------------------- Total debt outstanding $220,785 $220,519 Current portion of debt - - --------------------------------------------------------------------- Long-term debt $220,785 $220,519 --------------------------------------------------------------------- --------------------------------------------------------------------- The Trust, through its subsidiary NAL Ventures Trust, maintains a $300 million fully secured, extendible, revolving term credit facility with a syndicate of Canadian chartered banks. This facility consists of a $290 million production facility and a $10 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 a function of the net present value of the Trust's oil and gas reserves and other assets. The credit facility is fully secured by first priority security interests in all present and after acquired properties and assets of the Trust and its subsidiary and affiliated entities. The facility was renewed in April 2006 and will revolve until April 26, 2007 and is extendible at that time for a further 364-day revolving period upon agreement between the Trust and the bank syndicate. If the credit facility is not extended in April 2007, the amounts outstanding at that time will be converted to a two-year term loan. The term loan will be payable in four equal quarterly installments commencing April 2008 with a final residual payment, if any, in April 2009. The Trust is restricted, under the credit facility, from making distributions to its unitholders in excess of its consolidated operating cash flow during the eighteen-month period preceding the distribution date. 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 Trust. On December 31, 2006 the effective interest rate on amounts outstanding under the credit facility was 5.18 percent. 9. UNIT-BASED INCENTIVE COMPENSATION PLAN In January 2006, the Board of Directors approved a revised unit-based incentive plan (the "Plan") for all employees of the Manager. Under the Plan, employees receive cash compensation based upon the value and overall return of a specified number of awarded notional Trust units. The first payment under the previous plan was made in December 2005, the charge for which was accrued throughout the year and of which $1,415,000 was charged to income and $651,000 was capitalized in 2005. With the expansion of the Plan and the introduction of the annual vesting provision of the awarded notional units in 2006, the Trust has commenced to record its share of the value associated with the notional units in its accounts over the vesting period. During 2006, the Trust has accrued $4.2 million of unit-based incentive compensation charges in its accounts, of which, $2.5 million has been charged to income and $1.7 million has been capitalized. Of the $4.2 million, $2.2 million was paid in January 2007 and $1.0 million is expected to be paid in December 2007. The balance represents the long-term portion of the Trust's estimated liability for the unit-based incentive plan as at December 31, 2006. This amount is payable in December 2007 and 2008. 10. UNITHOLDERS' EQUITY Unitholders' Equity The Trust is authorized to issue 500 million Trust units of which 78 million units were issued and outstanding as at December 31, 2006 (December 31, 2005 - 74 million). Each unit is transferable, carries the right to one vote and represents an equal undivided beneficial interest in any distributions from the Trust and in the assets of the Trust in the event of termination or winding up of the Trust. All trust units are of the same class with equal rights and privileges. Redemption Unitholders may redeem their trust units for cash at any time, up to a maximum value of $100,000 in any calendar month, by delivering their unit certificates to the Trustee, accompanied by a properly completed notice requesting redemption. The redemption amount per trust unit will be the lesser of 95 percent of the market price of the units on the principal market on which the units are quoted as trading during the ten-trading day period commencing immediately after the date on which the units are surrendered for redemption, and the closing market price of the trust units or the principal market on which the units are quoted for trading on the date that the trust units are tendered for redemption. Units Issued: --------------------------------------------------------------------- 2006 2005 ----------------------------------------- Units Amount Units Amount --------------------------------------------------------------------- Balance, beginning of the year 73,977 $753,585 53,064 $476,620 Issued under management agreement restructuring (Note 3) 1,592 30,000 - - Issued for cash - - 17,000 232,900 Less issue expenses - (29) - (12,333) Issued from Distribution Reinvestment Plan 2,402 41,430 3,913 56,398 --------------------------------------------------------------------- Balance, end of the year 77,971 $824,986 73,977 $753,585 --------------------------------------------------------------------- --------------------------------------------------------------------- Distribution Reinvestment Plan The Trust has in place a Distribution Reinvestment Plan ("DRIP") and a Premium Distribution Reinvestment Plan ("Premium DRIP"). The regular DRIP entitles Unitholders to reinvest cash distributions in additional units of the Trust at 95% of the average market price with no additional fees or commissions. The average market price is the arithmetic average of the daily volume weighted average trading price of the Trust units during a defined period before the distribution payment date. The Premium Distribution component of the Plan allows Unitholders to exchange new Trust units, acquired by reinvesting their cash distributions, for a cash payment from the Plan Broker equal to 102% of the monthly distribution on the applicable distribution payment date. The Trust units issued under the Premium Distribution component of the Plan at a 5% discount to the average market price will be delivered to the Plan Broker in exchange for 102% of the cash distribution payable on the participant's