Crescent Point Energy Trust announces fourth quarter 2006 results



    CALGARY, March 12 /CNW/ - Crescent Point Energy Trust, ("Crescent Point"
or the "Trust") (TSX: CPG.UN), is pleased to announce its operating and
financial results for the fourth quarter and twelve months ended December 31,
2006.

    
    FINANCIAL AND OPERATING HIGHLIGHTS

    -------------------------------------------------------------------------
    ($000, except trust    Three months ended              Year ended
     units, per trust          December 31                December 31
     unit and per                               %                          %
     boe amounts)          2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Financial
    Cash flow from
     operations(1)       43,843   33,424       31  189,135  109,785       72
      Per unit(1)(2)       0.63     0.83      (24)    2.98     3.04       (2)
    Net income            6,918   33,453      (79)  68,947   38,509       79
      Per unit(2)          0.10     0.87      (89)    1.05     1.12       (6)
    Cash distributions   41,322   22,835       81  150,277   74,591      101
      Per unit(2)          0.60     0.59        2     2.40     2.14       12
    Payout ratio (%)(1)      94       68       26       79       68       11
      Per unit
       (%)(1)(2)             95       71       24       81       70       11
    Net debt(1)(3)      227,905  194,545       17  227,905  194,545       17
    Capital
     acquisitions
     (net)(4)             2,002  158,583       99  507,929  301,235       69
    Development capital
     expenditures(4)     30,039    8,696      245  109,995   35,720      208
    Weighted average
     trust units
     outstanding (mm)
      Basic                68.3     38.6       77     61.5     34.3       79
      Diluted              69.8     40.5       72     63.6     36.1       76
    -------------------------------------------------------------------------
    Operating
    Average daily
     production
      Crude oil and
       NGL (bbls/d)      17,967   10,637       69   17,417    9,196       89
      Natural gas
       (mcf/d)           20,410   18,927        8   19,833   17,810       11
    -------------------------------------------------------------------------
      Total (boe/d)      21,369   13,791       55   20,723   12,164       70
    -------------------------------------------------------------------------
    Average selling
     prices(5)
      Crude oil and
       NGL ($/bbl)        53.75    58.36       (8)   60.03    58.57        2
      Natural gas
       ($/mcf)             6.45    10.81      (40)    6.33     8.38      (24)
    -------------------------------------------------------------------------
      Total ($/boe)       51.35    59.85      (14)   56.52    56.55        -
    -------------------------------------------------------------------------
    Netback ($/boe)
      Oil and gas sales   51.35    59.85      (14)   56.52    56.55        -
      Royalties           (9.74)  (12.20)     (20)  (11.90)  (11.27)       6
      Operating
       expenses          (10.42)   (8.96)      16    (9.18)   (8.08)      14
      Transportation      (1.68)   (1.08)      56    (1.35)   (1.04)      30
    -------------------------------------------------------------------------
      Netback prior
       to realized
       financial
       instruments        29.51    37.61      (22)   34.09    36.16       (6)
      Realized loss on
       financial
       instruments        (1.87)   (5.49)     (66)   (4.01)   (7.42)     (46)
    -------------------------------------------------------------------------
      Netback             27.64    32.12      (14)   30.08    28.74        5
    -------------------------------------------------------------------------
    (1) Cash flow from operations, payout ratio and net debt as presented do
        not have any standardized meaning prescribed by GAAP and therefore
        may not be comparable with the calculation of similar measures
        presented by other entities.
    (2) The per unit amounts (with the exception of per unit distributions)
        are the per unit - diluted amounts.
    (3) Net debt includes working capital, but excludes the risk management
        liabilities and assets. Working capital as at December 31, 2006
        includes the $30.0 million long-term investment in Mission Oil & Gas
        Inc.
    (4) The capital acquisitions include the purchase price and assumed net
        debt. These amounts differ from the amounts allocated to property,
        plant and equipment as there were allocations made to goodwill, other
        assets and liabilities. The development capital expenditures in the
        table exclude capitalized administration costs. The prior period
        results have been restated to conform to the current period
        presentation.
    (5) The average selling prices reported are before realized financial
        instruments.
    

    HIGHLIGHTS

    In the fourth quarter of 2006, Crescent Point continued to execute its
integrated business strategy of acquiring, exploiting and developing high
quality, long life light and medium oil and natural gas properties.
    The Trust achieved low 2006 finding and development costs, excluding
change in future development costs, of $9.86 per proved plus probable boe and
$13.06 per proved boe of reserves. This equates to a proved plus probable
recycle ratio of 3.5 times. Including change in future development costs, the
Trust's 2006 finding and development costs are $13.53 per proved plus probable
boe and $14.85 per proved boe.
    Crescent Point's 2006 finding, development and acquisition costs,
excluding change in future development costs, are $12.34 per proved plus
probable boe and $15.97 per proved boe of reserves. This equates to a proved
plus probable recycle ratio of 2.8 times. Including future development costs,
the Trust's finding, development and acquisition costs for 2006 are $13.16 per
proved plus probable boe and $16.36 per proved boe.
    The Trust's five year rolling average for finding and development costs,
excluding change in future development costs, is $9.97 per proved plus
probable boe, which equates to a proved plus probable recycle ratio of
3.2 times. Crescent Point's five year rolling average for finding, development
and acquisition costs, excluding change in future development costs for proved
plus probable reserves is $12.40 per boe which equates to a proved plus
probable recycle ratio of 2.7 times.
    Crescent Point increased its net asset value ("NAV") per unit to $21.61
at year end 2006 from $15.12 at year end 2005, based on independent
engineering year-end price forecasts discounted at 5 percent. With the closing
of the acquisition of Mission Oil & Gas Inc. on February 9, 2007, the Trust's
NAV per unit is $22.05. Utilizing forward curve prices as of February 9, 2007,
the Trust's NAV per unit increases to $25.66. The Trust has increased NAV per
unit every year since inception.
    Crescent Point replaced 147 percent of 2006 production, not including
reserves added through acquisitions. Including acquisitions, the Trust
increased its year end reserve base by 94 percent on a proved basis and 88
percent on a proved plus probable basis. Year end 2006 reserves are
64.0 million boe proved and 90.3 million boe proved plus probable, up from
32.9 million boe proved and 47.9 million boe proved plus probable at the end
of 2005. With the acquisition of Mission, the Trust's independently assigned
reserve base increased by 15.9 million boe and 25.0 million boe to
79.9 million boe proved and 115.3 million boe proved plus probable,
respectively.
    Crescent Point increased its proved plus probable reserve life index to
11.9 years from 11.1 years.
    The Trust spent $30.0 million on development capital activities in the
fourth quarter, including the drilling of 23 (14.8 net) wells with a 100
percent success rate adding over 900 boe/d of initial interest production.
    The Trust exceeded its fourth quarter average daily production target,
producing 21,369 boe/d for the quarter. This represents a 55 percent increase
from the 13,791 boe/d produced in the fourth quarter of 2005.
    Crescent Point's cash flow from operations increased by 31 percent to
$43.8 million in the fourth quarter of 2006, compared to $33.4 million in the
fourth quarter of 2005.
    Crescent Point maintained consistent monthly distributions of $0.20 per
unit, totaling $0.60 per unit for the fourth quarter of 2006. This represents
a 2 percent increase from the $0.59 per unit distributed in the fourth quarter
of 2005 and resulted in an overall payout ratio of 94 percent and a 95 percent
payout ratio on a per unit - diluted basis. The Trust's overall 2006 payout
per unit - diluted was 81 percent and 2007 is forecasted to be 77 percent on a
per unit - diluted basis.
    The Trust continued to execute its core strategy of managing commodity
price risk using a combination of fixed price swaps, costless collars, and put
option instruments. As at March 1, 2007, the Trust had hedged 53 percent, 44
percent and 22 percent of production, net of royalty interest, for 2007, 2008
and 2009, respectively.
    On November 22, 2006, the Trust's borrowing base was increased to
$470 million. It is anticipated that the base will increase to $575 million
upon renewal in the second quarter of 2007. The Trust's balance sheet remains
strong with projected 2007 net debt to 12 month cash flow of less than
1.0 times.
    There were no acquisitions announced or closed during the fourth quarter.
The Trust closed the previously announced Plan of Arrangement ("the Plan") to
acquire Mission Oil & Gas Inc. ("Mission") on February 9, 2007. With the
closing of the Plan, Crescent Point acquired more than 7,000 boe/d of high
quality, long life, light sweet oil and natural gas production, of which more
than 5,000 boe/d is from the Viewfield Bakken resource play in southeast
Saskatchewan. Crescent Point estimates that the Viewfield Bakken pool is the
fifth largest light oil pool discovered in western Canada, containing an
estimated 1 billion barrels of original oil in place ("OOIP"). The completion
of the Plan increased the Trust's resource base to more than 2.5 billion
barrels OOIP and added more than 900 (570 net) low risk development drilling
locations.
    On October 26, 2006, Crescent Point announced a proposed reorganization
of the Trust's structure, which was approved by unitholders at a Special
Meeting held on November 27, 2006 and completed on March 1, 2007. The
reorganization results in the business of the Trust being carried on through
limited partnerships owned by the Trust, similar to reorganizations announced
by a number of other trusts. It provides the Trust with a "flow through"
structure that is expected to maximize the cash available for distribution.

    OPERATIONS REVIEW

    Forward-Looking Statements

    This report may contain forward-looking statements including expectations
of future production, cash flow and earnings. These statements are based on
current beliefs and expectations based on information available at the time
the assumption was made. By its nature, such forward-looking information is
subject to a number of risks, uncertainties and assumptions, which could cause
actual results or other expectations to differ materially from those
anticipated, including those material risks discussed in our annual
information form under "Risk Factors" and in our Management's Discussion and
Analysis for the year ended December 31, 2006, under "Business Risks and
Prospects". The material assumptions are disclosed in the Results of
Operations section of this press release under the headings "Cash
Distributions", "Taxation of Cash Distributions", "Capital Expenditures",
"Asset Retirement Obligation", "Liquidity and Capital Resources", "Critical
Accounting Estimates", "New Accounting Pronouncements", and "Business Risks
and Prospects". These risks include, but are not limited to: the risks
associated with the oil and gas industry (e.g., operational risks in
development, exploration and production; delays or changes in plans with
respect to exploration or development projects or capital expenditures; the
uncertainty of reserve estimates; the uncertainty of estimates and projections
relating to production, costs and expenses, and health, safety and
environmental risks), commodity price and exchange rate fluctuations and
uncertainties resulting from potential delays or changes in plans with respect
to exploration or development projects or capital expenditures. Additional
information on these and other factors that could affect Crescent Point's
operations or financial results are included in Crescent Point's reports on
file with Canadian securities regulatory authorities. Readers are cautioned
not to place undue reliance on this forward-looking information, which is
given as of the date it is expressed herein or otherwise and Crescent Point
undertakes no obligation to update publicly or revise any forward-looking
information, whether as a result of new information, future events or
otherwise.

    Fourth Quarter Operations Summary

    During the fourth quarter of 2006, Crescent Point continued to
aggressively implement management's business strategy of creating sustainable,
value-added growth in reserves, production and cash flow through acquiring,
exploiting and developing high quality, long life light and medium oil and
natural gas properties.
    Crescent Point achieved another record quarter for production in the
fourth quarter. Production averaged 21,369 boe/d, exceeding the Trust's market
guidance of 20,500 boe/d. The Trust participated in the drilling of 23 (14.8
net) oil wells, achieving a 100 percent success rate and adding in excess of
900 boe/d of initial interest production.
    In mid-October 2006, the Trust halted fourth quarter drilling and focused
on production optimization opportunities. The decision was in response to
third quarter 2006 drilling exceeding expectations and the anticipated
December 1, 2006 closing of the Mission acquisition. Due to the subsequent
delay and uncertainty surrounding the Mission acquisition, the Trust then
accelerated winter drilling operations in December with most of the associated
production being brought on stream in the first quarter of 2007. This
increased fourth quarter capital expenditures relative to production
additions.

    
    Drilling Results

    -------------------------------------------------------------------------
    Three months
     ended December                                                      %
     31, 2006          Gas  Oil  D&A  Service  Standing  Total   Net  Success
    -------------------------------------------------------------------------
    Southeast
     Saskatchewan        -    9    -                  -      9   6.2    100%
    Southwest
     Saskatchewan        -    9    -        -         -      9   3.9    100%
    South/Central
     Alberta             -    4    -        -         -      4   4.0    100%
    Northeast BC
     and West Peace
     River Arch,
     Alberta             -    1    -        -         -      1   0.7    100%
    -------------------------------------------------------------------------
    Total                -   23    -                  -     23  14.8    100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Year ended
     December 31,                                                        %
     2006              Gas  Oil  D&A  Service  Standing  Total   Net  Success
    -------------------------------------------------------------------------
    Southeast
     Saskatchewan        -   59    -        1         -     60  53.2    100%
    Southwest
     Saskatchewan        -   30    -        -         -     30  15.2    100%
    South/Central
     Alberta             -   10    -        -         -     10   7.6    100%
    Northeast BC
     and West Peace
     River Arch,
     Alberta             -    3    -        -         -      3   1.4    100%
    -------------------------------------------------------------------------
    Total                -  102    -        1         -    103  77.4    100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Southeast Saskatchewan

    In the fourth quarter of 2006, Crescent Point participated in the
drilling of 9 (6.2 net) oil wells in southeast Saskatchewan, of which 8 (5.8
net) were horizontal wells. The Trust achieved a 100 percent success rate on
the wells, which were located primarily in the Trust's core areas of Manor and
Glen Ewen. Initial interest production added was approximately 550 boe/d.
    The Glen Ewen gas plant was constructed during the quarter and was
commissioned in early February 2007 in time for a multi well drilling program
scheduled for the first quarter of 2007. 2 (2.0 net) wells of the program were
drilled in December.
    Revolving restrictions on the Enbridge Pipelines gathering system in
southeast Saskatchewan resulted in an average production restriction of
approximately 250 boe/d during the fourth quarter.

    Southwest Saskatchewan

    The Trust continued to optimize waterflood performance at the three
operated Battrum units. A total of 9 (3.9 net) wells were drilled achieving a
100 percent success rate and adding initial interest production of 250 boe/d.
The wells were completed and tied in through December 2006 and January 2007.
Workovers were completed on an additional 17 (7.8 net) wells at a cost of
$0.2 million, adding 100 boe/d at an average on stream cost of $2,000 per
boe/d.
    At the Cantuar Unit, 19 (10.5 net) wells drilled to the end of the third
quarter were being tied in and evaluated by the operator with expectations of
initial production rates of 40 boe/d per well.

    South/Central Alberta

    At Sounding Lake, gathering and injection line optimization work was
completed in the fourth quarter to accommodate additional fluid handling and
revised water injection schemes. 4 (4.0 net) oil wells were drilled adding
over 100 boe/d of interest production. These infill wells are expected to
increase pool recoveries and optimize water flood patterns in the future.

    Northeast British Columbia and Peace River Arch, Alberta

    At Worsley, the Trust received Good Production Practice ("GPP") approval
to remove regulatory production restrictions at the Charlie Lake S pool and at
the Charlie Lake Z pool. The Trust applied for GPP at the Charlie Lake T pool
in the fourth quarter of 2006 and approval is anticipated in the second or
third quarter of 2007. The Trust is also reviewing with other area operators
the opportunity to concurrently produce from more than one reservoir in a
single well bore. Crescent Point has negotiated an additional 1.0 mmcf/d of
processing capacity and continues to work with operators of several area
plants to expand and increase existing processing options and capacities.
1 (0.7 net) well was drilled in the Mulligan area and is currently being
evaluated. Up to 9 (6.9 net) wells are planned for the 2007 drilling season.

    Acquisitions

    On September 11, 2006, the Trust announced that Independent Committees of
the Boards of Directors of Crescent Point and Mission Oil & Gas Inc. had
unanimously approved a proposal pursuant to which the Trust would exchange, by
way of Plan of Arrangement, all of Mission's issued and outstanding shares for
trust units of Crescent Point.
    Under the terms of the Plan, each issued and outstanding Mission share
would be exchanged for 0.695 trust units of Crescent Point.
    A special meeting of the holders of Mission common shares to approve the
Plan was scheduled to be held on November 30, 2006, with closing of the Plan
anticipated for December 1, 2006. Due to the uncertainty created by the
October 31, 2006 federal government announcement of a proposed tax (the
"Proposal") on the distributions of certain income trusts, including Crescent
Point, the Independent Committees of the Boards of Directors of Crescent Point
and Mission decided to delay the special meeting to further assess the
implications of the Proposal.
    On December 12, 2006, Crescent Point revised the Plan such that each
outstanding common share of Mission would be exchanged for 0.695 trust units
of Crescent Point plus $0.78 cash. On January 12, 2007, the Trust announced
that the Independent Committees of the Boards of Directors of Crescent Point
and Mission had determined that the revised Plan was, in the case of Crescent
Point, in the best interests of the Crescent Point unitholders and, in the
case of Mission, in the best interests of the Mission shareholders. The
revised Plan was approved by Mission shareholders at a special meeting held on
February 8, 2007, and closed on February 9, 2007.
    With the closing of the Plan, the Trust acquired more than 7,000 boe/d of
production, of which more than 5,000 boe/d is from the Viewfield Bakken
resource play in the heart of Crescent Point's core southeast Saskatchewan
operating area. Crescent Point estimates that the Viewfield Bakken pool is the
fifth largest light oil pool discovered in western Canada, containing an
estimated 1 billion barrels of original oil in place ("OOIP"). The completion
of the Plan increased the Trust's resource base to more than 2.5 billion
barrels OOIP and added more than 900 (570 net) low risk development drilling
locations. This resource base extends the Trust's drilling inventory to more
than 6 years and positions Crescent Point for significant long term
development and reserve growth opportunities.

    
    Summary of Reserves (Escalated Pricing)

    As at December 31, 2006(1)

                               ----------------------------------------------
                                                  RESERVES(2)
                               ----------------------------------------------
                                        Oil (mstb)            Gas (mmscf)
    -------------------------------------------------------------------------
    Description                       Gross        Net      Gross        Net
    -------------------------------------------------------------------------
    Proved producing                 48,439     40,200     29,520     23,784
    Proved non-producing              8,415      7,213      9,439      6,593
    -------------------------------------------------------------------------
    Total proved                     56,854     47,412     38,959     30,377
    Probable                         23,635     19,745     14,446     11,261
    -------------------------------------------------------------------------
    Total proved plus
     probable(3)                     80,489     67,157     53,405     41,638
    -------------------------------------------------------------------------


                               ----------------------------------------------
                                                  RESERVES(2)
                               ----------------------------------------------
                                        NGL (mbbls)          Total (mboe)
    -------------------------------------------------------------------------
    Description                       Gross        Net      Gross        Net
    -------------------------------------------------------------------------
    Proved producing                    306        245     53,665     44,409
    Proved non-producing                298        225     10,286      8,536
    -------------------------------------------------------------------------
    Total proved                        604        470     63,951     52,945
    Probable                            327        255     26,370     21,876
    -------------------------------------------------------------------------
    Total proved plus
     probable(3)                        931        725     90,321     74,821
    -------------------------------------------------------------------------


                               ----------------------------------------------
                                      BEFORE TAX NET PRESENT VALUE ($000)
                               ----------------------------------------------
                                                Discount Rate
    -------------------------------------------------------------------------
    Description                Undiscounted     10%        12%        15%
    -------------------------------------------------------------------------
    Proved producing              1,473,196    848,765    788,307    714,801
    Proved non-producing            240,485    132,286    119,617    103,674
    -------------------------------------------------------------------------
    Total proved                  1,713,681    981,051    907,924    818,475
    Probable                        843,521    279,546    241,785    199,505
    -------------------------------------------------------------------------
    Total proved plus
     probable(3)                  2,557,202  1,260,597  1,149,709  1,017,980
    -------------------------------------------------------------------------
    (1) Based on GLJ's January 1, 2007 escalated price forecast.
    (2) "Gross Reserves" are the total Trust's interest share before the
        deduction of any royalties. "Net Reserves" are the total Trust's
        interest share after deducting royalties.
    (3) Numbers may not add due to rounding.


