Crescent Point Energy Trust Announces Second Quarter 2007 Results



    CALGARY, Aug. 13 /CNW/ - Crescent Point Energy Trust, ("Crescent Point"
or the "Trust") (TSX: CPG.UN), is pleased to announce its operating and
financial results for the second quarter and six months ended June 30, 2007.

    
    FINANCIAL AND OPERATING HIGHLIGHTS

    -------------------------------------------------------------------------
    ($000s except
    trust units,               Three months ended        Six months ended
    per trust unit                   June 30                  June 30
    and per boe       -------------------------------------------------------
    amounts)                                    %                        %
                              2007     2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Financial
    Cash flow from
     operations(1)          78,248   52,282      50  151,123  92,518      63
      Per unit(1)(2)          0.77     0.85      (9)    1.60    1.59       1
    Net income (loss)(3)  (117,773)  19,260    (711)  39,771  22,441      77
      Per unit(2)(3)         (1.17)    0.31    (477)    0.43    0.34      26
    Cash distributions      60,320   36,123      67  113,931  69,065      65
      Per unit(2)             0.60     0.60       -     1.20    1.20       -
    Payout ratio (%)(1)         77       69       8       75      75       -
      Per unit (%)(1)(2)        78       71       7       75      75       -
    Net debt(1)(4)         353,416  241,371      46  353,416 241,371      46
    Capital
     acquisitions (net)(5)  14,122   91,408     (85) 639,252 444,189      44
    Development capital
     expenditures           42,416   24,276      75   74,746  48,035      56
    Weighted average
     trust units
     outstanding (mm)
      Basic                  100.3     59.3      69     93.3    56.1      66
      Diluted                101.7     61.4      66     94.6    58.2      63
    -------------------------------------------------------------------------
    Operating
    Average daily production
      Crude oil and NGLs
       (bbls/d)             22,819   16,959      35   22,443  16,873      33
      Natural gas (mcf/d)   20,109   20,622      (2)  19,745  19,356       2
    -------------------------------------------------------------------------
      Total (boe/d)         26,170   20,396      28   25,733  20,099      28
    -------------------------------------------------------------------------
    Average selling
     prices(6)
      Crude oil and NGLs
       ($/bbl)               63.11    66.85      (6)   60.79   60.13       1
      Natural gas ($/mcf)     7.17     5.67      26     7.31    6.72       9
    -------------------------------------------------------------------------
      Total ($/boe)          60.54    61.31      (1)   58.62   56.95       3
    -------------------------------------------------------------------------
    Netback ($/boe)
      Oil and gas sales      60.54    61.31      (1)   58.62   56.95       3
      Royalties             (11.77)  (13.61)    (14)  (10.68) (12.49)    (14)
      Operating expenses     (9.44)   (8.14)     16    (9.42)  (8.30)     13
      Transportation         (1.61)   (1.28)     26    (1.65)  (1.19)     39
    -------------------------------------------------------------------------
      Netback prior to
       realized financial
       instruments           37.72    38.28      (1)   36.87   34.97       5
      Realized gain
       (loss) on financial
       instruments            0.72    (5.41)    113     0.94   (4.68)    120
    -------------------------------------------------------------------------
      Netback                38.44    32.87      17    37.81   30.29      25
    -------------------------------------------------------------------------

    (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 for the three months ended June 30, 2007 and six months
        ended June 30, 2007 includes the impact of the June 2007 Bill C-52
        Budget Implementation Act. Net income for the six months ended June
        30, 2007 also includes the impact of the Trust's March 1, 2007
        reorganization.

    (4) Net debt includes working capital, 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 second 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.

    -   Crescent Point achieved a record average daily production volume in
        the second quarter of 2007, driven by continued 100 percent
        successful development drilling at the Trust's Viewfield Bakken play.
        The Trust produced an average 26,170 boe/d for the quarter,
        87 percent weighted to light and medium crude oil. This represents a
        28 percent increase from the 20,396 boe/d produced in the second
        quarter of 2006.

    -   Crescent Point spent $42.4 million on development capital activities
        in the quarter, including $13.4 million on facilities, land, seismic
        and tangible well equipment. The Trust spent $29.0 million drilling
        41 (24.5 net) wells, comprised of 39 (23.1 net) oil wells and 2 (1.4
        net) water injection wells, achieving a 100 percent success rate. The
        Trust drilled 16 (9.0 net) wells in the Viewfield Bakken play in the
        second quarter, adding 630 boe/d of initial interest production. In
        total, Crescent Point added approximately 1,800 boe/d of initial
        interest production through its development drilling activities in
        the quarter.

    -   The Trust's cash flow from operations increased by 50 percent to a
        record $78.2 million ($0.77 per unit - diluted) in the second quarter
        of 2007, compared to $52.3 million ($0.85 per unit - diluted) in the
        second quarter of 2006.

    -   The Trust's netback remained strong during the second quarter of
        2007, averaging $38.44 per boe, up 17 percent from the second quarter
        of 2006 despite a 10 percent decline in the Canadian dollar benchmark
        crude oil price. The 17 percent increase highlights the Trust's high
        quality oil along with its low royalty and operating cost structure.
        A significant component of the Trust's improvement in corporate
        netback relates to the Viewfield Bakken production, which realized a
        second quarter netback of Cdn$56.19 per boe.

    -   The Trust maintained consistent monthly distributions of $0.20 per
        unit, totaling $0.60 per unit for the second quarter of 2007
        resulting in an overall payout ratio of 78 percent on a per unit -
        diluted basis. This compares to an overall payout ratio of 71 percent
        on a per unit - diluted basis in the second quarter of 2006.

    -   Crescent Point 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 August 1, 2007,
        the Trust had hedged 54 percent, 51 percent and 32 percent of
        production, net of royalty interest, for the balance of 2007, 2008
        and 2009, respectively. Crescent Point has initiated its 2010 hedging
        program, with 19 percent and 9 percent of production, net of royalty
        interest, hedged for the first and second quarters of 2010,
        respectively.

    -   On May 28, 2007, the Trust's bank syndicate increased the borrowing
        base from $470 million to $600 million recognizing the Trust's strong
        reserves growth through continued development success, the
        acquisition of Mission Oil & Gas Inc., and continued risk management
        activities.

    -   The Trust's balance sheet remains strong with projected net debt to
        12 month cash flow of less than 1.0 times.

    -   Crescent Point closed two minor property acquisitions during the
        second quarter of 2007 for a total consideration of $14.6 million. In
        total, the Trust acquired 370 boe/d of production and 0.9 million boe
        of proved plus probable reserves in its core areas of John Lake and
        southeast Saskatchewan.
    

    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.

    Second Quarter Operations Summary

    During the second 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, averaging
26,170 boe/d during the second quarter of 2007. The Trust drilled a total of
39 (23.1 net) oil wells and 2 (1.4 net) water injection wells, achieving a 100
percent success rate and adding approximately 1,800 boe/d of initial interest
production.

    
    Drilling Results

    -------------------------------------------------------------------------
    Three months ended
    June 30, 2007          Gas Oil D&A Service Standing Total  Net % Success
    -------------------------------------------------------------------------
    Southeast Saskatchewan   -  31   -    2        -     33   20.9     100
    Southwest Saskatchewan   -   8   -    -        -      8    3.6     100
    South/Central Alberta    -   -   -    -        -      -      -       -
    Northeast BC & W Peace
     River Arch, Alberta     -   -   -    -        -      -      -       -
    -------------------------------------------------------------------------
    Total                    -  39   -    2        -     41   24.5     100
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Six months ended
    June 30, 2007          Gas Oil D&A Service Standing Total  Net % Success
    -------------------------------------------------------------------------
    Southeast Saskatchewan   -  46   -    2        1     49   34.4      97
    Southwest Saskatchewan   -   8   -    -        -      8    3.6     100
    South/Central Alberta    -   1   -    1        -      2    1.9     100
    Northeast BC & W Peace
     River Arch, Alberta     -   4   -    -        -      4    4.0     100
    -------------------------------------------------------------------------
    Total                    -  59   -    3        1     63   43.9      98
    -------------------------------------------------------------------------
    

    Southeast Saskatchewan

    Drilling activities resumed in early May after the annual spring break up
period. During the quarter, Crescent Point drilled a total of 31 (19.5 net)
horizontal oil wells achieving a 100 percent success rate. Of the wells
drilled, 16 (9.0 net) were Bakken horizontal wells at Viewfield that averaged
70 boe/d each on a gross pre-fracture stimulation rate. The balance of the
wells were drilled in the Trust's core properties of Manor, Ingoldsby and
Tatagwa. Total initial interest production added from drilling activities in
southeast Saskatchewan was approximately 1,620 boe/d.
    Construction activities continued on the Viewfield gas plant expansion
from 3.0 mmcf/d to 6.0 mmcf/d. Construction was completed in late July and the
expansion was fully operational ahead of schedule at the beginning of August
2007. The Trust will continue to execute the development of the Viewfield
Bakken play with plans to drill up to 71 (40.0 net) wells during 2007. Up to
65 (42.3 net) Bakken horizontal wells will be fracture stimulated in the
second half of the year.
    At Manor, the Trust drilled a fourth 75-metre interwell spacing location
that achieved initial production rates of 65 boe/d. A fifth location is
planned for the fourth quarter of 2007. Also at Manor, the Trust expanded its
water handling capability to accommodate the increased production resulting
from recent drilling success. At Tatagwa, 2 (1.4 net) water injectors were
drilled into the Tatagwa Unit with an additional 2 (1.4 net) injector drills
planned for the second half of 2007.

    Southwest Saskatchewan

    During the quarter, the Trust drilled 8 (3.6 net) wells in the Battrum
Units achieving a 100 percent success rate and adding initial interest
production of 180 boe/d. The Trust is currently reviewing these results for a
potential second phase of drilling in late 2007. Preliminary results of a
reservoir simulation model for the Cantuar Unit are currently being reviewed
with the operator in order to optimize water injection and drill location
selections. Up to 11 (6.1 net) drills in the Cantuar Unit are planned for the
third quarter. The Trust is also working with its operated partner at the
Cantuar Unit to identify production optimization opportunities.

