Peyto Energy Trust announces second quarter 2007 results



    SYMBOL: PEY.UN - TSX

    CALGARY, Aug. 8 /CNW/ - Peyto Energy Trust ("Peyto") is pleased to
present the operating and financial results for the second quarter of the 2007
fiscal year. Peyto is a conventional oil and gas business that designs, drills
and builds high quality, tight gas assets located in Alberta's premier gas
exploration area, the Deep Basin.
    Peyto is well known for its long reserve life gas assets with low
operating costs and high revenue per boe. The following summarizes the Trust's
foundation.

    
    -   Long reserve life - Proved 14 years, Proved plus Probable 20 years
        from the end of 2006
    -   Low operating costs - $2.70/boe, three months ending June 30, 2007
    -   Low base general and administrative costs - $1.10/boe, three months
        ending June 30, 2007
    -   High revenue per boe - $51.13/boe, before hedging, $53.98/boe, after
        hedging, three months ending June 30, 2007
    -   High field netback - $41.21/boe, three months ending June 30, 2007
    -   High operatorship - we operate over 95% of our production
    -   Low cash distribution payout ratio - cash distributions were 64% of
        funds from operations for the three months ended June 30, 2007
    -   Low debt to funds from operations ratio - 1.5 (net debt, before
        provision for future compensation, divided by annualized second
        quarter 2007 funds from operations)
    -   Distribution growth - distributions have been increased 5 times,
        never decreased and are now 87% higher than when the trust was formed
        in July 2003
    -   Since inception, Peyto has raised a total of $406 million issuing
        units from treasury, accumulated earnings of $627 million, and
        distributed $534 million to unitholders
    -   Transparent capital structure - no convertible debentures, no
        exchangeable shares, no stock options, no warrants

    The second quarter was highlighted by strong commodity prices, sustained
distributions and increased financial flexibility from a disciplined capital
investment strategy. The following summarizes performance highlights of the
business for the second quarter of 2007.

    -   Capital expenditures - $12.9 million was invested into finding and
        developing new natural gas reserves in the quarter, an 81% reduction
        from Q2 2006. Capital expenditures for the first half of 2007 were
        $43 million versus $212 million for the first half of 2006, a
        reduction of 79%
    -   Production - decreased 10% from 22,892 boe/d in the second quarter of
        2006 to 20,509 boe/d in the second quarter of 2007
    -   Production per unit - decreased 15% per trust unit from the second
        quarter of 2006, after adjusting for debt and future unrealized
        performance based compensation
    -   Per unit funds from operations - decreased 11% from the previous year
        to $0.66/unit
    -   Strong commodity prices - Natural gas prices, both before and after
        hedging, were stronger in Q2 2007 with prices averaging $8.59/mcf and
        $8.10/mcf respectively versus $7.96/mcf and $6.80/mcf in Q2 2006
    -   Hedging - we had a $5.3 million gain for the second quarter versus a
        $16.3 million gain in the first quarter of 2007 based on financial
        instruments
    -   Distributions per unit were unchanged from the second quarter of 2006
        while the cash payout ratio increased to 64% from 57% in Q2 2006. A
        total of $44.4 million or $0.42 per unit was distributed to
        unitholders in the second quarter of 2007
    -   Net debt decreased $12 million from the first quarter of 2007 to
        $415 million. This decrease combined with increased bank lines to
        $525 million resulted in an increase in available debt capacity from
        $50 million in Q2 2006 to $110 million in Q2 2007

    Natural gas volumes recorded in thousand cubic feet (mcf) are converted to
barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic feet
to one (1) barrel of oil (bbl).


    -------------------------------------------------------------------------
                       3 Months Ended                 6 Months Ended
                            June 30       %                June 30       %
                       2007        2006 Change        2007        2006 Change
    -------------------------------------------------------------------------
    Operations
    Production
      Natural gas
       (mcf/d)      101,812     112,484   (9)%     103,986     111,685   (7)%
      Oil & NGLs
       (bbl/d)        3,540       4,145  (15)%       3,574       4,144  (14)%
      Barrels of
       oil
       equivalent
       (boe/d @
       6:1)          20,509      22,892  (10)%      20,904      22,758   (8)%
    Product prices
      Natural gas
       ($/mcf)         8.59        7.96     8%        9.19        8.60     7%
      Oil & NGLs
       ($/bbl)        65.65       66.94   (2)%       62.71       62.06     1%
    Operating
     expenses
     ($/boe)           2.70        2.26    19%        2.77        2.03    36%
    Transportation
     ($/boe)           0.57        0.59   (3)%        0.58        0.61   (5)%
    Field netback
     ($/boe)          41.21       39.64     4%       43.04       40.39     7%
    General &
     administrative
     expenses
     ($/boe)           1.10        0.43   156%        1.04        0.25   316%
    Interest
     expense
     ($/boe)           2.95        2.00    48%        2.96        1.69    75%