    Summary of Reserves (Constant Pricing)

    As at December 31, 2006

                               ----------------------------------------------
                                                  RESERVES(1)
                               ----------------------------------------------
                                        Oil (mstb)            Gas (mmscf)
    -------------------------------------------------------------------------
    Description                       Gross        Net      Gross        Net
    -------------------------------------------------------------------------
    Proved producing                 48,558     40,279     28,852     23,214
    Proved non-producing              8,405      7,200      9,432      6,587
    -------------------------------------------------------------------------
    Total proved                     56,963     47,479     38,284     29,801
    Probable                         23,738     19,849     14,370     11,189
    -------------------------------------------------------------------------
    Total proved plus
     probable(2)                     80,701     67,328     52,654     40,990
    -------------------------------------------------------------------------


                               ----------------------------------------------
                                                  RESERVES(1)
                               ----------------------------------------------
                                        NGL (mbbls)          Total (mboe)
    -------------------------------------------------------------------------
    Description                       Gross        Net      Gross        Net
    -------------------------------------------------------------------------
    Proved producing                    306        245     53,673     44,394
    Proved non-producing                298        225     10,276      8,521
    -------------------------------------------------------------------------
    Total proved                        604        470     63,949     52,915
    Probable                            329        257     26,461     21,971
    -------------------------------------------------------------------------
    Total proved plus
     probable(2)                        933        727     90,410     74,886
    -------------------------------------------------------------------------


                               ----------------------------------------------
                                      BEFORE TAX NET PRESENT VALUE ($000)
                               ----------------------------------------------
                                                Discount Rate
    -------------------------------------------------------------------------
    Description                Undiscounted      10%        12%        15%
    -------------------------------------------------------------------------
    Proved producing              1,353,810    799,078    743,024    674,316
    Proved non-producing            225,055    123,345    111,277     96,049
    -------------------------------------------------------------------------
    Total proved                  1,578,865    922,423    854,301    770,365
    Probable                        684,098    249,011    216,912    180,277
    -------------------------------------------------------------------------
    Total proved plus
     probable(2)                  2,262,963  1,171,434  1,071,213    950,642
    -------------------------------------------------------------------------
    (1) "Gross Reserves" are the total Trust's interest share before
        deduction of any royalties. "Net Reserves" are the total Trust's
        interest share after deducting royalties.
    (2) Numbers may not add due to rounding.


    Reserve Reconciliation (Escalated Pricing)
    Gross Reserves(1)

    For the year ended December 31, 2006

                                             --------------------------------
                                                 CRUDE OIL AND NGL (mbbl)
                                             --------------------------------
                                                Proved   Probable      Total
    -------------------------------------------------------------------------
    Opening balance January 1, 2006             28,379     13,022     41,401
    Acquired                                    28,081      8,079     36,160
    Disposed                                         -          -          -
    Production                                  (6,357)         -     (6,357)
    Development                                  3,432      2,773      6,205
    Technical revisions                          3,923         88      4,011
    -------------------------------------------------------------------------
    Closing balance December 31, 2006(2)        57,458     23,962     81,420
    -------------------------------------------------------------------------


                                             --------------------------------
                                                   NATURAL GAS (mmscf)
                                             --------------------------------
                                               Proved    Probable      Total
    -------------------------------------------------------------------------
    Opening balance January 1, 2006            27,361      11,890     39,251
    Acquired                                   12,444       3,342     15,787
    Disposed                                        -           -          -
    Production                                 (7,239)          -     (7,239)
    Development                                   883         513      1,395
    Technical revisions                         5,510      (1,299)     4,211
    -------------------------------------------------------------------------
    Closing balance December 31, 2006(2)       38,959      14,446     53,405
    -------------------------------------------------------------------------


                                             --------------------------------
                                                        BOE (mboe)
                                             --------------------------------
                                               Proved    Probable      Total
    -------------------------------------------------------------------------
    Opening balance January 1, 2006             32,940     15,003     47,943
    Acquired                                    30,155      8,636     38,791
    Disposed                                         -          -          -
    Production                                  (7,564)         -     (7,564)
    Development                                  3,580      2,858      6,437
    Technical revisions                          4,841       (128)     4,713
    -------------------------------------------------------------------------
    Closing balance December 31, 2006(2)        63,951     26,370     90,321
    -------------------------------------------------------------------------
    (1) Based on GLJ's January 1, 2007 escalated price forecast. "Gross
        reserves" are the Trust's working-interest share before deduction of
        any royalties. "Net Reserves" are the total Trust's interest share
        after deducting royalties.
    (2) Numbers may not add due to rounding.


    Finding, Development and Acquisition Costs
    (excluding future development costs)

    For the year ended December 31, 2006

                 ------------------------------------------------------------
                                                                  FINDING,
                    CAPITAL                                     DEVELOPMENT
                  EXPENDITURES                                AND ACQUISITION
                     (1)(4)            RESERVES(3)              COSTS(1)(2)
                 ------------------------------------------------------------
                                                  Proved              Proved
                                                   Plus                Plus
                                 Total Proved    Probable    Proved  Probable
    -------------------------------------------------------------------------
                     $000    %     mboe    %     mboe    %    $/boe    $/boe
    -------------------------------------------------------------------------
    Exploration
     development
     and
     revisions   $109,995   18%   8,421   22%  11,151   22%  $13.06   $ 9.86

    Acquisitions,
     net of
     dispos-
     itions      $506,156   82%  30,155   78%  38,791   78%  $16.79   $13.05
    -------------------------------------------------------------------------
    Total        $616,151        38,576        49,942        $15.97   $12.34
    -------------------------------------------------------------------------
    (1) Exploration development and revisions exclude the change during the
        most recent financial year in estimated future development costs
        relating to proved and proved plus probable reserves respectively.
        These costs would add $15.0 million and $40.9 million respectively,
        to the proved and proved plus probable reserves categories. Including
        these changes, the proved and proved plus probable finding,
        development and acquisition costs are $16.36 and $13.16 per barrel
        respectively.
    (2) Including change in future development costs, finding and development
        costs are $14.85 per proved boe and $13.53 per proved plus probable
        boe.
    (3) Gross Trust interest reserves are used in this calculation (interest
        reserves, before deduction of any royalties).
    (4) The capital expenditures includes the purchase price of corporate
        acquisitions rather than the amounts allocated to property, plant and
        equipment for accounting purposes. The capital expenditures also
        exclude capitalized administration costs and acquisition costs.


    Summary of Reserves, Including February 9, 2007 Acquisition of Mission
    Oil & Gas Inc. (Escalated Pricing)

    As at January 1, 2007(1)(2)

                               ----------------------------------------------
                                                  RESERVES(3)
                               ----------------------------------------------
                                       Oil (mstb)            Gas (mmscf)
    -------------------------------------------------------------------------
    Description                       Gross        Net      Gross        Net
    -------------------------------------------------------------------------
    Proved producing                 55,912     46,897     34,742     28,137
    Proved non-producing             13,744     12,096     14,586     11,164
    -------------------------------------------------------------------------
    Total proved                     69,656     58,993     49,328     39,301
    Probable                         30,886     26,260     19,778     15,943
    -------------------------------------------------------------------------
    Total proved plus
     probable(4)                    100,542     85,253     69,106     55,244
    -------------------------------------------------------------------------


                               ----------------------------------------------
                                                  RESERVES(3)
                               ----------------------------------------------
                                        NGL (mbbls)          Total (mboe)
    -------------------------------------------------------------------------
    Description                       Gross        Net      Gross        Net
    -------------------------------------------------------------------------
    Proved producing                    811        709     62,513     52,295
    Proved non-producing              1,220      1,068     17,396     15,025
    -------------------------------------------------------------------------
    Total proved                      2,031      1,777     79,909     67,320
    Probable                          1,177      1,037     35,359     29,954
    -------------------------------------------------------------------------
    Total proved plus
     probable(4)                      3,208      2,814    115,268     97,274
    -------------------------------------------------------------------------


                               ----------------------------------------------
                                      BEFORE TAX NET PRESENT VALUE ($000)
                               ----------------------------------------------
                                                Discount Rate
    -------------------------------------------------------------------------
    Description                Undiscounted      10%        12%        15%
    -------------------------------------------------------------------------
    Proved producing              1,836,295  1,093,936  1,020,037    929,618
    Proved non-producing            471,514    240,144    214,469    182,638
    -------------------------------------------------------------------------
    Total proved                  2,307,809  1,334,080  1,234,506  1,112,256
    Probable                      1,241,275    447,253    390,636    326,532
    -------------------------------------------------------------------------
    Total proved plus
     probable(4)                  3,549,083  1,781,333  1,625,142  1,438,788
    -------------------------------------------------------------------------
    (1) Includes independent engineers' evaluations of 2006 year-end and
        first quarter 2007 acquisitions.
    (2) Based on GLJ's January 1, 2007 escalated price forecast.
    (3) "Gross Reserves" are the total Trust's interest share before the
        deduction of any royalties. "Net Reserves" are the total Trust's
        interest share after deducting royalties.
    (4) Numbers may not add due to rounding.


    Net Asset Value Per Unit, Fully Diluted
    -------------------------------------------------------------------------
    Utilizing Independent Engineering Escalated Pricing

                              2007(1)     2006      2005      2004      2003
    -------------------------------------------------------------------------
    PV 0%                     $33.95    $34.08    $21.99    $16.19    $12.72
    PV 5%                     $22.05    $21.61    $15.12    $11.22     $9.15
    PV 10%                    $16.23    $15.70    $11.45     $8.56     $7.14
    PV 15%                    $12.80    $12.27     $9.10     $6.85     $5.83
    -------------------------------------------------------------------------
    (1) Includes acquisition of Mission Oil & Gas Inc. utilizing January 1,
        2007 Independent Engineering Escalated Pricing.
    

    UPDATE ON PROPOSAL TO TAX INCOME TRUSTS IN 2011

    On October 31, 2006, the Federal Minister of Finance announced a proposal
to tax the distributions of certain publicly traded income trusts. Draft
legislation regarding the proposal was released by the government in late
December 2006 and, in late January 2007, the House of Commons Standing
Committee on Finance held special public hearings into the matter. It is not
yet known if the proposal will be enacted into law in the form announced, if
at all. Should it be enacted into law in its current form, it would apply to
Crescent Point after four years and would come into effect in the 2011 tax
year.
    On December 15, 2006, the federal government announced guidelines with
respect to the implementation of the proposed tax on income trust
distributions. Included were guidelines setting limits on the expansion of
existing income trusts prior to the 2011 tax year. An existing income trust,
like Crescent Point, would be allowed to grow by the amount of its Safe
Harbour Limit, which was defined as a percentage of the trust's market
capitalization as of October 31, 2006. The Safe Harbour Limit was determined
to be 40 percent in 2007 and 20 percent for each of 2008, 2009 and 2010 for a
total of 100 percent of the Trust's October 31, 2006 market capitalization.
    Crescent Point is actively participating in industry initiatives to
influence the outcome of this proposed legislation. Despite uncertainty
regarding the tax proposal, the Trust continues to aggressively implement its
business plan. Crescent Point's key attributes of proven management, high
quality, large resource in place assets, and conservative balance sheet and
risk management strategy position the Trust well to succeed regardless of the
outcome of the income trust taxation debate.
    We urge all of our unitholders and concerned individuals to write, email
or visit the constituency office of their Member of Parliament to voice their
opinion regarding the tax proposal. Member of Parliament contact information
can be found on the Crescent Point website at www.crescentpointenergy.com.

    OUTLOOK

    Crescent Point continues to execute its proven business plan of creating
value added growth in reserves, production and cash flow through management's
integrated strategy of acquiring, exploiting and developing high quality, long
life, light and medium oil and natural gas properties. With another successful
year of strong reserve additions in 2006, the Trust has demonstrated year over
year growth in per unit net asset value since inception.
    Pro forma with Mission, the Trust has more than $1.1 billion of future
development projects and six years of low risk infill development drilling
inventory to sustain current production levels. With projected debt to cash
flow of less than 1.0 times and an aggressive three year hedge profile,
Crescent Point is well positioned to sustain distributions over time as the
Trust continues to exploit and develop its asset base and actively identify
and evaluate accretive acquisition opportunities.
    Crescent Point increased proved plus probable reserves by 88 percent in
2006 and achieved low finding, development and acquisition costs of $12.34 per
boe proved plus probable for the year. Crescent Point demonstrated a fifth
consecutive and record year for technical reserve additions and increased the
Trust's net asset value to $22.05 per unit fully diluted, including the
Mission assets.
    The Trust has more than 2.5 billion barrels of original oil in place and
a reserve life index of 11.9 years on a proved plus probable basis. Through
infill drilling, production optimization and waterflood implementation,
management believes the Trust has the potential to double its proved plus
probable reserves over time.
    In 2007, the Trust will continue to focus on development drilling at its
core properties of Manor, Tatagwa, Battrum/Cantuar, Worsley and Glen Ewen. The
Trust commissioned the Glen Ewen gas plant early in the first quarter, in time
for the winter drilling program. The Trust will actively implement development
activities at the newly acquired Viewfield Bakken play, including expansion of
the Viewfield gas plant from 3 mmcf/d to 6 mmcf/d.
    Crescent Point's 2007 development capital budget has been set at
$150.0 million, including the drilling of 110.0 net wells, of which
approximately 71 (40.0 net) are in the Viewfield Bakken resource play.
    Crescent Point's management anticipates crude oil prices to remain strong
in 2007. In the fourth quarter of 2006, West Texas Intermediate ("WTI") prices
averaged US$60.22 per barrel, off their third quarter peak of almost US$80 per
barrel. While inventories remain ample in the first quarter of 2007, cold
weather in late winter in major consuming areas and geo-political tensions in
Nigeria and Iran have supported strong prices. Canadian differentials in the
first quarter of 2007 have been tighter than expected due to strong demand for
Canadian crude oil in major US markets including the PADD II market and
extending south towards the Gulf Coast. For the balance of 2007, the Trust
anticipates WTI prices to remain strong, with seasonal demand helping to
support Canadian differentials at current levels. The addition of Mission's
high netback light sweet Bakken crude oil production will help mitigate the
impact on the Trust of widening winter differentials in late 2007.
    The Trust expects continued volatility in natural gas prices in the
coming months. Prices were soft in early winter trading due to record
inventory levels and mild temperatures. However, cold weather in late winter
has led to record storage withdrawals and a retreat from record high inventory
levels. Prices are currently stronger than expected with the focus turning to
forecasts for summer weather. Crescent Point believes this volatility will
continue and that the Trust's solid three year hedging program will provide
protection from price weakness and provide opportunities should high quality,
long life large oil or gas in place assets become available.
    The Trust continues to actively manage its three year commodity hedging
program, with more than 53 percent of volumes hedged in 2007, more than 44
percent in 2008, and more than 22 percent in 2009. Hedge instruments utilized
in the program include swaps, collars and put options, providing a floor of
more than Cdn $70 per barrel, with upside potential if prices strengthen above
current levels. The balance sheet remains strong, with projected net debt of
less than 1.0 times current annualized cash flow with significant unutilized
credit lines.
    The Trust anticipates 2007 cash flow will be in the range of
$314 million, or $3.11 per unit, fully diluted, based on forecast pricing of
US$60 per barrel WTI, US/Cdn $0.85 exchange rate, and Cdn $7.50 per mcf AECO
natural gas. Monthly distributions are anticipated to remain at $0.20 per unit
for a payout ratio per unit-diluted of 77 percent. Average daily production is
forecast at 26,250 boe/d.
    Crescent Point's management believes that with the high quality reserve
base and development inventory, excellent balance sheet and solid hedging
program, the Trust is well positioned to continue generating strong operating
and financial results and delivering sustainable distributions through 2007
and beyond.

    
    2007 Outlook

    Crescent Point's 2007 guidance, including Mission, is as follows:

    -------------------------------------------------------------------------
    Production
      Oil and NGL (bbls/d)                                            22,416
      Natural gas (mcf/d)                                             23,000
    -------------------------------------------------------------------------
      Total (boe/d)                                                   26,250
    -------------------------------------------------------------------------
    Cash flow ($000)                                                 314,000
    Cash flow per unit - diluted ($)                                    3.11
    Cash distributions per unit ($)                                     2.40
    Payout ratio - per unit - diluted (%)                                 77
    -------------------------------------------------------------------------
    Capital expenditures ($000)(1)                                   150,000
    Wells drilled, net                                                   110
    -------------------------------------------------------------------------
    Pricing
      Crude oil - WTI (US$/bbl)                                        60.00
      Crude oil - WTI (Cdn$/bbl)                                       70.59
      Natural gas - Corporate (Cdn$/mcf)                                7.50
      Exchange rate (US$/Cdn$)                                          0.85
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The projection of capital expenditures excludes acquisitions, which
        are separately considered and evaluated.
    

    ON BEHALF OF THE BOARD OF DIRECTORS

    (signed)
    Scott Saxberg
    President and Chief Executive Officer
    March 12, 2007



    RESULTS OF OPERATIONS

    Non-GAAP Financial Measures

    Throughout this discussion and analysis, Crescent Point Energy Trust
("Crescent Point" or the "Trust") uses the terms cash flow from operations,
cash flow from operations per unit, cash flow from operations per unit -
diluted, distributable cash, payout ratio, payout ratio per unit - diluted,
net debt, market capitalization and total capitalization. These terms do not
have any standardized meaning as prescribed by Canadian generally accepted
accounting principles ("GAAP") and therefore they may not be comparable with
the calculation of similar measures presented by other issuers.
    Cash flow from operations is calculated based on cash flow from operating
activities before changes in non-cash working capital and asset retirement
obligation expenditures. Management utilizes cash flow from operations as a
key measure to assess the ability of the Trust to finance distributions,
operating activities, capital expenditures and debt repayments. Cash flow from
operations as presented is not intended to represent cash flow from operating
activities, net earnings or other measures of financial performance calculated
in accordance with Canadian GAAP.
    The following table reconciles the cash flow from operating activities to
cash flow from operations:


    
    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
                                                %                          %
    ($000)                 2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Cash flow from
     operating
     activities          39,313   21,731       81  177,426   94,247       88
    Changes in non-cash
     working capital      3,915   11,222      (65)  10,691   14,512      (26)
    Asset retirement
     expenditures           615      471       31    1,018    1,026       (1)
    -------------------------------------------------------------------------
    Cash flow from
     operations          43,843   33,424       31  189,135  109,785       72
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Distributable cash is calculated based on cash flow from operating
activities before changes in non-cash working capital and asset retirement
obligation expenditures and after deducting reclamation fund contributions.
Management utilizes distributable cash as a measure of the total amount of
cash available for distribution to unitholders. Payout ratio is calculated as
the proportion of cash distributions to cash flow from operating activities
before changes in non-cash working capital and asset retirement obligation
expenditures. Management utilizes the payout ratio to measure the stability
and sustainability of both the Trust and distributions to unitholders.
    Net debt is calculated as current liabilities less current assets,
excluding risk management assets and liabilities, and including long term
investments. Management utilizes net debt as a key measure to assess the
liquidity of the Trust. Market capitalization is calculated by applying the
period end closing unit trading price to the number of trust units outstanding
and issuable for exchangeable shares. Market capitalization is an indication
of the enterprise value. Total capitalization is calculated as market
capitalization and current liabilities, less current assets and long term
investments, excluding the risk management asset and liabilities. Total
capitalization is used by management to measure the proportion of net debt in
the Trust's capital structure.
    A barrel of oil equivalent ("boe") is based on a conversion rate of six
thousand cubic feet of natural gas to one barrel of oil.