    South/Central Alberta

    Crescent Point continued to work on recovery optimization activities
within the Dina and Cummings formations at Sounding Lake. Three (2.8 net) Dina
recompletions were conducted at Sounding Lake in the second quarter, achieving
initial interest production rates totaling approximately 60 boe/d. Based on
encouraging core flood studies in the Sparky formation, the Trust submitted an
application for pool delineation in preparation for waterflood approval. Water
injection is expected to commence in late 2007 or early 2008.
    At John Lake, the Trust continued to work on optimization activities,
including 13 compressor reconfigurations and resizings which are expected to
result in rental and power consumption savings of approximately $75,000 per
month and which will help offset near term production declines.
    At Little Bow, the Trust has prepared the first 2 (2.0 net) of up to 15
(15.0 net) recompletion candidates. The first two are scheduled for August
2007 and, pending the results, additional candidates will be considered for
later in the third and fourth quarters of 2007.

    Northeast British Columbia and Peace River Arch, Alberta

    At Worsley, the Trust received Good Production Practice (GPP) approval
for the Charlie Lake T pool. Water injection commenced into the Charlie Lake S
pool and plans to convert a well for the Charlie Lake T pool injection are
underway, with conversion expected in the third quarter of 2007. Extended
spring rain conditions delayed the tie-in of approximately 200 boe/d from 4
(4.0 net) wells drilled in late 2006. Tie-in is now planned for the second
half of 2007.

    Acquisitions

    During the second quarter of 2007, Crescent Point closed two minor
property acquisitions for a total consideration of $14.6 million. The
properties acquired consolidate assets in the Trust's core areas of John Lake
and southeast Saskatchewan. In total, Crescent Point acquired 370 boe/d of
production and 0.9 million boe of proved plus probable reserves.
    In the second half of the year, the Trust plans to dispose of certain
non- core properties and redeploy the proceeds to fund consolidation
acquisitions in the Trust's core operating areas.

    MARKETS AND PRICING UPDATE

    Benchmark crude oil prices continued relatively strong, with West Texas
Intermediate ("WTI") averaging US$65.02 per barrel in the second quarter of
2007, down 8 percent from the second quarter of 2006. The Canadian dollar
strengthened in the quarter, averaging US/Cdn $0.91 and contributing to a 10
percent decline in the Canadian dollar benchmark crude oil price compared to
the second quarter of 2006. Despite this market price decline, the Trust's
netback increased by 17 percent to $38.44 per boe, reflecting the Trust's high
quality oil along with its low royalty and operating cost structure. This
improvement in corporate netback has been driven predominately by the
Viewfield Bakken production which realized a second quarter netback of $56.19
per boe.
    The Trust anticipates the trend of high oil prices and a strong Canadian
dollar to continue through the remainder of the year, as evidenced by WTI
hitting all time highs in August of 2007 and the Canadian dollar hitting 30
year highs in July.
    Differentials to WTI for Canadian grades of crude oil narrowed in the
first half of 2007, with some grades trading at a premium to WTI, as demand
for Canadian crude oil, light grade oil in particular, was strong relative to
demand for WTI crude oil at Cushing, Oklahoma. The Trust anticipates this
trend to continue in the third quarter before differentials widen seasonally
into the fourth quarter.
    AECO natural gas prices averaged Cdn$7.07 per mcf during the second
quarter of 2007 before falling below Cdn$5.00 per mcf in July. Near record
high storage levels combined with mild weather and continued natural gas
drilling in the United States has weakened the market considerably in the
third quarter. Crescent Point expects this weakness to continue into the
second half of the year absent major North American production disruptions.
With a strong balance sheet and solid three year hedging program, the Trust is
well positioned should commodity price weakness provide opportunities to
acquire high quality, long life, large oil or gas in place assets in the
coming quarters.

    UPDATE ON PROPOSAL TO TAX INCOME TRUSTS IN 2011

    On October 31, 2006, the Federal Minister of Finance announced the Tax
Fairness Plan, a proposal to tax the distributions of certain publicly traded
income trusts. On March 19, 2007, the Minister of Finance announced the
Federal budget, which included legislation to enact the Tax Fairness Plan. The
budget was subsequently passed by the House of Commons and received Royal
Assent from the Senate in June of 2007. As such, it is Crescent Point's
understanding that, subject to Safe Harbour growth limitations and any further
changes to the legislation, monthly distributions paid by Crescent Point will
become taxable in 2011.
    As a result of this legislation, the Trust has recorded a future income
tax adjustment in the three month and six month periods ending June 30, 2007.
Net income for the six month period ending June 30, 2007 increased to $39.8
million, compared to $22.4 million in the first six months of 2006. Net income
for the first six months of 2007 includes the future tax expense relating to
the enactment of the Tax Fairness Plan and the future tax recovery relating to
the Trust's March 2007 reorganization. These future tax items are non-cash
items and have no impact on the Trust's cash flows in either the three month
period or the six month period ending June 30, 2007.
    Despite the trust tax legislation, Crescent Point continues to
aggressively implement its business plan, which remains unchanged since
inception as a junior producer in 2001. Crescent Point's key attributes of
proven management, high quality, large resource in place assets, and
conservative balance sheet and risk management strategy have generated five
strong years of successful results and position the Trust well to succeed in
the future. In addition, with the Canadian Government's Tax Fairness Plan
beginning in 2011, the Trust is well positioned with substantial tax pools in
excess of $800 million to minimize future taxable income.
    Crescent Point continues to actively participate in industry initiatives
to influence the long term implementation of this legislation. The Trust
continues to urge all of its unitholders and concerned individuals to write,
email or visit the constituency office of their Member of Parliament to voice
their opinion regarding the taxation of income trusts. Member of Parliament
contact information can be found on the Crescent Point website at
www.crescentpointenergy.com.

    OUTLOOK

    Crescent Point continues to execute its proven business plan of creating
value added growth in reserves, production and cash flow through management's
integrated strategy of acquiring, exploiting and developing high quality, long
life, light and medium oil and natural gas properties.
    The Trust has more than $1.1 billion of future development projects
providing six years of low risk infill development drilling inventory to
sustain current production levels. With projected net debt to cash flow of
less than 1.0 times and a balanced three year hedge profile, Crescent Point is
well positioned to sustain distributions over time as the Trust continues to
exploit and develop its asset base and actively identify and evaluate
accretive acquisition opportunities.
    Crescent Point has more than 2.5 billion barrels of original oil in place
and a reserve life index of 11.9 years on a proved plus probable basis.
Through infill drilling, production optimization and waterflood
implementation, management believes the Trust has the potential to double its
proved plus probable reserves over time.
    For the balance of 2007, the Trust continues to focus on development
drilling at its core properties of Viewfield, Manor, Tatagwa, Battrum/Cantuar,
Worsley and Glen Ewen. The Viewfield gas plant expansion was completed ahead
of schedule in early August of 2007 and the Trust is actively drilling
development wells in the Viewfield Bakken play, with plans to drill 71 (40.0
net) horizontal wells during the year. Up to 65 (42.3 net) Bakken horizontal
wells will be fracture stimulated in 2007.
    The Trust continues to actively manage its three year commodity hedging
program, with 54 percent of volumes hedged for the balance of 2007, 51 percent
in 2008, and 32 percent in 2009. The 2010 hedge program has been initiated,
with 19 percent and 9 percent of volumes hedged in the first and second
quarters of 2010, respectively. Hedge instruments utilized in the program
include swaps, collars and put options, providing a floor of more than Cdn$70
per barrel, with upside participation in rising commodity prices.
    The Trust has revised its 2007 outlook to reflect higher than anticipated
benchmark crude oil prices and the Canadian dollar, as well as lower than
expected natural gas prices. WTI is forecast to average US$67 per barrel, up
from US$60 previously, and the Canadian dollar is forecast at US/Cdn $0.91, up
from US/Cdn $0.85 previously. The AECO natural gas price forecast has been
decreased by Cdn$0.75 per mcf to Cdn$6.75. As a result, the Trust anticipates
that cash flow will increase by $3 million to $317.0 million, or $3.17 per
unit, fully diluted ($3.11 previously). The average daily production forecast
remains unchanged at 26,250 boe/d.
    Crescent Point's management believes that with the high quality reserve
base and development inventory, excellent balance sheet and solid hedging
program, the Trust is well positioned to continue generating strong operating
and financial results and delivering sustainable distributions through 2007
and beyond.

    
    2007 Outlook

    Crescent Point's 2007 guidance as follows:

    -------------------------------------------------------------------------
                                         Previous Guidance  Revised Guidance

    Production
      Oil and NGL (bbls/d)                          22,416            22,917
      Natural gas (mcf/d)                           23,000            20,000
    -------------------------------------------------------------------------
    Total (boe/d)                                   26,250            26,250
    -------------------------------------------------------------------------
    Cash flow ($000)                               314,000           317,000
    Cash flow per unit - diluted ($)                  3.11              3.17
    Cash distributions per unit ($)                   2.40              2.40
    Payout ratio - per unit - diluted (%)               77                76
    -------------------------------------------------------------------------
    Capital expenditures ($000)(1)                 150,000           150,000
    Wells drilled, net                                 110               110
    -------------------------------------------------------------------------
    Pricing
      Crude oil - WTI (US$/bbl)                      60.00             67.00
      Crude oil - WTI (Cdn$/bbl)                     70.59             73.63
      Natural gas - Corporate (Cdn$/mcf)              7.50              6.75
      Exchange rate (US$/Cdn$)                        0.85              0.91
    -------------------------------------------------------------------------
    (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
    August 13, 2007


    MANAGEMENT'S DISCUSSION & ANALYSIS

    Management's discussion and analysis ("MD&A") is dated August 13, 2007
and should be read in conjunction with the unaudited interim consolidated
financial statements for the period ended June 30, 2007 and the audited
consolidated financial statements and MD&A for the year ended December 31,
2006, for a full understanding of the financial position and results of
operations of Crescent Point Energy Trust ("Crescent Point" or the "Trust").

