Crescent Point Energy Trust Announces Fourth Quarter 2007 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 year ended December 31, 2007.

    
    FINANCIAL AND OPERATING HIGHLIGHTS
    -------------------------------------------------------------------------
                             Three months ended              Year ended
    ($000s except                December 31                December 31
     trust units, per  ------------------------------------------------------
     trust unit and                            %                          %
     per boe amounts)       2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Financial
    Cash flow from
     operations(1)       112,572    43,843    157   355,910   189,135     88
      Per unit(1)(2)        0.99      0.63     57      3.51      2.98     18
    Net income(3)
     (loss)              (90,348)    6,918 (1,406)  (32,167)   68,947   (147)
      Per unit(2)(3)       (0.80)     0.10   (900)    (0.32)     1.05   (130)
    Cash distributions    67,971    41,322     64   245,108   150,277     63
      Per unit(2)           0.60      0.60      -      2.40      2.40      -
    Payout ratio (%)(1)       60        94    (34)       69        79    (10)
      Per unit (%)(1)(2)      61        95    (34)       68        81    (13)
    Net debt(1)(4)       650,088   227,905    185   650,088   227,905    185
    Capital acquisitions
     (net)(5)            408,377     2,002 20,298 1,068,406   507,929    110
    Development capital
     expenditures         95,385    30,039    218   227,923   109,995    107
    Weighted average
     trust units
     outstanding (mm)
      Basic                113.1      68.3     66     100.7      61.5     64
      Diluted              114.6      69.8     64     102.1      63.6     61
    -------------------------------------------------------------------------
    Operating
    Average daily
     production
      Crude oil and
       NGLs (bbls/d)      28,601    17,967     59    24,349    17,417     40
      Natural gas
       (mcf/d)            28,500    20,410     40    22,610    19,833     14
    -------------------------------------------------------------------------
      Total (boe/d)       33,351    21,369     56    28,117    20,723     36
    -------------------------------------------------------------------------
    Average selling
     prices(6)
      Crude oil and
       NGLs ($/bbl)        75.31     53.75     40     67.33     60.03     12
      Natural gas
       ($/mcf)              6.32      6.45     (2)     6.52      6.33      3
    -------------------------------------------------------------------------
      Total ($/boe)        69.99     51.35     36     63.55     56.52     12
    -------------------------------------------------------------------------
    Netback ($/boe)
      Oil and gas
       sales               69.99     51.35     36     63.55     56.52     12
      Royalties           (12.81)    (9.74)    32    (11.59)   (11.90)    (3)
      Operating
       expenses            (9.19)   (10.42)   (12)    (9.25)    (9.18)     1
      Transportation       (1.83)    (1.68)     9     (1.73)    (1.35)    28
    -------------------------------------------------------------------------
      Netback prior
       to realized
       financial
       instruments         46.16     29.51     56     40.98     34.09     20
    Realized loss
     on financial
     instruments           (3.68)    (1.87)    97     (0.96)    (4.01)   (76)
    -------------------------------------------------------------------------
      Netback              42.48     27.64     54     40.02     30.08     33
    -------------------------------------------------------------------------
    (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. The net income and cash flow per
        unit - diluted amounts exclude the cash portion of unit-based
        compensation.
    (3) Net income was $21.9 million for the three months ended December 31,
        2007 and $73.3 million for the year ended December 31, 2007,
        excluding financial instrument losses of $112.2 million and
        $105.4 million, respectively.
    (4) Net debt includes working capital and long term investments, but
        excludes the risk management liabilities and assets.
    (5) Capital acquisitions represent total consideration for the
        transactions including bank debt and working capital assumed.
    (6) The average selling prices reported are before realized financial
        instruments.

    HIGHLIGHTS

    In the fourth quarter of 2007, 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.

    -   Through a successful exploration, exploitation and development
        program, Crescent Point increased its net asset value ("NAV") per
        unit to $40.21 at year end 2007 from $21.61 at year end 2006, based
        on independent engineering evaluations of reserves and escalated
        price assumptions discounted at 5 percent.

    -   The Trust increased proved plus probable reserves by 85 percent to
        167.5 million boe at year end 2007, increasing its reserve life index
        to 13.3 years from 11.9.

    -   Including the acquisition of Pilot Energy Ltd. ("Pilot"), which
        closed January 16, 2008, and the acquisition of the non Bakken assets
        of Landex Petroleum Corp. ("Landex"), which is expected to close in
        late March 2008, the Trust's reserves will increase to 175.7 million
        boe proved plus probable, and its reserve life index to 14.0 years.

    -   Crescent Point replaced 410 percent of 2007 production on a proved
        plus probable basis, excluding reserves added through acquisitions.
        This is the sixth straight and a record year of strong positive
        technical reserve revisions.

    -   The Trust increased its internal estimates of the southeast
        Saskatchewan Bakken light oil resource play to more than 4 billion
        barrels of original oil in place ("OOIP") due to its successful step
        out drilling program and competitor drilling. Crescent Point's step
        out drilling program expanded the aerial extent of the play by
        11 townships.

    -   Through its aggressive Bakken exploration and exploitation program,
        the Trust achieved technical revisions on its core Viewfield Bakken
        assets of 35.7 mmboe proved plus probable. As at year end 2007, the
        Trust had Bakken reserves of 70.2 mmboe proved plus probable.

    -   The Trust grew its low risk Bakken drilling inventory to 1,050 net
        locations, only one third of which have been booked in the proved
        plus probable reserves category.

    -   Crescent Point achieved low 2007 finding and development ("F&D")
        costs of $5.42 per proved plus probable boe and $8.32 per proved boe
        of reserves. The Trust's finding, development and acquisition
        ("FD&A") costs are $14.71 per proved plus probable boe and $20.74 per
        proved boe of reserves.

           ------------------------------------------------------------------
                                                                      Proved
                                                                        plus
           Per boe, except Recycle Ratios                  Proved   Probable
           ------------------------------------------------------------------
           F&D
           ------------------------------------------------------------------
           2007 cost, excluding change in FDC(1)          $  8.32    $  5.42
           ------------------------------------------------------------------
           2007 average recycle ratio(2)                      4.9        7.6
           ------------------------------------------------------------------
           2007 cost, including change in FDC             $ 16.39    $ 12.90
           ------------------------------------------------------------------
           6-yr cost, excluding change in FDC             $ 10.17    $  6.96
           ------------------------------------------------------------------

           ------------------------------------------------------------------
           FD&A
           ------------------------------------------------------------------
           2007 cost, excluding change in FDC             $ 20.74    $ 14.71
           ------------------------------------------------------------------
           2007 average recycle ratio(2)                      2.0        2.8
           ------------------------------------------------------------------
           2007 cost, including change in FDC             $ 24.30    $ 18.31
           ------------------------------------------------------------------
           6-yr cost, excluding change in FDC             $ 18.28    $ 13.40
           ------------------------------------------------------------------
           1. Future Development Capital.
           2. Based on 2007 average operating netback (excluding realized
              hedging losses) of $40.98/boe.

    -   The Trust exceeded its fourth quarter average daily production target
        of 31,250 boe/d by more than six percent, largely due to continued
        success in the Viewfield Bakken light oil resource play. The Trust
        produced 33,351 boe/d for the quarter, up from 27,572 boe/d in the
        third quarter and up from 21,369 boe/d in the fourth quarter of 2006.
        Current production is in excess of 35,000 boe/d.

    -   The Trust spent $95.4 million on development capital activities in
        the fourth quarter, including $45.9 million on facilities, land and
        seismic. The Trust spent $49.5 million on drilling and completions
        activities, including the drilling of 37 (28.9 net) wells with a
        100 percent success rate.

    -   Crescent Point's cash flow from operations increased by 157 percent
        to $112.6 million ($0.99 per unit - diluted) in the fourth quarter of
        2007, compared to $43.8 million ($0.63 per unit - diluted) in the
        fourth quarter of 2006.

    -   The Trust's netback increased to $42.48 per boe from $27.64 in the
        fourth quarter of 2006. The increase is largely due to improvements
        in the Trust's oil quality and realized hedge prices, higher market
        prices and lower royalty rates. During the quarter, the Trust
        realized an operating netback of $66.38 per boe on its Bakken
        production.

    -   Crescent Point maintained consistent monthly distributions of
        $0.20 per unit, totaling $0.60 per unit for the fourth quarter of
        2007. This is unchanged from the fourth quarter of 2006 and resulted
        in a payout ratio of 61 percent on a per unit - diluted basis, down
        from 95 percent in 2006. The Trust is forecasting a 57 percent payout
        ratio in 2008, assuming a WTI price of US $92.50 per barrel.

    -   The Trust pursued a strategic Bakken land acquisition strategy in the
        fourth quarter, acquiring 44 net sections of undeveloped Crown and
        freehold Bakken land. In total, the Trust acquired 115 net sections
        of undeveloped Bakken land in 2007 for total consideration of
        $42.3 million.

    -   On October 22, 2007, Crescent Point closed the previously announced
        Bakken consolidation acquisition of Innova Exploration Ltd.
        ("Innova"). With the closing of the acquisition, the Trust acquired
        approximately 4,300 boe/d of high quality, high netback light oil and
        natural gas production, 65 percent of which is in the southeast
        Saskatchewan Bakken light oil resource play. The acquisition added
        more than 97 net sections of undeveloped Bakken land and 380 net low
        risk Bakken development locations to the Trust's inventory.

    -   On January 16, 2008, the Trust closed the previously announced
        acquisition of Pilot, adding approximately 1,000 boe/d of focused,
        high netback oil production, 50 percent of which is in the Bakken.
        The acquisition added 6.5 net sections of undeveloped Bakken land and
        22 (19.0 net) low risk Bakken drilling locations to the Trust's
        inventory.

    -   As at March 3, 2008, the Trust had hedged 60 percent, 57 percent,
        41 percent and 2 percent of production, net of royalty interest, for
        2008, 2009, 2010 and the first six months of 2011, respectively.
        Average hedge prices were greater than Cdn$83.00 per boe with minimum
        floor prices ranging from Cdn$74.00 per boe to Cdn$96.00 per boe.

    -   On December 11, 2007, Crescent Point announced a bought deal equity
        financing of 5.2 million trust units at $24.25 per trust unit for
        gross proceeds of approximately $125 million. Closing of the equity
        financing occurred on January 8, 2008.

    -   During 2007 the Crescent Point's borrowing base was increased to
        $800 million from $470 million. A further increase due to strong 2007
        reserve additions is expected in May 2008 when the credit line is
        renewed. The Trust's balance sheet remains strong with projected 2008
        net debt to 12 month cash flow of 1.0 times.
    

    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 2007, 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, averaging 33,351 boe/d and exceeding the Trust's market
guidance of 31,250 boe/d. The Trust participated in the drilling of 35 (27.2
net) oil wells and 2 (1.7 net) service wells, achieving a 100 percent success
rate and adding in excess of 1,800 boe/d of initial interest production, not
including volumes added from fracture stimulation activities. Crescent Point
fracture stimulated 23 (22.0 net) operated Bakken horizontal wells achieving
average post fracture production rates exceeding 200 boe/d per stimulation.

    
    Drilling Results
    -------------------------------------------------------------------------
    Three months ended
     December 31,                                                       %
     2007              Gas  Oil  D&A  Service  Standing  Total   Net Success
    -------------------------------------------------------------------------
    Southeast
     Saskatchewan        -   35    -        1         -     36  27.9    100
    Southwest
     Saskatchewan        -    -    -        -         -      -     -      -
    South/Central
     Alberta             -    -    -        -         -      -     -      -
    Northeast BC and
     West Peace River
     Arch, Alberta       -    -    -        1         -      1   1.0      -
    -------------------------------------------------------------------------
    Total                -   35    -        2         -     37  28.9    100
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Year ended
     December 31,                                                       %
     2007              Gas  Oil  D&A  Service  Standing  Total   Net Success
    -------------------------------------------------------------------------
    Southeast
     Saskatchewan        -  124    -        4         1    129  93.7     99
    Southwest
     Saskatchewan        -   13    -        -         -     13   6.4    100
    South/Central
     Alberta             -    1    -        1         -      2   1.9    100
    Northeast BC and
     West Peace River
     Arch, Alberta       -    4    -        1         -      5   5.0    100
    -------------------------------------------------------------------------
    Total                -  142    -        6         1    149 107.0     99
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Southeast Saskatchewan

    In the fourth quarter of 2007, Crescent Point participated in the
drilling of 35 (27.2 net) oil wells in southeast Saskatchewan, all of which
were horizontal wells in the Viewfield Bakken light oil resource play. The
Trust achieved a 100 percent success rate on the wells and added initial
interest production of approximately 1,800 boe/d, not including fracture
stimulations. The Trust also drilled 1 (0.7 net) water injector well at
Tatagwa during the quarter.
    Crescent Point fracture stimulated 23 (22.0 net) Viewfield Bakken wells
utilizing several progressive packer isolation techniques to optimize
productivity. Results indicate average post fracture production rates
exceeding 200 boe/d per stimulation.
    At the Viewfield gas plant, Crescent Point added depropanization and
debutanization facilities in the fourth quarter, providing for the production
of propane and butane and capturing additional processing value. The gas plant
was expanded in the third quarter of 2007, doubling capacity from 3 mmcf/d to
6 mmcf/d. Crescent Point will increase the capacity to 15 mmcf/d in 2008 to
accommodate the Trust's 2008 drilling plans at Viewfield, which include up to
79 (65.5 net) Bakken wells.
    Through a strategic Crown and freehold land acquisition strategy, the
Trust acquired 115 net sections of undeveloped Bakken land in 2007, including
44 net sections acquired in the fourth quarter. At year end, Crescent point
had 363 net sections of undeveloped Bakken Land.
    One (0.7 net) water injector well was drilled at the Tatagwa Unit in the
fourth quarter. Development plans for Tatagwa in 2008 include drilling up to 6
(4.2 net) water injector wells and 3 (2.1 net) oil wells to improve recovery
factors. Expansion of water handling facilities is also planned for 2008.
    Restrictions on the Enbridge Pipelines gathering system in southeast
Saskatchewan continued in the fourth quarter, resulting in marginally higher
average transportation costs. No volumes were shut in due to these
restrictions. Expansion of the gathering system is anticipated to be completed
in mid 2008.

    Southwest Saskatchewan

    Crescent Point continued to optimize water flood patterns at Battrum.
With Crescent Point's production exceeding targets in 2007, the Trust delayed
fourth quarter drilling and recompletion activities at Battrum into early
2008. In 2008, the Trust plans to drill up to 20 (9.1 net) oil wells in the
Battrum and Cantuar units which are expected to maintain production at current
levels. The Trust also plans to conduct a detailed review of unit facility
configurations to reduce fuel and utility consumption while increasing overall
productivity levels.

    South/Central Alberta

    At Sounding Lake, Crescent Point continued to work on recovery
optimization activities within the Dina and Cummings formations. The Trust
received regulatory approval for its application for pool delineation of the
Sparky formation and submitted its application for water flood implementation,
approval for which is expected in mid 2008. Plans for 2008 include drilling up
to 4 (3.8 net) wells and converting 6 (6.0 net) water injection wells in the
Sparky formation. Water injection may commence in mid to late 2008. In
addition, up to 4 (4.0 net) injector conversions in the Cummings formation are
planned to optimize flood patterns and recovery factors.
    Crescent Point continued to conduct several optimization operations in
the John Lake and Cold Lake areas to offset natural production declines and
reduce operating costs. A total of 13 (13.0 net) compression reconfigurations
were completed, adding over 300 mcf/d in 2007. Ten (10.0) well optimizations
added over 500 mcf/d of net incremental production. Combined area operating
costs were reduced by over $1.00 per boe.
    At Little Bow, the Trust plans to complete the first 8 (8.0 net) of up to
19 (19.0 net) recompletion candidates in 2008. Reserve additions of 20,000 boe
per location are internally estimated for these recompletions.

    Northeast British Columbia and Peace River Arch, Alberta

    At Worsley, water injection and optimization at the Charlie Lake S and T
pools continued during the fourth quarter. Three oil wells planned for tie-in
during the quarter were delayed until January 2008 due to pipeline operations
issues. An expansion of the Charlie Lake S pool water flood is currently
awaiting regulatory approval expected in early to mid 2008. Up to 4 (3.6 net)
wells targeting the Charlie Lake formation are planned for 2008 along with
continued optimization of gas gathering facilities.

    Acquisitions

    On September 5, 2007, Crescent Point announced the strategic Bakken
consolidation acquisition of Innova for $7.55 cash per share, plus assumed
debt, for a total consideration of approximately $400.0 million. The Trust
subsequently took effective control of Innova on October 22, 2007 when more
than 97 percent of outstanding Innova shares were tendered to the offer. With
the completion of the acquisition, Crescent Point acquired approximately
4,300 boe/d of high quality, high netback light oil and natural gas
production, 65 percent of which is in the Viewfield Bakken resource play. The
Innova acquisition consolidated the Trust's dominant Bakken land position,
adding more than 97 net sections of undeveloped land and 380 net low risk
development locations to the Trust's Bakken development drilling inventory.
    On January 16, 2008, the Trust closed the previously announced
acquisition of Pilot, adding approximately 1,000 boe/d of focused, high
netback oil production, 50 percent of which is in the Bakken. The acquisition
added 6.5 net sections of undeveloped Bakken land and 22 (19.0 net) low risk
Bakken drilling locations to the Trust's inventory.

    RESERVES

    In 2007, Crescent Point replaced 410 percent of production on a proved
plus probable basis, not including reserves added through acquisitions.
Including acquisitions, the Trust increased its year end proved plus probable
reserves by 85 percent to 167.5 million boe and its proved reserves by
81 percent to 115.7 million boe. Year end 2006 reserves were 90.3 million boe
proved plus probable and 64.0 million boe proved.

    
    -   The Trust increased its net asset value ("NAV") per unit to $40.21 at
        year end 2007 from $21.61 at year end 2006 and from $15.12 at year
        end 2005, based on independent engineering evaluations of reserves
        and escalated price assumptions discounted at 5 percent. The Trust
        has increased NAV per unit every year since inception.

    -   Crescent Point achieved technical revisions on its core Viewfield
        Bakken assets of 20.8 mmboe proved and 35.7 mmboe proved plus
        probable. At year end 2007, the Trust had Bakken reserves of 47.0
        mmboe proved and 70.2 mmboe proved plus probable.

    -   Crescent Point increased its proved plus probable reserve life index
        to 13.3 years from 11.9 years.