    Forward-Looking Information

    Certain statements contained in this report constitute forward-looking
statements and are based on the Trust's beliefs and assumptions based on
information available at the time the assumption was made. By its nature, such
forward-looking information involves known and unknown risks, uncertainties
and other factors that may cause actual results or events to differ materially
from those anticipated in such forward-looking statements. The Trust and
Crescent Point Resources Inc. ("CPRI"), believe the expectations reflected in
those forward-looking statements are reasonable but no assurance can be given
that these expectations will prove to be correct and such forward-looking
statements should not be unduly relied upon. These statements speak only as of
the date of this report.
    The material assumptions in making these forward-looking statements are
disclosed in this report under the headings "Cash Distributions", "Taxation of
Cash Distributions", "Capital Expenditures", "Asset Retirement Obligation",
"Liquidity and Capital Resources", "Critical Accounting Estimates", "New
Accounting Pronouncements", and "Business Risks and Prospects".
    This disclosure contains certain forward-looking estimates that involve
substantial known and unknown risks and uncertainties, certain of which are
beyond Crescent Point's control, including the impact of general economic
conditions; industry conditions including 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 and the lack
of availability of qualified personnel or management; fluctuations in
commodity prices, foreign exchange or interest rates; stock market volatility
and obtaining required approvals of regulatory authorities. In addition, there
are numerous risks and uncertainties associated with oil and gas operations
and the evaluation of oil and gas reserves. Therefore Crescent Point's actual
results, performance or achievement could differ materially from those
expressed in, or implied by, these forward-looking estimates and if such
actual results, performance or achievements transpire or occur, or if any of
them do so, there can be no certainty as to what benefits Crescent Point will
derive there from.

    Federal Government Proposal to Tax Income Trusts

    On October 31, 2006, the Minister of Finance for the Government of Canada
announced a proposal to tax the distributions of certain publicly traded
income trusts. Draft legislation regarding the proposal was released by the
government in late December 2006 and, in late January 2007, the House of
Commons Standing Committee on Finance held special public hearings into the
matter. It is not yet known if the proposal will be enacted into law in the
form announced, if at all. Should it be enacted into law in its current form,
it would apply to Crescent Point after four years and would come into effect
in the 2011 tax year.
    On December 15, 2006, the federal government announced guidelines with
respect to the implementation of the proposed tax on income trust
distributions. Included were guidelines setting limits on the expansion of
existing income trusts prior to the 2011 tax year. An existing income trust,
like Crescent Point, would be allowed to grow by the amount of its Safe
Harbour Limit, which was defined as a percentage of the trust's market
capitalization as of October 31, 2006. The Safe Harbour Limit was determined
to be 40 percent in 2007 and 20 percent for each of 2008, 2009 and 2010 for a
total of 100 percent of the Trust's October 31, 2006 market capitalization.

    Production

    Production increased by 70 percent year-over-year due to twelve
acquisitions completed in 2006, the acquisitions completed in the second half
of 2005 and the successful 2006 drilling results.
    The main acquisitions generating the increase in production include the
acquisition of two corporations with properties in the Cantuar and Battrum
areas of southwest Saskatchewan in January 2006 which added approximately
5,000 boe/d of initial medium oil production. The acquisition of Bulldog
Energy Inc. in November 2005 added approximately 1,925 boe/d of initial light
oil production in the Manor area of southeast Saskatchewan and the acquisition
of a private consortium of companies with properties in the Glen Ewen area of
southeast Saskatchewan in July 2005 added approximately 1,050 boe/d of initial
light oil and natural gas production. Lastly, the acquisition of Canex Energy
Inc. in May 2006 added approximately 975 boe/d of initial light oil and
natural gas production in the Peace River Arch area of northwest Alberta.
    The Trust's weighting to oil increased from 76 percent to 84 percent in
the year. This increase was largely the result of the acquisitions completed
in 2006 which were focused on light and medium oil assets.

    
    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
                                                %                          %
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Crude oil and NGL
     (bbls/d)            17,967   10,637       69   17,417    9,196       89
    Natural gas (mcf/d)  20,410   18,927        8   19,833   17,810       11
    -------------------------------------------------------------------------
    Total (boe/d)        21,369   13,791       55   20,723   12,164       70
    -------------------------------------------------------------------------
    Crude oil and NGL (%)    84       77        7       84       76        8
    Natural gas (%)          16       23       (7)      16       24       (8)
    -------------------------------------------------------------------------
    Total (%)               100      100        -      100      100        -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Marketing and Prices

    The Trust's average oil price for the year increased two percent over
2005, while the benchmark WTI price increased by 17 percent. The two percent
increase in the corporate price reflects the increase in market prices, offset
by widening corporate oil differentials and a stronger Canadian dollar.
Crescent Point's oil differential widened from $9.63 per bbl in 2005 to $15.25
per bbl in 2006 primarily due to a reduction in the average crude quality of
the Trust as a result of the acquisition of properties in the Cantuar and
Battrum areas of southwest Saskatchewan in January 2006.
    The Trust's realized prices, netbacks, revenues, cash flow from
operations and payout ratios are expected to become more seasonal due to the
impact of the Cantuar and Battrum properties which typically realize wider
price differentials in the first and fourth quarters. This makes comparisons
between fourth quarter 2005 and fourth quarter 2006 more difficult. The impact
will be offset somewhat in the future due to the acquisition of light, sweet
oil properties from Mission Oil & Gas Inc.
    The average natural gas price realized by the Trust decreased from $8.38
per mcf in 2005 to $6.33 per mcf in 2006. This decrease of 24 percent is
mainly attributable to the 26 percent decrease in the benchmark AECO daily
natural gas price.

    
    -------------------------------------------------------------------------
    Average Selling         Three months ended            Year ended
     Prices(1)                 December 31                December 31
                                                %                          %
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Crude oil and NGL
     ($/bbl)              53.75    58.36       (8)   60.03    58.57        2
    Natural gas ($/mcf)    6.45    10.81      (40)    6.33     8.38      (24)
    -------------------------------------------------------------------------
    Total ($/boe)         51.35    59.85      (14)   56.52    56.55        -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The average selling prices reported are before realized financial
        instrument losses and transportation charges.


    -------------------------------------------------------------------------
    Benchmark Pricing       Three months ended            Year ended
                               December 31                December 31
                                                %                          %
                           2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    WTI crude oil
     (US$/bbl)            60.22    60.04        -    66.25    56.61       17
    WTI crude oil
     (Cdn$/bbl)           68.43    70.64       (3)   75.28    68.20       10
    AECO natural gas(1)
     (Cdn$/mcf)            6.98    11.45      (39)    6.54     8.78      (26)
    Exchange rate
     - US$/Cdn$            0.88     0.85        4     0.88     0.83        6
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The AECO natural gas price reported is the average daily spot price.
    

    Financial Instruments and Risk Management

    Management of cash flow variability is an integral component of Crescent
Point's business strategy. Changing business conditions are monitored
regularly and reviewed with the Board of Directors to establish risk
management guidelines used by management in carrying out the Trust's strategic
risk management program. The risk exposure inherent in movements in the price
of crude oil and natural gas, fluctuations in the US/Cdn dollar exchange rate,
changes in the price of power and interest rate movements on long-term debt
are all proactively managed by Crescent Point through the use of derivatives
with reputable, financially sound counterparties. The Trust considers these
contracts to be an effective means to manage cash flow.
    The majority of the Trust's crude oil and natural gas financial
instruments are in Canadian dollars, with the exception of two U.S. dollar oil
contracts. The financial instrument contracts are referenced to WTI and AECO,
unless otherwise noted. These financial instruments allow the Trust to hedge
both commodity prices and fluctuations in the US/Cdn dollar exchange rate.
    The Trust's realized financial instrument loss of $30.3 million for 2006
remained generally consistent with the loss of $32.9 million incurred in 2005.
The primary reason for the slight decrease was due to a significant increase
in the financial instrument price for oil. The financial instrument price
increased from approximately $46.00 per bbl in 2005 to $63.00 per bbl in 2006.
This increase in financial instrument prices was partially offset by an
increase of approximately Cdn $7.00 per bbl in the benchmark WTI price and an
increase in contracted financial instrument volumes.
    The Trust has not designated any of its risk management activities as
accounting hedges under the Canadian Institute of Chartered Accountants (the
"CICA") accounting guideline 13 and, accordingly, has marked-to-market its
financial instruments. This resulted in an unrealized financial instrument
gain of $13.9 million in the year ended December 31, 2006 compared to a loss
of $24.1 million in 2005. The gain in 2006 resulted primarily from the
maturity of financial instrument contracts with lower average prices,
partially offset by increases in the WTI benchmark forward prices. The
$24.1 million loss in 2005 reflects the approximate Cdn $14.00 per bbl
increase in the WTI benchmark price through 2005.
    The following is a summary of the realized financial instrument gains
(losses) on oil and gas contracts:

    
    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
    ($000, except per boe                       %                          %
     and volume amounts)   2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Average crude oil
     volumes hedged
     (bbls/d)             7,500    3,750      100    6,917    4,037       71
    Crude oil realized
     financial
     instrument loss     (3,824)  (6,971)     (45) (30,410) (32,924)      (8)
      per bbl             (2.31)   (7.12)     (68)   (4.78)   (9.81)     (51)
    Average natural gas
     volumes hedged
     (GJ/d)               2,333        -        -      917        -        -
    Natural gas
     realized financial
     instrument gain        139        -        -       87        -        -
      per mcf              0.07        -        -     0.01        -        -
    Average barrels of
     oil equivalent
     hedged (boe/d)       7,910    3,750      111    7,078    4,037       75
    Total realized
     financial
     instrument loss     (3,685)  (6,971)     (47) (30,323) (32,924)      (8)
      per boe             (1.87)   (5.49)     (66)   (4.01)   (7.42)     (46)
    -------------------------------------------------------------------------

    Crescent Point has the following financial instrument contracts in place
as of February 28, 2007 (including contracts acquired through the acquisition
of Mission Oil & Gas Inc. on February 9, 2007):

    -------------------------------------------------------------------------
    Financial WTI Crude
     Oil Contracts                             Average    Average    Average
     - Canadian Dollar                            Swap     Bought  Sold Call
                                     Volume      Price  Put Price      Price
    Term                Contract    (bbls/d) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
    -------------------------------------------------------------------------
    2007
    January - March         Swap      1,000      58.72
    January - June          Swap        250      67.00
    January - September     Swap        250      74.52
    January - December      Swap      3,500      75.58
    April - June            Swap      1,000      72.02
    July - September        Swap      1,250      71.11
    October - December      Swap      1,500      73.22
    January - June        Collar        250                 64.00      75.32
    January - September   Collar        250                 68.00      81.28
    January - December    Collar      1,000                 67.61      81.39
    July - December       Collar        250                 65.00      82.03
    October - December    Collar        250                 65.00      86.00
    January - March          Put        250                 84.50
    January - June           Put        500                 64.50
    January - December       Put      2,750                 79.01
    July  - December         Put        500                 70.06
    -------------------------------------------------------------------------
    2007 Weighted Average             9,810      73.86      73.13      81.27
    -------------------------------------------------------------------------
    2008
    January - June          Swap      1,000      72.73
    January - September     Swap        250      68.10
    January - December      Swap      3,250      75.66
    July - December         Swap      1,000      73.52
    October - December      Swap        250      70.80
    January - June        Collar        250                 65.00      82.00
    January - December    Collar      1,250                 70.00      83.72
    July - December       Collar        250                 70.00      91.00
    January - December       Put      3,250                 72.34
    -------------------------------------------------------------------------
    2008 Weighted Average             9,250      74.71      71.47      84.19
    -------------------------------------------------------------------------
    2009
    January - March         Swap      2,750      77.68
    January - June          Swap      1,250      74.99
    April - June            Swap      2,250      77.58
    July - September        Swap      3,000      74.07
    July - December         Swap        250      70.00
    October - December      Swap      1,500      72.18
    January - March       Collar        250                 75.00      87.00
    January - June        Collar      1,250                 70.00      81.01
    January - September   Collar        250                 70.00      79.00
    April - June          Collar        250                 75.00      83.00
    July - September      Collar        250                 70.00      84.05
    July - December       Collar        750                 68.33      77.05
    -------------------------------------------------------------------------
    2009 Weighted Average             4,500      75.27      69.99      80.14
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Financial WTI Crude Oil                               Average    Average
     Contracts - U.S. Dollar                               Bought  Sold Call
                                                Volume  Put Price      Price
    Term                           Contract    (bbls/d)  ($US/bbl)  ($US/bbl)
    -------------------------------------------------------------------------
    2007
    January - December               Collar      1,000      67.50      75.73
    -------------------------------------------------------------------------
    2007 Weighted Average                        1,000      67.50      75.73
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Financial AECO Natural Gas                            Average    Average
     Contracts - Canadian Dollar                           Bought  Sold Call
                                                Volume  Put Price      Price
    Term                           Contract      (GJ/d)  ($Cdn/GJ)  ($Cdn/GJ)
    -------------------------------------------------------------------------
    2007
    January - March                  Collar      2,000       7.00       9.90
    April - October                  Collar      4,000       6.75       8.60
    -------------------------------------------------------------------------
    2007 Weighted Average                        2,840       6.79       8.82
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Financial Foreign Exchange
     Contracts - U.S. Dollar                                         Average
                                                           Volume       Swap
    Term                           Contract                  ($US) ($Cdn/$US)
    -------------------------------------------------------------------------
    2007
    January - December                 Swap            11,862,500     1.1600
    January - December                 Swap            12,775,000     1.1012
    -------------------------------------------------------------------------
    2007 Weighted Average                              12,318,750     1.1295
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Financial Interest Rate
     Contracts - Canadian Dollar                                       Fixed
                                                        Principal     Annual
    Term                           Contract                 ($Cdn)   Rate (%)
    -------------------------------------------------------------------------
    January 2007- May 2007             Swap            40,000,000       4.35
    February 2007 - February 2009      Swap            50,000,000       4.37
    May 2007 - May 2008                Swap            50,000,000       4.41
    -------------------------------------------------------------------------
    

    The Trust has a power swap for 3.0 MW/h at a fixed price of $63.25 per
MW/h for the period March 1, 2006 to December 31, 2008.

    Revenues

    Revenues were $427.5 million in 2006 compared with $251.1 million in
2005. The 70 percent increase in sales relates primarily to increases in
production from the acquisitions completed in 2005 and 2006, along with higher
realized oil prices. Partially offsetting this increase, oil differentials
widened reflecting market trends and a reduction of the Trust's crude quality
from the southwest Saskatchewan acquisition. Further, natural gas revenues
decreased 16 percent due to lower realized gas prices as a result of a
decrease in the AECO benchmark price.

    
    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
                                                %                          %
    ($000)(1)              2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Crude oil and
     NGL sales           88,855   57,111       56  381,655  196,594       94
    Natural gas sales    12,105   18,824      (36)  45,836   54,482      (16)
    -------------------------------------------------------------------------
    Revenues            100,960   75,935       33  427,491  251,076       70
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Revenue is reported before transportation charges and realized
        financial instruments.
    

    Transportation Expenses

    Transportation expenses increased from $1.04 per bbl in 2005 to $1.35 per
bbl in 2006. This increase relates to the properties acquired in the past year
and their proximity to market, along with pipeline capacity issues in
southeast Saskatchewan encountered in the fourth quarter of 2006. Growing
production volumes in southeast Saskatchewan and incremental imports from
other areas have exceeded the capacity of the area's major oil gathering
system, Enbridge Pipelines (Saskatchewan). Efforts to maintain crude sales led
to incremental trucking costs in the fourth quarter.

    
    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
    ($000, except per                           %                          %
     boe amounts)          2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Transportation
     expenses             3,293    1,374      140   10,175    4,619      120
    Per boe                1.68     1.08       56     1.35     1.04       30
    -------------------------------------------------------------------------

    Royalty Expenses

    Royalties were 21 percent of revenue in 2006 compared with 20 percent of
revenue in 2005. This increase relates to the acquisitions completed during
2006 which are subject to higher royalty rates, partially offset by royalty
incentives associated with successful drilling in southeast Saskatchewan.
    Royalties are calculated and paid based on commodity revenue net of
applicable costs and before any realized financial instrument losses.

    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
    ($000, except per                           %                          %
     boe amounts)          2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Total royalties,
     net of ARTC         19,157   15,480       24   90,013   50,052       80
    As a % of oil and
     gas sales              19%      20%       (1)     21%      20%        1
    Per boe                9.74    12.20      (20)   11.90    11.27        6
    -------------------------------------------------------------------------

    Operating Expenses

    Operating expenses per boe increased 14 percent in 2006 as a result of
higher operating costs associated with the properties acquired in 2005 and
2006, higher overall repairs and maintenance due to facility turnarounds,
increased utility costs and cost pressures resulting from higher activity in
the oil and gas sector.

    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
    ($000, except per                           %                          %
     boe amounts)          2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Operating expenses   20,475   11,369       80   69,424   35,879       93
    Per boe               10.42     8.96       16     9.18     8.08       14
    -------------------------------------------------------------------------

    Netbacks

    Crescent Point's netback after realized financial instruments for the year
increased from $28.74 per boe to $30.08 per boe as a result higher average
financial instrument prices which reduced realized financial instrument
losses, partially offset by lower average selling prices and higher royalty,
operating and transportation expenses.
    The Trust's netbacks are expected to become more seasonal due to the
impact of the Cantuar and Battrum properties which typically realize wider
price differentials in the first and fourth quarters. This makes comparisons
between fourth quarter 2005 and fourth quarter 2006 more difficult. The impact
will be offset somewhat in the future due to the acquisition of light, sweet
oil properties from Mission Oil & Gas Inc.