    Non-GAAP Financial Measures

    Throughout this discussion and analysis, Crescent Point uses the terms
cash flow from operations, cash flow from operations per unit, cash flow from
operations per unit - diluted, distributable cash, payout ratio, payout ratio
per unit - diluted, net debt, market capitalization and total capitalization.
These terms do not have any standardized meaning as prescribed by Canadian
generally accepted accounting principles ("GAAP") and therefore they may not
be comparable with the calculation of similar measures presented by other
issuers.
    Cash flow from operations is calculated based on cash flow from operating
activities before changes in non-cash working capital and asset retirement
obligation expenditures. 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        Six months ended
                                     June 30    %             June 30    %
    ($000)                     2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Cash flow from
     operating activities   102,637  49,683     107  152,813  87,203      75
    Changes in non-cash
     working capital        (24,586)  2,502  (1,083)  (2,379)  5,213    (146)
    Asset retirement
     expenditures               197      97     103      689     102     575
    -------------------------------------------------------------------------
    Cash flow from
     operations              78,248  52,282      50  151,123  92,518      63
    -------------------------------------------------------------------------
    

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

    Forward-Looking Information

    Certain statements contained in this report constitute forward-looking
statements and are based on the Trust's beliefs and assumptions based on
information available at the time the assumption was made. By its nature, such
forward-looking information involves known and unknown risks, uncertainties
and other factors that may cause actual results or events to differ materially
from those anticipated in such forward-looking statements. The Trust and
Crescent Point Resources Inc. ("CPRI"), believe the expectations reflected in
those forward-looking statements are reasonable but no assurance can be given
that these expectations will prove to be correct and such forward-looking
statements should not be unduly relied upon. These statements speak only as of
the date of this report.
    The material assumptions in making these forward-looking statements are
disclosed in this 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.

    Results of Operations

    Production

    Production increased by 28 percent in the second quarter of 2007 and for
the six months ended June 30, 2007 primarily due to the acquisition of Mission
Oil & Gas Inc. ("Mission"), several acquisitions completed in 2006 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 Bakken
resource play. This acquisition adds a new core area for the Trust in the
Viewfield area of southeast Saskatchewan.
    The Trust's weighting to oil increased to 87 percent, a four percent
increase quarter-over-quarter and a three percent increase for the six months
ended June 30, 2007. This increase was the result of the Mission acquisition
which was focused primarily on light oil assets.

    
    -------------------------------------------------------------------------
                               Three months ended        Six months ended
                                     June 30    %             June 30    %
                               2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Crude oil and NGL
     (bbls/d)                22,819  16,959      35   22,443  16,873      33
    Natural gas (mcf/d)      20,109  20,622      (2)  19,745  19,356       2
    -------------------------------------------------------------------------
    Total (boe/d)            26,170  20,396      28   25,733  20,099      28
    -------------------------------------------------------------------------
    Crude oil and NGL (%)        87      83       4       87      84       3
    Natural gas (%)              13      17      (4)      13      16      (3)
    -------------------------------------------------------------------------
    Total (%)                   100     100       -      100     100       -
    -------------------------------------------------------------------------
    

    Marketing and Prices

    The Trust's average oil price for the second quarter of 2007 decreased 6
percent over the comparable period in 2006 due to a decrease in the $US
benchmark WTI price and a stronger Canadian dollar, partially offset by
narrower corporate differentials. Crescent Point's oil differential narrowed
significantly from $12.59 per bbl in the second quarter of 2006 to $8.34 per
bbl in the second quarter of 2007. This trend is attributable to both changes
in market conditions and a change in the Trust's crude oil quality as a result
of the Viewfield Bakken light oil properties acquired through the Mission
acquisition.
    For the six months ended June 30, 2007, the Trust's average selling price
for crude oil increased by one percent over the comparable 2006 period. The
Trust's average selling price was reduced by an 8 percent decline in the
benchmark $US WTI price, but this was more than offset by improvements in the
Trust's average crude quality from the Mission acquisition, which narrowed
corporate oil differentials and provided a higher selling price. In addition,
market differentials narrowed from the higher levels experienced in the first
quarter of 2006. Collectively, the corporate oil differential for the six
months ended June 30, 2007 was $9.26 per bbl compared to $16.15 per bbl in the
comparable 2006 period.
    The Trust's average selling price for gas for the three and six months
ended June 30, 2007 increased 26 percent and nine percent, respectively,
compared to the same periods for 2006. These trends were reasonably consistent
with the trend in the AECO daily gas price, reflecting the Trust's portfolio
of gas marketing contracts.

    
    -------------------------------------------------------------------------
    Average Selling Prices(1)   Three months ended        Six months ended
                                      June 30   %              June 30   %
                               2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Crude oil and NGL
     ($/bbl)                  63.11   66.85      (6)   60.79   60.13       1
    Natural gas ($/mcf)        7.17    5.67      26     7.31    6.72       9
    -------------------------------------------------------------------------
    Total ($/boe)             60.54   61.31      (1)   58.62   56.95       3
    -------------------------------------------------------------------------
    (1) The average selling prices reported are before realized financial
        instrument losses and transportation charges.

    -------------------------------------------------------------------------
    Benchmark Pricing           Three months ended        Six months ended
                                      June 30   %              June 30   %
                               2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    WTI crude oil (US$/bbl)   65.02   70.70      (8)   61.64   67.13      (8)
    WTI crude oil (Cdn$/bbl)  71.45   79.44     (10)   70.05   76.28      (8)
    AECO natural gas(1)
     (Cdn$/mcf)                7.07    6.03      17     7.23    6.76       7
    Exchange rate - US$/Cdn$   0.91    0.89       2     0.88    0.88       -
    -------------------------------------------------------------------------
    (1) The AECO natural gas price reported is the average daily spot price.
    

    Financial Instruments and Risk Management

    Management of cash flow variability is an integral component of Crescent
Point's business strategy. Changing business conditions are monitored
regularly and reviewed with the Board of Directors to establish risk
management guidelines used by management in carrying out the Trust's strategic
risk management program. The risk exposure inherent in movements in the price
of crude oil and natural gas, fluctuations in the US/Cdn dollar exchange rate,
changes in the price of power and interest rate movements on long-term debt
are all proactively managed by Crescent Point through the use of derivatives
with reputable, financially sound counterparties. The Trust considers these
contracts to be an effective means to manage cash flow.
    The majority of the Trust's crude oil and natural gas financial
instruments are in Canadian dollars, and all contracts are referenced to WTI
and AECO, unless otherwise noted. These Canadian dollar financial instruments
allow the Trust to hedge both commodity prices and fluctuations in the US/Cdn
dollar exchange rate. The Trust's US dollar crude oil financial instrument
contracts were executed in conjunction with US dollar foreign exchange
contracts to mitigate fluctuations in the US/Cdn dollar.
    The Trust had a realized financial instrument gain of $1.7 million for
the second quarter of 2007 compared to a $10.0 million loss for the same
period in 2006. The gain is attributable to a higher average financial
instrument oil price, combined with a decline in the WTI benchmark price. The
Trust's average financial instrument oil price increased $8.83 per bbl, from
$64.10 per bbl in the second quarter of 2006 to $72.93 per bbl for the second
quarter 2007. WTI decreased Cdn$7.99 over the same period.
    The Trust's realized financial instrument gain was $4.3 million for the
six months ended June 30, 2007 compared to a loss of $17.0 million for the
comparable 2006 period. This trend also relates to a higher average financial
instrument oil price, and a decline in the WTI benchmark price.
    The Trust has not designated any of its risk management activities as
accounting hedges under the Canadian Institute of Chartered Accountants (the
"CICA") section 3865 and, accordingly, has marked-to-market its financial
instruments. This resulted in an unrealized financial instrument gain of
$18.8 million for the second quarter of 2007 compared to a loss of $3.3
million in 2006 for the comparable period. The gain resulted from a decline in
the WTI crude oil price at June 30, 2007 as compared to the end of the first
quarter of 2007.
    The Trust's unrealized financial instrument gain for the six months ended
June 30, 2007 was $3.4 million compared to a loss of $22.8 million for the
same period in 2006. The gain resulted from a decline in the WTI crude oil
price at June 30, 2007 compared to December 31, 2006.
    The following is a summary of the realized financial instrument gains
(losses) on oil and gas contracts:

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
    ($000, except per boe             June 30   %              June 30   %
    and volume amounts)        2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Average crude oil
     volumes hedged
     (bbls/d)                10,750   7,167      50   10,583   6,458      64
    Crude oil realized
     financial instrument
     gain (loss)              1,709 (10,040)    117    4,341 (17,042)    125
      per bbl                  0.82   (6.51)    113     1.07   (5.58)    119
    Average natural gas
     volumes hedged (GJ/d)    4,000       -       -    3,000       -       -
    Natural gas realized
     financial instrument
     gain                         9       -       -       22       -       -
      per mcf                     -       -       -     0.01       -       -
    Average barrels of oil
     equivalent hedged
     (boe/d)                 11,382   7,167      59   11,057   6,458      71
    Total realized financial
     instrument gain (loss)   1,718 (10,040)    117    4,363 (17,042)    126
      per boe                  0.72   (5.41)    113     0.94   (4.68)    120
    -------------------------------------------------------------------------

    Crescent Point has the following financial instrument contracts in place
as at August 1, 2007:

    -------------------------------------------------------------------------
    Financial WTI Crude             Average    Average    Average    Average
     Oil Contracts -                   Swap     Bought       Sold        Put
     Canadian Dollar      Volume      Price  Put Price  Call Price   Premium
    Term        Contract (bbls/d) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
    -------------------------------------------------------------------------
    2007
    July -
     September      Swap   1,500      71.68
    July -
     December       Swap   3,500      75.58
    October -
     December       Swap   2,000      74.94
    July -
     September    Collar     250                 68.00      81.28
    July -
     December     Collar   1,250                 67.09      81.52
    October -
     December     Collar     250                 65.00      86.00
    July -
     December        Put   3,250                 77.63                 (7.65)
    -------------------------------------------------------------------------
    2007 Weighted
     Average              10,000      74.90      74.27      81.87      (7.65)
    -------------------------------------------------------------------------