    -   Including the acquisitions of Pilot and Landex, the Trust's reserves
        will increase to 175.7 million boe proved plus probable and its
        reserve life index to 14.0 years.

    The Trust's year end reserves were independently evaluated by GLJ
Petroleum Consultants Ltd. and Sproule Associates Ltd. as at December 31,
2007.


    Summary of Reserves
    (Escalated Pricing)

    As at December 31, 2007(1)
                               ----------------------------------------------
                                                 RESERVES(2)
                               ----------------------------------------------
                                       Oil (mstb)              Gas (mmscf)
                               ----------------------------------------------
    Description                    Gross         Net       Gross         Net
    -------------------------------------------------------------------------
    Proved producing              62,088      52,945      43,262      35,429
    Proved non-producing          37,532      33,740      25,264      20,844
    -------------------------------------------------------------------------
    Total proved                  99,620      86,685      68,526      56,273
    Probable                      45,000      39,174      27,649      22,908
    -------------------------------------------------------------------------
    Total proved plus
     probable(3)                 144,620     125,859      96,175     79,181
    -------------------------------------------------------------------------

                               ----------------------------------------------
                                                 RESERVES(2)
                               ----------------------------------------------
                                       NGL (mbbls)             Total (mboe)
                               ----------------------------------------------
    Description                    Gross         Net       Gross         Net
    -------------------------------------------------------------------------
    Proved producing               1,611       1,425      70,910      60,274
    Proved non-producing           3,051       2,799      44,793      40,015
    -------------------------------------------------------------------------
    Total proved                   4,662       4,224     115,703     100,289
    Probable                       2,164       1,986      51,773      44,977
    -------------------------------------------------------------------------
    Total proved plus
     probable(3)                   6,826       6,210     167,476     145,266
    -------------------------------------------------------------------------
    (1) Based on GLJ's January 1, 2008 escalated price forecast.
    (2) "Gross Reserves" are the total Trust's interest share before the
        deduction of any royalties and without including any royalty interest
        of the Trust. "Net Reserves" are the total Trust's interest share
        after deducting royalties including any royalty interests.
    (3) Numbers may not add due to rounding.


    Summary of Before and After Tax Net Present Values
    (Escalated Pricing)

    As at December 31, 2007(1)
                            -------------------------------------------------
                                       BEFORE TAX NET PRESENT VALUE ($000)
                            -------------------------------------------------
                                                 Discount Rate
                            -------------------------------------------------
    Description             Undiscounted          5%         10%         15%
    -------------------------------------------------------------------------
    Proved producing           2,812,839   2,082,080   1,695,324   1,452,326
    Proved non-producing       1,935,941   1,406,808   1,088,634     878,279
    -------------------------------------------------------------------------
    Total proved               4,748,780   3,488,888   2,783,958   2,330,605
    Probable                   2,492,837   1,346,743     874,943     630,479
    -------------------------------------------------------------------------
    Total proved plus probable 7,241,617   4,835,631   3,658,901   2,961,084
    -------------------------------------------------------------------------

                            -------------------------------------------------
                                        AFTER TAX NET PRESENT VALUE ($000)
                            -------------------------------------------------
                                                 Discount Rate
                            -------------------------------------------------
    Description             Undiscounted          5%         10%         15%
    -------------------------------------------------------------------------
    Proved producing           2,630,828   1,987,669   1,638,386   1,414,651
    Proved non-producing       1,693,520   1,256,839     987,498     805,749
    -------------------------------------------------------------------------
    Total proved               4,324,348   3,244,508   2,625,884   2,220,400
    Probable                   1,854,205   1,020,979     674,088     492,498
    -------------------------------------------------------------------------
    Total proved plus probable 6,178,553   4,265,487   3,299,972   2,712,898
    -------------------------------------------------------------------------
    (1) Based on GLJ's January 1, 2008 escalated price forecast.


    Reserves Reconciliation
    (Escalated Pricing)

    Gross Reserves(1)

    For the year ended December 31, 2007
                                             --------------------------------
                                                  CRUDE OIL AND NGL (mbbl)
                                             --------------------------------
                                              Proved    Probable       Total
    -------------------------------------------------------------------------
    Opening balance
      January 1, 2007                         57,458      23,962      81,420
    Acquired                                  30,554       9,099      39,653
    Disposed                                     (32)        (34)        (66)
    Production                                (8,887)          0      (8,887)
    Development                               21,203      14,685      35,888
    Technical revisions                        3,987        (548)      3,439
    -------------------------------------------------------------------------
    Closing balance
      December 31, 2007(2)                   104,282      47,164     151,446
    -------------------------------------------------------------------------

                                             --------------------------------
                                                    NATURAL GAS (mmscf)
                                             --------------------------------
                                              Proved    Probable       Total
    -------------------------------------------------------------------------
    Opening balance
      January 1, 2007                         38,959      14,446      53,405
    Acquired                                  25,797      10,542      36,339
    Disposed                                  (1,197)       (522)     (1,719)
    Production                                (8,253)          0      (8,253)
    Development                                8,753       5,331      14,084
    Technical revisions                        4,466      (2,147)      2,319
    -------------------------------------------------------------------------
    Closing balance
      December 31, 2007(2)                    68,526      27,649      96,175
    -------------------------------------------------------------------------

                                             --------------------------------
                                                       BOE (mboe)
                                             --------------------------------
                                              Proved    Probable       Total
    -------------------------------------------------------------------------
    Opening balance
      January 1, 2007                         63,951      26,370      90,321
    Acquired                                  34,854      10,856      45,711
    Disposed                                    (232)       (121)       (353)
    Production                               (10,263)          0     (10,263)
    Development                               22,662      15,574      38,235
    Technical revisions                        4,731        (906)      3,825
    -------------------------------------------------------------------------
    Closing balance
      December 31, 2007(2)                   115,703      51,773     167,476
    -------------------------------------------------------------------------
    (1) Based on GLJ's January 1, 2008 escalated price forecast. "Gross
        reserves" are the Trust's working-interest share before deduction of
        any royalties and without including any royalty interests of the
        Trust.
    (2) Numbers may not add due to rounding.


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

    For the year ended December 31, 2007

                 ------------------------------------------------------------
                                                                 FINDING,
                       CAPITAL                                 DEVELOPMENT
                    EXPENDITURES                             AND ACQUISITION
                       (1)(4)             RESERVES(3)           COSTS(1)(2)
                 ------------------------------------------------------------
                                                   Proved             Proved
                                       Total        Plus               Plus
                                      Proved      Probable   Proved  Probable
    -------------------------------------------------------------------------
                     $000    %     mboe    %     mboe    %    $/boe    $/boe
    -------------------------------------------------------------------------
    Exploration
     development
     and
     revisions   $227,923   18%  27,392   44%  42,060   48%  $ 8.32   $ 5.42
    Acquisitions,
     net of
     dispos-
     itions    $1,058,069   82%  34,622   56%  45,358   52%  $30.56   $23.33
    -------------------------------------------------------------------------
    Total      $1,285,993  100%  62,015  100%  87,418  100%  $20.74   $14.71
    -------------------------------------------------------------------------
    (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 $220.927 million and $314.485 million
        respectively to the proved and proved plus probable reserves
        categories. Including these changes, the proved and proved plus
        probable finding and development costs are $16.39 and $12.90 per boe
        respectively.
    (2) Including change in future development costs, finding, development
        and acquisition costs are $24.30 per proved boe and $18.31 per proved
        plus probable boe.
    (3) Gross Trust interest reserves are used in this calculation (interest
        reserves, before deduction of any royalties and without including any
        royalty interests of the Trust).
    (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 First Quarter 2008 Acquisitions

    (Escalated Pricing)

    As at January 1, 2008(1)(2)
                               ----------------------------------------------
                                                   RESERVES(3)
                               ----------------------------------------------
                                       Oil (mstb)              Gas (mmscf)
    -------------------------------------------------------------------------
    Description                    Gross         Net       Gross         Net
    -------------------------------------------------------------------------
    Proved producing              65,643      56,077      44,384      36,466
    Proved non-producing          38,998      35,090      25,884      21,427
    -------------------------------------------------------------------------
    Total proved                 104,640      91,167      70,268      57,894
    Probable                      47,648      41,543      28,555      23,751
    -------------------------------------------------------------------------
    Total proved plus
     probable(4)                 152,288     132,710      98,823      81,645
    -------------------------------------------------------------------------

                               ----------------------------------------------
                                                   RESERVES(3)
                               ----------------------------------------------
                                       NGL (mbbls)             Total (mboe)
    -------------------------------------------------------------------------
    Description                    Gross         Net       Gross         Net
    -------------------------------------------------------------------------
    Proved producing               1,623       1,437      74,663      63,592
    Proved non-producing           3,122       2,864      46,434      41,526
    -------------------------------------------------------------------------
    Total proved                   4,745       4,302     121,097     105,117
    Probable                       2,235       2,053      54,642      47,554
    -------------------------------------------------------------------------
    Total proved plus
     probable(4)                   6,980       6,354     175,739     152,672
    -------------------------------------------------------------------------

                               ----------------------------------------------
                                    BEFORE TAX NET PRESENT VALUE ($000)
                               ----------------------------------------------
                                                Discount Rate
    -------------------------------------------------------------------------
    Description             Undiscounted          5%         10%         15%
    -------------------------------------------------------------------------
    Proved producing           2,982,478   2,223,327   1,817,660   1,561,112
    Proved non-producing       2,007,585   1,461,015   1,132,211     914,643
    -------------------------------------------------------------------------
    Total proved               4,990,063   3,684,342   2,949,872   2,475,755
    Probable                   2,630,987   1,432,863     936,188     677,719
    -------------------------------------------------------------------------
    Total proved plus
     probable(4)               7,621,051   5,117,205   3,886,060   3,153,475
    -------------------------------------------------------------------------
    (1) Includes independent engineers' evaluations of Crescent Point 2007
        year end, Pilot Energy Ltd 2007 year end, and Landex Petroleum
        non-Bakken assets 2007 year end.
    (2) Based on GLJ's January 1, 2008 escalated price forecast.
    (3) "Gross Reserves" are the total Trust's interest share before the
        deduction of any royalties and without including any royalty
        interests of the Trust. "Net Reserves" are the total Trust's interest
        share after deducting royalties including any royalty
        interests.
    (4) Numbers may not add due to rounding.


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

    -------------------------------------------------------------------------
                    2008(1)     2007      2006      2005      2004      2003
    -------------------------------------------------------------------------
    PV 0%           $59.69    $61.03    $34.08    $21.99    $16.19    $12.72
    PV 5%           $39.92    $40.21    $21.61    $15.12    $11.22    $ 9.15
    PV 10%          $30.23    $30.05    $15.70    $11.45    $ 8.56    $ 7.14
    PV 15%          $24.47    $24.04    $12.27    $ 9.10    $ 6.85    $ 5.83
    -------------------------------------------------------------------------
    (1) Includes the acquisition of Pilot Energy Ltd and Landex Petroleum
        Corp. non Bakken assets utilizing January 1, 2008 Independent
        Engineering Escalated Pricing and the impact of the bought deal
        equity financing of $125 million.
    


    CHANGES TO THE ALBERTA ROYALTY SYSTEM

    On October 25, 2007, the Province of Alberta announced changes to the
Alberta royalty system that would take effect on January 1, 2009. The changes
included increased royalty rates in many instances and the removal of many
royalty incentives currently in place.
    Crescent Point completed an evaluation of the royalty announcement and
concluded that the royalty changes would have minimal impact on the Trust's
current production and operations. More than 80 percent of Crescent Point's
current production is sourced from the province of Saskatchewan, and more than
90 percent of the Trust's 2008 capital development budget will be spent in
Saskatchewan. Crescent Point anticipates that the Alberta royalty announcement
will affect the Trust's corporate royalty rates on existing production by
approximately one percent.
    In late January of 2008, the Province announced that it would make
further revisions to the royalty system, tempering the increases announced on
October 25, with the hopes of offsetting the decline in drilling and
investment due to the October changes.

    SUBSEQUENT EVENT: INVESTMENT IN SHELTER BAY ENERGY INC. AND ACQUISITION
    OF LANDEX NON BAKKEN ASSETS

    As part of the October 31, 2006 federal government decision to tax
Canadian income trusts in 2011, the government also restricted the amount of
equity that could be issued by trusts between October 31, 2006 and
December 31, 2010 with the creation of Safe Harbour Limits, which are defined
as a percentage of October 31, 2006 market capitalization.
    To allow the Trust to continue to execute its business plan within the
constraints of the Safe Harbour Limits, Crescent Point announced in January
2008 a $60 million investment in Shelter Bay Energy Inc. ("Shelter Bay"), a
private corporation not subject to the equity growth constraints placed on
income trusts. Crescent Point's investment represents a 20 percent interest in
Shelter Bay. Crescent Point will provide Shelter Bay with management and
technical expertise under a Technical Services Agreement whereby Shelter Bay
will lever off Crescent Point's knowledge and infrastructure to further
consolidate and dominate the southeast Saskatchewan Bakken play and other core
Crescent Point areas.
    As part of its investment in Shelter Bay, Crescent Point has agreed to
farmout 22 net sections, representing approximately 6 percent, of the Trust's
undeveloped Bakken land to Shelter Bay. Crescent Point expects Shelter Bay to
drill 40 gross Bakken horizontal wells on these farmin lands in each of 2008
and 2009. Crescent Point retains an interest of up to 50 percent of each well,
adding production, cash flow and reserves with limited capital requirements.
    It is anticipated that Crescent Point and Shelter Bay will merge
operations in the future when the Safe Harbour Limits on equity issuance are
no longer of relevance for Crescent Point.
    Concurrent with the investment in Shelter Bay, Crescent Point announced
that it had entered into an agreement to acquire Landex, a private oil and gas
company with assets in southeast Saskatchewan, for total consideration of
approximately $310 million. As part of the agreement, Crescent Point is
expected to acquire the non Bakken assets of Landex, approximately
1,500 boe/d, for $80 million and Shelter Bay is expected to acquire the Bakken
assets of Landex, approximately 2,500 boe/d, for $230 million.
    The acquisition is expected to close in late March 2008.

    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 2007, the Trust has demonstrated year over
year growth in per unit net asset value since inception.
    The Trust has an extensive low risk development drilling inventory of
nearly 1,400 net locations, representing more than $2.2 billion of future
development projects and more than 13 years of low risk drilling inventory to
sustain and grow current production levels. With projected debt to cash flow
of 1.0 times and a balanced 3 1/2 year commodity price risk management
program, Crescent Point is well positioned to sustain distributions over time
as the Trust continues to exploit and develop its asset base.
    Crescent Point has more than 4.6 billion barrels of original oil in place
and a reserve life index of 14.0 years, including Pilot and Landex, on a
proved plus probable basis. Through infill drilling, production optimization
and water flood implementation, management believes the Trust has the
potential to more than double its proved plus probable reserves over time.
    Crescent Point's development capital budget for 2008 has been set at
$225 million, balanced more towards the development of the Bakken light oil
resource play. The Trust anticipates drilling up to 79 (65.5 net) Bakken
horizontal wells and fracture stimulating a further 92 (77.2) Bakken
horizontal wells during the year. Crescent Point's share of Shelter Bay
drilling on farmout lands will add up to 20 net additional fracture stimulated
Bakken horizontal wells.
    Due to the success of the Bakken drilling program, Crescent Point will
further expand the Viewfield gas plant from 6 mmcf/d to 15 mmcf/d. The
expansion will accommodate incremental gas and liquids volumes resulting from
the 2008 Bakken drilling program.
    In addition, the Trust will continue active development programs at its
core properties of Manor, Tatagwa, Battrum/Cantuar, Worsley, Sounding Lake and
Glen Ewen. Overall, the Trust expects to spend approximately $175 million on
drilling and fracture stimulation activities in 2008, including the drilling
of up to 140 (105.7 net) wells. The Trust will spend up to $50 million on
facilities, land and seismic.
    The Trust anticipates 2008 cash flow will be in the range of
$527 million, or $4.21 per unit, fully diluted, based on forecast pricing of
US$92.50 per barrel WTI, US$1.00 exchange rate, and Cdn$8.00 per mcf AECO.
Monthly distributions are anticipated to remain at $0.20 per unit for a payout
ratio of 57%. Production is forecast at 34,500 boe/d.
    The Trust increased its commodity hedging program to 3 1/2 years, with
60 percent, 57 percent, 41 percent and 2 percent of production, net of royalty
interest, hedged for 2008, 2009, 2010 and the first six months of 2011,
respectively. Average hedge prices are greater than Cdn$83.00 per boe. Hedge
instruments utilized in the program include swaps, collars and put options,
providing minimum floor prices ranging from Cdn$74.00 per boe to Cdn$96.00 per
boe, with upside potential if prices strengthen above current levels.
    Through its investment in Shelter Bay, the Trust remains exposed to
further consolidation opportunities, including land, asset and corporate
acquisitions, in the Bakken light oil resource play and in other core Crescent
Point areas.
    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 2008
and beyond.

    
    2008 Guidance

    Crescent Point's 2008 guidance is as follows:
    -------------------------------------------------------------------------
    Production
      Oil and NGL (bbls/d)                                            30,125
      Natural gas (mcf/d)                                             26,250
    -------------------------------------------------------------------------
      Total (boe/d)                                                   34,500
    -------------------------------------------------------------------------
    Cash flow ($000)                                                 527,000
    Cash flow per unit - diluted ($)                                    4.21
    Cash distributions per unit ($)                                     2.40
    Payout ratio - per unit - diluted (%)                                 57
    -------------------------------------------------------------------------
    Capital expenditures ($000)(1)                                   225,000
    Wells drilled, net                                                   106
    -------------------------------------------------------------------------
    Pricing
      Crude oil - WTI (US$/bbl)                                        92.50
      Crude oil - WTI (Cdn$/bbl)                                       92.50
      Natural gas - Corporate (Cdn$/mcf)                                8.00
      Exchange rate (US$/Cdn$)                                          1.00
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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, 2008


    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, 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. Cash flow from operations per unit-diluted is
calculated based on cash flow from operating activities before changes in
non-cash working capital and asset retirement obligation expenditures
excluding the cash portion of unit-based compensation. 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)                  2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Cash flow from
     operating
     activities           99,070    39,313    152   332,605   177,426     87
    Changes in non-cash
     working capital      12,623     3,915    222    21,450    10,691    101
    Asset retirement
     expenditures            879       615     43     1,855     1,018     82
    -------------------------------------------------------------------------
    Cash flow from
     operations          112,572    43,843    157   355,910   189,135     88
    -------------------------------------------------------------------------
    

    Net debt is calculated as current liabilities less current assets,
including long term investments, and excluding risk management assets and
liabilities. 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. 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.