    -------------------------------------------------------------------------
                                    Three months ended December 31
                                      2006                      2005
    -------------------------------------------------------------------------
                       Crude Oil    Natural
                         and NGL        Gas      Total      Total          %
                          ($/bbl)    ($/mcf)    ($/boe)    ($/boe)    Change
    -------------------------------------------------------------------------
    Average selling
     price                 53.75       6.45      51.35      59.85        (14)
    Royalties              (9.78)     (1.60)     (9.74)    (12.20)       (20)
    Operating expenses    (10.46)     (1.70)    (10.42)     (8.96)        16
    Transportation         (1.76)     (0.20)     (1.68)     (1.08)        56
    -------------------------------------------------------------------------
    Netback prior to
     realized financial
     instruments           31.75       2.95      29.51      37.61        (22)
    -------------------------------------------------------------------------
    Realized gain (loss)
     on financial
     instruments           (2.31)      0.07      (1.87)     (5.49)       (66)
    -------------------------------------------------------------------------
    Netback                29.44       3.02      27.64      32.12        (14)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                       Year ended December 31
                                      2006                      2005
    -------------------------------------------------------------------------
                       Crude Oil    Natural
                         and NGL        Gas      Total      Total          %
                          ($/bbl)    ($/mcf)    ($/boe)    ($/boe)    Change
    -------------------------------------------------------------------------
    Average selling
     price                 60.03       6.33      56.52      56.55          -
    Royalties             (12.48)     (1.47)    (11.90)    (11.27)         6
    Operating expenses     (9.24)     (1.47)     (9.18)     (8.08)        14
    Transportation         (1.41)     (0.16)     (1.35)     (1.04)        30
    -------------------------------------------------------------------------
    Netback prior to
     realized financial
     instruments           36.90       3.23      34.09      36.16         (6)
    -------------------------------------------------------------------------
    Realized gain (loss)
     on financial
     instruments           (4.78)      0.01      (4.01)     (7.42)       (46)
    -------------------------------------------------------------------------
    Netback                32.12       3.24      30.08      28.74          5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    General and Administrative Expenses

    General and administrative expenses per boe for the year increased 12
percent. This increase is mainly attributable to the overall growth of the
Trust along with industry cost pressures to retain and attract high quality
employees. In addition, the Trust incurred legal and professional fees in the
year associated with an internal reorganization as described in note 17(b) to
the consolidated financial statements.

    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
    ($000, except per                           %                          %
     boe amounts)          2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    General and
     administrative
     costs                4,578    2,871       59   14,863    8,177       82
    Capitalized            (773)    (614)      26   (2,591)  (1,740)      49
    -------------------------------------------------------------------------
    General and
     administrative
     expenses             3,805    2,257       69   12,272    6,437       91
    Per boe                1.94     1.78        9     1.62     1.45       12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Restricted Unit Bonus Plan

    The Trust has a Restricted Unit Bonus Plan and under the terms of this
plan, the Trust may grant restricted units to directors, officers, employees
and consultants. Restricted units vest at 33 1/3 percent on each of the first,
second and third anniversaries of the grant date or at a date approved by the
Board of Directors. Restricted unitholders are eligible for monthly
distributions, immediately upon grant.
    On May 31, 2006, at the annual general meeting, the unitholders approved
an increase in the maximum number of trust units issuable under the Restricted
Unit Bonus Plan from 935,000 units to 5,000,000 units. The Trust had 1,043,628
restricted units outstanding at December 31, 2006 compared with 589,555 units
outstanding at December 31, 2005.
    The Trust recorded compensation expense and contributed surplus of
$11.3 million for 2006 (2005 - $4.3 million) based on the fair value of the
units on the date of grant. Cash distributions paid on the restricted units
granted were $1.1 million for the year (2005 - $450,000). The total cash and
non-cash unit-based compensation recorded in the year was $12.4 million (2005
- $4.7 million). The unit-based compensation increased year-over-year due to
the growth of the Trust's operations and industry pressures to retain and
attract high quality employees.

    Interest Expense

    Interest expense per boe increased 48 percent in 2006. This increase is
attributable to higher average debt levels resulting from the Trust's growth
over the past year, along with increases in lending rates of Canadian
chartered banks.

    
    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
    ($000, except per                           %                          %
     boe amounts)          2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Interest expense      3,602    2,118       70   13,673    5,402      153
    Per boe                1.83     1.67       10     1.81     1.22       48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Depletion, Depreciation and Amortization

    The depletion, depreciation and amortization ("DD&A") rate increased to
$18.31 per boe in 2006 from $15.04 per boe in 2005.  The increase is
attributable to the acquisitions completed in the second half of 2005 and the
year ended December 31, 2006 which carried a higher cost per barrel than the
Trust's existing properties.

    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
    ($000, except per                           %                          %
     boe amounts)          2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Depletion,
     depreciation
     and amortization    35,448   23,536       51  138,511   66,790      107
    Per boe               18.03    18.55       (3)   18.31    15.04       22
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Taxes

    During 2006, there were several proposed amendments to Federal and
provincial corporate tax legislation which were substantively enacted. The
Federal amendments include the elimination of Large Corporations Tax,
effective January 1, 2006, a reduction in the Federal corporate income tax
rate from 21 percent (in 2007) to 19 percent over a three year period
beginning January 1, 2008 and the elimination of the Corporate Income Surtax,
effective January 1, 2008. The Saskatchewan amendments include a reduction in
the Saskatchewan corporate income tax rate from 17 percent to 12 percent over
a four year period beginning January 1, 2006. The Alberta amendments include a
reduction in the Alberta corporate income tax rate from 11.5 percent to 10
percent, effective April 1, 2006.
    Capital tax expense increased from $5.5 million in 2005 to $11.3 million
in 2006 due to the introduction of Saskatchewan Capital Tax and Resource
Surcharge on certain entities owned by the Trust effective April 1, 2005,
increases in the Trust's Saskatchewan production and an increase in realized
oil prices, partially offset by the elimination of Large Corporations Tax.
    Future income taxes arise from differences between the accounting and tax
basis of certain operating entity's assets and liabilities. In the Trust
structure, payments are made between the operating entities and the Trust
transferring both the income and tax liability to the unitholders.
    Corporate acquisitions completed in 2006 resulted in the Trust recording
a future tax liability of $56.1 million. Crescent Point's future income tax
decreased from a recovery of $27.8 million in 2005 to a $16.6 million recovery
in 2006.
    On October 26, 2006, the Trust announced a Special Meeting would be held
on November 27, 2006 to obtain conditional approval of a reorganization of the
Trust and its subsidiaries. Shareholder approval was received at the Special
Meeting and on March 1, 2007 the Trust closed the reorganization. The
reorganization resulted in the existing business of the Trust, which was
carried on through a limited partnership and corporations, being carried on
through limited partnerships indirectly owned by the Trust. The reorganization
which is similar to reorganizations completed by a number of other income
trusts, has provided the Trust with a "flow through" structure that should
maximize the cash available for distribution.
    On October 31, 2006, the Federal Government announced tax proposals
pertaining to taxation of distributions paid by trusts and if the tax
legislation becomes substantively enacted as proposed, future income taxes may
be adjusted to include temporary differences between the accounting and tax
basis of the Trust's assets and liabilities.

    
    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
                                                %                          %
    ($000)                 2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Capital and other
     tax expense          2,625    2,491        5   11,314    5,527      105
    Future income tax
     expense (recovery)    (220) (15,401)     (99) (16,560) (27,800)     (40)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Cash Flow and Net Income

    Cash flow from operations increased 72 percent in 2006 to $189.1 million
from $109.8 million in 2005. The increase in cash flow is primarily the result
of higher production attributable to the acquisitions completed in the second
half of 2005 and the year ended December 31, 2006. Cash flow per unit -
diluted decreased from $3.04 per unit - diluted in 2005 to $2.98 per unit -
diluted in 2006. Although corporate operating netbacks increased, cash flow
per unit - diluted declined due to increases in general and administrative,
interest, capital and other tax expenses relating to the growth of the Trust's
operations.
    The Trust's realized prices, netbacks, revenues, cash flow from
operations and payout ratios are expected to become more seasonal due to the
impact of the Cantuar and Battrum properties which typically realize wider
price differentials in the first and fourth quarters. This makes comparisons
between fourth quarter 2005 and fourth quarter 2006 more difficult. The impact
will be offset somewhat in the future due to the acquisition of light, sweet
oil properties from Mission Oil & Gas Inc.
    Net income increased from $38.5 million in 2005 to $68.9 million in 2006
primarily as a result of increases in cash flows from operations and the $13.9
million unrealized financial instrument gain compared to a $24.1 million
financial instrument loss in 2005. The financial instrument gain resulted
primarily from the maturity of lower priced financial instrument contracts.

    
    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
    ($000, except per                           %                          %
     unit amounts)         2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Cash flow from
     operations          43,843   33,424       31  189,135  109,785       72
    Cash flow from
     operations per unit
     - diluted             0.63     0.83      (24)    2.98     3.04       (2)

    Net income            6,918   33,453      (79)  68,947   38,509       79
    Net income per unit
     - diluted(1)          0.10     0.87      (89)    1.05     1.12       (6)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net income per unit - diluted is calculated by dividing the net
        income before non-controlling interest by the diluted weighted
        average trust units.
    

    Cash Distributions

    Crescent Point's distributions to unitholders are paid monthly and are
dependent upon commodity prices, production levels and the amount of capital
expenditures to be funded from cash flow. The Trust reinvests part of its cash
flow towards the capital program to provide for more sustainable distributions
in the future. The actual amount of the distributions is at the discretion of
the Board of Directors. In the event that commodity prices are higher than
anticipated and a cash surplus develops during the quarter, the surplus may be
used to increase distributions, reduce debt and/or increase the Trust's
capital program.
    During 2006, the Trust funded cash distributions from its cash flow from
operations and expects to continue this practice in the future. Cash flow from
operations in excess of distributions requirements is used to fund capital
expenditures and reduce bank indebtedness.
    The Trust's payout ratio on a per unit - diluted basis increased from 70
percent in 2005 to 81 percent in 2006. The payout ratio for 2006 increased
primarily due to the increase in distributions from $0.17 per unit to $0.19
per unit in September 2005 and a further increase to $0.20 per unit in
November 2005. Additionally, cash flow from operations per unit - diluted
declined in 2006 due to wider oil differentials in the first quarter of 2006
and higher costs incurred managing the growth of the Trust's operations.
    The increase in the Trust's payout ratio in fourth quarter 2006 relative
to third quarter 2006 and fourth quarter 2005 was due to the reduction in the
Trust's average crude quality resulting from the Battrum and Cantuar
acquisition along with anticipated seasonality in western Canadian oil
differentials. Battrum and Cantuar oil differentials tend to be widest in the
first and fourth quarters of the year, leading to decreased prices, netbacks
and cash flows and to increased payout ratios in those quarters. The impact of
this seasonality will be reduced somewhat in the future due to the acquisition
of light sweet oil properties from Mission Oil & Gas Inc.

    
    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
    ($000, except per
     unit and percent                           %                          %
     amounts)              2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Cash distributions   41,322   22,835       81  150,277   74,591      101
    Cash distributions
     - per unit            0.60     0.59        2     2.40     2.14       12

    Payout ratio (%)(1)      94       68       26       79       68       11
    Payout ratio - per
     unit - diluted (%)(1)   95       71       24       81       70       11
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Payout ratio is calculated as cash distributions divided by cash flow
        from operations. Payout ratio per unit - diluted is calculated as
        cash distributions per unit divided by cash flow from operations per
        unit - diluted.

    The following table provides a reconciliation of distributable cash:

    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
                                                %                          %
    ($000)                 2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Cash flow from
     operating
     activities          39,313   21,731       81  177,426   94,247       88
    Plus: changes in
     non-cash working
     capital              3,915   11,222      (65)  10,691   14,512      (26)
    Plus: ARO
     expenditures           615      471       31    1,018    1,026       (1)
    Less: reclamation
     fund contributions    (390)    (354)      10   (2,502)  (1,042)     140
    -------------------------------------------------------------------------
    Distributable cash   43,453   33,070       31  186,633  108,743       72
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Allocation of
     distributable cash
      Cash retained
       from cash
       available for
       distribution(1)    2,131   10,235      (79)  36,356   34,152        6
      Cash
       distributions
       declared          41,322   22,835       81  150,277   74,591      101
    -------------------------------------------------------------------------
    Distributable
     cash                43,453   33,070       31  186,633  108,743       72
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The Board of Directors determines the cash distributions level which
        results in a discretionary amount of cash retained. Cash flow from
        operations in excess of distributions requirements is used to fund
        capital expenditures and reduce bank indebtedness.
    

    Taxation of Cash Distributions

    Cash distributions are comprised of a return on capital portion (taxable)
and a return of capital portion (tax deferred). For cash distributions
received by Canadian residents outside of a registered pension or retirement
plan in the 2006 taxation year, the distributions are 100 percent taxable.
    The following is a breakdown of the cash distributions per unit paid or
payable by the Trust with respect to the record dates from January 31, 2006 to
December 31, 2006 for Canadian tax purposes:

    
    -------------------------------------------------------------------------
                                                              Tax
                                               Taxable   Deferred
                                                Amount     Amount      Total
                                               (Box 26    (Box 42       Cash
                                                 Other  Return of    Distri-
    Record Date                Payment Date     Income)   Capital)    bution
    -------------------------------------------------------------------------
    January 31, 2006      February 15, 2006      $0.20          -      $0.20
    February 28, 2006        March 15, 2006      $0.20          -      $0.20
    March 31, 2006           April 17, 2006      $0.20          -      $0.20
    April 30, 2006             May 15, 2006      $0.20          -      $0.20
    May 31, 2006              June 15, 2006      $0.20          -      $0.20
    June 30, 2006             July 17, 2006      $0.20          -      $0.20
    July 31, 2006           August 15, 2006      $0.20          -      $0.20
    August 31, 2006      September 15, 2006      $0.20          -      $0.20
    September 30, 2006     October 16, 2006      $0.20          -      $0.20
    October 31, 2006      November 15, 2006      $0.20          -      $0.20
    November 30, 2006     December 15, 2006      $0.20          -      $0.20
    December 31, 2006      January 15, 2007      $0.20          -      $0.20
    -------------------------------------------------------------------------
    Total per trust unit                         $2.40          -      $2.40
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Long-term Investment

    The long-term investment is comprised of shares of Mission Oil & Gas Inc.
(refer to Capital Expenditures discussion below). The investment is recorded
at carrying value, which is less than the fair value of $48.1 million at
December 31, 2006.

    Capital Expenditures

    The Trust closed twelve acquisitions and one disposition in the year
ended December 31, 2006 for net consideration of approximately $483.1 million,
including closing adjustments ($566.6 million was allocated to property, plant
and equipment). The acquisitions completed in 2006 were focused in the Cantuar
and Battrum areas of southwest Saskatchewan, Ingoldsby area of southeast
Saskatchewan and Worsley and John Lake areas of Alberta. Closing adjustments
on previously closed acquisitions were $6.6 million in the year ended
December 31, 2006.
    The Trust's development capital expenditures for 2006 were $110.0 million
compared to $35.7 million in 2005. In 2006, 103 wells (77.4 net) were drilled
with a success rate of 100 percent. The Trust incurred approximately
$11.0 million constructing the Glen Ewen gas plant in southeast Saskatchewan
during the fourth quarter of 2006. The plant was commissioned in January 2007,
in time for a multi well drilling program in the first quarter of 2007.
    On February 9, 2007, the Trust closed the acquisition of Mission Oil &
Gas Inc., a publicly traded company with properties in the Viewfield Bakken
area of southeast Saskatchewan for total consideration of approximately
$574.1 million, before closing adjustments (based on a trust unit price of
$17.37). The purchase was funded through the Trust's existing bank lines and
issuance of approximately 29.2 million trust units. The Trust owned 3,800,000
shares of Mission Oil & Gas Inc. prior to the closing which it purchased for
$7.90 per share or $30.0 million in November 2005.
    The Trust's budgeted capital program for 2007 is approximately
$150.0 million. The Trust does not set a budget for acquisitions. The Trust
searches for opportunities that align with strategic parameters and evaluates
each prospect on a case by case basis. The Trust's acquisitions are expected
to be financed through bank debt, the distribution reinvestment program and
new equity issuances.

    
    -------------------------------------------------------------------------
                            Three months ended            Year ended
                               December 31                December 31
                                                %                          %
    ($000)                 2006     2005   Change     2006     2005   Change
    -------------------------------------------------------------------------
    Capital acquisitions
     (net)(1)             2,002  168,651      (99) 573,215  326,623       75
    Development capital
     expenditures        30,039    8,696      245  109,995   35,720      208
    Capitalized
     administration         773      614       26    2,591    1,740       49
    Other(2)             29,515      469     6193   31,198   10,244      205
    -------------------------------------------------------------------------
    Total                62,329  178,430      (65) 716,999  374,327       92
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The capital acquisitions include the amount allocated to property,
        plant and equipment for corporate and property acquisitions. This
        differs from the purchase price as there were allocations made to
        goodwill and other assets and liabilities, including asset retirement
        obligations.
    (2) Other expenditures include office furniture and equipment, asset
        retirement obligations on development activities and fair value
        adjustments relating to the conversion of exchangeable shares.
    

    Goodwill

    The goodwill balance of $68.4 million as at December 31, 2006 is
attributable to the corporate acquisitions of Tappit Resources Ltd., Capio
Petroleum Corporation and Bulldog Energy Inc. during the period 2003 through
2005. The Trust performed a goodwill impairment test at December 31, 2006 and
no impairment of goodwill exists.

    Asset Retirement Obligation

    The asset retirement obligation increased by $12.6 million during 2006.
This increase relates to liabilities of $10.4 million recorded in respect of
twelve acquisitions (net of one disposition) and new wells drilled in the year
and accretion expense of $3.2 million, reduced by actual expenditures incurred
in the year of $1.0 million. The Board of Directors and management review the
adequacy of the fund annually and adjust the contributions as necessary.

    Liquidity and Capital Resources

    The Trust has a syndicated credit facility with seven banks and an
operating credit facility with one Canadian chartered bank. The amount
available under the Trust's combined credit facilities was increased from
$245.0 million to $320.0 million on January 9, 2006, from $320.0 million to
$350.0 million on May 29, 2006 and further increased to $470.0 million on
November 22, 2006 to reflect the additional borrowing base available as a
result of the acquisitions which closed up to that date. As at December 31,
2006, the Trust had debt of $254.4 million, leaving unutilized borrowing
capacity in excess of $215.0 million. The Trust expects to review its
borrowing base with the bank syndicate to include year end reserve evaluations
and the additional borrowing base available in respect of the Mission
acquisition, upon the facility renewal in May 2007.
    As at December 31, 2006, Crescent Point was capitalized with 16 percent
net debt and 84 percent equity compared to 18 percent net debt and 82 percent
equity at December 31, 2005 (based on year end market capitalization). The
Trust's net debt to cash flow of 1.2 times at December 31, 2006 reflects the
debt financing of the acquisitions completed during the year, while the cash
flow reflects only the amounts generated since closing of these acquisitions
(December 31, 2005 - 1.8 times). The Trust's projected net debt to 12 month
cash flow is less than 1.0 times.
    The Trust's ability to raise new equity commencing November 1, 2006, will
be limited by the Safe Harbour Limit guidelines as announced by the Federal
Government.
    The Federal Government's proposal to tax income trusts has created
uncertainty in the capital markets regarding the future of the trust sector
however, Crescent Point believes that it has sufficient capital resources to
meet its obligations given the significant credit facility available and
success raising new equity as demonstrated in fiscal 2006 (see Unitholders'
Equity discussion below).