    2008
    January -
     June           Swap   1,000      72.73
    January -
     September      Swap     250      68.10
    January -
     December       Swap   4,000      76.15
    July -
     December       Swap   1,000      73.52
    October -
     December       Swap     250      70.80
    January -
     June         Collar     250                 65.00      82.00
    January -
     December     Collar   1,750                 70.00      83.55
    July -
     December     Collar     250                 70.00      91.00
    January -
     December        Put   3,500                 72.58                 (6.66)
    -------------------------------------------------------------------------
    2008 Weighted
     Average              10,750      75.22      71.53      83.92      (6.66)
    -------------------------------------------------------------------------
    2009
    January -
     March          Swap   2,750      77.68
    January -
     June           Swap   1,250      74.99
    April -
     June           Swap   2,750      77.58
    July -
     September      Swap   3,000      74.07
    July -
     December       Swap   1,000      76.41
    October -
     December       Swap   3,000      74.37
    January -
     March        Collar     250                 75.00      87.00
    January -
     June         Collar   1,250                 70.00      81.01
    January -
     September    Collar     250                 70.00      79.00
    January -
     December     Collar     250                 70.00      79.25
    April -
     June         Collar     250                 75.00      83.00
    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     750                 70.97                 (7.00)
    -------------------------------------------------------------------------
    2009 Weighted
     Average               6,750      75.78      70.26      81.05      (7.00)
    -------------------------------------------------------------------------
    2010
    January -
     March          Swap   3,500      76.22
    April -
     June           Swap   1,500      75.45
    January -
     June         Collar     500                 70.00      80.50
    -------------------------------------------------------------------------
    2010 Weighted
     Average               2,995      75.99      70.00      80.50
    -------------------------------------------------------------------------


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


    -------------------------------------------------------------------------
    Financial AECO Natural Gas                            Average    Average
     Contracts - Canadian Dollar                           Bought       Sold
                                                Volume  Put Price Call Price
    Term                           Contract      (GJ/d)  ($Cdn/GJ)  ($Cdn/GJ)
    -------------------------------------------------------------------------
    2007
    July - October                   Collar      4,000       6.75       8.60
    -------------------------------------------------------------------------
    2007 Weighted Average                        2,674       6.75       8.60
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
    Financial Foreign Exchange
     Contracts - U.S. Dollar                                         Average
                                                           Volume       Swap
    Term                                       Contract      ($US) ($Cdn/$US)
    -------------------------------------------------------------------------
    2007
    July - December                               Swap  5,980,000     1.1600
    July - December                               Swap  6,440,000     1.1012
    -------------------------------------------------------------------------
    2007 Weighted Average                              12,420,000     1.1295
    -------------------------------------------------------------------------



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


    -------------------------------------------------------------------------
    Financial Power Contracts -
     Canadian Dollar
                                                          Volume  Fixed Rate
    Term                                      Contract    (MW/h)  ($Cdn/MW/h)
    -------------------------------------------------------------------------
    July 2007 - December 2008                     Swap      3.0        63.25
    July 2007 - December 2009                     Swap      1.0        82.45
    January 2009 - December 2009                  Swap      3.0        81.25
    -------------------------------------------------------------------------
    

    Revenues

    Oil revenues increased 27 percent in the second quarter of 2007 compared
to the same period in 2006, and increased 34 percent in the six month period
compared to the same period in 2006. These increases in crude oil and NGL
sales relate primarily to the increase in production resulting from the 2007
acquisition of Mission, along with several acquisitions completed in 2006 and
the Trust's successful drilling program. Partially offsetting these production
increases, were lower realized oil prices resulting primarily from a decline
in the benchmark $Cdn WTI price, despite narrowing corporate oil
differentials.
    Natural gas sales increased 23 percent and 11 percent for the second
quarter 2007 and six months ended June 30, 2007, respectively. These increases
are consistent with the increase in realized gas prices, resulting primarily
from a stronger AECO benchmark price.

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
                                      June 30   %              June 30   %
    ($000)(1)                  2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Crude oil and NGL
     sales                  131,050 103,158      27  246,937  183,635     34
    Natural gas sales        13,129  10,632      23   26,122   23,531     11
    -------------------------------------------------------------------------
    Revenues                144,179 113,790      27  273,059  207,166     32
    -------------------------------------------------------------------------
    (1) Revenue is reported before transportation charges and realized
        financial instruments.
    

    Transportation Expenses

    Transportation expense per boe increased in the three and six month
periods ended June 30, 2007 compared to the same periods in 2006. This
increase relates to properties acquired in the past year and their proximity
to market, along with pipeline capacity issues in southeast Saskatchewan which
began in the fourth quarter of 2006 and continued through the first half of
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 fourth quarter of 2006 and the
six month period ended June 30, 2007.

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
    ($000, except per                 June 30   %              June 30   %
     boe amounts)              2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Transportation
     expenses                 3,834   2,369      62    7,670   4,320      78
    Per boe                    1.61    1.28      26     1.65    1.19      39
    -------------------------------------------------------------------------
    

    Royalty Expenses

    Royalties as a percent of sales were 19 percent in the second quarter of
2007 and 18 percent for the six months ended June 30, 2007, down from 22
percent for both periods in 2006. These decreases are primarily associated
with lower royalty rates on the properties acquired through the Mission
acquisition. A factor further contributing to the Trust's lower royalty rate
are royalty incentives on new production associated with the Trust's
successful drilling program in Saskatchewan.
    Royalties are calculated and paid based on commodity revenue net of
applicable costs and before any realized financial instrument gain or loss.

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
    ($000, except per                 June 30   %              June 30   %
     boe amounts)              2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Total royalties          28,023  25,258      11   49,767  45,435      10
    As a % of oil and
     gas sales                   19      22      (3)      18      22      (4)
    Per boe                   11.77   13.61     (14)   10.68   12.49     (14)
    -------------------------------------------------------------------------
    

    Operating Expenses

    Operating expenses per boe increased by 16 percent in the second quarter
and 13 percent in the six month period ended June 30, 2007, over the
comparable periods in 2006. The increase in operating expenses during these
periods is a result of the increased cost of services experienced in the
Canadian oil and gas industry, continued repair and maintenance activities and
one time costs from a partner on a non-operated property. Partially offsetting
these increases in costs were lower operating costs associated with certain
properties acquired through the Mission acquisition.

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
    ($000, except per                 June 30   %              June 30   %
     boe amounts)              2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Operating expenses       22,477  15,104      49   43,867  30,212      45
    Per boe                    9.44    8.14      16     9.42    8.30      13
    -------------------------------------------------------------------------
    

    Netbacks

    The Trust's netback, after realized financial instruments, increased 17
percent to $38.44 per boe in the second quarter of 2007 from $32.87 per boe in
the second quarter of 2006. The Trust's netback for the three month period
increased by 17 percent despite a 10 percent decline in benchmark $Cdn WTI
crude oil pricing as the Trust's average crude quality improved from the prior
year as a result of the Viewfield Bakken production acquired in the first
quarter of 2007 resulting in lower corporate oil differentials. Additional
factors contributing to the improved netback were stronger financial
instrument prices and lower royalties which were modestly offset by higher
operating and transportation costs.
    The netback for the six month period ended June 30, 2007 increased 25
percent to $37.81 per boe compared to $30.29 for the same period in 2006. The
increase in the Trust's netback relates to the same factors as the three month
period, however for the six month period the eight percent decline in the
benchmark $Cdn WTI price was more than offset by improvements in the Trust's
average crude quality from the Mission acquisition.

    
    -------------------------------------------------------------------------
                                             Three months ended June 30
                                               2007                2006
    -------------------------------------------------------------------------
                                   Crude Oil Natural
                                     and NGL     Gas   Total   Total       %
                                      ($/bbl) ($/mcf) ($/boe) ($/boe) Change
    -------------------------------------------------------------------------
    Average selling price              63.11    7.17   60.54   61.31      (1)
    Royalties                         (11.28)  (2.51) (11.77) (13.61)    (14)
    Operating expenses                 (9.04)  (2.03)  (9.44)  (8.14)     16
    Transportation                     (1.61)  (0.26)  (1.61)  (1.28)     26
    -------------------------------------------------------------------------
    Netback prior to realized
     financial instruments             41.18    2.37   37.72   38.28      (1)
    -------------------------------------------------------------------------
    Realized gain (loss) on
     financial instruments              0.82       -    0.72   (5.41)    113
    -------------------------------------------------------------------------
    Netback                            42.00    2.37   38.44   32.87      17
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                              Six months ended June 30
                                               2007                2006
    -------------------------------------------------------------------------
                                   Crude Oil Natural
                                     and NGL     Gas   Total   Total       %
                                      ($/bbl) ($/mcf) ($/boe) ($/boe) Change
    -------------------------------------------------------------------------
    Average selling price              60.79    7.31   58.62   56.95       3
    Royalties                         (10.69)  (1.78) (10.68) (12.49)    (14)
    Operating expenses                 (9.04)  (2.00)  (9.42)  (8.30)     13
    Transportation                     (1.66)  (0.26)  (1.65)  (1.19)     39
    -------------------------------------------------------------------------
    Netback prior to realized
     financial instruments             39.40    3.27   36.87   34.97       5
    -------------------------------------------------------------------------
    Realized gain (loss) on
     financial instruments              1.07    0.01    0.94   (4.68)    120
    -------------------------------------------------------------------------
    Netback                            40.47    3.28   37.81   30.29      25
    -------------------------------------------------------------------------
    

    General and Administrative Expenses

    General and administrative expenses per boe increased 20 percent in the
second quarter of 2007 and 22 percent for the six month period ended June 30,
2007 compared to the 2006 respective periods. The increases are mainly
attributable to the overall growth of the Trust along with industry cost
pressures to retain and attract high quality employees.

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
    ($000, except per                 June 30   %              June 30   %
     boe amounts)              2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    General and
     administrative costs     5,103   3,308      54    9,974   6,252      60
    Capitalized                (920)   (584)     58   (1,880) (1,061)     77
    -------------------------------------------------------------------------
    General and
     administrative expenses  4,183   2,724      54    8,094   5,191      56
    Per boe                    1.76    1.47      20     1.74    1.43      22
    -------------------------------------------------------------------------
    

    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 1,378,200 restricted units
outstanding at June 30, 2007 compared with 692,647 units outstanding at June
30, 2006.
    The Trust recorded compensation expense and contributed surplus of $3.7
million for the second quarter ended June 30, 2007, based on the fair value of
the units on the date of grant, an increase of 112 percent over the same
period of 2006. Additionally, the Trust recorded $345,000 of cash
distributions on restricted units, an increase of 99 percent from $173,000 in
the second quarter 2006. The total cash and non-cash unit based compensation
recorded in the second quarter of 2007 was $4.1 million as compared to $1.9
million for the same 2006 period. 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. A similar trend was experienced for the six month
period ended June 30, 2007.