    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 analysis under the headings "Cash Distributions", "Capital
Expenditures", "Asset Retirement Obligation", "Liquidity and Capital
Resources", "Critical Accounting Estimates" and "New Accounting
Pronouncements".
    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.

    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.

    Production

    Crescent Point's production increased 36 percent year-over-year due to
the acquisition of Mission Oil & Gas Inc. ("Mission"), Innova Exploration Ltd.
("Innova"), several other acquisitions completed in 2007 and the Trust's
successful drilling program. The Mission acquisition closed on February 9,
2007 and added over 7,000 boe/d of high quality, long life, light oil and
natural gas assets, including more than 5,000 boe/d from the Viewfield Bakken
resource play. The Innova acquisition closed on October 22, 2007 and added
over 4,300 boe/d of high quality, long life, light oil and natural gas assets,
including more than 2,800 boe/d from the Viewfield Bakken resource play. These
acquisitions added a new core area for the Trust in the Viewfield area of
southeast Saskatchewan. Contributing to the increase in production were minor
property acquisitions in the Viewfield Bakken area and drilling of
149 (107.0 net) wells focused primarily in southeast Saskatchewan.
    The Trust's weighting to oil increased to 87 percent for the 2007 year, a
three percent increase over 2006. The increase in the Trust's oil weighting is
primarily the result of the Mission and Innova acquisitions which were focused
on light oil assets.

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
                                               %                          %
    ($000)                  2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Crude oil and
     NGL (bbls/d)         28,601    17,967     59    24,349    17,417     40
    Natural gas
     (mcf/d)              28,500    20,410     40    22,610    19,833     14
    -------------------------------------------------------------------------
    Total (boe/d)         33,351    21,369     56    28,117    20,723     36
    -------------------------------------------------------------------------
    Crude oil and NGL (%)     86        84      2        87        84      3
    Natural gas (%)           14        16     (2)       13        16     (3)
    -------------------------------------------------------------------------
    Total (%)                100       100      -       100       100      -
    -------------------------------------------------------------------------
    

    Marketing and Prices

    The Trust's selling price for oil increased 12 percent over 2006,
primarily due to narrower corporate oil differentials as increases in the
US$ benchmark price were largely offset by a stronger Canadian dollar.
Crescent Point's oil differential narrowed significantly from $15.25 per bbl
in 2006 to $10.52 per bbl in 2007, due to both changes in market conditions
and an improvement in the Trust's crude oil quality as a result of the
Viewfield Bakken light oil properties acquired through the Mission and Innova
acquisitions.
    The Trust's average selling price for gas was comparable to the 2006 year
with a slight increase of three percent. This compares to a two percent
decline in the AECO daily gas price. The variation in the Trust's gas price
compared to the AECO daily price reflects the Trust's portfolio of gas
marketing contracts and the addition of high heat content gas production
associated with the acquired Viewfield Bakken area.

    
    -------------------------------------------------------------------------
    Average Selling          Three months ended              Year ended
     Prices(1)                    December 31                December 31
                                               %                          %
                            2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Crude oil and
     NGL ($/bbl)           75.31     53.75     40     67.33     60.03     12
    Natural gas
     ($/mcf)                6.32      6.45     (2)     6.52      6.33      3
    -------------------------------------------------------------------------
    Total ($/boe)          69.99     51.35     36     63.55     56.52     12
    -------------------------------------------------------------------------
    (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
                                               %                          %
                            2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    WTI crude oil
     (US$/bbl)             90.63     60.22     50     72.40     66.25      9
    WTI crude oil
     (Cdn$/bbl)            88.85     68.43     30     77.85     75.28      3
    AECO natural gas(1)
     (Cdn$/mcf)             6.15      6.98    (12)     6.44      6.54     (2)
    Exchange rate
     - US$/Cdn$             1.02      0.88     16      0.93      0.88      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 Trust's crude oil and natural gas financial instruments are
referenced to WTI and AECO, unless otherwise noted. Crescent Point utilizes a
variety of financial instruments including swaps, collars and puts to protect
against downward commodity price movements while providing the opportunity for
some participation during periods of rising prices.
    Crescent Point had a realized financial instrument loss for oil of
$10.8 million for the 2007 year compared to a $30.4 million loss in 2006. The
decrease in the loss is attributable to higher average financial instrument
prices for oil. The Trust's effective financial instrument oil price increased
approximately $11.98 per barrel, from $63.24 per barrel in 2006 to $75.22 per
barrel in 2007.
    The following is a summary of the realized financial instrument gains
(losses) on oil and gas contracts:

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
    ($000, except                December 31                December 31
     per boe and                               %                          %
     volume amounts)        2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Average crude oil
     volumes hedged
     (bbls/d)             12,250     7,500     63    11,190     6,917     62
    Crude oil realized
     financial instrument
     loss                (11,594)   (3,824)   203   (10,752)  (30,410)   (65)
      per bbl              (4.41)    (2.31)    91     (1.21)    (4.78)   (75)
    Average natural gas
     volumes hedged
     (GJ/d)                2,674     2,333     15     3,173       917    246
    Natural gas realized
     financial instrument
     gain                    305       139    119       853        87    880
      per mcf               0.12      0.07     71      0.10      0.01    900
    Average barrels
     of oil equivalent
     hedged (boe/d)       12,672     7,869     61    11,691     7,062     66
    Total realized
     financial instrument
     loss                (11,289)   (3,685)   206    (9,899)  (30,323)   (67)
      per boe              (3.68)    (1.87)    97     (0.96)    (4.01)   (76)
    -------------------------------------------------------------------------
    

    The Trust has not designated any of its risk management activities as
accounting hedges under the Canadian Institute of Chartered Accountants (the
"CICA") section 3855 and, accordingly, has marked-to-market its financial
instruments. The Trust's unrealized financial instruments loss for the 2007
year was $105.4 million compared to a $13.9 million unrealized financial
instrument gain in 2006. The loss for the 2007 year is attributable to the
significant increase in the Cdn$ WTI benchmark price at December 31, 2007
compared to December 31, 2006, and an increase in the volume hedged, partially
offset by an increase in the average hedge price.
    Crescent Point has the following financial instrument contracts in place
as March 3, 2008:

    
    -------------------------------------------------------------------------
    Financial WTI Crude Oil Contracts - Canadian Dollar

                                                   Average  Average
                                         Average    Bought     Sold  Average
                                            Swap       Put     Call      Put
                                           Price     Price    Price  Premium
                                Volume    ($Cdn/    ($Cdn/   ($Cdn/   ($Cdn/
    Term            Contract   (bbls/d)      bbl)      bbl)     bbl)     bbl)
    -------------------------------------------------------------------------
    2008
    January -
     June               Swap     1,000     72.73
    January -
     September          Swap       250     68.10
    January -
     December           Swap     7,000     77.73
    February -
     December           Swap       500     93.00
    April -
     December           Swap       750     89.70
    July -
     December           Swap     1,000     73.52
    October -
     December           Swap       250     70.80
    January -
     June             Collar       250               65.00    82.00
    January -
     December         Collar     3,500               73.50    88.57
    July -
     December         Collar       250               70.00    91.00
    January -
     December            Put     3,500               72.58             (6.66)
    -------------------------------------------------------------------------
    2008 Weighted
     Average                    16,521     78.48     72.85    88.44    (6.66)
    -------------------------------------------------------------------------
    2009
    January -
     March              Swap     2,750     77.68
    April -
     June               Swap     2,750     77.58
    January -
     June               Swap     1,250     74.99
    July -
     September          Swap     3,000     74.07
    July -
     December           Swap     1,000     76.41
    October -
     December           Swap     3,000     74.37
    January -
     December           Swap     4,000     82.78
    January -
     March            Collar       250               75.00    87.00
    April -
     June             Collar       250               75.00    83.00
    January -
     June             Collar     1,250               70.00    81.01
    January -
     September        Collar       250               70.00    79.00
    January -
     December         Collar     3,000               74.25    89.05
    July -
     September        Collar       250               70.00    84.05
    July -
     December         Collar     1,250               69.00    80.37
    October -
     December         Collar       500               70.00    85.93
    January -
     December            Put     3,250               70.46             (6.03)
    -------------------------------------------------------------------------
    2009 Weighted Average       16,000     79.28     71.78    86.20    (6.03)
    -------------------------------------------------------------------------
    2010
    January -
     March              Swap     3,500     76.22
    April -
     June               Swap     2,750     74.38
    January -
     September          Swap     2,250     79.51
    April -
     September          Swap       750     75.53
    July -
     September          Swap     2,750     75.00
    October -
     December           Swap     5,250     89.57
    January -
     December           Swap       750     89.00
    January -
     June             Collar       500               70.00    80.50
    January -
     September        Collar     2,000               73.75    86.26
    July -
     September        Collar       500               70.00    81.75
    October -
     December         Collar     2,250               80.22    97.48
    January -
     December         Collar     1,000               83.50    96.63
    January -
     September           Put     1,000               71.00             (4.82)
    October -
     December            Put     1,000               72.00             (4.85)
    January -
     December            Put       750               73.00             (4.22)
    -------------------------------------------------------------------------
    2010 Weighted Average       11,561     80.99     75.48    90.54    (4.56)
    -------------------------------------------------------------------------
    2011
    January - June      Swap       500     96.20
    -------------------------------------------------------------------------
    2011 January -
     June Weighted Average         500     96.20
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Financial AECO Natural Gas Contracts - Canadian Dollar
                                                          Average    Average
                                                           Bought  Sold Call
                                               Volume   Put Price      Price
    Term                           Contract    (GJ/d)   ($Cdn/GJ)   ($Cdn/GJ)
    -------------------------------------------------------------------------
    2008
    January - March                  Collar     2,000        6.75       8.00
    April - October                  Collar     2,000        6.75       7.75
    -------------------------------------------------------------------------
    2008 January - October
     Weighted Average                           2,000        6.75       7.82
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Financial Interest Rate Contracts - Canadian Dollar
                                                                       Fixed
                                                        Principal     Annual
    Term                                     Contract      ($Cdn)    Rate (%)
    -------------------------------------------------------------------------
    January 2008 - May 2008                      Swap  50,000,000       4.41
    January 2008 - February 2009                 Swap  50,000,000       4.37
    January 2008 - November 2010                 Swap  75,000,000       4.35
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Financial Power Contracts - Canadian Dollar
                                                           Volume Fixed Rate
    Term                                     Contract      (MW/h) ($Cdn/MW/h)
    -------------------------------------------------------------------------
    January 2008 - December 2008                 Swap         3.0      63.25
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Physical Power Contracts - Canadian Dollar
                                                           Volume Fixed Rate
    Term                                     Contract      (MW/h) ($Cdn/MW/h)
    -------------------------------------------------------------------------
    January 2008 - December 2009                 Swap         1.0      82.45
    January 2009 - December 2009                 Swap         3.0      81.25
    -------------------------------------------------------------------------

    Revenues

    Oil revenues were $598.4 million in 2007 compared with $381.7 million in
2006. The 57 percent increase in oil sales relates primarily to increases in
production resulting from the 2007 acquisitions of Mission and Innova, several
other acquisitions completed in 2007 and the Trust's successful drilling
program. A narrowing of corporate oil differentials due to improvements in the
Trust's crude quality along with higher market oil prices further contributed
to the increase in revenues throughout the year.
    Natural gas sales increased 17 percent in the 2007 year primarily due to
the increase in production in the year resulting from 2007 acquisitions and
the Trust's successful drilling program.

    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
                                               %                          %
    (000)(1)                2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Crude oil and
     NGL sales           198,174    88,855    123   598,364   381,655     57
    Natural gas
     sales                16,574    12,105     37    53,811    45,836     17
    -------------------------------------------------------------------------
    Revenues             214,748   100,960    113   652,175   427,491     53
    -------------------------------------------------------------------------
    (1) Revenue is reported before transportation charges and realized
        financial instruments.
    

    Transportation Expenses

    Transportation expense per boe increased 28 percent compared to 2006. The
increase relates to properties acquired in the past year and their proximity
to market, along with pipeline constraint issues in southeast Saskatchewan
which began in the fourth quarter of 2006 and continued through 2007. Growing
production volumes in southeast Saskatchewan and incremental imports from
other areas have exceeded capacity of the area's major oil gathering system,
Enbridge Pipelines (Saskatchewan). Efforts to maintain crude sales led to
incremental trucking costs in the 2007 year. Expansion of the gathering system
is expected to be completed mid-year of 2008.

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
    ($000, except                              %                          %
     per boe amounts)       2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Transportation
     expenses              5,626     3,293     71    17,725    10,175     74
    Per boe                 1.83      1.68      9      1.73      1.35     28
    -------------------------------------------------------------------------
    

    Royalty Expenses

    Royalties were 18 percent of revenue in 2007 compared to 21 percent of
revenue in 2006. The decrease is primarily due to lower royalty rates on the
properties acquired through the Mission and Innova acquisitions. Further
contributing to the Trust's lower royalty rate are royalty incentives on new
production associated with the Trust's successful drilling program in
southeast Saskatchewan.
    Crescent Point completed an initial evaluation of the October 25, 2007
royalty announcement by the Province of Alberta and concluded that the royalty
changes will have minimal impact on the Trust's current production, operations
and cash flows.

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
    ($000, except                              %                          %
     per boe amounts)       2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Total royalties       39,295    19,157    105   118,915    90,013     32
    As a % of oil and
     gas sales               18%       19%     (1)      18%       21%     (3)
    Per boe                12.81      9.74     32     11.59     11.90     (3)
    -------------------------------------------------------------------------
    

    Operating Expenses

    Operating expense per boe for 2007 remained consistent with the 2006 year
with a slight increase of one percent. The increase in operating costs per boe
for the year reflects higher costs experienced for repairs and maintenance and
one time costs from a partner on a non-operated property during the first half
of 2007. These increases were partially offset by the reduction in operating
costs resulting from the Mission and Innova acquisitions and the lower
operating cost structure associated with the Viewfield Bakken area.

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
    ($000, except                              %                          %
     per boe amounts)       2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Operating expenses    28,192    20,475     38    94,918    69,424     37
    Per boe                 9.19     10.42    (12)     9.25      9.18      1
    -------------------------------------------------------------------------
    

    Netbacks

    Crescent Point's netback, after realized financial instruments, for the
2007 year increased 33 percent from $30.08 per boe to $40.02 per boe primarily
due to the high netback production associated with the Viewfield Bakken area
acquired in 2007. The Viewfield Bakken operating netback realized for 2007 was
$62.09 per boe. Also contributing to the improved netback were lower realized
financial instrument losses in 2007 resulting from higher financial instrument
prices.

    
    -------------------------------------------------------------------------
                                     Three months ended December 31
                                                      2007     2006
    -------------------------------------------------------------------------
                               Crude Oil  Natural
                                 and NGL      Gas    Total    Total        %
                                  ($/bbl)  ($/mcf)  ($/boe)  ($/boe)  Change
    -------------------------------------------------------------------------
    Average selling price          75.31     6.32    69.99    51.35       36
    Royalties                     (13.63)   (1.31)  (12.81)   (9.74)      32
    Operating expenses             (8.85)   (1.87)   (9.19)  (10.42)     (12)
    Transportation                 (1.96)   (0.18)   (1.83)   (1.68)       9
    -------------------------------------------------------------------------
    Netback prior to realized
     financial instruments         50.87     2.96    46.16    29.51       56
    -------------------------------------------------------------------------
    Realized gain (loss) on
     financial instruments         (4.41)    0.12    (3.68)   (1.87)      97
    -------------------------------------------------------------------------
    Netback                        46.46     3.08    42.48    27.64       54
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                             Year ended December 31
                                                      2007     2006
    -------------------------------------------------------------------------
                               Crude Oil  Natural
                                 and NGL      Gas    Total    Total        %
                                  ($/bbl)  ($/mcf)  ($/boe)  ($/boe)  Change
    -------------------------------------------------------------------------
    Average selling price          67.33     6.52    63.55    56.52       12
    Royalties                     (12.06)   (1.42)  (11.59)  (11.90)      (3)
    Operating expenses             (8.97)   (1.84)   (9.25)   (9.18)       1
    Transportation                 (1.79)   (0.22)   (1.73)   (1.35)      28
    -------------------------------------------------------------------------
    Netback prior to realized
     financial instruments         44.51     3.04    40.98    34.09       20
    -------------------------------------------------------------------------
    Realized gain (loss) on
     financial instruments         (1.21)    0.10    (0.96)   (4.01)     (76)
    -------------------------------------------------------------------------
    Netback                        43.30     3.14    40.02    30.08       33
    -------------------------------------------------------------------------
    

    General and Administrative Expenses

    General and administrative expense per boe for the 2007 year decreased
seven percent from 2006. The decrease is the result of higher legal and
professional fees in 2006 that were incurred in preparation for the March 2007
reorganization. In addition, the acquisitions completed in the year by the
Trust have added significant production volumes with minimal incremental
general and administrative expenses.
    Capitalized general and administrative expense increased by 78 percent in
2007 from $2.6 million to $4.6 million. This reflects the significant increase
in the acquisition and development capital expenditure levels in 2007.

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
    ($000, except                              %                          %
     per boe amounts)       2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    General and
     administrative
     costs                 5,402     4,578     18    19,965    14,863     34
    Capitalized           (1,488)     (773)    92    (4,607)   (2,591)    78
    -------------------------------------------------------------------------
    General and
     administrative
     expenses              3,914     3,805      3    15,358    12,272     25
    Per boe                 1.28      1.94    (34)     1.50      1.62     (7)
    -------------------------------------------------------------------------
    

    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.
    The maximum number of trust units issuable under the Restricted Unit
Bonus Plan is 5,000,000 units. The Trust had 1,486,050 restricted units
outstanding at December 31, 2007 compared with 1,043,628 units outstanding at
December 31, 2006.
    The Trust recorded compensation expense and contributed surplus of
$14.4 million in 2007, based on fair value of the units on the date of grant,
an increase of 28 percent over 2006. The cash distributions on restricted
units increased from $1.2 million for the 2006 year to $2.0 million for the
2007 year. The increase in the number of restricted units and corresponding
unit- based compensation expense is attributable to the growth in the Trust's
operations and industry pressures to retain and attract high quality
employees.