existing Trust units. At certain times and at the discretion of management, these premium distributions may be suspended. Distributions The Trust makes monthly distributions of its distributable cash to unitholders on the fifteenth day, or if such day is not a business day, the next business day. Cash distributions are calculated in accordance with the Trust's Indenture. Distributions since the inception of the Trust are as follows: --------------------------------------------------------------------- Other Return of Income Capital Total --------------------------------------------------------------------- Accumulated distributions at December 31, 2004 $195,243 $195,598 $390,841 2005 distributions 142,050 - 142,050 --------------------------------------------------------------------- Accumulated distributions at December 31, 2005 337,293 195,598 532,891 2006 distributions 169,589 - 169,589 --------------------------------------------------------------------- Accumulated distributions at December 31, 2006 $506,882 $195,598 $702,480 --------------------------------------------------------------------- --------------------------------------------------------------------- Deficit The deficit is comprised of the following: --------------------------------------------------------------------- 2006 2005 --------------------------------------------------------------------- Accumulated income $333,994 $273,796 Accumulated cash distributions (702,480) (532,891) --------------------------------------------------------------------- Deficit, end of year $(368,486) $(259,095) --------------------------------------------------------------------- --------------------------------------------------------------------- During 2006 presentation changes were made to combine the previously reported accumulated income and accumulated cash distributions figures on the balance sheet into a single deficit figure. The Trust has historically paid cash distributions in excess of accumulated income as cash distributions are based on cash flow generated in the period whereas accumulated earnings are based on net income which includes non-cash items such as depletion and depreciation, unit-based compensation charges and future income tax provisions. 11. INCOME TAXES The provision for income taxes in the financial statements differs from the result that would have been obtained by applying the combined federal and provincial tax rate to income before income taxes as follows: --------------------------------------------------------------------- 2006 2005 --------------------------------------------------------------------- Income before taxes $59,125 $100,838 Statutory income tax rate 39.0% 39.0% --------------------------------------------------------------------- Expected income tax expense 23,059 39,327 Increase (decrease) resulting from: Non-deductible Crown charges 8,471 16,657 Resource allowance (9,208) (17,260) Alberta Royalty Tax Credit (39) (127) Valuation allowance 200 459 Net income of the Trust (24,937) (37,019) Other 1,045 503 --------------------------------------------------------------------- Current and future income tax expense (recovery) (1,409) 2,540 Capital taxes (recovery) 336 (240) --------------------------------------------------------------------- Income and capital taxes (recovery) (1,073) 2,300 --------------------------------------------------------------------- --------------------------------------------------------------------- The future income tax asset is comprised of: --------------------------------------------------------------------- 2006 2005 --------------------------------------------------------------------- Property, plant and equipment $6,794 $1,536 Future tax liability resulting from different year ends - 532 Non-capital tax loss carry forward (3,197) (2,440) Asset retirement obligation (7,889) (7,452) Other (400) - --------------------------------------------------------------------- (4,692) (7,824) Valuation allowance 1,347 5,688 --------------------------------------------------------------------- Future income tax asset $(3,345) $(2,136) --------------------------------------------------------------------- --------------------------------------------------------------------- The Trust meets the criteria qualifying it for income tax treatment permitting a tax deduction for distributions paid to the unit holders in addition to other deductions available in the Trust. At December 31, 2006, the book amounts of the Trust's assets and liabilities exceed the tax basis by $192.2 million (2005 - $319.3 million). On December 21, 2006, the Minister of Finance released for comment draft legislation concerning the taxation of certain publicly traded trusts. The legislation reflects proposals originally announced by the Minister on October 31, 2006. Under the proposed legislation, distributions to unitholders will not be deductible by publicly traded income trusts and, as a result, the Trust will be taxed on its income similar to corporations. The proposed rules, if passed into law, would be applicable commencing in 2011. However, if the proposed legislation is implemented, the Trust would be required to recognize in its accounts, in the period in which the change is substantially enacted, future income taxes on temporary differences in the Trust. 12. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT Fair Values The carrying value of the Trust's financial instruments, including accounts receivable, bank debt, and accounts payable and accrued liabilities approximate their fair value due to their short terms to maturity and variable interest rates. Credit Risk Management Accounts receivable includes amounts due from NAL Resources for oil, natural gas and natural gas liquids sales. Oil and gas sales marketing is conducted by the Manager on behalf of the Trust and NAL Resources generally with large, creditworthy purchasers, for which the Trust views the credit risk as low. The credit risk associated with NAL Resources is also considered to be minimal as amounts owing are from actual collections of oil and gas sales. Interest Rate The Trust is exposed to interest rate risk to the extent that bank debt is at a floating interest rate. Commodity Price Risk Management As at December 31, 2006 the Trust had entered into the following derivatives to protect its 2007 cash flow from the volatility of oil and natural gas commodity prices. For 2007, NAL has the following WTI oil contracts in place: ------------------------------------------------------------------------- Total Bought Volume Volume Put Sold Call Swap ------ ------ ------ --------- ---- Days Contract Bbls/d Bbls US$/bbl US$/bbl US$/bbl ------------------------------------------------------------------------- COLLARS 181 2-way 300 54,300 70.00 85.85 - 181 2-way 300 54,300 72.00 88.10 - 365 2-way 500 182,500 62.00 68.25 - 365 2-way 200 73,000 64.00 71.00 - 184(1) 2-way 300 55,200 62.00 69.75 - ------------------------------------------------------------------------- Weighted average Collars 1,148 419,300 64.68 73.78 - ------------------------------------------------------------------------- SWAPS ------------------------------------------------------------------------- 365 Swap 500 182,500 - - 65.05 365 Swap 500 182,500 - - 72.33 184(1) Swap 300 55,200 - - 61.07 ------------------------------------------------------------------------- Weighted average Swaps 1,150 420,200 - - 67.70 ------------------------------------------------------------------------- For 2007, NAL has the following AECO natural gas contracts in place ------------------------------------------------------------------------- Total Bought Volume Volume Put Sold Call Swap ------ ------ ------- --------- ---- Days Contract GJ/d GJ Cdn$/GJ Cdn$/GJ Cdn$/GJ ------------------------------------------------------------------------- COLLARS 365 2-way 3,000 1,095,000 6.00 8.10 - 365 2-way 1,000 365,000 6.50 8.85 - 365 2-way 1,000 365,000 7.00 8.70 - 365 2-way 1,000 365,000 6.75 8.60 - 365 2-way 2,000 730,000 7.00 8.70 - 365 2-way 1,000 365,000 7.25 8.51 - ------------------------------------------------------------------------- Weighted average Collars 9,000 3,285,000 6.61 8.48 - ------------------------------------------------------------------------- SWAPS ------------------------------------------------------------------------- 365 Swap 3,000 1,095,000 - - 6.77 365 Swap 1,000 365,000 - - 7.90 334(1) Swap 1,500 501,000 - - 7.20 306(1) Swap 1,500 459,000 - - 7.43 ------------------------------------------------------------------------- Weighted average Swaps 6,630 2,420,000 - - 7.15 ------------------------------------------------------------------------- (1) Entered into subsequent to year-end. The estimated fair value of the above contracts excluding the contracts entered into subsequent to year-end, all of which qualify for hedge accounting, was a gain of $4,500,000 as at December 31, 2006. The fair value of these instruments is not recorded on the Balance Sheet. 13. COMMITMENTS At December 31, 2006 the Trust had the following contractual obligations and commitments: --------------------------------------------------------------------- ($000s) 2007 2008 2009 2010 2011 --------------------------------------------------------------------- Office lease(1) 2,734 2,580 2,580 2,365 - Transportation agreement 716 716 80 - - Processing agreement(2) 491 469 446 428 414 Drilling rigs(3) 1,975 494 - - - Retention bonus(4) 938 938 - - - --------------------------------------------------------------------- (1) Represents the full amount of office lease commitments, both base rent and operating costs, held by the Manager of which the Trust is allocated a pro rata share (currently approximately 53 percent) of the expense on a monthly basis. (2) Represents gas processing agreement under take or pay arrangement. (3) Represents the Trust's share of the minimum payments required under drilling rig contracts held by NAL Resources. (4) Represents the Trust's share of expected future payments under a staff retention program. TRADING PERFORMANCE ------------------------------------------------------------------------- For the Quarter Ended ------------------------------------------------------------------------- 31-Dec-06 30-Sep-06 31-Dec-05 30-Sep-05 ------------------------------------------------------------------------- PRICE ------------------------------------------------------------------------- High $18.74 $21.70 $19.15 $17.80 ------------------------------------------------------------------------- Low $11.80 $16.14 $13.39 $14.31 ------------------------------------------------------------------------- Close $12.31 $17.57 $18.08 $15.95 ------------------------------------------------------------------------- Volume 27,691,472 12,786,792 16,922,700 18,992,928 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Full Year ------------------------------------------------------------------------- 2006 2005 ------------------------------------------------------------------------- PRICE ------------------------------------------------------------------------- High $21.70 $19.15 ------------------------------------------------------------------------- Low $11.80 $12.82 ------------------------------------------------------------------------- Close $12.31 $18.08 ------------------------------------------------------------------------- Volume 65,412,678 72,097,477 ------------------------------------------------------------------------- NAL Oil & Gas Trust is an open-end investment trust that generates distributions through the acquisition, development, production and marketing of oil, natural gas and natural gas liquids. The Trust owns high quality assets in Alberta, Saskatchewan and Ontario. Trust units trade on the Toronto Stock Exchange under the symbol "NAE.UN".

For further information:

For further information: Gordon Currie - Manager, Investor Relations,
Telephone: (403) 294-3620, Toll Free: (888) 223-8792, Fax: (403) 515-3407,
Email: Investor.Relations@nal.ca, Website: www.nal.ca

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NAL Oil & Gas Trust

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