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
    ($000, except per                 June 30   %              June 30   %
     boe amounts)              2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Cash unit-based
     compensation expense       345     173      99      785     347     126
    Non-cash unit-based
     compensation expense     3,746   1,767     112    7,066   3,305     114
    -------------------------------------------------------------------------
    Total                     4,091   1,940     111    7,851   3,652     115
    Per boe                    1.72    1.05      64     1.69    1.00      69
    -------------------------------------------------------------------------
    

    Interest Expense

    Interest per boe increased 22 percent in the second quarter 2007 compared
to the same period in 2006. For the six month period ended June 30, 2007,
interest per boe increased five percent. The increase in interest per boe is
attributable to higher effective interest rates resulting from an increase in
the prime rate and related bankers acceptances rates through 2006. Crescent
Point actively manages exposure to fluctuations in interest rates through
interest rate swaps (refer to Financial Instruments and Risk Management
section above).

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
    ($000, except per                 June 30   %              June 30   %
     boe amounts)              2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Interest expense          4,853   3,107      56    8,971   6,646      35
    Per boe                    2.04    1.67      22     1.93    1.83       5
    -------------------------------------------------------------------------
    

    Depletion, Depreciation and Amortization

    The depletion, depreciation and amortization ("DD&A") rate increased to
$24.17 per boe for the three month period ended June 30, 2007 from $18.68 in
the same period of 2006. The higher DD&A rate in both the three and six month
periods ended June 30, 2007 is due to the acquisitions completed in 2006 as
well as the Mission acquisition completed in 2007 which carried a higher cost
per barrel than the Trust's existing properties.

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
    ($000, except per                 June 30   %              June 30   %
     boe amounts)              2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Depletion, depreciation
     and amortization        57,549  34,668      66  112,115  65,556      71
    Per boe                   24.17   18.68      29    24.07   18.02      34
    -------------------------------------------------------------------------
    

    Taxes

    Capital and other tax expense consists of Saskatchewan Corporation
Capital Tax Resource Surcharge. Capital and other tax expense increased from
$2.7 million in the second quarter of 2006 to $4.0 million in the second
quarter 2007 due to increases in the Trust's Saskatchewan production,
partially offset by a decrease in realized oil prices. A similar trend was
noted for the six month period ended June 30, 2007.
    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 will be applicable to trusts in 2011 under current legislation.
    In the first quarter of 2007, the future income tax liability was
eliminated due to the March 1, 2007 reorganization providing the Trust with a
"flow through" structure. This resulted in a future income tax recovery of
$158.8 million in the first quarter of 2007. Accordingly, for the six month
period ending June 30, 2007 the Trust recorded a $6.5 million recovery which
is the excess of the recovery recorded in the first quarter of 2007 in respect
of the internal reorganization over the liability recognized in the second
quarter of 2007 in respect of the taxation on trusts.
    Despite the trust tax legislation, Crescent Point continues to
aggressively implement its business plan, which remains unchanged since
inception as a junior producer in 2001. Crescent Point's key attributes of
proven management, high quality, large resource in place assets, and
conservative balance sheet and risk management strategy have generated five
strong years of successful results and position the Trust well to succeed in
the future. In addition, with the Canadian Government's Tax Fairness Plan
beginning in 2011, the Trust is well positioned with substantial tax pools in
excess of $800.0 million to minimize future taxable income.

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
                                      June 30   %              June 30   %
    ($000)                     2007    2006  Change    2007     2006  Change
    -------------------------------------------------------------------------
    Capital and other tax
     expense                  4,000   2,733      46   7,211    5,455      32
    Future income tax
     expense (recovery)     152,346  (7,120)  2,240  (6,471) (20,632)     69
    -------------------------------------------------------------------------
    

    Cash Flow and Net Income

    Cash flow from operations increased from $52.3 million in the second
quarter of 2006 to $78.2 million in the second quarter of 2007, primarily due
to an increase in the Trust's production and an increase in the Trust's
corporate netback. Cash flow from operations per unit - diluted decreased 9
percent from $0.85 to $0.77 due to a decrease in the $Cdn WTI benchmark price.
For the six month period ended June 30, 2007, cash flow from operations
increased from $92.5 million in 2006 to $151.1 million in 2007, while on a per
unit - diluted basis it was consistent with a slight increase from $1.59 per
unit - diluted in 2006 to $1.60 per unit - diluted in 2007.
    A net loss of $117.8 million for the second quarter of 2007 was incurred
compared to net income of $19.3 million for the second quarter 2007. This
change is primarily the result of the future income tax expense of $152.3
million incurred in the three month period ended June 30, 2007 which was
recorded in respect of Bill C-52 which was substantively enacted in June 2007.
Bill C-52 includes legislation to tax publicly traded trusts, beginning
January 1, 2011. For the six month period ended June 30, 2007, net income
increased to $39.8 million from $22.4 million for the same period of 2006.
This increase is due primarily to an increase in cash flow from operations as
a result of increases in production, realized gains instead of losses on
financial instruments in the period, partially offset by an increase in DD&A
expense.

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
    ($000, except per                 June 30   %              June 30   %
     unit amounts)             2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Cash flow from
     operations              78,248  52,282      50  151,123  92,518      63
    Cash flow from
     operations per unit -
     diluted                   0.77    0.85      (9)    1.60    1.59       1

    Net income (loss)      (117,773) 19,260    (711)  39,771  22,441      77
    Net income (loss)
     per unit - diluted(1)    (1.17)   0.31    (477)    0.43    0.34      26
    -------------------------------------------------------------------------
    (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

    Crescent Point's distributions to unitholders are paid monthly and are
dependent upon commodity prices, production levels and the amount of capital
expenditures to be funded from cash flow. The Trust reinvests part of its cash
flow towards the capital program to provide for more sustainable distributions
in the future. The actual amount of the distributions is at the discretion of
the Board of Directors. In the event that commodity prices are higher than
anticipated and a cash surplus develops during the quarter, the surplus may be
used to increase distributions, reduce debt and/or increase the Trust's
capital program.
    The Trust maintained monthly distributions of $0.20 per unit during the
second quarter and six month period ended June 30, 2007, despite declines in
market oil prices compared to 2006. Crescent Point's hedging strategy
minimizes corporate price volatility which has provided the Trust with the
ability to maintain sustainable distributions through periods of weakening
market prices.
    Cash distributions increased by 67 percent for the second quarter of 2007
compared to the same period in 2006, and by 65 percent for the six month
period ended June 30, 2007. The increase relates to the increase in trusts
unit outstanding, primarily as a result of the Mission acquisition, the Canex
acquisition and the Trust's distribution reinvestment programs.
    During the second quarter and six months ended June 30, 2007, the Trust
funded cash distributions from its cash flow from operations and expects to
continue this practice in the future. Cash flow from operations in excess of
distributions requirements is used to fund capital expenditures and reduce
bank indebtedness.
    The Trust's payout on a $Cdn per unit - diluted basis increased from 71
percent to 78 percent in the three month period ended June 30, 2007. This
increase is the result of a decrease in the cash flow from operations per unit
- diluted which resulted primarily from lower $Cdn WTI benchmark pricing. The
payout ratio per unit - diluted of 75 percent for the six month period ended
June 30, 2007 remained unchanged from the comparable 2006 timeframe.

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
    ($000, except per unit            June 30   %              June 30   %
     and percent amounts)      2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Cash distributions       60,320  36,123      67  113,931  69,065      65
    Cash distributions -
     per unit                  0.60    0.60       -     1.20    1.20       -

    Payout ratio (%)             77      69       8       75      75       -
    Payout ratio - per
     unit - diluted (%)          78      71       7       75      75       -
    -------------------------------------------------------------------------

    The following table provides a reconciliation of cash distributions:

    -------------------------------------------------------------------------
                                Three months ended        Six months ended
    ($000, except per                 June 30   %              June 30   %
     unit amounts)             2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Accumulated cash
     distributions,
     beginning of period    344,053 173,107      99  290,442 140,165     107
    Cash distributions
     declared to
     unitholders(1)          60,320  36,123      67  113,931  69,065      65
    -------------------------------------------------------------------------
    Accumulated cash
     distributions, end
     of period              404,373 209,230      93  404,373 209,230      93
    -------------------------------------------------------------------------

    Accumulated cash
     distributions per unit,
     beginning of period       7.86    5.46      44     7.26    4.86      49
    Cash distributions
     declared to
     unitholders per unit(1)   0.60    0.60       -     1.20    1.20       -
    -------------------------------------------------------------------------
    Accumulated cash
     distributions per unit,
     end of period             8.46    6.06      40     8.46    6.06      40
    -------------------------------------------------------------------------
    (1) Cash distributions reflect the sum of the amounts declared monthly to
        unitholders, including distributions under the DRIP and Premium DRIP
        plans.

    The following table provides a reconciliation of distributable cash:

    -------------------------------------------------------------------------
                                Three months ended        Six months ended
                                      June 30   %              June 30   %
    ($000)                     2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Cash flow from
     operating activities   102,637  49,683     107  152,813  87,203      75
    Plus: changes in
     non-cash working
     capital                (24,586)  2,502  (1,083)  (2,379)  5,213    (146)
    Plus: ARO expenditures      197      97     103      689     102     575
    Less: reclamation fund
     contributions             (709)   (372)     91   (1,164) (1,721)    (32)
    -------------------------------------------------------------------------
    Distributable cash       77,539  51,910      49  149,959  90,797      65
    -------------------------------------------------------------------------

    Allocation of
     distributable cash
      Cash retained from
       cash available for
       distribution(1)       17,219  15,787      (9)  36,028  21,732      66
        Cash distributions
         declared            60,320  36,123      67  113,931  69,065      65
    -------------------------------------------------------------------------
    Distributable cash       77,539  51,910      49  149,959  90,797      65
    -------------------------------------------------------------------------
    (1) The Board of Directors determines the cash distributions level which
        results in a discretionary amount of cash retained. Cash flow from
        operations in excess of distributions requirements is used to fund
        capital expenditures and reduce bank indebtedness.
    