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
    ($000, except                              %                          %
     per boe amounts)       2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Cash unit-based
     compensation
     expense                 559       475     18     1,997     1,162     72
    Non-cash
     unit-based
     compensation
     expense               3,786     2,818     34    14,378    11,254     28
    -------------------------------------------------------------------------
    Total                  4,345     3,293     32    16,375    12,416     32
    Per boe                 1.42      1.68    (15)     1.60      1.64     (2)
    -------------------------------------------------------------------------
    

    Interest Expense

    Interest expense per boe increased 17 percent in 2007. This increase is
attributable to increased amounts drawn on credit facilities reflecting the
growth of the Trust and higher effective interest rates resulting from an
increase in the prime rate through the majority of the year. Crescent Point
actively manages exposure to fluctuations in interest rates through interest
rate swaps and short term banker's acceptances (refer to Financial Instruments
and Risk Management section above).

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
    ($000, except                              %                          %
     per boe amounts)       2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Interest expense       8,107     3,602    125    21,805    13,673     59
    Per boe                 2.64      1.83     44      2.12      1.81     17
    -------------------------------------------------------------------------
    

    Depletion, Depreciation and Amortization

    The depletion, depreciation and amortization ("DD&A") rate increased to
$23.67 per boe for the 2007 year from $18.31 per boe in 2006. The higher DD&A
rate is due primarily to the Mission and Innova acquisitions completed in 2007
which carried a higher cost per boe than the Trust's existing properties.

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
    ($000, except                              %                          %
     per boe amounts)       2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Depletion,
     depreciation and
     amortization         68,017    35,448     92   242,923   138,511     75
    Per boe                22.17     18.03     23     23.67     18.31     29
    -------------------------------------------------------------------------
    

    Taxes

    Capital and other tax expense consists of Saskatchewan Corporation
Capital Tax Resource Surcharge. Capital and other tax expense for the 2007
year increased 36 percent due to an increase in the Trust's Saskatchewan based
revenues primarily as a result of the Mission and Innova acquisitions
completed in 2007.
    In 2007, a future income tax expense of $21.2 million was included in
income compared to a $16.6 million recovery in 2006.
    On March 1, 2007, the Trust completed a reorganization of the Trust and
its subsidiaries. The reorganization resulted in the existing business of the
Trust, which was carried on through limited partnerships and corporations,
being carried on through a limited partnership indirectly owned by the Trust.
In the Trust structure, payments are made between the operating entities and
the Trust transferring both the income and tax liability to the unitholders.
As a result of the reorganization, Crescent Point recorded a future tax
recovery of $158.8 million in the first quarter.
    On October 31, 2006, the Finance Minister announced the Federal
Government's plan regarding the taxation of income trusts. Currently,
distributions paid to unitholders, other than returns of capital, are claimed
as a deduction by the Trust in arriving at taxable income whereby tax is
eliminated at the Trust level and is paid by the unitholders. On June 12,
2007, the Federal Government's Bill C-52, which included legislation to tax
publicly traded trusts, was substantively enacted as defined under Canadian
GAAP. As a result of this new legislation, a new 31.5 percent tax will be
applied to distributions from Canadian public income trusts. The new tax is
not expected to apply to Crescent Point until January 1, 2011 as a transition
period applies to publicly traded trusts that existed prior to November 1,
2006. As a result of this change in legislation, a future income tax liability
and future tax expense of $152.3 million was recognized in the second quarter
of 2007. The future income tax represents the taxable temporary differences of
Crescent Point tax effected at 31.5 percent, which is the rate that was
applicable to trusts in 2011 under legislation in place in June 2007.
    On October 30, 2007, the Finance Minister announced, as part of the 2007
Economic Statement, changes to the tax system including reduction of the
corporate income tax rate from 22.1 per cent to 15 per cent by 2012. The
reductions will be phased in between 2008 and 2012. Legislation enacting the
measures announced in the Economic Statement received Royal Assent on December
 14, 2007. The reduction in the general corporate tax rate will also apply to
the taxation of income trusts, reducing the combined federal and deemed
Provincial tax rate for distributions to 29.5 percent in 2011 and 28 percent
in 2012. These rate changes were reflected in the future income tax provision
recorded in the fourth quarter.
    The Trust recorded future tax expenses of $18.0 million in the fourth
quarter of 2007 primarily as a result of the change in temporary differences,
partially offset by the future tax recovery of $23.3 million resulting from
the federal tax rate reductions.
    At December 31, 2007, the Trust had tax pools of approximately
$1.0 billion consisting of intangible resource pools, tangible pools and trust
unit issue costs.
    On February 26, 2008, the federal government announced that beginning
with the 2009 taxation year, the provincial component of the trust tax will be
based on the general provincial corporate tax rate in each province in which
the trust has a permanent establishment instead of the deemed 13 percent
provincial tax rate. On December 20, 2007, the Finance Minister announced
technical amendments to provide some clarification to the Trust tax
legislation. As part of the announcement the Minister indicated that the
federal government intends to provide legislation in 2008 to permit income
trusts to convert to taxable Canadian corporations without any undue tax
consequences to investors or the Trust. Management and the Board of Directors
continue to review the impact of this tax on our business strategy.

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
                                               %                          %
    ($000)                  2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Capital and other
     tax expense           4,874     2,625     86    15,394    11,314     36
    Future income tax
     expense (recovery)   17,965      (220)(8,266)   21,173   (16,560)  (228)
    -------------------------------------------------------------------------
    

    Cash Flow and Net Income

    Cash flow from operations increased from $189.1 million in 2006 to
$355.9 million in 2007. Cash flow from operations per unit-diluted increased
18 percent from $2.98 to $3.51 per unit-diluted. The increase in cash flow
from operations and cash flow per unit-diluted is primarily the result of the
Trust's increased production attributable to the Mission and Innova
acquisitions and increased corporate netbacks driven by improved corporate oil
differentials reflecting the light oil production in the Viewfield Bakken core
area and higher oil prices.
    Cash flow from operating activities increased from $177.4 million in 2006
to $332.6 million in 2007. Cash flow from operating activities per unit-
diluted increased 18 percent from $2.79 to $3.28 per unit-diluted. The
increase in cash flow from operating activities and cash flow from operating
activities per unit-diluted is a result of the same factors described above,
offset slightly by changes in working capital.
    Net income for the 2007 year decreased to a loss of $32.2 million from
income of $68.9 million in 2006, primarily as a result of the $105.4 million
unrealized financial instrument loss in 2007 compared to a $13.9 million
unrealized financial instrument gain in 2006. This fluctuation was the result
of a higher $Cdn WTI benchmark price at December 31, 2007 compared to the
prior year and higher hedged volumes.
    As noted in the Financial Instruments and Risk Management section, the
Trust has not designated any of its risk management activities as accounting
hedges under the Canadian Institute of Chartered Accountants (the "CICA")
section 3855 and, accordingly, has marked-to-market its financial instruments.
Changes in the forward value of these financial instruments are recorded in
net income. The Trust's offsetting physical sales and assets are not
marked-to- market and, as such, changes in the forward value of these assets
are not recorded in net income. As a result, changes in the forward price of
crude oil and natural gas impact the Trust's net income from period to period.
Excluding the Trust's unrealized financial loss of $105.4 million, net income
for 2007 was $73.3 million.

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
    ($000, except                              %                          %
     per unit amounts)      2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Cash flow from
     operations          112,572    43,843    157   355,910   189,135     88
    Cash flow from
     operations per
     unit - diluted         0.99      0.63     57      3.51      2.98     18

    Cash flow from
     operating
     activities           99,070    39,313    152   332,605   177,426     87
    Cash flow from
     operating
     activities per
     unit - diluted         0.87      0.56     55      3.28      2.79     18

    Net income (loss)    (90,348)    6,918 (1,406)  (32,167)   68,947   (147)
    Net income (loss)
     per unit -
     diluted(1)            (0.80)     0.10   (900)    (0.32)     1.05   (130)
    -------------------------------------------------------------------------
    (1) Net income per unit - diluted is calculated by dividing the net
        income before non-controlling interest by the diluted weighted
        average trust units, excluding the cash portion of unit based
        compensation.
    

    Cash Distributions

    The Trust maintained monthly distributions of $0.20 per unit during 2007.
Crescent Point's risk management strategy minimizes corporate price volatility
which has provided the Trust with the ability to maintain sustainable
distributions through periods of fluctuating market prices.
    Cash distributions increased by 63 percent in 2007 compared to 2006. The
rise in distributions relates to the increase in the trust units outstanding
primarily as a result of 2007 corporate acquisitions, a bought deal equity
financing in September 2007 and the Trust's distribution reinvestment
programs.

    
    The following table provides a reconciliation of cash distributions:

    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
    ($000, except                              %                          %
     per unit amounts)      2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Accumulated cash
     distributions,
     beginning of
     period              467,579   249,120     88   290,442   140,165    107
    Cash distributions
     declared to
     unitholders(1)       67,971    41,322     64   245,108   150,277     63
    -------------------------------------------------------------------------
    Accumulated cash
     distributions,
     end of period       535,550   290,442     84   535,550   290,442     84
    -------------------------------------------------------------------------

    Accumulated cash
     distributions
     per unit,
     beginning of
     period                 9.06      6.66     36      7.26      4.86     49
    Cash distributions
     declared to
     unitholders
     per unit(1)            0.60      0.60      -      2.40      2.40      -
    -------------------------------------------------------------------------
    Accumulated cash
     distributions
     per unit,
     end of period         9.66     7.26       33     9.66     7.26       33
    -------------------------------------------------------------------------
    (1) Cash distributions reflect the sum of the amounts declared monthly to
        unitholders, including distributions under the DRIP and Premium DRIP
        plans.
    

    For the 2007 year, cash flow from operating activities (including changes
in non-cash working capital) of $332.6 million exceeded cash distributions of
$245.1 million. This was consistent with the trend in 2006 and 2005.
    Cash distributions of $245.1 million for the 2007 year exceeded the net
loss of $32.2 million. This is consistent with distributions in the 2005 and
2006 years. Net income includes significant non-cash charges that do not
impact cash flow which in 2007 were $388.1 million for the year. The non-cash
charges also include fluctuations in future income taxes due to changes in tax
rates and tax rules, unrealized gains and losses on financial instruments and
unit-based compensation which includes a significant non-cash component.
    Crescent Point does not anticipate cash distributions will exceed cash
flow from operating activities, however it is likely they will exceed net
income as noted above given the significant non-cash items that are recorded
such as future income taxes, DD&A, unit-based compensation and unrealized
losses on financial instruments. Further, the cash flow from operating
activities can be significantly impacted by large fluctuations in working
capital adjustments that may vary quarter-to-quarter but level out over the
period. The distributions paid to unitholders represent a return on their
initial investment and is not intended to be a return of capital.
    An objective of the Trust's distribution policy is to provide unitholders
with relatively stable and predictable monthly distributions. An additional
objective is to retain a portion of cash flow to fund ongoing development and
optimization projects designed to enhance the sustainability of the Trust's
cash flow. Although the Trust strives to provide unitholders with stable and
predictable cash flows, the percentage of cash flow from operations paid to
unitholders each month may vary according to a number of factors, including
fluctuations in resource prices, exchange rates and production rates, reserves
growth, the size of development drilling programs and the portion thereof
funded from cash flow and the overall level of debt of the Trust. The actual
amount of the distributions are at the discretion of the Board of Directors.
In the event that commodity prices are higher than anticipated and a cash
surplus develops, such surplus may be used to increase distributions, reduce
debt and/or increase the capital program.
    The Trust has a strong balance sheet and a balanced three year derivative
profile and is, therefore, well positioned to sustain distributions over time
as Crescent Point continues to exploit and develop its asset base and actively
identify and evaluate acquisition opportunities. As discussed above, there are
many factors impacting the Trust's ability to sustain distributions. The Trust
continues to monitor these factors in connection with setting distribution
levels.

    
    -------------------------------------------------------------------------
                                    Three months
                                        ended               Year ended
                                     December 31           December 31
                                    2007     2006     2007     2006     2005
    -------------------------------------------------------------------------
    Cash flow from operating
     activities                   99,070   39,313  332,605  177,426   94,247
    Net income (loss)            (90,348)   6,918  (32,167)  68,947   38,509
    Cash distributions paid
     or payable                   67,971   41,322  245,108  150,277   74,591
    -------------------------------------------------------------------------
    Excess (shortfall) of
     cash flows from
     operating activities
     over cash
     distributions paid           31,099   (2,009)  87,497   27,149   19,656
    -------------------------------------------------------------------------
    Excess (shortfall) of net
     income (loss) over cash
     distributions paid         (158,319) (34,404)(277,275) (81,330) (36,082)
    -------------------------------------------------------------------------
    

    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 2007 taxation year, the distributions are 75 percent taxable for
the January 1 - March 1, 2007 taxation year and 100 percent taxable for the
March 2, 2007 - December 31, 2007 taxation year, for Canadian income tax
purposes.
    During 2007, a corporate reorganization of the Trust and its subsidiaries
was completed. As a result of this reorganization, the Trust had two taxation
years within the 2007 calendar year. The first is from January 1 - March 1,
2007 and the second is from March 2 - December 31, 2007. The amount of the
distributions which are taxable in each of the two taxation years is outlined
in the table below. Unitholders who held their units throughout the year will
receive a separate T3 slip for each of the taxation years.
    The following table outlines the breakdown of the cash distributions per
unit paid or payable by the Trust with respect to the record dates from
January 31, 2007 to December 31, 2007 for Canadian income tax purposes:

    
    -------------------------------------------------------------------------
                                                              Tax
                                    Taxable              Deferred
                                     Amount    Taxable     Amount      Total
                                    (Box 26    Capital    (Box 42       Cash
                                      Other       Gain  Return of    Distri-
    Record Date     Payment Date     Income)  Amount(1)   Capital)    bution
    -------------------------------------------------------------------------
    January 31,     February 15,
     2007            2007           $0.1500          -    $0.0500      $0.20
    February 28,    March 15,
     2007            2007           $0.1500          -    $0.0500      $0.20
    March 31,       April 16,
     2007            2007           $0.1960    $0.0040          -      $0.20
    April 30,       May 15,
     2007            2007           $0.1960    $0.0040          -      $0.20
    May 31,         June 15,
     2007            2007           $0.1960    $0.0040          -      $0.20
    June 30,        July 16,
     2007            2007           $0.1960    $0.0040          -      $0.20
    July 31,        August 15,
     2007            2007           $0.1960    $0.0040          -      $0.20
    August 31,      September 17,
     2007            2007           $0.1960    $0.0040          -      $0.20
    September 30,   October 15,
     2007            2007           $0.1960    $0.0040          -      $0.20
    October 31,     November 15,
     2007            2007           $0.1960    $0.0040          -      $0.20
    November 30,    December 17,
     2007            2007           $0.1960    $0.0040          -      $0.20
    December 31,    January 15,
     2007            2008           $0.1960    $0.0040          -      $0.20
    -------------------------------------------------------------------------
    TOTAL PER TRUST UNIT              $2.26      $0.04      $0.10      $2.40
    -------------------------------------------------------------------------
    (1) The taxable capital gain represents 50 percent of the capital gain
        which will be reported in Box 21 of the T3 slips.
    

    Investments in Marketable Securities

    During the year ended December 31, 2007, the Trust owned shares of
publicly traded exploration and production companies. In accordance with new
accounting standards for financial instruments, in the first quarter of 2007,
the Trust marked-to-market its investment in marketable securities. The
carrying amount of $171,000 at December 31, 2006 was increased to $1.6 million
at January 1, 2007 to reflect the fair value of the investment. The unrealized
gain of $1.5 million at January 1, 2007 was recorded through retained
earnings.  In the second quarter of 2007, the Trust sold the securities for a
realized gain of $1.4 million.
    In the fourth quarter of 2007, the Trust received 1.5 million shares of a
publicly traded exploration and production company for $1.00 per share or
$1.5 million in connection with a disposition of properties. The fair value at
December 31, 2007 was $1.4 million, resulting in an unrealized loss on
investment of $150,000 recorded through the income statement.

    Long-term Investments

    During the year ended December 31, 2007, the Trust purchased 2.2 million
shares of Innova Exploration Ltd. a publicly traded exploration and production
company for an average price of approximately $7.51 per share or
$16.6 million. The Trust acquired all remaining shares of Innova Exploration
Ltd. in October 2007 (refer to Capital Expenditures section below).
    During the fourth quarter of 2007, the Trust purchased 2.0 million shares
of Pilot Energy Ltd. ("Pilot"), a publicly traded exploration and production
company for an average price of approximately $2.90 per share or $5.9 million.
The Trust acquired the remaining shares on January 16, 2008, with the closing
of the acquisition of Pilot (refer to Subsequent Event Note 17 (b)). The fair
value at December 31, 2007 was $6.4 million resulting in an unrealized gain on
investment of $470,000 recorded through the income statement.

    Capital Expenditures

    Current Year

    The Trust closed three corporate acquisitions in 2007 for net
consideration of approximately $1.0 billion including closing adjustments and
net debt assumed ($1.2 billion was allocated to property, plant and
equipment). The Trust also closed property acquisitions for total
consideration of approximately $20.4 million, a property disposition for
$3.4 million and recorded purchase price adjustments on previously closed
acquisitions for the year ended December 31, 2007 of $1.8 million
($20.6 million was allocated to property, plant and equipment, net of
dispositions). The acquisitions completed in 2007 were predominantly focused
in the Viewfield Bakken area of southeast Saskatchewan.
    On February 9, 2007, the Trust closed the acquisition of Mission Oil &
Gas Inc., a publicly traded company with properties in the Viewfield area of
southeast Saskatchewan for consideration of approximately $627.8 million,
including closing adjustments and net debt assumed. The acquisition added
production of 7,000 boe/d, including more than 5,000 boe/d from the Bakken
resource play. The purchase was funded through the Trust's existing bank lines
and the issuance of approximately 29.2 million trust units.
    On September 5, 2007, the Trust closed the acquisition of a private
corporation with properties in the Wilmar and Browning areas of southeast
Saskatchewan for consideration of approximately $18.9 million including net
debt assumed. The purchase was funded through the transfer of 605,815 trust
units and cash of $121,000 from the Trust's existing bank lines.
    On October 22, 2007, the Trust purchased 97 percent of the issued and
outstanding shares of Innova Exploration Ltd., a publicly traded company with
properties in the Viewfield area of southeast Saskatchewan. On October 25,
2007, the Trust acquired the remaining shares outstanding. The shares were
purchased for total consideration of $402.9 million, including assumed bank
debt and working capital. The acquisition added production of 4,300 boe/d,
including more than 2,800 boe/d from the Viewfield Bakken resource play. The
purchase was paid through the Trust's existing bank lines.
    The Trust's development capital expenditures for the year 2007 were
$227.9 million, compared to $110.0 million for the same period in 2006. In
2007, 149 wells (107.0 net) were drilled with a success rate of 99 percent.