    
    -------------------------------------------------------------------------
    Capitalization Table ($000, except unit,       December 31,  December 31,
     per unit and percent amounts)                        2006          2005
    -------------------------------------------------------------------------
    Bank debt                                          254,438       225,710
    Working capital(1)                                 (26,533)      (31,165)
    -------------------------------------------------------------------------
    Net debt(1)                                        227,905       194,545
    Trust units outstanding and issuable
     for exchangeable shares                        69,531,952    43,062,885
    Market price at end of year (per unit)               17.60         20.68
    Market capitalization                            1,223,762       890,540
    -------------------------------------------------------------------------
    Total capitalization                             1,451,667     1,085,085
    -------------------------------------------------------------------------
    Net debt as a percentage of
     total capitalization (%)                               16            18
    -------------------------------------------------------------------------
    Annual cash flow from operations                   189,135       109,785
    -------------------------------------------------------------------------
    Net debt to cash flow(2)                               1.2           1.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The working capital and net debt exclude the risk management asset
        and liability. The working capital and net debt as at December 31,
        2006 include the $30.0 million long-term investment in Mission Oil &
        Gas Inc.
    (2) The net debt reflects the financing of acquisitions, however the cash
        flow only reflects cash flows generated from the acquired properties
        since the closing dates of the acquisitions.
    

    Unitholders' Equity

    At December 31, 2006, Crescent Point had 69,531,952 trust units issued
and issuable for exchangeable shares compared to 43,062,885 trust units at
December 31, 2005 (using the exchangeable share ratio in effect at the end of
2005). The increase by more than 26.0 million trust units relates primarily to
three bought deal equity financings and two equity issuances in connection
with acquisitions completed during the year ended December 31, 2006.
    Three bought deal equity financings closed on January 9, 2006, March 23,
2006 and July 20, 2006 whereby the Trust issued 18,546,000 trust units and
raised gross proceeds of $395.4 million ($21.15 to $21.80 per trust unit).
    On February 6, 2006, the Trust issued 2,080,379 trust units at $21.15 per
unit in conjunction with the acquisition of a partnership owning properties in
the Peace River Arch area of northwest Alberta, and on May 30, 2006 Crescent
Point issued 2,583,505 trust units at $22.42 per unit in conjunction with the
acquisition of Canex Energy Inc.
    Crescent Point's total capitalization increased 34 percent to $1.5
billion at December 31, 2006 compared to $1.1 billion at December 31, 2005,
with the market value of trust units representing 84 percent of total
capitalization. The increase in capitalization is attributable to the three
bought deal equity financings and two equity issuances in connection with
acquisitions, offset slightly by decreases in the unit trading price as a
result of the Federal tax proposals.
    During the year ended December 31, 2006, the units traded in the range of
$15.55 to $23.60 with an average daily trading volume of 360,323 units. The
range in the unit trading price reflects the market uncertainty associated
with the Federal Government's proposal to tax income trusts.
    For the year ended December 31, 2006, the distribution reinvestment and
premium distribution reinvestment plans resulted in an additional 2,941,850
trust units being issued at an average price of $18.77 per unit raising a
total of $55.2 million. Participation levels in these plans are approximately
35 percent. The cash raised through these alternative equity programs is used
to reduce bank debt. Crescent Point will continue to monitor participation
levels and utilize these funds in the most effective manner.

    Non-Controlling Interest

    The Trust had recorded a non-controlling interest in respect of the
issued and outstanding exchangeable shares of Crescent Point Resources Ltd.
("CPRL"), a corporate subsidiary of the Trust. In 2006, the Trust exercised
its redemption call right in respect of all of the issued and outstanding
exchangeable shares of CPRL. As a result, the Trust purchased all of the
issued and outstanding exchangeable shares from the holders on October 27,
2006. The redemption of the exchangeable shares was satisfied by the delivery
to each exchangeable shareholder of 1.46210 trust units per exchangeable share
held.
    The non-controlling interest was eliminated in the fourth quarter of 2006
(December 31, 2005 - $7.6 million) as all exchangeable shares were redeemed by
the Trust on October 27, 2006. The non-controlling interest on the statement
of operations and accumulated earnings for the year ended December 31, 2006
and 2005 of ($2.4) million and $1.9 million, respectively, represents the net
earnings (loss) attributable to the exchangeable shareholders for these years.

    Contractual Obligations and Commitments

    The Trust has assumed various contractual obligations and commitments in
the normal course of operations. The following table summarizes the Trust's
contractual obligations and commitments as at December 31, 2006 (including
contractual obligations and commitments acquired through the acquisition of
Mission Oil & Gas Inc. on February 9, 2007):

    
    -------------------------------------------------------------------------
    Contractual Obligations
     Summary ($000)                      Expected Payout Date
    -------------------------------------------------------------------------
                           Total       2007  2008-2009  2010-2011  After 2011
    -------------------------------------------------------------------------
    Operating Leases(1)   21,244      3,195      5,288      4,406      8,355
    -------------------------------------------------------------------------
    (1) Operating leases includes leases for office space and equipment.
    

    Critical Accounting Estimates

    The preparation of the Trust's financial statements requires management
to adopt accounting policies that involve the use of significant estimates and
assumptions. These estimates and assumptions are developed based on the best
available information and are believed by management to be reasonable under
the existing circumstances. New events or additional information may result in
the revision of these estimates over time. A summary of the significant
accounting policies used by Crescent Point can be found in Note 2 to the
December 31, 2006 consolidated financial statements. The following discussion
outlines what management believes to be the most critical accounting policies
involving the use of estimates or assumptions.

    Depletion, Depreciation and Amortization ("DD&A")

    Crescent Point follows the CICA accounting guideline AcG-16 on full cost
accounting in the oil and gas industry to account for oil and gas properties.
Under this method, all costs associated with the acquisition of, exploration
for, and the development of natural gas and crude oil reserves are capitalized
and costs associated with production are expensed. The capitalized costs are
depleted using the unit-of-production method based on estimated proved
reserves using management's best estimate of future prices (see Oil and Gas
Reserves discussion below).
    Reserve estimates can have a significant impact on earnings, as they are
a key component in the calculation of depletion. A downward revision in a
reserve estimate could result in a higher DD&A charge to earnings. In
addition, if net capitalized costs are determined to be in excess of the
calculated ceiling, which is based largely on reserve estimates (see Asset
Impairment discussion below), the excess must be written off as an expense
charged against earnings. In the event of a property disposition, proceeds are
normally deducted from the full cost pool without recognition of a gain or
loss unless there is a change in the DD&A rate of 20 percent or greater.

    Asset Retirement Obligation

    Upon retirement of its oil and gas assets, the Trust anticipates
incurring substantial costs associated with asset retirement activities.
Estimates of the associated costs are subject to uncertainty associated with
the method, timing and extent of future retirement activities. A liability for
these costs and a related asset are recorded using the discounted asset
retirement costs and the capitalized costs are depleted on a
unit-of-production basis over the associated reserve life. Accordingly, the
liability, the related asset and the expense are impacted by changes in the
estimates and timing of the expected costs and reserves (see Oil and Gas
Reserves discussion below).

    Asset Impairment

    Producing properties and unproved properties are assessed annually, or as
economic events dictate, for potential impairment. Impairment is assessed by
comparing the estimated undiscounted future cash flows to the carrying value
of the asset. The cash flows used in the impairment assessment require
management to make assumptions and estimates about recoverable reserves (see
Oil and Gas Reserves discussion below), future commodity prices and operating
costs. Changes in any of the assumptions, such as a downward revision in
reserves, a decrease in future commodity prices, or an increase in operating
costs could result in an impairment of an asset's carrying value.

    Purchase Price Allocation

    Business acquisitions are accounted for by the purchase method of
accounting. Under this method, the purchase price is allocated to the assets
acquired and the liabilities assumed based on the fair value at the time of
acquisition. The excess purchase price over the fair value of identifiable
assets and liabilities acquired is goodwill. The determination of fair value
often requires management to make assumptions and estimates about future
events. The assumptions and estimates with respect to determining the fair
value of property, plant and equipment acquired generally requires the most
judgment and include estimates of reserves acquired (see Oil and Gas Reserves
discussion below), future commodity prices, and discount rates. Changes in any
of the assumptions or estimates used in determining the fair value of acquired
assets and liabilities could impact the amounts assigned to assets,
liabilities, and goodwill in the purchase price allocation. Future net
earnings can be affected as a result of changes in future depletion and
depreciation, asset impairment or goodwill impairment.

    Goodwill Impairment

    Goodwill is subject to impairment tests annually, or as economic events
dictate, by comparing the fair value of the reporting entity to its carrying
value, including goodwill. If the fair value of the reporting entity is less
than its carrying value, a goodwill impairment loss is recognized as the
excess of the carrying value of the goodwill over the implied value of the
goodwill. The determination of fair value requires management to make
assumptions and estimates about recoverable reserves (see Oil and Gas Reserves
discussion below), future commodity prices, operating costs, production
profiles, and discount rates. Changes in any of these assumptions, such as a
downward revision in reserves, a decrease in future commodity prices, an
increase in operating costs or an increase in discount rates could result in
an impairment of all or a portion of the goodwill carrying value in future
periods.

    Oil and Gas Reserves

    Reserves estimates, although not reported as part of the Trust's
financial statements, can have a significant effect on net earnings as a
result of their impact on depletion and depreciation rates, asset retirement
provisions, asset impairments, purchase price allocations, and goodwill
impairment (see discussion of these items above). Independent petroleum
reservoir engineering consultants perform evaluations of the Trust's oil and
gas reserves on an annual basis. However, the estimation of reserves is an
inherently complex process requiring significant judgment. Estimates of
economically recoverable oil and gas reserves are based upon a number of
variables and assumptions such as geoscientific interpretation, commodity
prices, operating and capital costs and production forecasts, all of which may
vary considerably from actual results. These estimates are expected to be
revised upward or downward over time, as additional information such as
reservoir performance becomes available, or as economic conditions change.

    New Accounting Pronouncements

    Accounting Changes in the Current Period

    The Trust did not adopt any new accounting standards during the year
ended December 31, 2006.

    Future Accounting Changes

    Financial Instruments

    The CICA issued new accounting standards, CICA Accounting Standard
Handbook section 3855, "Financial Instruments Recognition and Measurement",
section 3865 "Hedges" and section 1530 "Comprehensive Income". These standards
prescribe how and at what amount financial assets, financial liabilities and
non-financial derivatives are to be recognized on the balance sheet. The
standards prescribe fair value in some cases while cost-based measures are
prescribed in other cases. It also specifies how financial instrument gains
and losses are to be presented. The new standards are effective for fiscal
years beginning on or after October 1, 2006. The Trust has not assessed the
impact of these standards on its financial statements.

    Outstanding Trust Unit Data

    As at February 26, 2007, the Trust had 98,979,471 trust units
outstanding.

    
    Selected Annual Information

    -------------------------------------------------------------------------
                                                  2006       2005       2004
                                                                   (restated
    ($000 except per unit amounts)(1)                                    (1))
    -------------------------------------------------------------------------
    Total revenue                              427,491    251,076    155,299
    Net income(2)                               68,947     38,509     29,743
    Net income per unit(2)                        1.12       1.12       1.14
    Net income per unit-diluted(2)                1.05       1.12       1.07
    Cash flow from operations                  189,135    109,785     69,828
    Cash flow from operations per unit            3.07       3.20       2.66
    Cash flow from operations per
     unit-diluted                                 2.98       3.04       2.49
    Working capital(3)                          26,533     31,165     (2,640)
    Total assets                             1,373,466    808,297    407,530
    Total liabilities                          467,086    375,632    182,380
    Net debt(3)                                227,905    194,545     95,360
    Total long-term financial liabilities       11,697      4,590          -
    Weighted average trust units
     (thousands)(4)                             63,569     36,086     28,084
    Cash distributions                         150,277     74,591     53,877
    Cash distributions per unit                   2.40       2.14       2.04
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The comparative annual results have been restated for the retroactive
        impact of the application of the change in accounting policy for
        exchangeable shares.
    (2) Net income and net income before discontinued operations and
        extraordinary items are the same.
    (3) The working capital and net debt exclude the risk management asset
        and liability. The working capital and net debt as at December 31,
        2006 include the $30.0 million long-term investment in Mission Oil &
        Gas Inc. The working capital excludes bank indebtedness.
    (4) The trust units issuable on conversion of the exchangeable shares
        reflect the weighted average exchangeable shares outstanding
        converted at the exchange ratio in effect at the end of the period.
        For the 2006 amounts, the exchangeable share ratio applied is the one
        in effect for the October 27, 2006 redemption.

    Crescent Point's revenue, cash flow from operations and assets have
increased significantly from the year ended December 31, 2004 through the year
December 31, 2006 due to numerous corporate and property acquisitions, which
have resulted in higher production volumes. This factor combined with
favourable commodity prices and the Trust's successful drilling and
development program have produced the increases realized in the table noted
above.

    Summary of Quarterly Results

    -------------------------------------------------------------------------
                                                   2006
    ($000, except per unit amounts)      Q4         Q3         Q2         Q1
    -------------------------------------------------------------------------
    Revenues                        100,960    119,365    113,790     93,376

    Net income (loss)(1)              6,918     39,588     19,260      3,181
    Net income (loss) per unit(1)      0.10       0.61       0.32       0.06
    Net income (loss) per unit
     - diluted(1)                      0.10       0.58       0.31       0.02

    Cash flow from operations        43,843     52,774     52,282     40,236
    Cash flow from operations
     per unit                          0.64       0.81       0.88       0.76
    Cash flow from operations
     per unit - diluted                0.63       0.78       0.85       0.73

    Working capital(2)               26,533     29,354     29,840     25,946
    Total assets                  1,373,466  1,351,245  1,294,214  1,188,260
    Total liabilities               467,086    448,483    503,903    452,648
    Net debt(2)                     227,905    212,073    241,371    206,991
    Total long-term financial
     liabilities                     11,697      8,650     18,791     16,097

    Weighted average trust
     units (thousands)(3)            69,764     67,810     61,372     54,958

    Capital expenditures(4)          62,329     96,689    129,637    428,344

    Cash distributions               41,322     39,890     36,123     32,942
    Cash distributions per unit        0.60       0.60       0.60       0.60
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                   2005
    ($000, except per unit amounts)      Q4         Q3         Q2         Q1
    -------------------------------------------------------------------------
    Revenues                         75,935     72,336     54,489     48,316

    Net income (loss)(1)             33,453     10,506      6,534    (11,984)
    Net income (loss) per unit(1)      0.87       0.29       0.20      (0.41)
    Net income (loss) per unit
     - diluted(1)                      0.87       0.28       0.19      (0.41)

    Cash flow from operations        33,424     33,275     22,978     20,108
    Cash flow from operations
     per unit                          0.87       0.93       0.69       0.68
    Cash flow from operations
     per unit - diluted                0.83       0.88       0.66       0.64

    Working capital(2)               31,165       (874)     4,202     (3,733)
    Total assets                    808,297    579,869    512,489    427,192
    Total liabilities               375,632    266,498    238,615    230,906
    Net debt(2)                     194,545    119,110    112,934    119,977
    Total long-term financial
     liabilities                      4,590     11,610     13,427     11,863

    Weighted average trust
     units (thousands)(3)            40,464     37,645     34,820     31,349

    Capital expenditures(4)         178,430     74,638     86,019     35,240

    Cash distributions               22,835     19,329     17,340     15,087
    Cash distributions per unit        0.59       0.53       0.51       0.51
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The comparative quarterly results have been restated for the
        application of the change in accounting policy for exchangeable
        shares. Net income (loss) per unit - diluted is calculated by
        dividing the net income before non-controlling interest by the
        diluted weighted average trust units.
    (2) The working capital and net debt exclude the risk management asset
        and liability. The working capital and net debt as at December 31,
        2006 include the $30.0 million long-term investment in Mission Oil &
        Gas Inc. The working capital excludes bank indebtedness.
    (3) The trust units issuable on conversion of the exchangeable shares
        reflect the weighted average exchangeable shares outstanding
        converted at the exchange ratio in effect at the end of the period.
        For the fourth quarter 2006 amounts, the exchangeable share ratio
        applied is the one in effect for the October 27, 2006 redemption.
    (4) The capital expenditures in the table include asset retirement
        obligations on development activities and fair value adjustments
        relating to the conversion of exchangeable shares. The prior
        quarterly results have been restated to conform with the current
        presentation.
    

    Crescent Point's revenue has increased significantly due to several
property and corporate acquisitions completed in each of the past two years
and the Trust's successful drilling program. The overall growth of the Trust's
asset base also contributed to the general increase in cash flow from
operations. Net income has fluctuated primarily due to unrealized financial
instruments gains and losses on oil and gas contracts, which fluctuate with
the changes in the market conditions. Capital expenditures fluctuated
throughout this period as a result of timing of acquisitions. The general
increase in cash flows throughout the last eight quarters has allowed the
Trust to maintain stable monthly cash distributions of $0.17 per unit through
August 2005 with increases to $0.19 per unit in September 2005 and to $0.20
per unit in November 2005.

    Fourth Quarter Review

    The following are the main highlights of the fourth quarter of 2006:

    The Trust spent $30.0 million on development capital activities in the
    fourth quarter, including the drilling of 23 (14.8 net) wells with a 100
    percent success rate adding over 900 boe/d of initial interest
    production.

    The Trust exceeded its fourth quarter average daily production target,
    producing 21,369 boe/d for the quarter. This represents a 55 percent
    increase from the 13,791 boe/d produced in the fourth quarter of 2005.

    Crescent Point's cash flow from operations increased by 31 percent to
    $43.8 million in the fourth quarter of 2006, compared to $33.4 million in
    the fourth quarter of 2005.

    Crescent Point maintained consistent monthly distributions of $0.20 per
    unit, totaling $0.60 per unit for the fourth quarter of 2006. This
    represents a 2 percent increase from the $0.59 per unit distributed in
    the fourth quarter of 2005 and resulted in an overall payout ratio of
    94 percent and a 95 percent payout ratio on a per unit - diluted basis.
    The Trust's overall 2006 payout ratio per unit - diluted was 81 percent
    and 2007 is forecasted to be 77 percent on a per unit - diluted basis.

    The Trust continued to execute its core strategy of managing commodity
    price risk using a combination of fixed price swaps, costless collars,
    and put option instruments. As at March 1, 2007, the Trust had hedged
    53 percent, 44 percent and 22 percent of production, net of royalty
    interest, for 2007, 2008 and 2009, respectively.

    On November 22, 2006, the Trust's borrowing base was increased to
    $470 million. It is anticipated that the base will increase to
    $575 million upon renewal in the second quarter of 2007. The Trust's
    balance sheet remains strong with projected 2007 net debt to 12 month
    cash flow of less than 1.0 times.

    On October 26, 2006, Crescent Point announced a proposed reorganization
    of the Trust's structure, which was approved by unitholders at a Special
    Meeting held on November 27, 2006 and completed on March 1, 2007. The
    reorganization results in the business of the Trust being carried on
    through limited partnerships owned by the Trust, similar to
    reorganizations announced by a number of other trusts. It provides the
    Trust with a "flow through" structure that is expected to maximize the
    cash available for distribution.