    Investment in Marketable Securities

    During the six month period ended June 30, 2007, the Trust owned shares
of a publicly traded exploration and production company. In accordance with
new accounting standards, 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.

    Capital Expenditures

    The Trust closed two property acquisitions in the John Lake area of
Alberta and southeast area of Saskatchewan in the second quarter of 2007 for
total consideration of $14.6 million. The Trust recorded favorable purchase
price adjustments on previously closed acquisitions of $500,000 in the second
quarter of 2007. In the six month period ended June 30, 2007, the Trust closed
one corporate acquisition and three property acquisitions for total
consideration of $640.4 million, including closing adjustments and assumed net
debt. The Trust recorded favorable purchase price adjustments of $1.1 million
on previously closed acquisitions in the six months ended June 30, 2007.
    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 $621.4 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.
    The Trust's development capital expenditures for the second quarter of
2007 were $42.4 million, compared to $24.3 million for the comparable period
in 2006. In the second quarter of 2007, 41 wells (24.5 net) were drilled with
a success rate of 100 percent.
    The Trust's budgeted capital program for 2007 is approximately $150.0
million and no budget has been established for acquisitions. The Trust
searches for opportunities that align with strategic parameters and evaluates
each prospect on a case by case basis. The Trust's acquisitions are expected
to be financed through bank debt and new equity issuances.

    
    -------------------------------------------------------------------------
                                Three months ended        Six months ended
                                      June 30   %              June 30   %
    ($000)                     2007    2006  Change     2007    2006  Change
    -------------------------------------------------------------------------
    Capital acquisitions
     (net)(1)(2)             14,122  91,408     (85) 639,252 444,189      44
    Development capital
     expenditures            42,416  24,276      75   74,746  48,035      56
    Capitalized
     administration             920     584      58    1,880   1,061      77
    Office equipment          1,377     219     529    1,597     405     294
    -------------------------------------------------------------------------
    Total                    58,835 116,487     (49) 717,475 493,690      45
    -------------------------------------------------------------------------
    (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.
    

    Goodwill

    The goodwill balance of $68.4 million as at June 30, 2007 is attributable
to the corporate acquisitions of Tappit Resources Ltd., Capio Petroleum
Corporation and Bulldog Energy Inc. during the period 2003 through 2005.

    Asset Retirement Obligation

    The asset retirement obligation increased by $4.0 million during the
second quarter of 2007. This increase relates to liabilities of $3.1 million
recorded in respect of two acquisitions and new drills in the quarter and
accretion expense of $1.1 million, offset slightly by actual expenditures
incurred in the quarter of $197,000.

    Liquidity and Capital Resources

    The Trust has a syndicated credit facility with seven banks and an
operating credit facility with one Canadian chartered bank. On May 28, 2007,
the amount available under the Trust's combined credit facilities was
increased from $470.0 million to $600.0 million, to reflect the growth of the
Trust's reserve base and the Mission acquisition. As at June 30, 2007, the
Trust had debt of $330.0 million, leaving unutilized borrowing capacity of
$270.0 million.
    As at June 30, 2007, Crescent Point was capitalized with 15 percent net
debt and 85 percent equity, a one percent change from December 31, 2006 (based
on period end market capitalization). The Trust's net debt to cash flow of 1.1
times at June 30, 2007 reflects the debt financing of the acquisitions
completed during the second quarter of 2007, while the cash flow reflects only
the amounts generated since closing the acquisitions (December 31, 2006 - 1.2
times). The Trust's projected net debt to 12 month cash flow is less than 1.0
times.
    The Trust's ability to raise new equity 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 significant credit facility available and success
raising new equity as demonstrated in fiscal 2006.

    
    -------------------------------------------------------------------------
    Capitalization Table
    ($000, except unit, per unit
    and percent amounts)                    June 30, 2007  December 31, 2006
    -------------------------------------------------------------------------
    Bank debt                                     330,070            254,438
    Working capital(1)                             23,346            (26,533)
    -------------------------------------------------------------------------
    Net debt(1)                                   353,416            227,905
    Trust units outstanding                   101,499,865         69,531,952
    Market price at end of period (per unit)        19.63              17.60
    Market capitalization                       1,992,442          1,223,762
    -------------------------------------------------------------------------
    Total capitalization                        2,345,858          1,451,667
    -------------------------------------------------------------------------
    Net debt as a percentage of total
     capitalization (%)                                15                 16
    -------------------------------------------------------------------------
    Annualized cash flow from operations          312,992            189,135
    -------------------------------------------------------------------------
    Net debt to cash flow(2)                          1.1                1.2
    -------------------------------------------------------------------------
    (1) Working capital and net debt exclude the risk management liabilities
        and assets. Working capital and net debt as at December 31, 2006
        include the $30.0 million long-term investment in Mission Oil & Gas
        Inc.

    (2) The net debt reflects the financing of acquisitions, however the cash
        flow only reflects cash flows generated from the acquired properties
        since the closing dates of the acquisitions.
    

    Unitholders' Equity

    At June 30, 2007, Crescent Point had 101,499,865 trust units issued
compared to 69,531,952 trust units at December 31, 2006. The increase by more
than 31.0 million trust units relates primarily to the Mission acquisition
completed February 9, 2007. The Trust issued 29.2 million trust units to
Mission shareholders at a price of $17.37 per trust unit.
    Crescent Point's total capitalization increased 62 percent to $2.3
billion at June 30, 2007 compared to $1.5 billion at December 31, 2006, with
the market value of the trust units representing 85 percent of the total
capitalization. The increase in capitalization is attributable to the closing
of the Mission acquisition along with an increase in the unit trading price.
During the second quarter of 2007, the Trust's units traded in the range of
$17.94 to $20.89 with an average daily trading volume of 441,803 units.
    For the second quarter of 2007, the distribution reinvestment and premium
distribution reinvestment plans resulted in an additional 1.4 million trust
units being issued at an average price of $18.99 raising a total of $27.5
million. Participation levels in these plans are approximately 45 percent. The
cash raised through these alternative equity programs is used to reduce bank
debt. Crescent Point will continue to monitor participation levels and utilize
these funds in the most effective manner.

    Critical Accounting Estimates

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

    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 resulting in a realized gain of $1.4
million.
    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 June 30, 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.
    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. 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.
    The standards are effective for fiscal years beginning on or after
October 1, 2007. The Trust has not assessed the impact of these standards on
its financial statements.

    Internal Controls Update

    Crescent Point is required to comply with Multilateral Instrument 52-109
"Certification of Disclosure in Issuers' Annual and Interim Filings". The 2007
certificate requires that the Trust disclose in the interim MD&A any changes
in the Trust's internal control over financial reporting that occurred during
the period that has materially affected, or is reasonably likely to materially
affect the Trust's internal control over financial reporting. The Trust
confirms that no such changes were made to the internal controls over
financial reporting during the second quarter of 2007.

    
    Summary of Quarterly Results

    -------------------------------------------------------------------------
    ($000, except per                         2007                  2006
     unit amounts)                       Q2         Q1         Q4         Q3
    -------------------------------------------------------------------------
    Revenues                        144,179    128,880    100,960    119,365

    Net income (loss)(1)(5)        (117,773)   157,544      6,918     39,588
    Net income (loss) per
     unit(1)(5)                       (1.17)      1.83       0.10       0.61
    Net income (loss) per unit -
     diluted(1)(5)                    (1.17)      1.80       0.10       0.58

    Cash flow from operations        78,248     72,875     43,843     52,774
    Cash flow from operations
     per unit                          0.78       0.84       0.64       0.81
    Cash flow from operations
     per unit - diluted                0.77       0.84       0.63       0.78

    Working capital(2)              (23,346)    13,044     26,533     29,354
    Total assets                  2,051,979  2,076,521  1,373,466  1,351,245
    Total liabilities               656,693    534,299    467,086    448,483
    Net debt(2)                     353,416    340,612    227,905    212,073
    Total long-term financial
     liabilities                      7,286     16,107     11,697      8,650

    Weighted average trust units
     - diluted (thousands)(3)       101,681     87,537     69,764     67,810

    Capital expenditures(4)          58,835    658,640     32,925     94,548

    Cash distributions               60,320     53,611     41,322     39,890
    Cash distributions per unit        0.60       0.60       0.60       0.60
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    ($000, except per                         2006                  2005
     unit amounts)                       Q2         Q1         Q4         Q3
    -------------------------------------------------------------------------
    Revenues                        113,790     93,376     75,935     72,336

    Net income (loss)(1)(5)          19,260      3,181     33,453     10,506
    Net income (loss) per
     unit(1)(5)                        0.32       0.06       0.87       0.29
    Net income (loss) per unit -
     diluted(1)(5)                     0.31       0.02       0.87       0.28

    Cash flow from operations        52,282     40,236     33,424     33,275
    Cash flow from operations
     per unit                          0.88       0.76       0.87       0.93
    Cash flow from operations
     per unit - diluted                0.85       0.73       0.83       0.88

    Working capital(2)               29,840     25,946     31,165       (874)
    Total assets                  1,294,214  1,188,260    808,297    579,869
    Total liabilities               503,903    452,648    375,632    266,498
    Net debt(2)                     241,371    206,991    194,545    119,110
    Total long-term financial
     liabilities                     18,791     16,097      4,590     11,610

    Weighted average trust units
     - diluted (thousands)(3)        61,372     54,958     40,464     37,645

    Capital expenditures(4)         116,487    377,202    167,927     62,418

    Cash distributions               36,123     32,942     22,835     19,329
    Cash distributions per unit        0.60       0.60       0.59       0.53
    -------------------------------------------------------------------------
    (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 exclude the risk management liabilities
        and assets and unrealized gain on investment in marketable
        securities, and includes long term investments.

    (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 form 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. Net income
through 2005 and 2006 has fluctuated primarily due to unrealized financial
instrument gains and losses on oil and gas contracts, which fluctuate with the
changes in market conditions. Net income for the six month period
June 30, 2007 fluctuated due to changes in the future tax 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
throughout the last eight quarters has allowed the Trust to maintain stable
monthly cash distributions of $0.17 per unit through August 2005 with
increases to $0.19 per unit in September and to $0.20 per unit in November
2005.