    Subsequent Events

    Subsequent to the year end, on January 14, 2008, the Trust announced its
investment in Shelter Bay Energy Inc. ("Shelter Bay"), a private Bakken light
oil growth company. Shelter Bay will be managed through a Technical Services
Agreement with Crescent Point, will accelerate development of the Bakken light
oil resource play in southeast Saskatchewan and follow a similar business plan
to the Trust to develop, exploit and acquire light oil and natural gas
properties in western Canada. Crescent Point will initially invest up to
$60 million in Shelter Bay, which will be financed from available lines of
credit, and will represent a 20 percent interest in Shelter Bay.
    In connection with the Shelter Bay announcement, Crescent Point announced
that the Trust had entered into an agreement (the "Agreement') with Landex
Petroleum Corp. ("Landex"), a private oil and gas company to acquire all of
its issued and outstanding shares by way of a plan of arrangement (the
"Arrangement") for total consideration of approximately $310 million which
includes the assumption of $16 million of net debt. Landex shareholders will
receive a maximum of $295 million cash and up to $75 million of trust units
based on an exchange rate of 0.632 trust units for each Landex share.
    Subsequent to the entering into of the Agreement, the parties amended and
restated the Agreement (the "Amended Agreement') such that Shelter Bay has
agreed to complete the acquisition of Landex pursuant to the Arrangement.
Under the terms of the Amended Agreement, Landex shareholders will receive a
maximum of $275 million cash, up to $75 million of trust units based on an
exchange rate of 0.632 trust units for each Landex share, and a minimum of
$20 million to a maximum of $60 million Shelter Bay shares. Under the terms of
the Amended Agreement Crescent Point would acquire the non-Bakken assets of
Landex for $80 million and Shelter Bay would acquire the Bakken assets of
Landex for $230 million, for combined consideration of $310 million. The
Arrangement is subject to Landex shareholder approval and is expected to close
in late-March 2008.
    Also subsequent to the year end, on January 16, 2008, the Trust closed
the acquisition of Pilot Energy Ltd., a publicly traded company with
properties in the Viewfield Bakken area of southeast Saskatchewan by way of a
Plan of Arrangement for total consideration of approximately $76.0 million
before closing adjustments and including net debt (based on a trust unit price
of $22.48). The purchase was funded through the Trust's existing bank lines
and issuance of 2.9 million trust units.

    
    -------------------------------------------------------------------------
                             Three months ended              Year ended
                                 December 31                December 31
                                               %                          %
    ($000)                  2007      2006  Change     2007      2006  Change
    -------------------------------------------------------------------------
    Capital
     acquisitions
     (net)(1)(2)         408,377     2,002 20,298 1,068,406   507,929    110
    Development
     capital
     expenditures         95,385    30,039    218   227,923   109,995    107
    Capitalized
     administration        1,488       773     92     4,607     2,591     78
    Office equipment(2)      981       111    784     3,258       647    404
    -------------------------------------------------------------------------
    Total                506,231    32,925  1,438 1,304,194   621,162    110
    -------------------------------------------------------------------------
    (1) Capital acquisitions represent total consideration for the
        transactions including bank debt and working capital assumed.
    (2) Comparative prior period results have been restated to conform to
        current period presentation.
    

    The Trust's budgeted capital program for 2008 is approximately
$225 million, not including 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 and new equity issuances where applicable within the federal
government's Safe Harbour Limits on equity issuance.

    Goodwill

    The goodwill balance of $68.4 million as at December 31, 2007 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, 2007 and
no impairment of goodwill exists.

    Asset Retirement Obligation

    The asset retirement obligation increased by $20.2 million during 2007.
This increase relates to liabilities of $17.7 million recorded in respect of
three corporate and several minor property acquisitions (net of one
disposition) and new wells drilled in the year and accretion expense of
$4.4 million, reduced by actual expenditures incurred in the year of $1.9
million. The Board of Directors and management review the adequacy of the fund
annually and adjust contributions as necessary.
    The reclamation fund increased by approximately $700,000 during 2007.
This increase relates to contributions of approximately $2.6 million,
partially offset by expenditures of $1.9 million. The Board of Directors
approved contributions of $0.25 per barrel of production beginning January 1,
2007.

    Liquidity and Capital Resources

    At December 31, 2007, the Trust had a syndicated credit facility with
nine banks and an operating credit facility with one Canadian chartered bank.
During 2007, the Trust received increases from $470 million to $800 million in
the amount available under its combined credit facilities. The increase in the
borrowing base reflects the increase in the Trust's reserve base and the
Mission and Innova acquisitions. As at December 31, 2007, the Trust had bank
debt of $595.9 million, leaving unutilized borrowing capacity of
$204.1 million.
    As at December 31, 2007, Crescent Point was capitalized with 19 percent
net debt and 81 percent equity, a three percent change from December 31, 2006.
The Trust's net debt to cash flow at December 31, 2007 was 1.8 times
(December 31, 2006 - 1.2 times). The Trust's projected net debt to 12 month
cash flow is 1.0 times.
    The Trust's ability to raise new equity will be limited by the Safe
Harbour Limit guidelines as announced by the Federal Government. The Federal
Government's decision 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 Trust's significant unutilized borrowing capacity
available and success raising new equity within the guidelines as demonstrated
from 2006 through early 2008.

    
    -------------------------------------------------------------------------
    Capitalization Table ($000, except unit,       December 31,  December 31,
     per unit and percent amounts)                        2007          2006
    -------------------------------------------------------------------------
    Bank debt                                          595,984       254,438
    Working capital(1)                                  54,104       (26,533)
    -------------------------------------------------------------------------
    Net debt(1)                                        650,088       227,905
    Trust units outstanding                        113,760,732    69,531,952
    Market price at end of period (per unit)             24.81         17.60
    Market capitalization                            2,822,404     1,223,762
    -------------------------------------------------------------------------
    Total capitalization                             3,472,492     1,451,667
    -------------------------------------------------------------------------
    Net debt as a percentage of total
     capitalization(%)                                      19            16
    -------------------------------------------------------------------------
    Annual cash flow from operations                   355,910       189,135
    -------------------------------------------------------------------------
    Net debt to cash flow(2)                               1.8           1.2
    -------------------------------------------------------------------------
    (1) Working capital and net debt include long-term investments, but
        exclude the risk management liabilities and assets.
    (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, 2007, Crescent Point had 113,760,732 trust units issued
and outstanding compared to 69,531,952 trust units at December 31, 2006. The
increase by more than 44.2 million trust units relates primarily to the
corporate acquisitions completed in 2007, the bought deal financing in
September 2007 and the Trust's distribution reinvestment programs.
    The Trust issued 29.2 million trust units to Mission shareholders at a
price of $17.37 per trust unit on closing of the acquisition on February 9,
2007. On September 5, 2007, the Trust transferred 605,815 trust units at
$20.02 per unit in connection with the acquisition of a private corporation
owning properties in the Willmar and Browning areas of southeast Saskatchewan.
    The Trust and a syndicate of underwriters closed a bought deal equity
financing on September 25, 2007 pursuant to which the syndicate sold
8.9 million trust units for gross proceeds of $165.1 million ($18.55 per trust
unit).
    For the year ended December 31, 2007, the distribution reinvestment and
premium distribution reinvestment plans resulted in an additional 5.3 million
trust units being issued at an average price of $18.96 raising a total of
$100.7 million. Participation levels in these plans averaged approximately
44 percent. The cash raised through these alternative equity programs is used
to reduce bank debt.
    In December 2007, the Trust announced that as a result of the federal
government Safe Harbour Limits on equity issuances for income trusts, the
DRIP, Premium DRIP and Optional Unit Purchase programs would be suspended
until further notice beginning with the month of December 2007.
    Crescent Point's total capitalization increased 139 percent to
$3.5 billion at December 31, 2007 compared to $1.5 billion at December 31,
2006, with the market value of the trust units representing 81 percent of the
total capitalization. The increase in capitalization is attributable to the
increase in the number of units outstanding along with a significant
appreciation in the unit trading price. During 2007, the Trust's units traded
in the range of $15.89 to $24.93 with an average daily trading volume of
510,501 units.
    Subsequent to the year end, on January 8, 2008, the Trust and a syndicate
of underwriters closed a bought deal equity financing pursuant to which the
syndicate sold 5.2 million trust units for gross proceeds of $125 million
($24.25 per trust unit). In addition, on January 16, 2008, the Trust closed
the acquisition of Pilot. The Trust issued 2.9 million trust units to Pilot
shareholders at a price of $22.48 per trust unit on closing of the
acquisition.

    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, 2007:

    
    -------------------------------------------------------------------------
    Contractual Obligations
     Summary ($000)                      Expected Payout Date
    -------------------------------------------------------------------------
                           Total       2008  2009-2010  2011-2012  After 2012
    -------------------------------------------------------------------------
    Operating
     Leases(1)(2)         34,838      5,170     10,325      7,618     11,725
    -------------------------------------------------------------------------
    Premiums on Put
     Contracts            15,041      8,505      6,536          -          -
    -------------------------------------------------------------------------
    (1) Operating leases includes leases for office space, equipment and
        vehicles.
    (2) Included in operating leases are recoveries of rent expense on office
        space the Trust has acquired through various acquisitions and has
        subleased out to other tenants.
    

    Off Balance Sheet Arrangements

    The Trust has off-balance sheet financing arrangements consisting of
various lease agreements. All leases have been treated as operating leases
whereby the lease payments are included in operating expenses or general and
administrative expenses depending on the nature of the lease. No asset or
liability value has been assigned to these leases in the balance sheet as of
December 31, 2007. All of the lease agreement amounts have been reflected in
the Contractual Obligations and Commitments table above, which were entered
into in the normal course of operations.

    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, 2007 consolidated financial statements. The following discussion
outlines what management believes to be the most critical accounting policies
involving the use of estimates and 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.

    Future Income Taxes

    The determination of the Trust's income and other tax liabilities
requires interpretation of complex laws and regulations often involving
multiple jurisdictions. All tax filings are subject to audit and potential
reassessment after the lapse of considerable time. Accordingly, the actual
income tax liability may differ significantly from that estimated and
recorded.
    The Trust Tax Legislation results in a tax applicable at the trust level
on certain income from publicly traded mutual fund trusts at rates of tax
comparable to the combined federal and provincial corporate tax and treats
distributions as dividends to the Unitholders. Existing trusts will have a
transition period and the new tax will apply in January 2011.

    New Accounting Pronouncements

    Accounting Changes in the Current Period

    Financial Instruments

    On January 1, 2007, the Trust adopted the CICA Handbook sections 3855
"Financial Instruments Recognition and Measurement", 3865 "Hedges", 3861
"Financial Instruments - Disclosure and Presentation", 1530 "Comprehensive
Income," and 3251 "Equity". Other than the effect on the Investment in
Marketable Securities as described in the above section, the adoption of the
financial instruments standards has not affected the current or comparative
period balances on the consolidated financial statements as all financial
instruments identified have been fair valued.
    Section 3855 requires that all financial assets be classified as
held-for- trading, available-for-sale, held-to-maturity, or loans and
receivables and that all financial liabilities must be classified as
held-for-trading or other. Financial assets and financial liabilities
classified as held-for- trading are measured at fair value with changes in
those fair values recognized in earnings. Financial assets held-to-maturity,
loans and receivables, and other financial liabilities are measured at
amortized cost using the effective interest method of amortization.
Available-for-sale financial assets are measured at fair value with unrealized
gains and losses, including changes in foreign exchange rates, being
recognized in other comprehensive income. Investments in equity instruments
classified as available-for-sale that do not have a quoted market price in an
active market are measured at cost. Accordingly, the investment in marketable
securities balance of $171,000 at January 1, 2007 consisting of an investment
in a publicly traded exploration and production company, was fair valued at
January 1, 2007 to $1.6 million. Under prospective application, the
$1.5 million gain was recorded as an adjustment to opening retained earnings.
    During the three month period ended June 30, 2007, the Trust sold the
investment in marketable securities. As a result, the change in the unrealized
gain on investment of $1.5 million was recorded through the income statement
and a realized gain was recorded for $1.4 million.
    During the three month period ended December 31, 2007, the Trust received
1.5 million shares of a publicly traded exploration and production company for
$1.00 per share or $1.5 million in connection with a disposition of
properties. The fair value at December 31, 2007 was $1.4 million, resulting in
an unrealized loss on investment of $150,000 recorded through the income
statement. During the three months ended December 31, 2007, the Trust also
purchased 2.0 million shares of Pilot Energy Ltd., a publicly traded
exploration and production company for an average price of approximately $2.90
per share or $5.9 million. The Trust acquired the remaining shares on
January 16, 2008, with the closing of Pilot Energy Ltd. acquisition (refer to
Subsequent Event Note 17 (b) below). The fair value at December 31, 2007 was
$6.4 million resulting in an unrealized gain on investment of $470,000
recorded through the income statement.
    Section 1530 establishes new standards for reporting comprehensive
income, consisting of Net Income and Other Comprehensive Income ("OCI"). OCI
is the change in equity (net assets) of an entity during a reporting period
from transactions and other events from non-owner sources and excludes those
resulting from investments by owners and distributions to owners. The Trust
has no such transactions and events which would require the disclosure of OCI
for the three month period ended December 31, 2007. Any changes in these items
would be presented in a consolidated statement of comprehensive income.

    Future Accounting Changes

    The CICA issued new accounting standards, CICA Accounting Standard
Handbook Section 3862, "Financial Instruments - Disclosures" and Section 3863
"Financial Instruments - Presentation". These standards require entities to
provide disclosures in their financial statements that enable users to
evaluate the significance of financial instruments to the entity's financial
position and performance. It also requires that entities disclose the nature
and extent of risks arising from financial instruments and how the entity
manages those risks. The standards establish presentation guidelines for
financial instruments and non-financial derivatives and deals with the
classification of financial instruments, from the perspective of the issuer,
between liabilities and equity, the classification of related interest,
dividends, losses and gains, and the circumstances in which financial assets
and financial liabilities are offset. This standard is effective for fiscal
years beginning on or after October 1, 2007. Increased disclosure will be
required on the nature and extent of risks arising from financial instruments
and how the entity manages those risks.
    The CICA issued Section 1535, "Capital Disclosures". The application of
these recommendations will provide readers of financial statements with
information pertinent to the Trust's objectives, policies and processes for
managing capital. Increased disclosure of quantitative data regarding what is
considered capital and whether the Trust is in compliance with all externally
imposed capital requirements and consequences of non-compliance will be
disclosed. This standard is effective for fiscal years beginning on or after
October 1, 2007.
    The CICA issued Section 3064, "Goodwill and Other Intangible Assets",
replacing Section 3062, "Goodwill and Other Intangible Assets" and Section
3450, "Research and Development Costs". This new standard establishes
standards for the recognition, measurement, presentation and disclosure of
goodwill and intangible assets subsequent to its initial recognition.
Standards concerning goodwill are unchanged from the standards included in the
previous Section 3062. This standard is effective on January 1, 2009. The
Trust has not assessed the impact of this standard on its financial
statements.

    
    Outstanding Trust Unit Data

    As at March 3, 2008, the Trust had 121,669,469 trust units outstanding.

    Selected Annual Information

    -------------------------------------------------------------------------
    ($000 except per unit amounts)                2007       2006       2005
    -------------------------------------------------------------------------
    Total revenue                              652,175    427,491    251,076

    Net income (loss)(1)                       (32,167)    68,947     38,509
    Net income (loss) per unit(1)                (0.32)      1.12       1.12
    Net income (loss) per unit-diluted(1)        (0.32)      1.05       1.12

    Cash flow from operating activities        332,605    177,426     94,247
    Cash flow from operating activities
     per unit                                     3.30       2.88       2.75
    Cash flow from operating activities
     per unit-diluted                             3.28       2.79       2.61

    Cash flow from operations                  355,910    189,135    109,785
    Cash flow from operations per unit            3.54       3.07       3.20
    Cash flow from operations per
     unit-diluted                                 3.51       2.98       3.04

    Working capital(2)                         (54,104)    26,533     31,165
    Total assets                             2,613,432  1,373,466    808,297
    Total liabilities                        1,196,429    467,086    375,632
    Net debt(2)                                650,088    227,905    194,545
    Total long-term financial liabilities       59,652     11,697      4,590

    Weighted average trust units
     (thousands)(3)                            102,059     63,569     36,086
    Cash distributions                         245,108    150,277     74,591
    Cash distributions per unit                   2.40       2.40       2.14
    -------------------------------------------------------------------------
    (1) Net income and net income before discontinued operations and
        extraordinary items are the same.
    (2) Working capital and net debt include long-term investments, but
        exclude the risk management liabilities and assets.
    (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 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, 2005 through the year
December 31, 2007 due to numerous corporate and property acquisitions and the
Trust's successful drilling program, which have resulted in higher production
volumes. This factor combined with favourable commodity prices resulting from
higher market prices and narrower corporate oil differentials have produced
the increases realized in the table noted above. Net income through 2005 to
2007 has fluctuated primarily due to unrealized financial instrument gains and
losses on oil and gas contracts, which fluctuate with changes in market
conditions along with fluctuations in the future income tax expense and
recovery.