    Internal Controls

    Crescent Point has implemented a system of internal controls that it
believes adequately protects the assets of the Trust and is appropriate for
the nature of its business and the size of its operations. These internal
controls include disclosure controls and procedures designed to ensure that
information required to be disclosed by the Trust is accumulated and
communicated to management as appropriate to allow timely decisions regarding
required disclosure. Crescent Point's Chief Executive Officer and Chief
Financial Officer have concluded, based on their evaluation that Crescent
Point's disclosure controls and procedures are effective to provide reasonable
assurance that material information related to the Crescent Point is made
known to them and have been operating effectively during 2006. It should be
noted that while Crescent Point's Chief Executive Officer and Chief Financial
Officer believe that Crescent Point's disclosure controls and procedures
provide a reasonable level of assurance that the system of internal controls
are effective, they do not guarantee that the disclosure controls and
procedures will prevent all errors and fraud. A control system, no matter how
well conceived or operated, can provide only reasonable, not absolute,
assurance that the objectives of the control system are met.
    In addition, in accordance with Multilateral Instrument 52-109, the
Crescent Point has, under the supervision of its Chief Executive Officer and
Chief Financial Officer, designed a process of internal control over financial
reporting, which has been effected by Crescent Point's board of directors and
management. The process was designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with Canadian GAAP and includes
those policies and procedures that:

    
    -   Pertain to the maintenance of records that in reasonable detail
        accurately and fairly reflect the transactions and dispositions of
        Crescent Point's assets;

    -   Provide reasonable assurance that transactions are recorded as
        necessary to permit preparation of financial statements in accordance
        with GAAP, and that receipts and expenditures of the Trust are being
        made only in accordance with authorizations of management and the
        board of directors; and

    -   Provide reasonable assurance regarding prevention or timely detection
        of unauthorized acquisition, use or disposition of Crescent Point's
        assets that could have a material effect on the annual or interim
        financial statements.
    

    Based on the Chief Executive Officer and the Chief Financial Officer's
review of the design of internal controls over financial reporting, the Chief
Executive Officer and Chief Financial Officer have concluded that the design
of internal controls is adequate for the nature of the Trust's business and
size of its operations.

    Business Risks and Prospects

    Crescent Point is exposed to several operational risks inherent in
exploiting, developing, producing and marketing crude oil and natural gas.
These risks include:

    
    -   Economic risk of finding and producing reserves at a reasonable cost;

    -   Financial risk of marketing reserves at an acceptable price given
        market conditions;

    -   Cost of capital risk to carry out the Trust's operations; and

    -   The risk of carrying out operations with minimal environmental
        impact.

    Crescent Point strives to manage or minimize these risks in a number of
ways, including:

    -   Employing qualified professional and technical staff;

    -   Concentrating in a limited number of areas with low cost exploitation
        and development objectives;

    -   Utilizing the latest technology for finding and developing reserves;

    -   Constructing quality, environmentally sensitive, safe production
        facilities;

    -   Maximizing operational control of drilling and producing operations;

    -   Mitigating price risk through strategic hedging; and

    -   Adhering to conservative borrowing guidelines.

    Health, Safety and Environment Policy

    The health and safety of employees, contractors, visitors and the public,
as well as the protection of the environment, is of utmost importance to
Crescent Point. The Trust endeavours to conduct its operations in a manner
that will minimize both adverse effects and consequences of emergency
situations by:

    -   Complying with government regulations and standards;

    -   Conducting operations consistent with industry codes, practices and
        guidelines;

    -   Ensuring prompt, effective response and repair to emergency
        situations and environmental incidents;

    -   Providing training to employees and contractors to ensure compliance
        with Trust safety and environmental rules and procedures;

    -   Promoting the aspects of careful planning, good judgment,
        implementation of the Trust's procedures, and monitoring Trust
        activities;

    -   Communicating openly with members of the public regarding our
        activities; and

    -   Amending the Trust's policies and procedures as may be required from
        time to time.

    Crescent Point believes that all employees have a vital role in achieving
excellence in environmental, health and safety performance. This is best
achieved through careful planning and the support and active participation of
everyone involved.

    Outlook

    The Trust's annual projections for 2007, including Mission, are as
follows:

    -------------------------------------------------------------------------
    Production
      Oil and NGL (bbls/d)                                            22,416
      Natural gas (mcf/d)                                             23,000
    -------------------------------------------------------------------------
      Total (boe/d)                                                   26,250
    -------------------------------------------------------------------------
    Cash flow ($000)                                                 314,000
    Cash flow per unit - diluted ($)                                    3.11
    Cash distributions per unit ($)                                     2.40
    Payout ratio - per unit - diluted (%)                                 77
    -------------------------------------------------------------------------
    Capital expenditures ($000)(1)                                   150,000
    Wells drilled, net                                                   110
    -------------------------------------------------------------------------
    Pricing
      Crude oil - WTI (US$/bbl)                                        60.00
      Crude oil - WTI (Cdn$/bbl)                                       70.59
      Natural gas - Corporate (Cdn$/mcf)                                7.50
      Exchange rate (US$/Cdn$)                                          0.85
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The projection of capital expenditures excludes acquisitions, which
        are separately considered and evaluated.

    Additional information relating to Crescent Point, including the Trust's
renewal annual information form, is available on SEDAR at www.sedar.com.



    CONSOLIDATED BALANCE SHEETS
    As at December 31
    (UNAUDITED) ($000)                                    2006          2005
    -------------------------------------------------------------------------
    ASSETS
      Current assets
        Cash                                               205           317
        Accounts receivable                             53,279        40,733
        Investments in marketable securities               171        30,191
        Prepaids and deposits                            4,509         7,098
        Risk management asset (Note 15)                    586             -
    -------------------------------------------------------------------------
                                                        58,750        78,339
      Long-term investment (Note 17 (a))                30,020             -
      Deposit on property, plant and equipment               -        25,700
      Reclamation fund (Note 7)                          1,725           241
      Risk management asset (Note 15)                      466             -
      Property, plant and equipment (Note 6)         1,214,155       635,667
      Goodwill                                          68,350        68,350
    -------------------------------------------------------------------------
    Total assets                                     1,373,466       808,297
    -------------------------------------------------------------------------

    LIABILITIES
      Current liabilities
        Accounts payable and accrued liabilities        53,053        41,406
        Cash distributions payable                       8,598         5,768
        Bank indebtedness (Note 8)                     254,438       225,710
        Risk management liability (Note 15)              7,581        27,495
    -------------------------------------------------------------------------
                                                       323,670       300,379
      Asset retirement obligation (Note 9)              45,829        33,275
      Risk management liability (Note 15)               11,697         4,590
      Future income taxes (Note 13)                     85,890        37,388
    -------------------------------------------------------------------------
    Total liabilities                                  467,086       375,632
    -------------------------------------------------------------------------

    NON-CONTROLLING INTEREST
      Exchangeable shares (Note 11)                          -         7,565

    UNITHOLDERS' EQUITY
      Unitholders' capital (Note 10)                 1,045,929       488,060
      Contributed surplus (Note 12)                      9,150         4,409
      Accumulated earnings                             141,743        72,796
      Accumulated cash distributions (Note 4)         (290,442)     (140,165)
    -------------------------------------------------------------------------
    Total unitholders' equity                          906,380       425,100
    -------------------------------------------------------------------------
    Total liabilities and unitholders' equity        1,373,466       808,297
    -------------------------------------------------------------------------
    Commitments (Note 16)

    See accompanying notes to the consolidated financial statements.



    CONSOLIDATED STATEMENTS OF OPERATIONS AND ACCUMULATED EARNINGS

                                    Three months ended            Year ended
    (UNAUDITED) ($000, except              December 31           December 31
     per unit amounts)                 2006       2005       2006       2005
    -------------------------------------------------------------------------

    REVENUE
      Oil and gas sales             100,960     75,935    427,491    251,076
      Royalties, net of ARTC        (19,157)   (15,480)   (90,013)   (50,052)
      Financial instruments
        Realized losses              (3,685)    (6,971)   (30,323)   (32,924)
        Unrealized gains (losses)
         (Note 15)                    1,987     13,138     13,859    (24,098)
    -------------------------------------------------------------------------
                                     80,105     66,622    321,014    144,002
    EXPENSES
      Operating                      20,475     11,369     69,424     35,879
      Transportation                  3,293      1,374     10,175      4,619
      General and administrative      3,805      2,257     12,272      6,437
      Unit-based compensation
       (Note 12)                      3,293      1,832     12,416      4,706
      Interest on bank
       indebtedness (Note 8)          3,602      2,118     13,673      5,402
      Depletion, depreciation
       and amortization              35,448     23,536    138,511     66,790
      Accretion on asset retirement
       obligation (Note 9)              913        584      3,220      2,000
    -------------------------------------------------------------------------
                                     70,829     43,070    259,691    125,833
    -------------------------------------------------------------------------
      Income before taxes             9,276     23,552     61,323     18,169
      Capital and other taxes         2,625      2,491     11,314      5,527
      Future income tax recovery       (220)   (15,401)   (16,560)   (27,800)
    -------------------------------------------------------------------------
      Net income before
       non-controlling interest       6,871     36,462     66,569     40,442
      Non-controlling interest
       (Note 11)                         47     (3,009)     2,378     (1,933)
    -------------------------------------------------------------------------
      Net income for the period       6,918     33,453     68,947     38,509
    -------------------------------------------------------------------------
      Accumulated earnings,
       beginning of the period,
       as previously reported       134,825     39,343     72,796     34,792
      Retroactive application of
       change in accounting
       policy (Note 3)                    -          -          -       (505)
    -------------------------------------------------------------------------
      Accumulated earnings,
       beginning of period,
       as restated                  134,825     39,343     72,796     34,287
    -------------------------------------------------------------------------
      Accumulated earnings,
       end of the period            141,743     72,796    141,743     72,796
    -------------------------------------------------------------------------

    Net income per unit (Note 14)
      Basic                            0.10       0.87       1.12       1.12
      Diluted                          0.10       0.87       1.05       1.12

    See accompanying notes to the consolidated financial statements.



    CONSOLIDATED STATEMENTS OF CASH FLOWS

                                    Three months ended            Year ended
                                           December 31           December 31
    (UNAUDITED) ($000)                 2006       2005       2006       2005
    -------------------------------------------------------------------------

    CASH PROVIDED BY (USED IN)
     OPERATING ACTIVITIES
      Net income for the period       6,918     33,453     68,947     38,509
      Items not affecting cash
        Non-controlling interest        (47)     3,009     (2,378)     1,933
        Future income taxes            (220)   (15,401)   (16,560)   (27,800)
        Unit-based compensation
         (Note 12)                    2,818      1,381     11,254      4,255
        Depletion, depreciation
         and amortization            35,448     23,536    138,511     66,790
        Accretion on asset
         retirement obligation
         (Note 9)                       913        584      3,220      2,000
        Unrealized losses (gains)
         on financial instruments
         (Note 15)                   (1,987)   (13,138)   (13,859)    24,098
      Asset retirement
       expenditures (Note 9)           (615)      (471)    (1,018)    (1,026)
      Change in non-cash
       working capital
        Accounts receivable           8,639        (10)    (6,932)   (12,446)
        Prepaid expenses
         and deposits                (1,139)    (5,352)     2,589     (6,760)
        Accounts payable            (11,415)    (5,860)    (6,348)     4,694
    -------------------------------------------------------------------------
                                     39,313     21,731    177,426     94,247
    -------------------------------------------------------------------------
    INVESTING ACTIVITIES
      Development capital and
       other expenditures           (30,923)    (9,205)  (113,234)   (38,286)
      Capital acquisitions           (2,002)   (41,121)  (362,186)  (143,112)
      Deposits on property,
       plant & equipment                  -    (21,925)         -    (25,700)
      Investments in marketable
       securities                         -    (30,191)         -    (30,191)
      Reclamation fund net
       contributions                    225        117     (1,484)       (16)
      Change in non-cash
       working capital
        Accounts receivable          (1,987)      (149)    (3,553)      (233)
        Accounts payable              8,177      1,626     15,175      2,378
    -------------------------------------------------------------------------
                                    (26,510)  (100,848)  (465,282)  (235,160)
    -------------------------------------------------------------------------
    FINANCING ACTIVITIES
    Issue of trust units,
     net of issue costs              14,961      6,499    425,202     93,215
    Restricted unit vests                 -          -     (1,377)         -
    Increase in bank indebtedness    13,011     94,624     11,366    120,140
    Cash distributions              (41,322)   (22,835)  (150,277)   (74,591)
    Change in non-cash
     working capital
        Cash distributions
         payable                        572        924      2,830      2,422
    -------------------------------------------------------------------------
                                    (12,778)    79,212    287,744    141,186
    -------------------------------------------------------------------------
    INCREASE (DECREASE) IN CASH          25         95       (112)       273
    CASH AT BEGINNING OF PERIOD         180        222        317         44
    -------------------------------------------------------------------------
    CASH AT END OF PERIOD               205        317        205        317
    -------------------------------------------------------------------------

    See accompanying notes to the consolidated financial statements.



    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
    DECEMBER 31, 2006 and 2005 (UNAUDITED)

    1.  STRUCTURE OF THE TRUST

    Crescent Point Energy Trust ("the Trust") is an open-ended unincorporated
    investment trust created on September 5, 2003 pursuant to a Declaration
    of Trust and Plan of Arrangement operating under the laws of the Province
    of Alberta. Olympia Trust Company is the trustee and the beneficiaries of
    the Trust are the unitholders.

    The principal undertaking of the Trust's operating companies, Crescent
    Point General Partner Corp. and Crescent Point Resources Limited
    Partnership is to acquire, hold directly or indirectly, interests in oil
    and gas properties.

    2.  SIGNIFICANT ACCOUNTING POLICIES

    a)  Principles of Consolidation

        The consolidated financial statements include the accounts of the
        Trust and its subsidiaries. Any reference to "the Trust" throughout
        these consolidated financial statements refers to the Trust and its
        subsidiaries. All transactions between the Trust and its subsidiaries
        have been eliminated.

    b)  Joint Ventures

        Certain of the Trust's development and production activities are
        conducted jointly with others through unincorporated joint ventures.
        The accounts of the Trust reflect its proportionate interest in such
        activities.

    c)  Property, Plant and Equipment

        The Trust follows the full cost method of accounting for petroleum
        and natural gas properties and equipment, 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 lease acquisition costs, geological and
        geophysical expenditures, costs of drilling both productive and non-
        productive wells, related plant and production equipment costs and
        related overhead charges. Maintenance and repairs are charged against
        income, and renewals and enhancements which extend the economic life
        of the properties and equipment are capitalized.

        Gains and losses are not recognized upon disposition of petroleum and
        natural gas properties unless such a disposition would alter the rate
        of depletion by 20 percent or more.

        Depletion, Depreciation and Amortization

        Depletion of petroleum and natural gas properties is calculated using
        the unit-of-production method based on the estimated proved reserves
        before royalties, as determined by independent engineers. Natural gas
        reserves and production are converted to equivalent barrels of oil
        based upon the relevant energy content (6:1). The depletion base
        includes capitalized costs, plus future costs to be incurred in
        developing proven reserves and excludes the unimpaired cost of
        undeveloped land. Costs associated with unproved properties are not
        subject to depletion and are assessed periodically to ascertain
        whether impairment has occurred. When proved reserves are assigned or
        the value of the unproved property is considered to be impaired, the
        cost of the unproved property or the amount of impairment is added to
        costs subject to depletion.

        Tangible production equipment is depreciated on a straight-line basis
        over its estimated useful life of 15 years. Office furniture,
        equipment and motor vehicles are depreciated on a declining balance
        basis at rates ranging from 10 percent to 30 percent.

        Ceiling Test

        A limit is placed on the aggregate carrying value of property, plant
        and equipment, which may be amortized against revenues of future
        periods (the "ceiling test"). The ceiling test is an impairment test
        whereby the carrying amount of property, plant and equipment is
        compared to the undiscounted cash flows from proved reserves using
        management's best estimate of future prices. If the carrying value
        exceeds the undiscounted cash flows, an impairment loss would be
        recorded against income. The impairment is measured as the amount by
        which the carrying amount of property, plant and equipment exceeds
        the discounted cash flows from proved and probable reserves.

    d)  Reclamation Fund

        The Trust established a reclamation fund effective July 1, 2004 to
        fund future asset retirement obligation costs. The Board of Directors
        has approved contributions of $0.20 per barrel of production
        beginning April 1, 2005. Prior to April 1, 2005 contributions of
        $0.15 per barrel of production were made. Additional contributions
        are made at the discretion of management. Contributions to the
        reclamation fund have been deducted from the cash distributions to
        the unitholders and cash withheld to fund current period capital
        expenditures.

    e)  Asset Retirement Obligation

        The Trust recognizes the fair value of an asset retirement obligation
        in the period in which it is incurred. The obligation is recorded as
        a liability on a discounted basis when incurred, with a corresponding
        increase to the carrying amount of the related asset. Over time the
        liabilities are accreted for the change in their present value and
        the capitalized costs are depleted on a unit-of-production basis over
        the life of the reserves. Revisions to the estimated timing of cash
        flows or the original estimated undiscounted cost would also result
        in an increase or decrease to the obligation and related asset.

    f)  Goodwill

        The Trust must record goodwill relating to a corporate acquisition
        when the total purchase price exceeds the fair value for accounting
        purposes of the net identifiable assets and liabilities of the
        acquired company. The goodwill balance is assessed for impairment
        annually at year-end or as events occur that could result in an
        impairment. Impairment is recognized based on the fair value of the
        reporting entity ("consolidated Trust") compared to the book value of
        the reporting entity. If the fair value of the consolidated Trust is
        less than the book value, impairment is measured by allocating the
        fair value of the consolidated Trust to the identifiable assets and
        liabilities as if the Trust has been acquired in a business
        combination for a purchase price equal to its fair value. The excess
        of the fair value of the consolidated Trust over the amounts assigned
        to the identifiable assets and liabilities is the implied value of
        the goodwill. Any excess of the book value of goodwill over the
        implied value of goodwill is the impairment amount. Impairment is
        charged to earnings and is not tax affected, in the period in which
        it occurs. Goodwill is stated at cost less impairment and is not
        amortized.

    g)  Unit-based Compensation

        The Trust established a Restricted Unit Bonus Plan on September 5,
        2003. The fair value based method of accounting is used to account
        for the restricted units granted under the Restricted Unit Bonus
        Plan. Compensation expense is determined based on the estimated fair
        value of trust units on the date of grant. The compensation expense
        is recognized over the vesting period, with a corresponding increase
        to contributed surplus. At the time the restricted units vest, the
        issuance of units is recorded with a corresponding decrease to
        contributed surplus and increase to unitholders' equity.

    h)  Income Taxes

        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 financial statements
        of the Trust's corporate subsidiaries and their respective tax base,
        using substantively enacted future income tax rates. The effect of a
        change in income tax rates on future tax liabilities and assets is
        recognized in income in the period in which the change occurs.
        Temporary differences arising on acquisitions result in future income
        tax assets and liabilities. The Trust is a taxable entity under the
        Income Tax Act (Canada) and is taxable only on income that is not
        distributed or distributable to the unitholders.

    i)  Financial Instruments

        The Trust uses financial instruments and physical delivery commodity
        contracts from time to time to reduce its exposure to fluctuations in
        commodity prices, foreign exchange rates and interest rates.
        Financial instruments that are not designated as hedges under CICA
        accounting guideline 13 "Hedging Relationships" are recorded on the
        balance sheet as either an asset or a liability with the change in
        fair value from the prior period recognized in net earnings. The
        Trust has not designated any of its risk management activities as
        accounting hedges under AcG-13, and accordingly has marked-to-market
        its financial instruments.

    j)  Non-Controlling Interest

        The Trust has recorded a non-controlling interest in respect of the
        issued and outstanding exchangeable shares of Crescent Point
        Resources Ltd. ("CPRL"), a corporate subsidiary of the Trust, in
        accordance with EIC-151. The intent is that exchangeable shares of a
        subsidiary which are transferable to third parties, outside of the
        consolidated entity, represent a non-controlling interest in the
        subsidiary.