    Financial
     ($000, except
     per unit)
    Revenue         100,750     106,751   (6)%     213,576     220,468   (3)%
    Royalties
     (net of
     ARTC)           17,734      18,236   (3)%      38,060      45,494  (16)%
    Funds from
     operations      69,345      77,507  (11)%     147,709     156,124   (5)%
    Funds from
     operations
     per unit          0.66        0.74  (11)%        1.40        1.50   (7)%
    Total
     distributions   44,399      43,921     1%      88,750      85,439     4%
    Total
     distributions
     per unit          0.42        0.42     0%        0.84        0.82     2%
      Payout ratio       64          57    12%          60          55     9%
    Cash
     distributions
     (net of DRIP)   44,399      38,315    16%      88,750      72,980    22%
      Payout ratio       64          49    31%          60          47    28%
    Earnings         38,825      56,768  (32)%      95,709     102,061   (6)%
    Earnings per
     diluted unit      0.37        0.54  (31)%        0.91        0.98   (7)%
    Capital
     expenditures    12,949      67,195  (81)%      43,426     212,289  (80)%
    Weighted
     average
     trust units
     out-
     standing   105,712,364 104,472,570     1% 105,670,476 104,333,091     1%

    As at June 30
    Net debt
     (before future
     compensation
     expense)                                      415,266     399,963
    Unitholders'
     equity                                        514,651     467,978
    Total assets                                 1,150,589   1,073,338



    -------------------------------------------------------------------------
                                        3 Months Ended      6 Months Ended
                                            June 30             June 30
                                        2007      2006      2007      2006
    -------------------------------------------------------------------------
    Net Earnings                        38,825    56,768    95,709   102,061
    Items not requiring cash:
      Non-cash provision for
       (recovery of) performance
       based compensation                  431    (2,626)      438     2,196
      Future income tax expense         11,326     2,878    12,965    11,556
      Depletion, depreciation
       and accretion                    18,763    20,487    38,597    40,311
    -------------------------------------------------------------------------
    Funds from operations(1)            69,345    77,507   147,709   156,124
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Funds from operations
    

    Management uses funds from operations to analyze the operating
performance of its energy assets. In order to facilitate comparative analysis,
funds from operations is defined throughout this report as earnings before
performance based compensation, non-cash and non-recurring expenses. We
believe that funds from operations is an important parameter to measure the
value of an asset when combined with reserve life. Funds from operations is
not a measure recognized by Canadian generally accepted accounting principles
("GAAP") and does not have a standardized meaning prescribed by GAAP.
Therefore, funds from operations, as defined by Peyto, may not be comparable
to similar measures presented by other issuers, and investors are cautioned
that funds from operations should not be construed as an alternative to net
earnings, cash flow from operating activities or other measures of financial
performance calculated in accordance with GAAP. Funds from operations cannot
be assured and future distributions may vary.

    Quarterly Review

    For the second quarter, Peyto maintained its disciplined strategy of
reduced capital investments, while awaiting lower service costs and improved
rates of return. As a result, the $12.9 million of capital that was invested
in the quarter into building new gas assets was 81% less than the
$67.2 million invested in Q2 2006. For the third quarter in a row, cash flow
has exceeded the total of the distributions and capital expenditures,
improving financial flexibility. Despite the reduced capital program, Peyto
continues to maintain a large and growing inventory of drill-ready
opportunities and remains poised to execute on them when a more favorable cost
environment returns.

    
    -------------------------------------------------------------------------
                                               2007                2006
    $ millions                             Q2        Q1        Q4        Q3
    -------------------------------------------------------------------------

    Funds from operations                 69.3      78.4      77.4      72.4
    Distributions                        (44.4)    (44.4)    (44.2)    (44.1)
    Capital Expenditures                 (12.9)    (30.5)    (28.4)    (71.2)

    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total                                 12.0       3.5       4.7     (43.0)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                               2006                2005
    $ millions                             Q2        Q1        Q4        Q3
    -------------------------------------------------------------------------

    Funds from operations                 77.5      78.6      86.6      77.2
    Distributions                        (43.9)    (41.5)    (36.8)    (35.5)
    Capital Expenditures                 (67.2)   (145.1)   (107.6)    (93.0)