    
    Summary of Quarterly Results

    -------------------------------------------------------------------------
                                                   2007
    ($000, except per unit amounts)      Q4         Q3         Q2         Q1
    -------------------------------------------------------------------------
    Revenues                        214,748    164,368    144,179    128,880

    Net income (loss)(1)(5)         (90,348)    18,410   (117,773)   157,544
    Net income (loss)
     per unit(1)(5)                   (0.80)      0.18      (1.17)      1.83
    Net income (loss) per unit
     - diluted(1)(5)                  (0.80)      0.18      (1.17)      1.80

    Cash flow from operating
     activities                      99,070     80,722    102,637     50,176
    Cash flow from operating
     activities per unit               0.88       0.79       1.02       0.58
    Cash flow from operating
     activities per unit -
     diluted                           0.87       0.78       1.01       0.58

    Cash flow from operations       112,572     92,215     78,248     72,875
    Cash flow from operations
     per unit                          1.00       0.90       0.78       0.84
    Cash flow from operations
     per unit - diluted                0.99       0.89       0.77       0.84

    Working capital(2)              (54,104)    (9,908)   (23,346)    13,044
    Total assets                  2,613,432  2,106,227  2,051,979  2,076,521
    Total liabilities             1,196,429    555,233    656,693    534,299
    Net debt(2)                     650,088    208,554    353,416    340,612
    Total long-term financial
     liabilities                     59,652          -      7,286     16,107

    Weighted average trust
     units - diluted
     (thousands)(3)                 114,623    104,074    101,681     87,537

    Capital expenditures(4)         506,231     80,488     58,835    658,640

    Cash distributions               67,971     63,206     60,320     53,611
    Cash distributions per unit        0.60       0.60       0.60       0.60
    -------------------------------------------------------------------------

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

    Net income (loss)(1)(5)           6,918     39,588     19,260      3,181
    Net income (loss)
     per unit(1)(5)                    0.10       0.61       0.32       0.06
    Net income (loss) per unit
     - diluted(1)(5)                   0.10       0.58       0.31       0.02

    Cash flow from operating
     activities                      39,313     50,910     49,683     37,520
    Cash flow from operating
     activities per unit               0.58       0.78       0.84       0.71
    Cash flow from operating
     activities per unit -
     diluted                           0.56       0.75       0.81       0.68

    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 - diluted
     (thousands)(3)                  69,764     67,810     61,372     54,958

    Capital expenditures(4)          32,925     94,548    116,487    377,202

    Cash distributions               41,322     39,890     36,123     32,942
    Cash distributions per unit        0.60       0.60       0.60       0.60
    -------------------------------------------------------------------------
    (1) Net income per unit - diluted is calculated by dividing the net
        income before non-controlling interest by the diluted weighted
        average trust units, excluding the cash portion of unit - based
        compensation.
    (2) Working capital and net debt include long-term investments, but
        exclude the risk management liabilities and assets.
    (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) Capital expenditures includes capital acquisitions. Capital
        acquisitions represent total consideration for the transactions
        including bank debt and working capital assumed. Prior period results
        have been restated to conform to current period presentation.
    (5) Net income for the first quarter of 2007 includes the $158.8 million
        future income tax recovery resulting from the March 1, 2007
        reorganization. Net income for the second quarter of 2007 includes
        the $152.3 million future income tax expense resulting from the
        June 12, 2007 Bill C-52 Budget Implementation Act that was
        substantively enacted.
    

    Crescent Point's revenue has increased due to several property and
corporate acquisitions completed over 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 and cash flow
from operating activities. Net income through 2006 and 2007 has fluctuated
primarily due to unrealized financial instrument gains and losses on oil and
gas contracts, which fluctuate with the changes in market conditions along
with fluctuations in the future income tax expense (recovery). The March 1,
2007 internal reorganization resulted in a $158.8 million future tax recovery
in the first quarter of 2007. Bill C-52 became substantively enacted on
June 12, 2007, resulting in the future tax expense of $152.3 million in the
second quarter of 2007. Capital expenditures fluctuated through this period as
a result of timing of acquisitions. The general increase in cash flows from
operations and operating activities throughout the last eight quarters has
allowed the Trust to maintain stable monthly cash distributions over the past
two years.

    
    Fourth Quarter Review

    The following are the main highlights for the fourth quarter of 2007:

    -   The Trust spent $95.4 million on development capital activities in
        the fourth quarter, including the drilling of 37 (28.9 net) wells
        with a 100 percent success rate adding over 1,800 boe/d initial
        interest production.

    -   The Trust exceeded its fourth quarter average daily production
        target, producing 33,351 boe/d for the quarter. This represents a 56
        percent increase from 21,369 boe/d produced in the fourth quarter of
        2006. The increase resulted from the Mission and Innova acquisitions
        completed in 2007 and the Trust's successful drilling program.

    -   Crescent Point's cash flow from operations increased by 157 percent
        to $112.6 million in the fourth quarter of 2007, compared to
        $43.8 million in the fourth quarter of 2006. The increase is
        primarily due to the Trust's increased production and increased
        corporate netbacks due to narrower corporate oil differentials as a
        result of the Mission and Innova acquisitions.

    -   Crescent Point maintained consistent monthly distributions of $0.20
        per unit, totaling $0.60 per unit for the fourth quarter of 2007.

    -   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 3, 2008,
        the Trust had hedged 60 percent, 57 percent and 41 percent and 2
        percent of production, net of royalty interest, for 2008, 2009, 2010
        and the first six months of 2011, respectively.

    -   On October 22, 2007, the Trust purchased 97 percent of the issued and
        outstanding shares of Innova Exploration Ltd., a publicly traded
        company with properties in the Viewfield area of southeast
        Saskatchewan. On October 25, 2007, the Trust acquired the remaining
        shares outstanding. The shares were purchased for total consideration
        of $402.9 million, including assumed bank debt and working capital
        ($472.0 million was allocated to property, plant and equipment). The
        purchase was paid for through the Trust's existing bank lines.

    -   In October 2007, the amount available under the Trust's credit
        facility was increased from $600 to $800 million reflecting the
        growth in the Trust's lending base and the completion of the Innova
        Exploration Ltd. acquisition.
    

    Internal Controls

    Disclosure controls and procedures have been designed to ensure that
information required to be disclosed by Crescent Point is accumulated and
communicated to Crescent Point's 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
as of the end of the period covered by the annual filings, that Crescent
Point's disclosure controls and procedures for the years ended December 31,
2007 are effective and provide reasonable assurance that material information
related to Crescent Point is made known to them by others within the Trust.
Crescent Point's Chief Executive Officer and Chief Financial Officer have
designed or caused to be designed under their supervision, internal controls
over financial reporting related to the Trust to provide reasonable assurance
regarding the reliability of the Trust's financial reporting and the
preparation of financial statements for external purposes in accordance with
Canadian GAAP.
    During 2007, the Trust engaged external consultants to assist in
documenting and assessing the Trust's design of internal controls over
financial reporting. No material changes in the Trust's internal control over
financial reporting were identified during the period ended December 31, 2007
that has materially affected, or are reasonably likely to materially affect,
the Trust's internal control over financial reporting.
    It should be noted that while Management believes that Crescent Point's
disclosure controls and procedures provide a reasonable level of assurance
with regard to their effectiveness, they do not expect that the disclosure
controls and procedures or internal controls over financial reporting will
prevent all errors and fraud. A control system, no matter how well conceived
or operated, can provide only reasonable, but not absolute, assurance that the
objectives of the control system are met.

    
    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 but are not limited to:

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

    -   Reliance on reserve estimates for the year as well as on
        acquisitions;

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

    -   Fluctuations in foreign currency and exchange rates;

    -   Operational matters related to non operated properties;

    -   Delays in business operations, pipeline restrictions, blowouts;

    -   Debt service, indebtedness may limit timing or amount of
        distributions as well as market price of trust units;

    -   Oil and gas market is highly competitive;

    -   Sufficient liquidity for future operations;

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

    -   Unforeseen title defects;

    -   Aboriginal land claims;

    -   Loss of key personnel;

    -   Uncertainty of Government Policy changes;

    -   The risk of carrying out operations with minimal environmental
        impact; and

    -   Operational hazards and availability of insurance.

    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

    Crescent Point's 2008 guidance is as follows:

    -------------------------------------------------------------------------
                                                                        2008
    Production
      Oil and NGL (bbls/d)                                            30,125
      Natural gas (mcf/d)                                             26,250
    -------------------------------------------------------------------------
    Total (boe/d)                                                     34,500
    -------------------------------------------------------------------------
    Cash flow from operations ($000)                                 527,000
    Cash flow from operations per unit - diluted ($)                    4.21
    Cash distributions per unit ($)                                     2.40
    Payout ratio - per unit - diluted (%)                                 57
    -------------------------------------------------------------------------
    Capital expenditures ($000) (1)                                  225,000
    Wells drilled, net                                                   106
    -------------------------------------------------------------------------
    Pricing
      Crude oil - WTI (US$/bbl)                                        92.50
      Crude oil - WTI (Cdn$/bbl)                                       92.50
      Natural gas - Corporate (Cdn$/mcf)                                8.00
      Exchange rate (US$/Cdn$)                                          1.00
    -------------------------------------------------------------------------
    (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)                                    2007          2006
    -------------------------------------------------------------------------
    ASSETS
      Current assets
        Cash                                                 -           205
        Accounts receivable                            102,800        53,279
        Investments in marketable securities
         (Note 15)                                       1,385           171
        Prepaids and deposits                            2,218         4,509
        Risk management asset (Note 15)                    451           586
    -------------------------------------------------------------------------
                                                       106,854        58,750
      Long-term investment (Note 15 & 17(b))             6,386        30,020
      Reclamation fund (Note 7)                          2,436         1,725
      Risk management asset (Note 15)                        -           466
      Property, plant and equipment (Note 5 & 6)     2,429,406     1,214,155
      Goodwill                                          68,350        68,350
    -------------------------------------------------------------------------
    Total assets                                     2,613,432     1,373,466
    -------------------------------------------------------------------------

    LIABILITIES
      Current liabilities
        Accounts payable and accrued liabilities       144,141        53,053
        Cash distributions payable                      22,752         8,598
        Bank indebtedness (Note 8)                     595,984       254,438
        Risk management liability (Note 15)             63,819         7,581
    -------------------------------------------------------------------------
                                                       826,696       323,670
      Asset retirement obligation (Note 9)              66,074        45,829
      Risk management liability (Note 15)               59,652        11,697
      Future income taxes (Note 13)                    244,007        85,890
    -------------------------------------------------------------------------
    Total liabilities                                1,196,429       467,086
    -------------------------------------------------------------------------

    UNITHOLDERS' EQUITY
      Unitholders' capital (Note 10)                 1,826,423     1,045,929
      Contributed surplus (Note 11)                     15,086         9,150
      Deficit (Note 12)                               (424,506)     (148,699)
    -------------------------------------------------------------------------
    Total unitholders' equity                        1,417,003       906,380
    -------------------------------------------------------------------------
    Total liabilities and unitholders' equity        2,613,432     1,373,466
    -------------------------------------------------------------------------
    Commitments (Note 16)
    See accompanying notes to the consolidated financial statements.



    CONSOLIDATED STATEMENTS OF OPERATIONS,
    COMPREHENSIVE INCOME (LOSS) AND DEFICIT

    -------------------------------------------------------------------------
                                    Three months ended          Year ended
    (UNAUDITED)                          December 31           December 31
    ($000, except per
     unit amounts)                     2007       2006       2007       2006
    -------------------------------------------------------------------------
    REVENUE
      Oil and gas sales             214,748    100,960    652,175    427,491
      Royalties                     (39,295)   (19,157)  (118,915)   (90,013)
      Financial instruments
        Realized losses             (11,289)    (3,685)    (9,899)   (30,323)
        Unrealized gains (losses)
         (Note 15)                 (112,236)     1,987   (105,426)    13,859
    -------------------------------------------------------------------------
                                     51,928     80,105    417,935    321,014
    EXPENSES
      Operating                      28,192     20,475     94,918     69,424
      Transportation                  5,626      3,293     17,725     10,175
      General and administrative      3,914      3,805     15,358     12,272
      Unit-based compensation
       (Note 11)                      4,345      3,293     16,375     12,416
      Interest on bank indebtedness
       (Note 8)                       8,107      3,602     21,805     13,673
      Depletion, depreciation and
       amortization                  68,017     35,448    242,923    138,511
      Accretion on asset retirement
       obligation (Note 9)            1,236        913      4,431      3,220
    -------------------------------------------------------------------------
                                    119,437     70,829    413,535    259,691
    -------------------------------------------------------------------------
      Income (loss) before taxes    (67,509)     9,276      4,400     61,323
      Capital and other taxes         4,874      2,625     15,394     11,314
      Future income tax expense
       (recovery) (Note 13)          17,965       (220)    21,173    (16,560)
    -------------------------------------------------------------------------
      Net income (loss) before
       non-controlling interest     (90,348)     6,871    (32,167)    66,569
      Non-controlling interest            -         47          -      2,378
    -------------------------------------------------------------------------
      Net income (loss) and
       comprehensive income
       (loss) for the period        (90,348)     6,918    (32,167)    68,947
    -------------------------------------------------------------------------
      Deficit, beginning of period (266,187)  (114,295)  (148,699)   (67,369)
      Change in accounting policy
       (Note 3)                           -          -      1,468          -
      Cash distributions paid
       or declared                  (67,971)   (41,322)  (245,108)  (150,277)
    -------------------------------------------------------------------------
      Deficit, end of the period
       (Note 12)                   (424,506)  (148,699)  (424,506)  (148,699)
    -------------------------------------------------------------------------

    Net income (loss) per unit
     (Note 14)
      Basic                           (0.80)      0.10      (0.32)      1.12
      Diluted                         (0.80)      0.10      (0.32)      1.05
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.



    CONSOLIDATED STATEMENTS OF CASH FLOWS

    -------------------------------------------------------------------------
                                    Three months ended          Year ended
                                         December 31           December 31

    (UNAUDITED) ($000)                 2007       2006       2007       2006
    -------------------------------------------------------------------------
    CASH PROVIDED BY (USED IN)
     OPERATING ACTIVITIES
      Net income (loss) for the
       period                       (90,348)     6,918    (32,167)    68,947
      Items not affecting cash
        Non-controlling interest          -        (47)         -     (2,378)
        Future income taxes
         (Note 13)                   17,965       (220)    21,173    (16,560)
        Unit-based compensation
         (Note 11)                    3,786      2,818     14,378     11,254
        Depletion, depreciation
         and amortization            68,017     35,448    242,923    138,511
        Accretion on asset
         retirement obligation
         (Note 9)                     1,236        913      4,431      3,220
        Realized gain on sale
         of investment (Note 3)           -          -     (1,402)         -
        Unrealized losses (gains)
         on financial instruments
         (Note 15)                  112,236     (1,987)   105,426    (13,859)
        Unrealized losses (gains)
         on investment (Note 3)        (320)         -      1,148          -
      Asset retirement expenditures
       (Note 9)                        (879)      (615)    (1,855)    (1,018)
      Change in non-cash working
       capital
        Accounts receivable          14,062      8,639     19,753     (6,932)
        Prepaid expenses and
         deposits                       363     (1,139)     2,291      2,589
        Accounts payable            (27,048)   (11,415)   (43,494)    (6,348)
    -------------------------------------------------------------------------
                                     99,070     39,313    332,605    177,426
    -------------------------------------------------------------------------
    INVESTING ACTIVITIES
      Development capital and
       other expenditures           (97,854)   (30,923)  (235,788)  (113,234)
      Capital acquisitions,
       net (Note 5)                (343,791)    (2,002)  (401,034)  (362,186)
      Proceeds on sale of
       investment (Note 3)                -          -      1,573          -
      Reclamation fund net
       contributions                    112        225       (711)    (1,484)
      Long-term investment
       (Note 15 & 17 (b))            10,694          -     (5,912)         -
      Change in non-cash
       working capital
        Accounts receivable          (4,022)    (1,987)   (11,667)    (3,553)
        Accounts payable             10,645      8,177     48,417     15,175
    -------------------------------------------------------------------------
                                   (424,216)   (26,510)  (605,122)  (465,282)
    -------------------------------------------------------------------------
    FINANCING ACTIVITIES
      Issue of trust units,
       net of issue costs            20,542     14,961    253,926    425,202
      Restricted unit vests               -          -       (833)    (1,377)
      Increase in bank
       indebtedness                 359,983     13,011    250,173     11,366
      Cash distributions            (67,971)   (41,322)  (245,108)  (150,277)
      Change in non-cash
       working capital
        Cash distributions payable   10,840        572     14,154      2,830
    -------------------------------------------------------------------------
                                    323,394    (12,778)   272,312    287,744
    -------------------------------------------------------------------------
    INCREASE (DECREASE) IN CASH      (1,752)        25       (205)      (112)
    CASH AT BEGINNING OF PERIOD       1,752        180        205        317
    -------------------------------------------------------------------------
    CASH AT END OF PERIOD                 -        205          -        205
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.



    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
    DECEMBER 31, 2007 and 2006 (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, CPRI is the
    administrator of the Trust and the beneficiaries of the Trust are the
    unitholders.

    On March 1, 2007, the Trust completed a 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 a limited partnership, directly
    and indirectly owned by the Trust.

    The principal undertaking of the Trust's operating entities, Crescent
    Point Resources Limited Partnership along with its general partner,
    Crescent Point General Partner Corp. is to acquire, hold directly or
    indirectly, interests in oil and gas properties. The administrator of
    the Trust's business is Crescent Point Resources Inc.

    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, whereas 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
        unproved 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 and environmental
        emissions reduction costs. The Board of Directors has approved
        contributions of $0.25 per barrel of production beginning
        January 1, 2007. Prior to January 1, 2007, contributions ranged from
        $0.15 to $0.20 per barrel of production. Additional contributions are
        made at the discretion of management.

    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 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 and its 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. Currently, 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. Effective in
        2011, the Trust's distributions are taxable. Accordingly, income tax
        liabilities and assets have been recognized on the Trust's temporary
        differences at the substantively enacted rate applicable to the
        periods in which the temporary differences reverse.

    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. The
        Trust also makes investments in corporations from time to time in
        connection with the Trust's acquisition and divesture activities.

        All financial assets must be classified as held-for-trading,
        available-for-sale, held-to-maturity, or loans and receivables and
        all financial liabilities must be classified as held-for-trading or
        other. Financial assets and financial liabilities classified as held-
        for-trading are measured at fair value with changes in those fair
        values recognized in earnings. Financial assets held-to-maturity,
        loans and receivables, and other financial liabilities are measured
        at amortized cost using the effective interest method of
        amortization.

        The Trust has not designated any of its risk management activities as
        accounting hedges and accordingly marks-to-market its financial
        instruments with the resulting gains and losses recorded in the
        statement of operations.