        The exchangeable shares issued pursuant to the conversion to a trust
        were initially recorded at their pro-rata percentage of carrying
        value of CPRL equity, while the exchangeable shares issued pursuant
        to the acquisition of Tappit Resources Ltd. were recorded at their
        fair value. When the exchangeable shares recorded at carrying value
        are converted into trust units, the conversion is recorded as an
        acquisition of the non-controlling interest at fair value and is
        accounted for as a step acquisition. Upon conversion of the
        exchangeable shares, the fair value of the trust units issued is
        recorded in the unitholders' capital, and the difference between the
        carrying value of the non-controlling interest and the fair value of
        the trust units is recorded as property, plant and equipment.

        The non-controlling interest on the consolidated balance sheet
        represents the book value of exchangeable shares plus accumulated
        earnings attributable to the outstanding shares. The non-controlling
        interest on the income statement represents the net earnings
        attributable to the exchangeable shareholders for the period based on
        the trust units issuable for exchangeable shares in proportion to the
        total trust units issued and issuable at each period end.

    k)  Revenue Recognition

        Revenues associated with sales of crude oil, natural gas and natural
        gas liquids are recognized when title passes to the purchaser.

    l)  Cash and Cash Equivalents

        Cash and cash equivalents include short-term investments with a
        maturity of three months or less when purchased.

    m)  Investments in Marketable Securities

        Investments are recorded at the lower of cost or net realizable
        value. Any impairment that is other than temporary in nature is
        written down to the fair value.

    n)  Measurement Uncertainty

        Certain items recognized in the financial statements are subject to
        measurement uncertainty. The recognized amounts of such items are
        based on the Trust's best information and judgment. Such amounts are
        not expected to change materially in the near term. They include the
        amounts recorded for depletion, depreciation, amortization and asset
        retirement costs which depend on estimates of oil and gas reserves or
        the economic lives and future cash flows from related assets.

    3.  EXCHANGEABLE SHARES - NON-CONTROLLING INTEREST

    On January 19, 2005, the CICA issued revised draft EIC-151 "Exchangeable
    Securities Issued by Subsidiaries of Income Trusts" that states that
    exchangeable securities issued by a subsidiary of an income trust should
    be reflected as either non-controlling interest or debt on the
    consolidated balance sheet unless they meet certain criteria. The
    exchangeable shares issued by Crescent Point Resources Ltd. ("CPRL"), a
    corporate subsidiary of the Trust, are transferable to third parties.
    EIC-151 states that if the exchangeable shares are transferable to a
    third party, they should be reflected as non-controlling interest.
    Previously, the exchangeable shares were reflected as a component of
    unitholders' equity.

    Effective in the second quarter of 2005, this accounting policy was
    adopted retroactively and prior period comparative balances have been
    restated. Adoption of the policy had the following effects on the Trust's
    consolidated balance sheets:

    -------------------------------------------------------------------------
    ($000)                                                 December 31, 2005
    -------------------------------------------------------------------------
    Increase in property, plant and equipment                         16,940
    Increase in future income tax liability                            5,979
    Increase in non-controlling interest                               7,565
    Decrease in exchangeable shares                                   (5,598)
    Increase in unitholders' capital                                  12,843
    Decrease in accumulated earnings, end of period                   (3,849)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Adoption of the policy had the following effects on Crescent Point's
    consolidated statements of operations and accumulated earnings:

    -------------------------------------------------------------------------
                                                   Three months
                                                          ended   Year ended
                                                    December 31  December 31
    ($000, except per unit amounts)                        2005         2005
    -------------------------------------------------------------------------
    Increase in depletion expense                           451        2,177
    Increase in future income tax recovery                 (159)        (766)
    Increase in non-controlling interest                  3,009        1,933
    Decrease in net income                               (3,301)      (3,344)
    Decrease in accumulated earnings, beginning
     of period                                             (548)        (505)

    Decrease in net income per unit                       (0.08)       (0.10)
    Decrease in net income per unit-diluted               (0.04)       (0.04)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    4.  RECONCILIATION OF CASH DISTRIBUTIONS

    Crescent Point's distributions to unitholders are paid monthly and are
    dependent upon commodity prices, production levels and the amount of
    capital expenditures to be funded from cash flow. The Trust reinvests
    part of its cash flow towards the capital program to provide for more
    sustainable distributions in the future. The actual amount of the
    distributions is at the discretion of the Board of Directors. In the
    event that commodity prices are higher than anticipated and a cash
    surplus develops during the quarter, the surplus may be used to increase
    distributions, reduce debt and/or increase the Trust's capital program.

    During 2006, the Trust funded cash distributions from its cash flow from
    operations and expects to continue this practice in the future. Cash flow
    from operations in excess of distributions requirements is used to fund
    capital expenditures and reduce bank indebtedness.

    Cash distributions are calculated in accordance with the Trust's
    indenture. To arrive at cash distributions, cash flow from operations,
    before changes in non cash working capital and asset retirement
    obligation ("ARO") expenditures, is reduced by reclamation fund
    contributions and a portion of capital expenditures.

    -------------------------------------------------------------------------
                                Three months ended                Year ended
    ($000, except                      December 31               December 31
    per unit amounts)            2006         2005         2006         2005
    -------------------------------------------------------------------------
    Accumulated cash
     distributions,
     beginning of period      249,120      117,330      140,165       65,574
    Cash distributions
     declared to
     unitholders(1)            41,322       22,835      150,277       74,591
    -------------------------------------------------------------------------
    Accumulated cash
     distributions,
     end of period            290,442      140,165      290,442      140,165
    -------------------------------------------------------------------------

    Accumulated cash
     distributions per
     unit, beginning of
     period                      6.66         4.27         4.86         2.72
    Cash distributions
     declared to
     unitholders per
     unit(1)                     0.60         0.59         2.40         2.14
    -------------------------------------------------------------------------
    Accumulated cash
     distributions per
     unit, end of period         7.26         4.86         7.26         4.86
    -------------------------------------------------------------------------
    (1) Cash distributions reflect the sum of the amounts declared monthly
        to unitholders, including distributions under the DRIP and Premium
        DRIP plans.

    5.  CAPITAL ACQUISITIONS AND DISPOSITIONS

    a)  Acquisition of a Partnership (Southeast Saskatchewan Property)

        On January 3, 2006, the Trust closed the acquisition of all the
        outstanding partnership units of a partnership with properties in the
        corridor between Manor and Ingoldsby, Saskatchewan for total
        consideration of $24.5 million ($25.4 million was allocated to
        property, plant and equipment). The purchase was paid for with cash
        and was accounted for as an asset acquisition pursuant to EIC-124.

    b)  Acquisition of a Corporation (Cantuar/Battrum Property)

        On January 9, 2006, the Trust purchased all the outstanding shares of
        two corporations with properties in the Cantuar and Battrum areas of
        southwest Saskatchewan for total consideration of $254.6 million
        ($302.3 million was allocated to property, plant and equipment). The
        purchase was paid for with cash raised from an equity financing of
        $220.1 million with the balance financed from the Trust's existing
        credit facilities.

        The transaction was accounted for as an asset acquisition pursuant to
        EIC-124. The net assets acquired and consideration is allocated as
        follows:

    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Net assets acquired
    Property, plant and equipment                                    302,338
    Working capital                                                   (1,285)
    Asset retirement obligation                                       (1,706)
    Future income taxes                                              (44,789)
    -------------------------------------------------------------------------
    Total net assets acquired                                        254,558
    -------------------------------------------------------------------------
    Consideration
    Cash                                                             254,473
    Acquisition costs                                                     85
    -------------------------------------------------------------------------
    Total purchase price                                             254,558
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    c)  Acquisition of a Partnership (Peace River Arch Property)

        On February 6, 2006, the Trust closed the acquisition of all the
        outstanding partnership units of a partnership with properties in the
        Peace River Arch area of northwest Alberta for total consideration of
        $55.3 million ($55.6 million was allocated to property, plant and
        equipment). The purchase was paid for with cash of $11.3 million and
        2,080,379 trust units and was accounted for as an asset acquisition
        pursuant to EIC-124.

    d)  Acquisition of Canex Energy Inc.

        On May 30, 2006, the Trust purchased all the issued and outstanding
        shares of Canex Energy Inc., a public company with properties in the
        Peace River Arch area of northwest Alberta for total consideration of
        $70.6 million ($100.3 million was allocated to property, plant and
        equipment). The purchase was paid for with a combination of cash and
        trust units and was accounted for using the purchase method of
        accounting. The net assets acquired and consideration is allocated as
        follows:

    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Net assets acquired
    Working capital                                                      526
    Property, plant and equipment                                    100,271
    Bank debt                                                        (17,362)
    Asset retirement obligation                                       (1,442)
    Future income taxes                                              (11,356)
    -------------------------------------------------------------------------
    Total net assets acquired                                         70,637
    -------------------------------------------------------------------------
    Consideration
    Cash                                                              12,114
    Trust units issued (2,583,505 trust units)                        57,922
    Acquisition costs                                                    601
    -------------------------------------------------------------------------
    Total purchase price                                              70,637
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    e)  Property Acquisitions and Disposals

        In the year ended December 31, 2006, the Trust closed eight property
        acquisitions for total consideration before closing adjustments of
        approximately $84.6 million and one property disposition for
        approximately $6.4 million (the net amount allocated to property,
        plant and equipment was $83.0 million).

    f)  Acquisition of a Private Consortium (Glen Ewen Property)

        On July 26, 2005, the Trust purchased all of the issued and
        outstanding shares of a group of private companies with common
        properties located in the Glen Ewen area of southeast Saskatchewan.
        The purchase was paid for with a combination of cash and trust units
        and was accounted for using the purchase method of accounting. The
        net assets and consideration is allocated as follows:

    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Net assets acquired
    Cash                                                               2,000
    Working capital                                                      300
    Property, plant and equipment                                     56,318
    Asset retirement obligation                                       (1,716)
    Future income taxes                                               (9,086)
    -------------------------------------------------------------------------
    Total net assets acquired                                         47,816
    -------------------------------------------------------------------------
    Consideration
    Cash                                                              11,443
    Trust units (2,000,000 trust units)                               36,300
    Acquisition costs                                                     73
    -------------------------------------------------------------------------
    Total purchase price                                              47,816
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    g)  Acquisition of a Private Company (Tatagwa Property)

        On September 13, 2005, the Trust purchased all of the issued and
        outstanding shares of a private company with properties in the
        Tatagwa area of southeast Saskatchewan. The purchase was paid for
        with a combination of cash and trust units and was accounted for
        using the purchase method of accounting. The net assets and
        consideration is allocated as follows:

    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Net assets acquired
    Cash                                                                 570
    Working capital                                                       77
    Property, plant and equipment                                      4,665
    Asset retirement obligation                                          (80)
    -------------------------------------------------------------------------
    Total net assets acquired                                          5,232
    -------------------------------------------------------------------------
    Consideration
    Cash                                                                 647
    Trust units (235,000 trust units)                                  4,559
    Acquisition costs                                                     26
    -------------------------------------------------------------------------
    Total purchase price                                               5,232
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    h)  Acquisition of Partnership (Tatagwa Property)

        On October 28, 2005, the Trust purchased all of the outstanding
        partnership units of a partnership with properties in the Tatagwa
        area of southeast Saskatchewan. The purchase was paid for with cash
        and was accounted for as an asset acquisition pursuant to EIC-124.
        The net assets acquired and consideration is allocated as follows:

    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Net assets acquired
    Property, plant and equipment                                     39,399
    Asset retirement obligation                                       (1,622)
    -------------------------------------------------------------------------
    Total net assets acquired                                         37,777
    -------------------------------------------------------------------------
    Consideration
    Cash                                                              37,423
    Acquisition costs                                                    354
    -------------------------------------------------------------------------
    Total purchase price                                              37,777
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    i)  Acquisition of Bulldog Energy Inc.

        On November 29, 2005, the Trust purchased all of the issued and
        outstanding shares of Bulldog Energy Inc., a public oil and gas
        company. The purchase was paid for with a combination of cash and
        trust units and was accounted for using the purchase method of
        accounting. The net assets and consideration is allocated as follows:

    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Net assets acquired
    Property, plant and equipment                                    128,855
    Goodwill                                                          10,203
    Working capital deficiency                                        (7,072)
    Bank debt                                                        (12,850)
    Asset retirement obligation                                       (2,373)
    Future income taxes                                              (16,276)
    -------------------------------------------------------------------------
    Total net assets acquired                                        100,487
    -------------------------------------------------------------------------
    Consideration
    Cash                                                               1,629
    Trust units (4,490,564 trust units)                               97,564
    Acquisition costs                                                  1,294
    -------------------------------------------------------------------------
    Total purchase price                                             100,487
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    6.  PROPERTY, PLANT AND EQUIPMENT

    -------------------------------------------------------------------------
                                                    Accumulated
                                                      depletion,
                                                   depreciation
    December 31, 2006                                       and
    ($000)                                    Cost amortization          Net
    -------------------------------------------------------------------------
    Petroleum and natural
     gas properties                      1,181,422      238,401      943,021
    Production equipment                   300,693       31,392      269,301
    Office furniture and equipment           3,979        2,146        1,833
    -------------------------------------------------------------------------
                                         1,486,094      271,939    1,214,155
    -------------------------------------------------------------------------


                                                    Accumulated
                                                      depletion,
                                                   depreciation
    December 31, 2005                                       and
    ($000)                                    Cost amortization          Net
    -------------------------------------------------------------------------
    Petroleum and natural
     gas properties                        617,838      117,923      499,915
    Production equipment                   147,925       13,954      133,971
    Office furniture and equipment           3,332        1,551        1,781
    -------------------------------------------------------------------------
                                           769,095      133,428      635,667
    -------------------------------------------------------------------------

    At December 31, 2006, unproved land costs of $33.9 million (2005 -
    $23.8 million) have been excluded from costs subject to depletion. Future
    development costs of $147.3 million (2005 - $103.1 million) are included
    in costs subject to depletion.

    General and administrative expenses capitalized by the Trust during the
    year were $2.6 million (2005 - $1.7 million). The capitalized
    administration costs do not include any related unit-based compensation
    costs.

    The ceiling test calculation at December 31, 2006 indicated that the net
    recoverable amount from proved reserves exceeded the net carrying value
    of the petroleum and natural gas properties and equipment. The following
    are the prices that were used in the December 31, 2006 ceiling test:

    -------------------------------------------------------------------------
                          Average Price Forecast(1)
    -------------------------------------------------------------------------
                      2007      2008      2009      2010      2011      2012
    -------------------------------------------------------------------------

    WTI ($US/bbl)    62.00     60.00     58.00     57.00     57.00     57.50
    Exchange rate     0.87      0.87      0.87      0.87      0.87      0.87
    -------------------------------------------------------------------------
    WTI ($Cdn/bbl)   71.26     68.97     66.67     65.52     65.52     66.09
    AECO ($Cdn/mcf)   7.20      7.45      7.75      7.80      7.85      8.15
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                      2013      2014      2015      2016      2017   2018+(2)
    -------------------------------------------------------------------------

    WTI ($US/bbl)    58.50     59.75     61.00     62.25     63.50       2.0%
    Exchange rate     0.87      0.87      0.87      0.87      0.87      0.87
    -------------------------------------------------------------------------
    WTI ($Cdn/bbl)   67.24     68.68     70.11     71.55     72.99       2.0%
    AECO ($Cdn/mcf)   8.30      8.50      8.70      8.90      9.10       2.0%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The benchmark prices listed above are adjusted for quality
        differentials, heat content, distance to market and other factors
        in performing our ceiling test.

    (2) Percentage change represents the change in each year after 2017 to
        the end of the reserve life.

    7.  RECLAMATION FUND

    A reclamation fund was established to fund future asset retirement
    obligation costs. The Board of Directors has approved contributions of
    $0.20 per barrel of production which results in minimum annual
    contributions of approximately $1.5 million based on properties owned at
    December 31, 2006. Additional contributions are made at the discretion
    of management. The following table reconciles the reclamation fund.

    -------------------------------------------------------------------------
    ($000)                                                 2006         2005
    -------------------------------------------------------------------------
    Balance, beginning of year                              241          225
    Contributions                                         2,502        1,042
    Actual expenditures                                  (1,018)      (1,026)
    -------------------------------------------------------------------------
    Balance, end of year                                  1,725          241
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    8.  BANK INDEBTEDNESS

    The Trust has a syndicated credit facility with seven banks and an
    operating credit facility with one Canadian chartered bank. The amount
    available under the combined credit facilities was increased from
    $245.0 million to $320.0 million on January 9, 2006, from $320.0 million
    to $350.0 million on May 29, 2006 and further increased to $470.0 million
    on November 22, 2006. The Trust has letters of credit in the amount of
    $310,000 outstanding at December 31, 2006.

    The credit facilities bear interest at the prime rate plus a margin based
    on a sliding scale ratio of the Trust's debt to cash flows. The credit
    facility is secured by the oil and gas assets owned by the Trust's wholly
    owned subsidiaries.

    The cash interest paid in the year was $15.2 million (2005 -
    $5.2 million).

    9.  ASSET RETIREMENT OBLIGATION

    The total future asset retirement obligation was estimated by management
    based on the Trust's net ownership in all wells and facilities. This
    includes all estimated costs to reclaim and abandon the wells and
    facilities and the estimated timing of the costs to be incurred in future
    periods. The Trust has estimated the net present value of its total asset
    retirement obligation to be $45.8 million at December 31, 2006
    (December 31, 2005 - $33.3 million) based on total estimated undiscounted
    cash flows to settle the obligation of $104.0 million (December 31, 2005 -
    $67.4 million). The expected period until settlement ranges from a
    minimum of 2 years to a maximum of 50 years, with the costs expected to
    be paid over an average of 20 years. The estimated cash flows have been
    discounted using a credit adjusted risk free rate of eight percent and an
    inflation rate of two percent.

    The following table reconciles the asset retirement obligation:

    -------------------------------------------------------------------------
    ($000)                                                 2006         2005
    -------------------------------------------------------------------------
    Asset retirement obligation, beginning of year       33,275       21,403
    Liabilities incurred                                  1,211          669
    Liabilities acquired through capital acquisitions     9,141       10,229
    Liabilities settled                                  (1,018)      (1,026)
    Accretion expense                                     3,220        2,000
    -------------------------------------------------------------------------
    Asset retirement obligation, end of year             45,829       33,275
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    10. UNITHOLDERS' CAPITAL

    a)  Authorized

    An unlimited number of voting trust units has been authorized.

    b)  Issued and outstanding

    The Trust has initiated a distribution reinvestment plan (the "Regular
    DRIP") and a premium distribution reinvestment plan (the "Premium DRIP").
    The Regular DRIP permits eligible unitholders to direct their
    distributions to the purchase of additional units at 95 percent of the
    average market price, as defined in the plan. The Premium DRIP permits
    eligible unitholders to elect to receive 102 percent of the cash the
    unitholder would otherwise have received on the distribution date. The
    additional cash distributed to the Premium DRIP unitholders is funded
    through the issuance of additional trust units in the open market.
    Participation in the Regular and Premium DRIP is subject to proration by
    the Trust. Unitholders who participate in either the Regular DRIP or the
    Premium DRIP are also eligible to participate in the Optional Unit
    Purchase Plan as defined in the plan.