    
    Outlook

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

    -------------------------------------------------------------------------
                                         Previous Guidance  Revised Guidance
    Production
      Oil and NGL (bbls/d)                          22,416            22,917
      Natural gas (mcf/d)                           23,000            20,000
    -------------------------------------------------------------------------
    Total (boe/d)                                   26,250            26,250
    -------------------------------------------------------------------------
    Cash flow ($000)                               314,000           317,000
    Cash flow per unit - diluted ($)                  3.11              3.17
    Cash distributions per unit ($)                   2.40              2.40
    Payout ratio - per unit - diluted (%)               77                76
    -------------------------------------------------------------------------
    Capital expenditures ($000)(1)                 150,000           150,000
    Wells drilled, net                                 110               110
    -------------------------------------------------------------------------
    Pricing
      Crude oil - WTI (US$/bbl)                      60.00             67.00
      Crude oil - WTI (Cdn$/bbl)                     70.59             73.63
      Natural gas - Corporate (Cdn$/mcf)              7.50              6.75
      Exchange rate (US$/Cdn$)                        0.85              0.91
    -------------------------------------------------------------------------
    (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
    (UNAUDITED)($000)                       June 30, 2007  December 31, 2006
    -------------------------------------------------------------------------
    ASSETS
      Current assets
        Cash                                          528                205
        Accounts receivable                        71,862             53,279
        Investments in marketable
         securities (Note 2)                            -                171
        Prepaids and deposits                       3,727              4,509
        Risk management asset (Note 11)             2,524                586
    -------------------------------------------------------------------------
                                                   78,641             58,750
      Long-term investment (Note 3 (a))                 -             30,020
      Reclamation fund                              2,200              1,725
      Risk management asset (Note 11)                 469                466
      Property, plant and equipment (Note 3)    1,902,319          1,214,155
      Goodwill                                     68,350             68,350
    -------------------------------------------------------------------------
    Total assets                                2,051,979          1,373,466
    -------------------------------------------------------------------------

    LIABILITIES
      Current liabilities
        Accounts payable and accrued
         liabilities                               88,591             53,053
        Cash distributions payable                 10,872              8,598
        Bank indebtedness (Note 4)                330,070            254,438
        Risk management liability (Note 11)         8,443              7,581
    -------------------------------------------------------------------------
                                                  437,976            323,670
      Asset retirement obligation (Note 5)         59,085             45,829
      Risk management liability (Note 11)           7,286             11,697
      Future income taxes (Note 9)                152,346             85,890
    -------------------------------------------------------------------------
    Total liabilities                             656,693            467,086
    -------------------------------------------------------------------------

    UNITHOLDERS' EQUITY
      Unitholders' capital (Note 6)             1,602,457          1,045,929
      Contributed surplus (Note 7)                 14,220              9,150
      Deficit (Note 8)                           (221,391)          (148,699)
    -------------------------------------------------------------------------
    Total unitholders' equity                   1,395,286            906,380
    -------------------------------------------------------------------------
    Total liabilities and unitholders' equity   2,051,979          1,373,466
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.



    CONSOLIDATED STATEMENTS OF OPERATIONS, COMPREHENSIVE INCOME AND DEFICIT

    -------------------------------------------------------------------------
                                      Three months ended    Six months ended
    (UNAUDITED)                              June 30              June 30
    ($000, except per unit amounts)       2007      2006      2007      2006
    -------------------------------------------------------------------------
    REVENUE
      Oil and gas sales                144,179   113,790   273,059   207,166
      Royalties                        (28,023)  (25,258)  (49,767)  (45,435)
      Financial instruments
        Realized gains (losses)          1,718   (10,040)    4,363   (17,042)
        Unrealized gains (losses)
         (Note 11)                      18,785    (3,284)    3,427   (22,776)
    -------------------------------------------------------------------------
                                       136,659    75,208   231,082   121,913
    EXPENSES
      Operating                         22,477    15,104    43,867    30,212
      Transportation                     3,834     2,369     7,670     4,320
      General and administrative         4,183     2,724     8,094     5,191
      Unit-based compensation (Note 7)   4,091     1,940     7,851     3,652
      Interest on bank indebtedness
       (Note 4)                          4,853     3,107     8,971     6,646
      Depletion, depreciation and
       amortization                     57,549    34,668   112,115    65,556
      Accretion on asset retirement
       obligation (Note 5)               1,099       802     2,003     1,458
    -------------------------------------------------------------------------
                                        98,086    60,714   190,571   117,035
    -------------------------------------------------------------------------
      Income before taxes               38,573    14,494    40,511     4,878
      Capital and other taxes            4,000     2,733     7,211     5,455
      Future income tax expense
       (recovery) (Note 9)             152,346    (7,120)   (6,471)  (20,632)
    -------------------------------------------------------------------------
      Net income (loss) before
       non-controlling interest       (117,773)   18,881    39,771    20,055
      Non-controlling interest               -       379         -     2,386
    -------------------------------------------------------------------------
      Net income (loss) and
       comprehensive income for
       the period                     (117,773)   19,260    39,771    22,441
    -------------------------------------------------------------------------
      Deficit, beginning of period     (43,298)  (97,130) (148,699)  (67,369)
      Change in accounting policy
       (Note 2)                              -         -     1,468         -
      Cash distributions paid or
       declared                        (60,320)  (36,123) (113,931)  (69,065)
    -------------------------------------------------------------------------
      Deficit, end of the period
       (Note 8)                       (221,391) (113,993) (221,391) (113,993)
    -------------------------------------------------------------------------
    Net income (loss) per unit
     (Note 10)
      Basic                              (1.17)     0.32      0.43      0.40
      Diluted                            (1.17)     0.31      0.43      0.34
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.



    CONSOLIDATED STATEMENTS OF CASH FLOWS
    -------------------------------------------------------------------------
                                      Three months ended    Six months ended
                                             June 30              June 30
    (UNAUDITED)($000)                     2007      2006      2007      2006
    -------------------------------------------------------------------------
    CASH PROVIDED BY (USED IN)
     OPERATING ACTIVITIES
      Net income (loss) for the
       period                         (117,773)   19,260    39,771    22,441
      Items not affecting cash
        Non-controlling interest             -      (379)        -    (2,386)
        Future income taxes (Note 9)   152,346    (7,120)   (6,471)  (20,632)
        Unit-based compensation
         (Note 7)                        3,746     1,767     7,066     3,305
        Depletion, depreciation and
         amortization                   57,549    34,668   112,115    65,556
        Accretion on asset retirement
         obligation (Note 5)             1,099       802     2,003     1,458
        Realized gain on sale of
         investment (Note 2)            (1,402)        -    (1,402)        -
        Unrealized losses on financial
         instruments (Note 11)         (18,785)    3,284    (3,427)   22,776
        Unrealized loss on investment
         (Note 2)                        1,468         -     1,468         -
      Asset retirement expenditures
       (Note 5)                           (197)      (97)     (689)     (102)
      Change in non-cash working
       capital
        Accounts receivable             31,070    (6,055)   19,976   (14,462)
        Prepaid expenses and deposits    2,152       999       782     3,935
        Accounts payable                (8,636)    2,554   (18,379)    5,314
    -------------------------------------------------------------------------
                                       102,637    49,683   152,813    87,203
    -------------------------------------------------------------------------
    INVESTING ACTIVITIES
      Development capital and other
       expenditures                    (44,713)  (25,080)  (78,223)  (49,501)
      Capital acquisitions (Note 3)    (14,122)  (16,650)  (55,135) (298,446)
      Deposits on property, plant
       and equipment                         -    (3,800)        -    (3,800)
      Proceeds on sale of investment
       (Note 2)                          1,573         -     1,573         -
      Reclamation fund net
       contributions                      (513)     (275)     (475)   (1,619)
      Change in non-cash working
       capital
        Accounts receivable             (3,457)      307    (4,724)     (980)
        Accounts payable                15,277    (1,585)   20,570     4,849
    -------------------------------------------------------------------------
                                       (45,955)  (47,083) (116,414) (349,497)
    -------------------------------------------------------------------------
    FINANCING ACTIVITIES
      Issue of trust units, net of
       issue costs                      27,411    12,197    48,533   301,310
      Restricted unit vests                  -         -      (833)        -
      Increase in bank indebtedness    (23,586)   20,912    27,881    28,139
      Cash distributions               (60,320)  (36,123) (113,931)  (69,065)
      Change in non-cash working
       capital
        Cash distributions payable        (191)      514     2,274     2,115
    -------------------------------------------------------------------------
                                       (56,686)   (2,500)  (36,076)  262,499
    -------------------------------------------------------------------------
    INCREASE (DECREASE) IN CASH             (4)      100       323       205
    CASH AT BEGINNING OF PERIOD            532       422       205       317
    -------------------------------------------------------------------------
    CASH AT END OF PERIOD                  528       522       528       522
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements.


    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

    JUNE 30, 2007 (UNAUDITED)

    1.  SIGNIFICANT ACCOUNTING POLICIES

    These interim consolidated financial statements of Crescent Point
    Energy Trust ("the Trust") have been prepared by management in
    accordance with Canadian generally accepted accounting principles and
    follow the same accounting policies as the most recent annual audited
    financial statements, except as described below. The specific
    accounting policies used are described in the annual consolidated
    financial statements appearing on pages 49 through 51 of the Trust's
    2006 Annual Report. All amounts reported in these statements are in
    Canadian dollars.

    2.  CHANGES IN ACCOUNTING POLICIES

    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 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.

    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 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 three month
    period ended June 30, 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.

    3.  CAPITAL ACQUISITIONS

    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 $621.4 million, including assumed bank debt and
    working capital ($700.5 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
    Working capital                                                      488
    Risk management asset                                              2,063
    Property, plant and equipment                                    700,511
    Bank debt                                                        (47,751)
    Asset retirement obligation                                       (8,285)
    Future income taxes                                              (72,927)
    -------------------------------------------------------------------------
    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)  Property Acquisitions

    During the six months ended June 30, 2007, the Trust closed three
    property acquisitions for total consideration of approximately
    $19.0 million ($21.7 million was allocated to property, plant and
    equipment). The Trust recorded favorable purchase price adjustments on
    previously closed acquisitions for the six months ended June 30, 2007
    of $1.1 million.