        The Trust has elected to classify its investments in marketable
        securities and long term investments as held for trading, and
        accordingly, marks-to-market the investments with the resulting gain
        or loss being recorded in the statement of operations.

    j)  Non-Controlling Interest

        During the 2006 year, the Trust had a non-controlling interest
        recorded in respect of the issued and outstanding exchangeable shares
        of Crescent Point Resources Ltd. ("CPRL"), a predecessor 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)  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 future income taxes, 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.  CHANGES IN ACCOUNTING POLICIES

    On January 1, 2007, the Trust adopted the CICA Handbook sections 3855
    "Financial Instruments Recognition and Measurement", 3865 "Hedges", 3861
    "Financial Instruments - Disclosure and Presentation", 1530
    "Comprehensive Income," and 3251 "Equity". Other than the effect on the
    Investment in Marketable Securities as described in the section below,
    the adoption of the financial instruments standards has not affected the
    current or comparative period balances on the consolidated financial
    statements as all financial instruments identified have been fair valued.

    Financial Instruments

    Section 3855 requires that all financial assets be classified as held-
    for-trading, available-for-sale, held-to-maturity, or loans and
    receivables and that all financial liabilities must be classified as
    held-for-trading or other. Financial assets and financial liabilities
    classified as held-for-trading are measured at fair value with changes in
    those fair values recognized in earnings. Financial assets held-to-
    maturity, loans and receivables, and other financial liabilities are
    measured at amortized cost using the effective interest method of
    amortization. Available-for-sale financial assets are measured at fair
    value with unrealized gains and losses, including changes in foreign
    exchange rates, being recognized in other comprehensive income.
    Investments in equity instruments classified as available-for-sale that
    do not have a quoted market price in an active market are measured at
    cost. The Trust has elected to classify the investment in marketable
    securities as held for trading. Accordingly, the investment in marketable
    securities balance of $171,000 at January 1, 2007 consisting of an
    investment in a publicly traded exploration and production company, was
    fair valued at January 1, 2007 to $1.6 million. Under prospective
    application, the $1.5 million gain was recorded as an adjustment to
    opening retained earnings.

    During the three month period ended June 30, 2007, the Trust sold the
    investment in marketable securities. As a result, the change in the
    unrealized gain on investment of $1.5 million was recorded through the
    income statement and a realized gain was recorded for $1.4 million.

    During the three month period ended September 30, 2007, the Trust
    purchased 2.2 million shares of Innova Exploration Ltd., a publicly
    traded exploration and production company, for an average price of
    approximately $7.51 per share or $16.6 million. The Trust acquired the
    remaining shares in October 2007 in connection with the closing of the
    Innova Exploration Ltd. acquisition (refer to Financial Statement
    Note 5(c) below). The fair value at September 30, 2007 was $16.6 million,
    unchanged from the carrying value. Accordingly, there was no adjustment
    required to mark the investment to market.

    During the three month period ended December 31, 2007, the Trust received
    1.5 million shares of a publicly traded exploration and production
    company for $1.00 per share or $1.5 million in connection with a
    disposition of properties. The fair value at December 31, 2007 was
    $1.4 million, resulting in an unrealized loss on investment of $150,000
    recorded through the income statement. During the three months ended
    December 31, 2007, the Trust also purchased 2.0 million shares of Pilot
    Energy Ltd., a publicly traded exploration and production company for an
    average price of approximately $2.90 per share or $5.9 million. The Trust
    acquired the remaining shares on January 16, 2008, with the closing of
    Pilot Energy Ltd. acquisition (refer to Subsequent Event Note 17(b)
    below). The fair value at December 31, 2007 was $6.4 million resulting in
    an unrealized gain on investment of $470,000 recorded through the income
    statement.

    Derivative instruments are always carried at fair value and reported as
    assets where they have a positive fair value and as liabilities where
    they have a negative fair value. Derivatives may be embedded in other
    financial instruments. Under the new financial instruments standards the
    derivatives embedded in other financial instruments are valued as
    separate derivatives when their economic characteristic and risks are not
    clearly and closely related to those of the host contract; the terms of
    the embedded derivative are the same as those of a free standing
    derivative; and the combined contract is not held-for-trading. When an
    entity is unable to measure the fair value of the embedded derivative
    separately, the combined contract is treated as a financial asset or
    liability that is held-for-trading and measured at fair value with
    changes therein recognized in earnings. The Trust was previously marking
    to market its derivative instruments and, accordingly there was no
    adjustment required on adoption of this accounting standard.

    The fair value of a financial instrument on initial recognition is
    normally the transaction price, i.e. the fair value of the consideration
    given or received. Subsequent to initial recognition, the fair values are
    based on quoted market price where available from active markets,
    otherwise fair values are estimated based upon market prices at reporting
    date for other similar assets or liabilities with similar terms and
    conditions, or by discounting future payments of interest and principal
    at estimated interest rates that would be available to the Trust at the
    reporting date.

    Hedges

    Section 3865 replaces the guidance formerly in Section 1650, "Foreign
    Currency Translation" and Accounting Guideline 13, "Hedging
    Relationships" by specifying how hedge accounting is applied and what
    disclosures are necessary when it is applied. The Trust does not have any
    derivative instruments that have been designated as hedges. Accordingly,
    the Trust is marking to market its financial instruments.

    Comprehensive Income

    Section 1530 establishes new standards for reporting the display of
    comprehensive income, consisting of Net Income and Other Comprehensive
    Income ("OCI"). OCI is the change in equity (net assets) of an entity
    during a reporting period from transactions and other events from non-
    owner sources and excludes those resulting from investments by owners and
    distributions to owners. The Trust has no such transactions and events
    which would require the disclosure of OCI for the year ended
    December 31, 2007. Any changes in these items would be presented in a
    consolidated statement of operations and comprehensive income.

    Equity

    Section 3251 replaces section 3250, "Surplus" and establishes standards
    for the presentation of equity and changes in equity during reporting
    period, including changes in Accumulated Other Comprehensive Income
    ("Accumulated OCI"). Any cumulative changes in OCI would be included in
    Accumulated OCI and be presented as a new category of Shareholder's
    Equity on the consolidated balance sheet. As the Trust has no OCI
    transactions, the Trust does not have any Accumulated OCI.

    4.  FUTURE ACCOUNTING CHANGES

    The CICA issued new accounting standards, CICA Accounting Standard
    Handbook Section 3862, "Financial Instruments - Disclosures" and Section
    3863 "Financial Instruments - Presentation". These standards require
    entities to provide disclosures in their financial statements that enable
    users to evaluate the significance of financial instruments to the
    entity's financial position and performance. It also requires that
    entities disclose the nature and extent of risks arising from financial
    instruments and how the entity manages those risks. The standards
    establish presentation guidelines for financial instruments and non-
    financial derivatives and deals with the classification of financial
    instruments, from the perspective of the issuer, between liabilities and
    equity, the classification of related interest, dividends, losses and
    gains, and the circumstances in which financial assets and financial
    liabilities are offset. This standard is effective for fiscal years
    beginning on or after October 1, 2007. Increased disclosure will be
    required on the nature and extent of risks arising from financial
    instruments and how the entity manages those risks.

    The CICA issued Section 1535, "Capital Disclosures". The application of
    these recommendations will provide readers of financial statements with
    information pertinent to the Trust's objectives, policies and processes
    for managing capital. Increased disclosure of quantitative data regarding
    what is considered capital and whether the Trust is in compliance with
    all externally imposed capital requirements and consequences of non-
    compliance will be disclosed. This standard is effective for fiscal years
    beginning on or after October 1, 2007.

    The CICA issued Section 3064, "Goodwill and Other Intangible Assets",
    replacing Section 3062, "Goodwill and Other Intangible Assets" and
    Section 3450, "Research and Development Costs". This new standard
    establishes standards for the recognition, measurement, presentation and
    disclosure of goodwill and intangible assets subsequent to its initial
    recognition. Standards concerning goodwill are unchanged from the
    standards included in the previous Section 3062. This standard is
    effective on January 1, 2009. The Trust has not assessed the impact of
    this standard on its financial statements.

    5.  CAPITAL ACQUISITIONS AND DISPOSITIONS

    a)  Acquisition of Mission Oil & Gas Inc.

    On February 9, 2007, the Trust purchased all the issued and outstanding
    shares of Mission Oil & Gas Inc., a publicly traded company with
    properties in the Viewfield area of southeast Saskatchewan for total
    consideration of $627.8 million, including assumed bank debt and working
    capital ($708.2 million was allocated to property, plant and equipment).
    The purchase was paid for through the Trust's existing bank lines and
    issuance of approximately 29.2 million trust units and was accounted for
    as a business combination using the purchase method of accounting. The
    Trust owned 3.8 million 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.

    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Net assets acquired
    Risk management asset                                              2,063
    Property, plant and equipment                                    708,161
    Working capital deficiency                                        (5,922)
    Bank debt                                                        (47,751)
    Asset retirement obligation                                       (8,285)
    Future income taxes                                              (74,167)
    -------------------------------------------------------------------------
    Total net assets acquired                                        574,099
    -------------------------------------------------------------------------
    Consideration
    Cash                                                              62,767
    Trust units issued (29,178,562 trust units)                      506,832
    Acquisition costs                                                  4,500
    -------------------------------------------------------------------------
    Total purchase price                                             574,099
    -------------------------------------------------------------------------


    b)  Acquisition of a Private Corporation

    On September 5, 2007, the Trust purchased all the issued and outstanding
    shares of a private corporation with properties in the Willmar and
    Browning areas of southeast Saskatchewan for total consideration of
    $18.9 million including assumed bank debt and working capital
    ($19.6 million was allocated to property, plant and equipment). The
    purchase was paid for with cash of $121,000 from the Trust's existing
    bank lines and 605,815 trust units and was accounted for as a business
    combination using the purchase method of accounting.

    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Net assets acquired
    Property, plant and equipment                                     19,638
    Working capital deficiency                                          (275)
    Bank debt                                                         (6,266)
    Asset retirement obligation                                         (697)
    -------------------------------------------------------------------------
    Total net assets acquired                                         12,400
    -------------------------------------------------------------------------
    Consideration
    Cash                                                                 121
    Trust units issued (605,815 trust units)                          12,129
    Acquisition costs                                                    150
    -------------------------------------------------------------------------
    Total purchase price                                              12,400
    -------------------------------------------------------------------------

    c)  Acquisition of Innova Exploration Ltd.

    On October 22, 2007, the Trust purchased 97 percent of the issued and
    outstanding shares of Innova Exploration Ltd., a publicly traded company
    with properties in the Viewfield area of southeast Saskatchewan. On
    October 25, 2007, the Trust acquired the remaining shares outstanding.
    The shares were purchased for total consideration of $402.9 million,
    including assumed bank debt and working capital ($472.0 million was
    allocated to property, plant and equipment). The purchase was paid
    through the Trust's existing bank lines and was accounted for as a
    business combination using the purchase method of accounting. The Trust
    owned 2.2 million shares of Innova Exploration Ltd. prior to the closing
    which it purchased for $7.51 per share or $16.6 million in September
    2007.

    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Net assets acquired
    Property, plant and equipment                                    471,958
    Risk management liability                                         (1,431)
    Working capital deficiency                                       (22,361)
    Bank debt                                                        (37,355)
    Asset retirement obligation                                       (4,816)
    Future income taxes                                              (62,776)
    -------------------------------------------------------------------------
    Total net assets acquired                                        343,219
    -------------------------------------------------------------------------
    Consideration
    Cash                                                             338,145
    Acquisition costs                                                  5,074
    -------------------------------------------------------------------------
    Total purchase price                                             343,219
    -------------------------------------------------------------------------

    d)  Property Acquisitions and Disposals

    During the three months ended December 31, 2007, the Trust closed minor
    property acquisitions for total consideration of approximately $200,000
    and a property disposition for $3.4 million (($4.1 million) net of
    dispositions was also allocated to property, plant and equipment). The
    Trust recorded purchase price adjustments on previously closed
    acquisitions for the three months ended December 31, 2007 of
    $2.2 million.

    During the year ended December 31, 2007, the Trust closed property
    acquisitions for total consideration of approximately $20.4 million and a
    property disposition for $3.4 million ($18.8 million net of dispositions
    was allocated to property, plant and equipment). The Trust recorded
    purchase price adjustments on previously closed acquisitions for the year
    ended December 31, 2007 of $1.8 million.

    6.  PROPERTY, PLANT AND EQUIPMENT

    -------------------------------------------------------------------------
                                                Accumulated
                                                  depletion,
    December 31, 2007                      depreciation and
    ($000)                        Cost         amortization              Net
    -------------------------------------------------------------------------
    Petroleum and
     natural gas
     properties              2,330,613              448,101        1,882,512
    Production
     equipment                 606,418               63,878          542,540
    Office furniture
     and equipment               7,237                2,883            4,354
    -------------------------------------------------------------------------
                             2,944,268              514,862        2,429,406
    -------------------------------------------------------------------------

                                                Accumulated
                                                  depletion,
    December 31, 2006                      depreciation 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
    -------------------------------------------------------------------------

    At December 31, 2007, unproved land costs of $312.7 million
    (2006 - $33.9 million) have been excluded from costs subject to
    depletion. Future development costs of $719.6 million
    (2006 - $147.3 million) are included in costs subject to depletion.

    General and administrative expenses capitalized by the Trust during the
    year were $4.6 million (2006 - $2.6 million). The capitalized
    administration costs do not include any related unit-based compensation
    costs.

    The ceiling test calculation at December 31, 2007 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, 2007 ceiling test:

    -------------------------------------------------------------------------
                                     Average Price Forecast(1)
    -------------------------------------------------------------------------
                      2008      2009      2010      2011      2012      2013
    -------------------------------------------------------------------------

    WTI ($US/bbl)    92.00     88.00     84.00     82.00     82.00     82.00
    Exchange rate     1.00      1.00      1.00      1.00      1.00      1.00
    -------------------------------------------------------------------------
    WTI ($Cdn/bbl)   92.00     88.00     84.00     82.00     82.00     82.00
    AECO ($Cdn/mcf)   6.75      7.55      7.60      7.60      7.60      7.60
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


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

    WTI ($US/bbl)    82.00     82.00     82.02     83.66      2.0%
    Exchange rate     1.00      1.00      1.00      1.00      1.00
    -------------------------------------------------------------------------
    WTI ($Cdn/bbl)   82.00     82.00     82.02     83.66      2.0%
    AECO ($Cdn/mcf)   7.80      7.97      8.14      8.31      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

    The following table reconciles the reclamation fund:

    -------------------------------------------------------------------------
    ($000)                                                2007          2006
    -------------------------------------------------------------------------
    Balance, beginning of year                           1,725           241
    Contributions                                        2,566         2,502
    Actual expenditures                                 (1,855)       (1,018)
    -------------------------------------------------------------------------
    Balance, end of year                                 2,436         1,725
    -------------------------------------------------------------------------

    8.  BANK INDEBTEDNESS

    The Trust has a syndicated credit facility that was expanded from seven
    to nine banks in October 2007 and an operating credit facility with one
    Canadian chartered bank. During the year ended December 31, 2007, the
    amount available under the combined credit facilities was increased from
    $470.0 million to $800.0 million. The Trust has letters of credit in the
    amount of $440,000 outstanding at December 31, 2007.

    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 Trust
    also manages its debt facility through a combination of bank acceptances
    and interest rate swaps. 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 ended December 31, 2007 was
    $25.4 million (2006 - $15.2 million). The cash interest paid in the
    fourth quarter of 2007 was $12.3 million (2006 - $4.3 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 $66.1 million at December 31, 2007
    (December 31, 2006 - $45.8 million) based on total estimated undiscounted
    cash flows to settle the obligation $153.3 million (December 31, 2006 -
    $104.0 million). The expected period until settlement ranges from 2 years
    to a maximum of 50 years, with the costs expected to be paid over an
    average of 10 years for wells and 30 years for facilities. The estimated
    cash flows have been discounted using a credit adjusted risk free rate of
    return of eight percent and an inflation rate of two percent.

    The following table reconciles the asset retirement obligation:

    -------------------------------------------------------------------------
    ($000)                                                2007          2006
    -------------------------------------------------------------------------
    Asset retirement obligation,
     beginning of year                                  45,829        33,275
    Liabilities incurred                                 2,101         1,211
    Liabilities acquired through
     capital acquisitions (net)                         15,568         9,141
    Liabilities settled                                 (1,855)       (1,018)
    Accretion expense                                    4,431         3,220
    -------------------------------------------------------------------------
    Asset retirement obligation, end of year            66,074        45,829
    -------------------------------------------------------------------------

    10. UNITHOLDERS' CAPITAL

    a)  Authorized

    An unlimited number of voting trust units has been authorized.

    b)  Issued and outstanding

    The Trust has 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.

    In December 2007, the Trust announced that as a result of the federal
    government Safe Harbour Limits on equity issuances for income trusts, the
    DRIP, Premium DRIP and Optional Unit Purchase programs would be suspended
    until further notice beginning with the month of December 2007.

    On September 25, 2007, the Trust and a syndicate of underwriters closed a
    bought deal equity financing pursuant to which the syndicate sold
    8,900,000 trust units for gross proceeds of $165.1 million ($18.55 per
    trust unit).

    -------------------------------------------------------------------------
                                      2007                      2006
    -------------------------------------------------------------------------
                              Number of     Amount      Number of     Amount
                            trust units      ($000)   trust units      ($000)
    -------------------------------------------------------------------------
    Trust units, beginning
     of year                 69,531,952  1,083,948     41,745,784    502,879
    Issued for cash           8,900,000    165,095     18,546,000    395,424
    Issued on capital
     acquisitions            29,784,377    518,961      4,663,884    101,923
    Issued on conversion
     of exchangeable shares           -          -      1,444,213     25,608
    Issued on vesting of
     restricted units(1)        236,127      4,859        190,221      2,889
    Issued pursuant to the
     distribution
     reinvestment plans       5,308,276    100,660      2,604,619     49,984
    To be issued pursuant
     to the distribution
     reinvestment plans               -          -        337,231      5,241
    -------------------------------------------------------------------------
    Trust units, end of
     year                   113,760,732  1,873,523     69,531,952  1,083,948
    -------------------------------------------------------------------------
    Cumulative unit
     issue costs                      -    (47,100)             -    (38,019)
    -------------------------------------------------------------------------
    Total unitholders'
     capital, end of year   113,760,732  1,826,423     69,531,952  1,045,929
    -------------------------------------------------------------------------
    (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. 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.

    The unitholders have approved a maximum number of trust units issuable
    under the Restricted Unit Bonus Plan of 5,000,000 trust units.