    On December 29, 2005, the Trust and a syndicate of underwriters closed a
    bought deal equity financing pursuant to which the syndicate sold
    10,406,000 subscription receipts of the Trust for gross proceeds of
    $220.1 million ($21.15 per subscription receipt). On January 9, 2006, all
    conditions of this offering were satisfied and the subscription receipts
    were converted to trust units and the proceeds were released to the
    Trust.

    On March 23, 2006, the Trust and a syndicate of underwriters closed a
    bought deal equity financing pursuant to which 3,440,000 trust units were
    issued for gross proceeds of $75.0 million ($21.80 per trust unit).

    On July 20, 2006, the Trust and a syndicate of underwriters closed a
    bought deal equity financing pursuant to which the syndicate sold
    4,700,000 trust units for gross proceeds of $100.3 million ($21.35 per
    trust unit).

    -------------------------------------------------------------------------
                                      2006                      2005
    -------------------------------------------------------------------------
                            Number of       Amount    Number of       Amount
                          trust units        ($000) trust units        ($000)
    -------------------------------------------------------------------------
    Trust units,
     beginning of year     41,745,784      502,879   29,347,408      257,468
    Issued for cash        18,546,000      395,424    3,930,000       75,063
    Issued on capital
     acquisitions           4,663,884      101,923    6,725,564      138,423
    Issued on conversion
     of exchangeable
     shares                 1,444,213       25,608      393,007        7,405
    Issued on vesting
     of restricted
     units(1)                 190,221        2,889       90,803        1,035
    Issued pursuant to
     the distribution
     reinvestment plans     2,604,619       49,984    1,128,564       20,930
    To be issued pursuant
     to the distribution
     reinvestment plans       337,231        5,241      130,438        2,555
    -------------------------------------------------------------------------
    Trust units, end
     of year               69,531,952    1,083,948   41,745,784      502,879
    -------------------------------------------------------------------------
    Cumulative unit
     issue costs                    -      (38,019)           -      (14,819)
    -------------------------------------------------------------------------
    Total unitholders'
     capital, end
     of year               69,531,952    1,045,929   41,745,784      488,060
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The amount of trust units issued on vesting of restricted units is
        net of trust units purchased in the market to satisfy the issuance
        of trust units under the restricted unit bonus plan and employee
        withholding taxes.

    11. EXCHANGEABLE SHARES

    The exchangeable shareholders had the option to convert their
    exchangeable shares of Crescent Point Resources Ltd. into trust units at
    any time before September 5, 2013. Once the exchangeable shares
    outstanding reached one million, the Trust could elect to redeem the
    exchangeable shares for trust units. As the number of exchangeable shares
    outstanding had reached one million, the Trust exercised its redemption
    call right in respect of all the issued and outstanding exchangeable
    shares. As a result, the Trust purchased all of the issued and
    outstanding exchangeable shares from the holders on October 27, 2006. The
    redemption of the exchangeable shares was satisfied by the delivery to
    each shareholder of 1.4621 trust units per exchangeable share held.

    For other conversions in the year, the number of trust units issued upon
    conversion was based on the exchange ratio in effect on the date of
    conversion. The exchange ratio was calculated monthly based on the
    distributions declared and the ten day weighted average trust unit
    trading price preceding the monthly effective date. The exchangeable
    shares were not eligible for distributions, and were not publicly traded.

    -------------------------------------------------------------------------
    Exchangeable Shares                                    2006         2005
    -------------------------------------------------------------------------
    Balance, beginning of year                          988,073    1,307,140
    Exchanged for trust units                          (988,073)    (319,067)
    -------------------------------------------------------------------------
    Balance, end of year                                      -      988,073
    Exchange ratio, end of year                               -        1.333
    -------------------------------------------------------------------------
    Trust units issuable upon conversion, end of year         -    1,317,101
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Non-controlling Interest ($000)                        2006         2005
    -------------------------------------------------------------------------
    Non-controlling interest, beginning of year           7,565        7,266
    Reduction of book value for conversion to
     trust units                                         (5,187)      (1,634)
    Current period net earnings (loss)
     attributable to non-controlling interest            (2,378)       1,933
    -------------------------------------------------------------------------
    Non-controlling interest, end of year                     -        7,565
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    12. RESTRICTED UNIT BONUS PLAN

    The Trust has a Restricted Unit Bonus Plan. Under the terms of the
    Restricted Unit Bonus Plan, the Trust may grant restricted units to
    directors, officers, employees and consultants. Restricted units vest at
    33 1/3 percent on each of the first, second and third anniversaries of
    the grant date. Restricted unitholders are eligible for monthly
    distributions on their restricted units, immediately upon grant.

    At the annual general meeting on May 31, 2006, the unitholders approved
    an increase in the maximum number of trust units issuable under the
    Restricted Unit Bonus Plan from 935,000 to 5,000,000 trust units.

    A summary of the changes in the restricted units outstanding under the
    plan is as follows:

    -------------------------------------------------------------------------
                                                           2006         2005
    -------------------------------------------------------------------------
    Restricted units, beginning of year                 589,555      400,559
    Granted                                             848,426      406,026
    Exercised                                          (354,967)    (126,852)
    Forfeited                                           (39,386)     (90,178)
    -------------------------------------------------------------------------
    Restricted units, end of year                     1,043,628      589,555
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Trust recorded compensation expense and contributed surplus of
    $11.3 million in the year ended December 31, 2006, (2005 - $4.3 million)
    based on the amortization of the fair value of the units on the date of
    grant. Additionally, the Trust recorded $1.1 million (2005 - $450,000) of
    cash distributions on restricted units. The total cash and non-cash unit
    based compensation recorded in the year was $12.4 million (2005 -
    $4.7 million).

    13. INCOME TAXES

    During 2006, there were several proposed amendments to Federal and
    provincial corporate tax legislation which were substantively enacted.
    The Federal amendments include the elimination of Large Corporations Tax,
    effective January 1, 2006, a reduction in the Federal corporate income
    tax rate from 21 percent (in 2007) to 19 percent over a three year period
    beginning January 1, 2008 and the elimination of the Corporate Income
    Surtax, effective January 1, 2008. The Saskatchewan amendments include a
    reduction in the Saskatchewan corporate income tax rate from 17 percent
    to 12 percent over a four year period beginning January 1, 2006. The
    Alberta amendments include a reduction in the Alberta corporate income
    tax rate from 11.5 percent to 10 percent, effective April 1, 2006. As a
    result of the rate changes, the Trust's future income tax rate decreased
    to approximately 30 percent in 2006 (35 percent in 2005) compared to the
    tax rate of 37 percent applicable for the 2006 income tax year
    (40 percent for 2005).

    The tax provision differs from the amount computed by applying the
    combined Canadian federal and provincial income tax statutory rates to
    income before taxes as follows:

    -------------------------------------------------------------------------
    ($000)                                                 2006         2005
    -------------------------------------------------------------------------
    Income before taxes                                  61,323       18,169
    Statutory income tax rate                             36.53%       39.70%
    -------------------------------------------------------------------------
    Expected provision for income taxes                  22,401        7,213
    Effect of change in corporate tax rates              (5,623)      (1,945)
    Non-deductible Crown charges                          5,359        3,847
    Resource allowance                                   (4,466)      (9,272)
    Net income of the Trust and other                   (34,231)     (27,643)
    -------------------------------------------------------------------------
    Future income tax recovery                          (16,560)     (27,800)
    -------------------------------------------------------------------------

    The cash capital taxes paid during the year were $13.2 million
    (2005 - $3.9 million).

    The future tax liability of $85.9 million is comprised primarily of tax
    on the differences between the accounting basis and tax basis of certain
    operating companies' property, plant and equipment and on the differences
    between certain subsidiaries' accounting basis and tax basis for
    investments in partnerships.

    On October 26, 2006, the Trust announced a Special Meeting would be held
    on November 27, 2006 to obtain conditional approval of a reorganization
    of the Trust and its subsidiaries. Shareholder approval was received at
    the Special Meeting and on March 1, 2007 the Trust closed the
    reorganization. The reorganization resulted in the existing business of
    the Trust, which was carried on through a limited partnership and
    corporations, being carried on through limited partnerships indirectly
    owned by the Trust. The reorganization which is similar to
    reorganizations completed by a number of other income trusts, has
    provided the Trust with a "flow through" structure that should maximize
    the cash available for distribution.

    On October 31, 2006, the Federal Government announced tax proposals
    pertaining to taxation of distributions paid by trusts and the personal
    tax treatment of trust distributions. On December 21, 2006, the Minister
    of Finance released for comment draft legislation concerning the new tax
    proposals. Currently, Crescent Point does not pay tax on distributions as
    tax is paid by the unitholders. The proposals would result in a tax at
    the Trust level. If legislation is enacted, the proposals would apply to
    the Trust effective January 1, 2011, however the plan has not been
    enacted at this time. If the tax legislation becomes substantively
    enacted as proposed, future income taxes may be adjusted to include
    temporary differences between the accounting and tax basis of the Trust's
    assets and liabilities.

    14. PER TRUST UNIT AMOUNTS

    The following table summarizes the weighted average trust units used in
    calculating net income per trust unit:

    -------------------------------------------------------------------------
                    Three months ended December 31    Year ended December 31
                                 2006         2005         2006         2005
    -------------------------------------------------------------------------
    Weighted average
     trust units           68,312,948   38,557,539   61,542,223   34,263,054
    -------------------------------------------------------------------------
    Trust units issuable
     on conversion of
     exchangeable
     shares(1)(2)             403,437    1,317,101    1,178,761    1,317,101
    Dilutive impact of
     restricted units       1,047,581      589,222      847,832      505,347
    -------------------------------------------------------------------------
    Dilutive trust units
     and exchangeable
     shares(2)             69,763,966   40,463,862   63,568,816   36,085,502
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The trust units issuable on conversion of the exchangeable shares
        reflect the weighted average exchangeable shares outstanding
        converted at the exchange ratio in effect at the end of the period.
        The exchange rate used for 2006 was the rate in effect on October 27,
        2006, immediately prior to the conversion of all remaining
        exchangeable shares.

    (2) The exchangeable shares and restricted units for the fourth quarter
        of 2005 are not included in the calculation of the net income per
        unit - diluted as they are anti-dilutive.

    15. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

    a)  Fair values

        The Trust's financial instruments recognized on the consolidated
        balance sheet include cash, accounts receivable, the reclamation
        fund, accounts payable, accrued liabilities and debt. The fair value
        of these financial instruments approximates their carrying amounts
        due to their short-term nature.

    b)  Credit risk

        A substantial portion of the Trust's accounts receivable are with
        customers in the oil and gas industry and are subject to normal
        industry credit risks.

    c)  Interest rate risk

        The Trust is exposed to interest rate risk on debt instruments to the
        extent of changes in the prime interest rate.

    d)  Risk management

        The Trust has entered into fixed price oil, gas and power contracts
        along with interest rate swaps to manage its exposure to fluctuations
        in the price of crude oil, gas, power and interest rates on debt.

    The following is a summary of the financial instrument contracts in place
    as at December 31, 2006:

    -------------------------------------------------------------------------
    Financial WTI Crude
     Oil Contracts                             Average    Average    Average
     - Canadian Dollar                            Swap     Bought  Sold Call
                                     Volume      Price  Put Price      Price
    Term                Contract    (bbls/d) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
    -------------------------------------------------------------------------
    2007
    January - March         Swap      1,000      58.72
    January - June          Swap        250      67.00
    January - September     Swap        250      74.52
    January - December      Swap      2,750      75.64
    April - June            Swap      1,000      72.02
    July - September        Swap      1,250      71.11
    October - December      Swap      1,500      73.22
    January - June        Collar        250                 64.00      75.32
    January - September   Collar        250                 68.00      81.28
    January - December    Collar      1,000                 67.61      81.39
    July - December       Collar        250                 65.00      82.03
    October - December    Collar        250                 65.00      86.00
    January - March          Put        250                 84.50
    January - June           Put        500                 64.50
    January - December       Put      2,750                 79.01
    July - December          Put        500                 70.06
    -------------------------------------------------------------------------
    2007 Weighted Average             9,060      73.59      74.13      81.12
    -------------------------------------------------------------------------
    2008
    January - June          Swap      1,000      72.73
    January - September     Swap        250      68.10
    January - December      Swap      3,250      75.66
    July - December         Swap      1,000      73.52
    October - December      Swap        250      70.80
    January - June        Collar        250                 65.00      82.00
    January - December    Collar      1,250                 70.00      83.72
    July - December       Collar        250                 70.00      91.00
    January - December       Put      3,250                 72.34
    -------------------------------------------------------------------------
    2008 Weighted Average             9,250      74.71      71.47      84.19
    -------------------------------------------------------------------------
    2009
    January - March         Swap      2,750      77.68
    January - June          Swap      1,250      74.99
    April - June            Swap      2,250      77.58
    July - September        Swap      3,000      74.07
    January - March       Collar        250                 75.00      87.00
    January - June        Collar      1,250                 70.00      81.01
    January - September   Collar        250                 70.00      79.00
    April - June          Collar        250                 75.00      83.00
    July - September      Collar        250                 70.00      84.05
    -------------------------------------------------------------------------
    2009 Weighted Average             3,610      75.98      70.62      81.32
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Financial AECO Natural
     Gas Contracts                                        Average    Average
     - Canadian Dollar                                     Bought  Sold Call
                                                Volume  Put Price      Price
    Term                           Contract      (GJ/d)  ($Cdn/GJ)  ($Cdn/GJ)
    -------------------------------------------------------------------------
    2007
    January - March                  Collar      2,000       7.00       9.90
    April - October                  Collar      2,000       6.50       8.04
    -------------------------------------------------------------------------
    2007 Weighted Average                        1,665       6.65       8.59
    -------------------------------------------------------------------------

    The Trust has a power swap for 3.0 MW/h at a fixed price of $63.25
    per MW/h for the period March 1, 2006 to December 31, 2008. The Trust
    also has an interest rate swap in the amount of $40.0 million bearing an
    interest rate of 4.35 percent (before stamping fees) for the period
    May 25, 2006 to May 25, 2007.

    None of the Trust's commodity or interest rate contracts have been
    designated as accounting hedges. Accordingly, all commodity and interest
    rate contracts have been recorded on the balance sheet as assets and
    liabilities based on their fair values.

    The following table reconciles the movement in the fair value of the
    Trust's commodity and interest rate contracts:

    -------------------------------------------------------------------------
    ($000)                                                 2006         2005
    -------------------------------------------------------------------------
    Risk management asset, beginning of year                  -            -
    Unrealized mark-to-market gain                        1,052            -
    -------------------------------------------------------------------------
    Risk management asset, end of year                    1,052            -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Less: current risk management asset, end of year       (586)           -
    -------------------------------------------------------------------------
    Long term risk management asset, end of year            466            -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    ($000)                                                 2006         2005
    -------------------------------------------------------------------------
    Risk management liability, beginning of year         32,085        7,898
    Unrealized mark-to-market loss (gain)(1)            (12,807)      24,187
    -------------------------------------------------------------------------
    Risk management liability, end of year               19,278       32,085
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Less: current risk management liability,
     end of year                                         (7,581)     (27,495)
    -------------------------------------------------------------------------
    Long term risk management liability, end of year     11,697        4,590
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) The realized financial instrument gain on the income statement for
        the year ended December 31, 2005 also reflects the amortization of
        deferred financial instrument gains and losses.

    16. COMMITMENTS

    At December 31, 2006, the Trust had contractual obligations and
    commitments for office space and equipment:
                                                                       ($000)
    -------------------------------------------------------------------------
    2007                                                               3,087
    2008                                                               2,698
    2009                                                               2,589
    2010                                                               2,304
    2011                                                               2,102
    -------------------------------------------------------------------------

    17. SUBSEQUENT EVENTS

    a)  Acquisition of Mission Oil & Gas Inc. (Viewfield Bakken Property)

    On February 9, 2007, the Trust closed the acquisition of Mission Oil &
    Gas Inc., a publicly traded company with properties in the Viewfield
    Bakken area of southeast Saskatchewan for total consideration of
    approximately $574.1 million, before closing adjustments (based on a
    trust unit price of $17.37). The purchase was funded through the Trust's
    existing bank lines and issuance of approximately 29.2 million trust
    units. The Trust owned 3,800,000 shares of Mission Oil & Gas Inc. prior
    to the closing which it purchased for $7.90 per share or $30.0 million in
    November 2005.

    b)  Internal Reorganization

    On March 1, 2007, the Trust closed the previously announced
    reorganization of the Trust and its subsidiaries. The reorganization
    resulted in the existing business of the Trust, which was carried on
    through a limited partnership and corporations, being carried on through
    limited partnerships indirectly owned by the Trust. The reorganization
    which is similar to reorganizations completed by a number of other income
    trusts, has provided the Trust with a "flow through" structure that
    should maximize the cash available for distribution.

    18. COMPARATIVE INFORMATION

    Certain information provided for the previous period has been restated to
    conform to the current period presentation.


    Directors                                   Legal Counsel

    Peter Bannister, Chairman(1)(3)             McCarthy Tétrault LLP
                                                Calgary, Alberta
    Paul Colborne(2)(4)
                                                Evaluation Engineers
    Ken Cugnet (3)(4)(5)
                                                GLJ Petroleum Consultants
    Hugh Gillard (1)(2)(3)                       Ltd.
                                                Calgary, Alberta
    Gerald Romanzin(1)(5)
                                                Sproule Associates Ltd.
    Scott Saxberg(4)                            Calgary, Alberta

    Greg Turnbull(2)(5)                         Registrar and Transfer Agent

    (1) Member of the Audit Committee           Investors are encouraged to
        of the Board of Directors               contact Crescent Point's
                                                Registrar and  Transfer Agent
    (2) Member of the Compensation Committee    for information regarding
        of the Board of Directors               their security holdings:

    (3) Member of the Reserves Committee        Olympia Trust Company
        of the Board of Directors               2300, 125 - 9 Avenue SE
                                                Calgary, Alberta T2G 0P6
    (4) Member of the Health, Safety and        Tel: (403) 261-0900
        Environment Committee of the Board
        of Directors                            Stock Exchange

    (5) Member of the Corporate Governance      Toronto Stock Exchange - TSX
        Committee
                                                Stock Symbol
    Officers
                                                CPG.UN
    Scott Saxberg
    President and Chief Executive Officer       Investor Contacts

    C. Neil Smith                               Scott Saxberg
    Vice President, Engineering and             President and Chief Executive
     Business Development                        Officer
                                                (403) 693-0020
    Greg Tisdale
    Chief Financial Officer                     Greg Tisdale
                                                Chief Financial Officer
    Dave Balutis                                (403) 693-0020
    Vice President, Geosciences
                                                Trent Stangl
    Tamara MacDonald                            Manager, Marketing and
    Vice President, Land                         Investor Relations
                                                (403) 693-0020
    Ken Lamont
    Controller and Treasurer

    Head Office
    Suite 2800, 111 - 5th Avenue SW
    Calgary, Alberta
    T2P 3Y6
    Tel: (403) 693-0020
    Fax: (403) 693-0070

    Banker

    The Bank of Nova Scotia
    Calgary, Alberta

    Auditor

    PricewaterhouseCoopers LLP
    Calgary, Alberta
    





For further information:

For further information: Investor Contacts: Scott Saxberg, President and
Chief Executive Officer, (403) 693-0020; Greg Tisdale, Chief Financial
Officer, (403) 693-0020; Trent Stangl, Manager, Marketing and Investor
Relations, (403) 693-0020

Organization Profile

Crescent Point Energy Corp.

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