    4.  BANK INDEBTEDNESS

    The Trust has a syndicated credit facility with seven banks and an
    operating credit with one Canadian chartered bank. On May 28, 2007, the
    amount available under the combined credit facilities was increased
    from $470.0 million to $600.0 million. The Trust has letters of credit
    in the amount of $340,000 outstanding at June 30, 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
    credit facility is secured by the oil and gas assets owned by the
    Trust's wholly owned subsidiaries.

    The cash interest paid in the in the six months ended June 30, 2007 was
    $10.6 million (2006 - $7.6 million). The cash interest paid in the
    second quarter of 2007 was $4.9 million (2006 - $2.7 million).

    5.  ASSET RETIREMENT OBLIGATION

    The following table reconciles the asset retirement obligation:

    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Asset retirement obligation, January 1, 2007                      45,829
    Liabilities incurred                                                 939
    Liabilities acquired through capital acquisitions                 11,003
    Liabilities settled                                                 (689)
    Accretion expense                                                  2,003
    -------------------------------------------------------------------------
    Asset retirement obligation, June 30, 2007                        59,085
    -------------------------------------------------------------------------

    6.  UNITHOLDERS' CAPITAL

    -------------------------------------------------------------------------
                                                        Number of     Amount
                                                      trust units      ($000)
    -------------------------------------------------------------------------
    Trust units, January 1, 2007                       69,531,952  1,083,948
    Issued on capital acquisitions                     29,178,562    506,832
    Issued on vesting of restricted units(1)               19,674        650
    Issued pursuant to the distribution
     reinvestment plans                                 2,279,047     39,997
    To be issued pursuant to the distribution
     reinvestment plans                                   490,630      9,331
    -------------------------------------------------------------------------
    Trust units, June 30, 2007                        101,499,865  1,640,758
    -------------------------------------------------------------------------
    Cumulative unit issue costs                                 -    (38,301)
    -------------------------------------------------------------------------
    Total unitholders' capital, June 30, 2007         101,499,865  1,602,457
    -------------------------------------------------------------------------
    (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.

    7.  RESTRICTED UNIT BONUS PLAN

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

    -------------------------------------------------------------------------
    Restricted units, January 1, 2007                              1,043,628
    Granted                                                          456,411
    Exercised                                                       (105,475)
    Forfeited                                                        (16,364)
    -------------------------------------------------------------------------
    Restricted units, June 30, 2007                                1,378,200
    -------------------------------------------------------------------------

    8.  DEFICIT

    The deficit balance is composed of the following items:
    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Accumulated earnings                                             182,982
    Accumulated cash distributions                                  (404,373)
    -------------------------------------------------------------------------
    Deficit                                                         (221,391)
    -------------------------------------------------------------------------

    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.

    9.  INCOME TAXES

    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 three month period ended June 30, 2007. For the six
    month period ended June 30, 2007, the Trust recorded a $6.5 million
    future tax recovery. There was no future tax liability recorded at
    March 31, 2007 as the Trust completed a reorganization into a flow
    through structure on March 1, 2007, resulting in the recovery of the
    future tax liability of $158.8 million in the first quarter of 2007.
    The future income tax liability of $152.3 million represents the
    taxable temporary differences of Crescent Point tax effected at
    31.5 percent, which is the rate that will be applicable to trusts in
    2011 under current legislation.

    The cash capital taxes paid during the six month period ended June 30,
    2007 were $7.5 million (2006 - $2.6 million). The cash capital taxes
    paid during the second quarter of 2007 were $3.9 million (2006 - $1.0
    million).

    10. PER TRUST UNIT AMOUNTS

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

    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                         June 30                 June 30
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    Weighted average trust
     units                   100,302,229  59,295,502  93,318,061  56,139,248
    -------------------------------------------------------------------------
    Trust units issuable
     on conversion of
     exchangeable shares(1)            -   1,384,367           -   1,384,367
    Dilutive impact of
     restricted units          1,378,354     691,646   1,329,990     675,685
    -------------------------------------------------------------------------
    Dilutive trust units
     and exchangeable
     shares(1)               101,680,583  61,371,515  94,648,051  58,199,300
    -------------------------------------------------------------------------
    (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.

    11. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

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

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

    The following is a summary of the financial instrument contracts in place
    as at June 30, 2007:

    -------------------------------------------------------------------------
    Financial WTI
    Crude Oil Contracts -
     Canadian Dollar
                                    Average    Average    Average    Average
                                       Swap     Bought       Sold        Put
                          Volume      Price  Put Price Call Price    Premium
    Term       Contract  (bbls/d) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl)
    -------------------------------------------------------------------------
    2007
    July -
     September     Swap    1,500      71.68
    July -
     December      Swap    3,500      75.58
    October -
     December      Swap    1,500      73.22
    July -
     September   Collar      250                 68.00      81.28
    July -
     December    Collar    1,250                 67.09      81.52
    October -
     December    Collar      250                 65.00      86.00
    July -
     December       Put    3,250                 77.63                 (7.65)
    -------------------------------------------------------------------------
    2007 Weighted
     Average               9,750      74.64      74.27      81.87      (7.65)
    -------------------------------------------------------------------------
    2008
    January -
     June          Swap    1,000      72.73
    January -
     September     Swap      250      68.10
    January -
     December      Swap    3,750      76.04
    July -
     December      Swap    1,000      73.52
    October -
     December      Swap      250      70.80
    January -
     June        Collar      250                 65.00      82.00
    January -
     December    Collar    1,500                 70.00      83.93
    July -
     December    Collar      250                 70.00      91.00
    January -
     December       Put    3,250                 72.34                 (6.63)
    -------------------------------------------------------------------------
    2008 Weighted
     Average              10,000      75.09      71.40      84.30      (6.63)
    -------------------------------------------------------------------------
    2009
    January -
     March         Swap    2,750      77.68
    January -
     June          Swap    1,250      74.99
    April -
     June          Swap    2,750      77.58
    July -
     September     Swap    3,000      74.07
    July -
     December      Swap    1,000      76.41
    October -
     December      Swap    3,000      74.37
    January -
     March       Collar      250                 75.00      87.00
    January -
     June        Collar    1,250                 70.00      81.01
    January -
     September   Collar      250                 70.00      79.00
    April -
     June        Collar      250                 75.00      83.00
    July -
     September   Collar      250                 70.00      84.05
    July -
     December    Collar    1,250                 69.00      80.37
    October -
     December    Collar      500                 70.00      85.93
    January -
     December       Put      750                 70.97                 (7.00)
    -------------------------------------------------------------------------
    2009 Weighted
     Average               6,500      75.78      70.29      81.31      (7.00)
    -------------------------------------------------------------------------
    2010
    January -
     March         Swap    3,500      76.22
    -------------------------------------------------------------------------
    2010 Weighted
     Average               1,740      76.22
    -------------------------------------------------------------------------


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



    -------------------------------------------------------------------------
    Financial AECO Natural Gas
     Contracts - Canadian Dollar                          Average    Average
                                                           Bought       Sold
                                                Volume  Put Price Call Price
    Term                           Contract      (GJ/d)  ($Cdn/GJ)  ($Cdn/GJ)
    -------------------------------------------------------------------------
    2007
    July - October                   Collar      4,000       6.75       8.60
    -------------------------------------------------------------------------
    2007 Weighted Average                        2,674       6.75       8.60
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Financial Foreign Exchange
     Contracts - U.S. Dollar                                         Average
                                                           Volume       Swap
    Term                                      Contract       ($US) ($Cdn/$US)
    -------------------------------------------------------------------------
    2007
    July - December                               Swap  5,980,000     1.1600
    July - December                               Swap  6,440,000     1.1012
    -------------------------------------------------------------------------
    2007 Weighted Average                              12,420,000     1.1295
    -------------------------------------------------------------------------


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


    -------------------------------------------------------------------------
    Financial Power Contracts -
     Canadian Dollar                                                   Fixed
                                                          Volume        Rate
    Term                                      Contract     (MW/h) ($Cdn/MW/h)
    -------------------------------------------------------------------------
    July 2007 - December 2008                     Swap       3.0       63.25
    July 2007 - December 2009                     Swap       1.0       82.45
    January 2009 - December 2009                  Swap       3.0       81.25
    -------------------------------------------------------------------------

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

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

    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Risk management asset, January 1, 2007                             1,052
    Acquired through capital acquisitions                              2,063
    Unrealized mark-to-market loss                                      (122)
    -------------------------------------------------------------------------
    Risk management asset, June 30, 2007                               2,993
    Less: current risk management asset, June 30, 2007                (2,524)
    -------------------------------------------------------------------------
    Long term risk management asset, June 30, 2007                       469
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                                       ($000)
    -------------------------------------------------------------------------
    Risk management liability, January 1, 2007                        19,278
    Unrealized mark-to-market gain                                    (3,549)
    -------------------------------------------------------------------------
    Risk management liability, June 30, 2007                          15,729
    Less: current risk management liability, June 30, 2007            (8,443)
    -------------------------------------------------------------------------
    Long term risk management liability, June 30, 2007                 7,286
    -------------------------------------------------------------------------

    12. 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 Ltd.
    Hugh Gillard(1)(2)(3)                     Calgary, Alberta

    Gerald Romanzin(1)(5)                     Sproule Associates Ltd.
                                              Calgary, Alberta
    Scott Saxberg(4)
                                              Registrar and Transfer Agent
    Greg Turnbull(2)(5)
                                              Investors are encouraged to
    (1) Member of the Audit Committee of the  contact Crescent Point's
        Board of Directors                    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
        the Board of Directors                Olympia Trust Company
    (4) Member of the Health, Safety and      2300, 125 - 9 Avenue SE
        Environment Committee of the Board    Calgary, Alberta T2G 0P6
        of Directors                          Tel: (403) 261-0900
    (5) Member of the Corporate Governance
        Committee                             Stock Exchange

    Officers                                  Toronto Stock Exchange - TSX

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

    Dave Balutis                              Greg Tisdale
    Vice President, Geosciences               Chief Financial Officer
                                              (403) 693-0020

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

    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
    

    %SEDAR: 00019829E




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

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Crescent Point Energy Corp.

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