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

    -------------------------------------------------------------------------
                                                          2007          2006
    -------------------------------------------------------------------------
    Restricted units, beginning of year              1,043,628       589,555
    Granted                                            898,476       848,426
    Exercised                                         (434,557)     (354,967)
    Forfeited                                          (21,497)      (39,386)
    -------------------------------------------------------------------------
    Restricted units, end of year                    1,486,050     1,043,628
    -------------------------------------------------------------------------

    The Trust recorded compensation expense and contributed surplus of
    $14.4 million in the year ended December 31, 2007 (2006 - $11.3 million),
    based on the amortization of the fair value of the units on the date of
    grant. Additionally, the Trust recorded $2.0 million (2006 -
    $1.1 million) of cash distributions on restricted units. The total cash
    and non-cash unit based compensation recorded in the year was
    $16.4 million (2006 - $12.4 million).

    During the three months ended December 31, 2007 the Trust recorded
    compensation and contributed surplus of $3.8 million (2006 -
    $2.8 million), based on the amortization of the fair value of the units
    on the date of grant. Additionally, the Trust recorded $560,000 (2006 -
    $475,000) of cash distributions on restricted units. The total cash and
    non-cash unit based compensation recorded in the year was $4.3 million
    (2006 - $3.3 million).

    A summary of the changes in the contributed surplus is as follows:

    -------------------------------------------------------------------------
                                                          2007          2006
    -------------------------------------------------------------------------
    Contributed surplus, beginning of year               9,150         4,409
    Unit based compensation                             14,516        11,615
    Exercised restricted units                          (8,442)       (6,513)
    Forfeited restricted units                            (138)         (361)
    -------------------------------------------------------------------------
    Contributed surplus, end of year                    15,086         9,150
    -------------------------------------------------------------------------

    12. DEFICIT

    The deficit balance is composed of the following items:

    -------------------------------------------------------------------------
    ($000)                                                2007          2006
    -------------------------------------------------------------------------
    Accumulated earnings                               111,044       141,743
    Accumulated cash distributions                    (535,550)     (290,442)
    -------------------------------------------------------------------------
    Deficit                                           (424,506)     (148,699)
    -------------------------------------------------------------------------

    During the period, presentation changes were made to combine the
    previously reported accumulated earnings and accumulated cash
    distribution figures on the balance sheet into a single deficit balance.
    The Trust has historically paid cash distributions in excess of
    accumulated earnings as cash distributions are based on cash flow from
    operating activities before changes in non-cash working capital generated
    in the current period while accumulated earnings are based on cash flow
    from operating activities before changes in non-cash working capital
    generated in the current period less a depletion, depreciation, and
    accretion expense recorded on original property, plant, and equipment,
    unrealized financial instrument gains/losses and other non-cash charges.

    13. INCOME TAXES

    In 2007, income trust tax legislation was passed resulting in a two-
    tiered tax structure subjecting distributions to the federal corporate
    income tax rate plus a deemed 13 per cent provincial income tax at the
    Trust level commencing in 2011. Currently, distributions paid to
    unitholders, other than returns of capital, are claimed as a deduction by
    the Trust in arriving at taxable income whereby tax is eliminated at the
    Trust level and is paid by the unitholders. As a result, the future tax
    position of the Trust, the parent entity, is now required to be reflected
    in the consolidated future income tax calculation.

    On March 1, 2007, the Trust completed a reorganization of the Trust and
    its subsidiaries. The reorganization resulted in the existing business of
    the Trust, which was carried on through limited partnerships and
    corporations, being carried on through a limited partnership indirectly
    owned by the Trust. In the Trust structure, payments are made between the
    operating entities and the Trust transferring both the income and tax
    liability to the unitholders. As a result of the reorganization, Crescent
    Point recorded a future tax recovery of $158.8 million in the first
    quarter.

    On October 31, 2006, the Finance Minister announced the Federal
    Government's plan regarding the taxation of income trusts. On June 12,
    2007, Bill C-52 Budget Implementation Act, 2007 was substantively enacted
    by the Canadian federal government, which contains legislation to tax
    publicly traded trusts in Canada. As a result, a new 31.5 percent tax
    will be applied to distributions from Canadian public income trusts. The
    new tax is not expected to apply to Crescent Point until 2011 as a
    transition period applies to publicly traded trusts that existed prior to
    November 1, 2006. The impact of the substantive enactment of trust
    taxation was that Crescent Point recorded a $152.3 million future income
    tax liability and future income tax expense in the second quarter of
    2007.

    On October 30, 2007, the Finance Minister announced a reduction of the
    corporate income tax rate from 22.1 percent to 15 percent by 2012. The
    reductions will be phased in between 2008 and 2012. Legislation enacting
    the measures received Royal Assent on December 14, 2007. The reduction in
    the general corporate tax rate will also apply to the taxation of income
    trusts, reducing the combined federal and deemed Provincial tax rate for
    distributions to 29.5 percent in 2011 and 28 percent in 2012.

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

    -------------------------------------------------------------------------
    ($000)                                                2007          2006
    -------------------------------------------------------------------------
    Income before income taxes                           4,400        61,323
    Statutory income tax rate                           33.72%        36.53%
    -------------------------------------------------------------------------
    Expected provision for income taxes                  1,484        22,401
    Internal reorganization                           (158,817)            -
    Initial recognition of tax liability               152,346             -
    Effect of change in corporate tax rates            (23,337)       (5,623)
    Capital and other tax expense                       15,394        11,314
    Non-deductible Crown charges                             -         5,359
    Resource allowance                                       -        (4,466)
    Change in amounts not subject to tax and other      49,497       (34,231)
    -------------------------------------------------------------------------
    Capital and future income tax expense (recovery)    36,567        (5,246)
    -------------------------------------------------------------------------

    The future income tax liability of the Trust at December 31, 2007 of
    $244.0 million is comprised of future tax liabilities related to capital
    assets in excess of tax value of $263.3 million, a future tax asset
    related to asset retirement obligations of $18.6 million and other items
    of $0.7 million.

    At December 31, 2007, the Trust had tax pools of approximately
    $1.0 billion consisting of intangible resource pools, tangible pools and
    trust unit issue costs.

    The cash capital taxes paid during the year ended December 31, 2007 were
    $14.0 million (2006 - $13.2 million). During the three month period
    ended December 31, 2007, the cash capital taxes paid were $2.6 million
    (2006 - $3.3 million)

    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           Year ended
                                      December 31              December 31
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    Weighted average
     trust units             113,136,424  68,312,948 100,670,407  61,542,223
    -------------------------------------------------------------------------
    Trust units issuable
     on conversion of
     exchangeable shares(1)            -     403,437           -   1,178,761
    Dilutive impact of
     restricted units          1,486,714   1,047,581   1,388,254     847,832
    -------------------------------------------------------------------------
    Dilutive trust units
     and exchangeable
     shares (1)              114,623,138  69,763,966 102,058,661  63,568,816
    -------------------------------------------------------------------------
    (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.
        On October 27, 2006, the Trust purchased all issued and outstanding
        exchangeable shares.

    15. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

    a)  Fair values

        The Trust's financial instruments recognized on the consolidated
        balance sheet include cash, accounts receivable, prepaids, deposits,
        the reclamation fund, accounts payable, and accrued liabilities and
        bank indebtedness. 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)  Investments

        The Trust makes investments shares of publicly traded oil and gas
        companies from time to time. The Trust is exposed to fluctuations in
        the value assigned to the shares in the market. The Trust has
        designated these investments as held for trading and as such, they
        have been marked-to-market.

        For the year ended December 31, 2007, the unrealized loss on
        investments was $1.1 million. This is comprised of a $1.5 million
        unrealized loss on marketable securities in the second quarter of
        2007, an unrealized gain of $470,000 on the long term investment in
        the fourth quarter of 2007 and an unrealized loss of $150,000 on the
        marketable securities in the fourth quarter of 2007.

    e)  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, 2007:

    -------------------------------------------------------------------------
    Financial WTI Crude Oil Contracts - Canadian Dollar

                                     Average    Average    Average   Average
                                        Swap     Bought       Sold       Put
    Term        Contract   Volume      Price  Put Price Call Price   Premium
                          (bbls/d) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)($Cdn/bbl)
    -------------------------------------------------------------------------
    2008
    January -
     June           Swap    1,000      72.73
    January -
     September      Swap      250      68.10
    January -
     December       Swap    7,000      77.73
    July -
     December       Swap    1,000      73.52
    October -
     December       Swap      250      70.80
    January -
     June         Collar      250                 65.00      82.00
    January -
     December     Collar    3,500                 73.50      88.57
    July -
     December     Collar      250                 70.00      91.00
    January -
     December        Put    3,500                 72.58                (6.66)
    -------------------------------------------------------------------------
    2008
     Weighted
     Average               15,500      76.90      72.85      88.44     (6.66)
    -------------------------------------------------------------------------
    2009
    January -
     March          Swap    2,750      77.68
    April -
     June           Swap    2,750      77.58
    January -
     June           Swap    1,250      74.99
    July -
     September      Swap    3,000      74.07
    July -
     December       Swap    1,000      76.41
    October -
     December       Swap    3,000      74.37
    January -
     December       Swap    2,750      78.38
    January -
     March        Collar      250                 75.00      87.00
    April -
     June         Collar      250                 75.00      83.00
    January -
     June         Collar    1,250                 70.00      81.01
    January -
     September    Collar      250                 70.00      79.00
    January -
     December     Collar    2,750                 73.55      88.14
    July -
     September    Collar      250                 70.00      84.05
    July -
     December     Collar    1,250                 69.00      80.37
    October -
     December     Collar      500                 70.00      85.93
    January -
     December        Put    3,250                 70.46                (6.03)
    -------------------------------------------------------------------------
    2009
     Weighted
     Average               14,500      76.84      71.45      85.49     (6.03)
    -------------------------------------------------------------------------
    2010
    January -
     March          Swap    3,500      76.22
    April -
     June           Swap    2,750      74.38
    January -
     September      Swap    2,250      79.51
    April -
     September      Swap      750      75.53
    July -
     September      Swap    2,750      75.00
    October -
     December       Swap    1,000      87.00
    January -
     June         Collar      500                 70.00      80.50
    January -
     September    Collar    2,000                 73.75      86.26
    July -
     September    Collar      500                 70.00      81.75
    October -
     December     Collar    1,250                 78.40      96.24
    January -
     September       Put    1,000                 71.00                (4.82)
    -------------------------------------------------------------------------
    2010 Weighted Average   7,486      77.51      73.07      86.78     (4.82)
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
    Financial AECO Natural Gas Contracts - Canadian Dollar

                                                          Average    Average
                                                           Bought       Sold
                                                 Volume Put Price Call Price
    Term                            Contract      (GJ/d) ($Cdn/GJ)  ($Cdn/GJ)
    -------------------------------------------------------------------------
    2008
    January - March                   Collar      2,000      6.75       8.00
    April - October                   Collar      2,000      6.75       7.75
    -------------------------------------------------------------------------
    2008 January - October Weighted Average       2,000      6.75       7.82
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
    Financial Interest Rate Contracts - Canadian Dollar

                                                Principal       Fixed Annual
    Term                 Contract                   ($Cdn)           Rate (%)
    -------------------------------------------------------------------------

    January 2008
     - May 2008            Swap                50,000,000               4.41
    January 2008
     - February
     2009                  Swap                50,000,000               4.37
    January 2008
     - November
     2010                  Swap                75,000,000               4.35
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
    Financial Power Contract - Canadian Dollar

                                                   Volume         Fixed Rate
    Term                 Contract                   (MW/h)        ($Cdn/MW/h)
    -------------------------------------------------------------------------
    January 2008
     - December
     2008                  Swap                       3.0              63.25
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
    Physical Power Contracts - Canadian Dollar

                                                   Volume         Fixed Rate
    Term                 Contract                   (MW/h)        ($Cdn/MW/h)
    -------------------------------------------------------------------------

    January 2008
     - December
     2009                  Swap                       1.0              82.45
    January 2009
     - December
     2009                  Swap                       3.0              81.25
    -------------------------------------------------------------------------

    The Trust has two physical power contracts and one financial power
    contract. The physical contracts have not been marked-to-market. The
    unrealized loss on the physical contracts at December 31, 2007 is
    $312,000.

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

    -------------------------------------------------------------------------
    ($000)                                                2007          2006
    -------------------------------------------------------------------------
    Risk management asset, beginning of year             1,052             -
    Acquired through capital acquisitions                2,063             -
    Unrealized mark-to-market gain (loss)               (2,664)        1,052
    -------------------------------------------------------------------------
    Risk management asset, end of year                     451         1,052
    Less: current risk management asset, end of year      (451)         (586)
    -------------------------------------------------------------------------
    Long term risk management asset, end of year             -           466
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    ($000)                                                2007          2006
    -------------------------------------------------------------------------
    Risk management liability, beginning of year        19,278        32,085
    Acquired through capital acquisitions                1,431             -
    Unrealized mark-to-market loss (gain)              102,762       (12,807)
    -------------------------------------------------------------------------
    Risk management liability, end of year             123,471        19,278
    Less: current risk management liability,
     end of year                                       (63,819)       (7,581)
    -------------------------------------------------------------------------
    Long term risk management liability,
     end of year                                        59,652        11,697
    -------------------------------------------------------------------------

    16. COMMITMENTS

    At December 31, 2007, the Trust had contractual obligations and
    commitments for office space, equipment, vehicles and premiums on put
    contracts:
                                                                       ($000)
    -------------------------------------------------------------------------
    2008                                                              13,675
    2009                                                              10,524
    2010                                                               6,337
    2011                                                               4,087
    2012                                                               3,531
    -------------------------------------------------------------------------
    (1) Included in the above commitments are recoveries of rent expense on
        office space the Trust has acquired through various acquisitions and
        has  subleased out to other tenants.

    17. SUBSEQUENT EVENTS

    a)  Equity Financings

        On January 8, 2008, the Trust and a syndicate of underwriters closed
        a bought deal equity financing pursuant to which the syndicate sold
        5,155,000 trust units for gross proceeds of $125.0 million
        ($24.25 per trust unit).

    b)  Acquisition of Pilot Energy Ltd.

        On January 16, 2008, the Trust closed the acquisition of Pilot
        Energy Ltd., a publicly traded company with properties in the
        Viewfield Bakken area of southeast Saskatchewan by way of a Plan of
        Arrangement for total consideration of approximately $76.0 million
        before closing adjustments and including net debt (based on a trust
        unit price of $22.48). The purchase was funded through the Trust's
        existing bank lines and issuance of 2.9 million trust units. The
        Trust owned 2.0 million shares of Pilot Energy Ltd. prior to the
        closing which it purchased for $2.90 per share or $5.9 million in
        November 2007.

    c)  Investment in Shelter Bay Energy Inc. and Acquisition of Landex
        Petroleum Corp. Non Bakken Assets

        On January 14, 2008, the Trust announced its investment in Shelter
        Bay Energy Inc. ("Shelter Bay"), a private Bakken light oil growth
        company. Shelter Bay will be managed through a Technical Services
        Agreement with Crescent Point, will accelerate development of the
        Bakken light oil resource play in southeast Saskatchewan and follow a
        similar business plan to the Trust to develop, exploit and acquire
        light oil and natural gas properties in western Canada. Crescent
        Point will initially invest up to $60 million in Shelter Bay, which
        will be financed from available lines of credit, and will represent a
        20 percent interest in Shelter Bay.

        Crescent Point also announced on January 14, 2008 that the Trust has
        entered into an agreement (the "Agreement') with Landex Petroleum
        Corp. ("Landex"), a private oil and gas company to acquire all of its
        issued and outstanding shares by way of a plan of arrangement (the
        "Arrangement") for total consideration of approximately $310 million
        which includes the assumption of $16 million of net debt. Landex
        shareholders will receive a maximum of $295 million cash and up to
        $75 million of trust units based on an exchange rate of 0.632 trust
        units for each Landex share.

        Subsequent to entering into the Agreement, the parties amended and
        restated the Agreement ("the "Amended Agreement') such that Shelter
        Bay has agreed to complete the acquisition of Landex pursuant to the
        Arrangement. Under the terms of the Amended Agreement, Landex
        shareholders will receive a maximum of $275 million cash, up to
        $75 million of trust units based on an exchange rate of 0.632 trust
        units for each Landex share, and a minimum of $20 million to a
        maximum of $60 million Shelter Bay shares.

        Under the terms of the Amended Agreement, Crescent Point
        would acquire the non-Bakken assets of Landex, for $80 million and
        Shelter Bay would acquire the Bakken assets of Landex for
        $230 million, for combined consideration of $310 million. The
        Arrangement is subject to Landex shareholder approval and is expected
        to close in late March 2008.

        Initial funding for Shelter Bay is expected to be $300 million, of
        which Crescent Point will invest $60 million, or 20 percent, which
        Crescent Point will finance through its existing bank lines. Under
        the Amended Agreement Landex shareholders are expected to elect to
        receive a minimum of $20 million to a maximum of $60 million of
        Shelter Bay shares in consideration for the Landex Bakken assets. The
        remaining $180 million to $220 million in initial funding will be
        raised via a private placement of Shelter Bay shares. The private
        placement is expected to close in late March 2008.

    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 of the    Investors are encouraged
        Board of Directors                      to 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 of     Olympia Trust Company
        the Board of Directors                  2300, 125 - 9th Avenue SE
                                                Calgary, Alberta
    (4) Member of the Health, Safety and        T2G 0P6
        Environment Committee of the Board      Tel: (403) 261-0900
        of Directors
                                                Stock Exchange
    (5) Member of the Corporate Governance
        Committee                               Toronto Stock Exchange - TSX

    Officers                                    Stock Symbol

    Scott Saxberg                               CPG.UN
    President and Chief Executive Officer
                                                Investor Contacts
    C. Neil Smith
    Vice President, Engineering and             Scott Saxberg
    Business Development                        President and Chief Executive
                                                Officer
    Greg Tisdale                                (403) 693-0020
    Chief Financial Officer
                                                Greg Tisdale
    Dave Balutis                                Chief Financial Officer
    Vice President, Geosciences                 (403) 693-0020

    Tamara MacDonald                            Trent Stangl
    Vice President, Land                        Manager, Marketing and
                                                Investor Relations
    Ken Lamont                                  (403) 693-0020
    Controller and Treasurer

    Head Office

    Suite 2800, 111 - 5th Avenue SW
    Calgary, Alberta
    T2P 3Y6
    Tel: (403) 693-0020
    Fax: (403) 693-0070
    Toll Free: (888) 693-0020

    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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