    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total                                 (33.6)  (108.0)    (57.8)    (51.3)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Peyto drilled 6 gross (5.2 net) wells, completed 6 gross (6.0 net) gas
zones and brought 10 gross (8.1 net) zones on-stream in the quarter.
Approximately 70% of the capital was invested in the month of June due to an
extended spring breakup. Average production declined from 21,305 boe/d in the
first quarter to 20,509 boe/d in the second quarter of 2007 as this reduced
level of activity did not fully replace natural declines.
    Operating costs were $2.70/boe for the second quarter, up 19% from the
previous year but down 15% from $2.84/boe in Q1 2007. Gains were made in
certain cost categories such as utilities and chemicals (methanol), where both
consumption and price fell, contributing to the reduction from the prior
quarter. Average operating costs for the first six months of 2007 were
$2.77/boe.
    Peyto achieved a natural gas price of $8.59/mcf and an oil and natural
gas liquids price of $65.65/bbl in the second quarter, after hedging gains.
Royalties for Q2 2007 averaged 17.6% or $9.50/boe. These second quarter prices
combined with low royalties and Peyto's industry leading operating costs
yielded field netbacks of $41.21/boe, which were 4% higher than a year ago.

    Activity Update

    To date in 2007, Peyto has drilled 27 gross (20.5 net) wells and brought
on production 29 gross (21.4 net) zones. Drilling and completion operations,
which re-commenced later than expected in mid-June following spring breakup,
have since been steady with three to four drilling rigs operating in the
Greater Sundance and Chime/Cutpick areas. Chime volumes, which were being
produced intermittently through third party processing, have reached a
critical mass that now warrants an investment in a pipeline to connect them to
the Peyto Kakwa gas plant. This pipeline connection will result in a
significant operating cost reduction and firmer processing capacity for these
volumes, and is anticipated to be operational in the fourth quarter of 2007.
Material decreases in service costs continue to be observed with average
drilling costs declining 25% from a year ago. This decrease, combined with
reductions in other areas like completions and pipelines, means the return on
invested capital is improving.

    Marketing

    Peyto's natural gas price before hedging was $8.10/mcf in the second
quarter of 2007, an increase of 19% from $6.80/mcf in Q2 2006 but down from
$8.17/mcf in Q1 2007. Oil and natural gas liquids prices, before hedging,
averaged $63.19/boe, down 8% from the equivalent period in 2006 but up from
$56.82 in Q1 2007. Forward sales for the second quarter 2007 increased the
achieved natural gas price by $0.49/mcf and the oil and natural gas liquids
price by $2.46/bbl for a combined $2.85/boe.
    As at June 30, 2007, the Trust had committed to the future sale of
13,010,000 gigajoules (GJ) of natural gas at an average price of $8.17/GJ or
$9.55/mcf based on the historical high heat content of Peyto's gas, and
146,700 bbls of crude oil at an average price of $80.72/bbl. Had these
contracts been closed on June 30, 2007, the Trust would have realized a gain
in the amount of $21.9 million.

    Outlook

    The financial and operational discipline that Peyto has employed over the
last year is paying off. It is becoming easier to build upon the base asset as
production declines stabilize. Service costs have decreased significantly,
improving the rate of return on future capital investments. The marketing
strategy has protected against soft short term gas prices, while longer term
prices remains strong, as does the value of our long reserve life asset base.
With the slowdown in industry activity, opportunities to add to Peyto's
inventory of top quality drilling locations have become more abundant. As
always, the ability to generate solid returns on capital invested will come
from Peyto's technical expertise and the efficient execution of ideas.
Unitholders, both current and future, are encouraged to visit the Peyto
website at www.Peyto.com where there is a wealth of information designed to
educate and inform.

    Conference Call and Webcast

    A conference call will be held with the senior management of Peyto to
answer questions with respect to the 2007 second quarter results on Thursday,
August 9, 2007 at 9:00 a.m. Mountain Standard Time (MST), 11:00 a.m. Eastern
Standard Time (EST). To participate, please call 1-416-644-3419 (Toronto area)
or 1-866-249-1964 for all other participants. The conference call will also be
available on replay by calling 1-416-640-1917 (Toronto area) or 1-877-289-8525
for all other parties, using passcode 21239197 followed by the pound key. The
replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday, August 9,
2007 until midnight EST on Thursday, August 16, 2007. The conference call can
also be accessed through the internet at
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=1916420.

    Darren Gee
    President and Chief Executive Officer
    August 8, 2007

    Certain information set forth in this document and Management's
Discussion and Analysis, including management's assessment of Peyto's future
plans and operations, contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and uncertainties,
some of which are beyond these parties' control, including the impact of
general economic conditions, industry conditions, volatility of commodity
prices, currency fluctuations, imprecision of reserve estimates, environmental
risks, competition from other industry participants, the lack of availability
of qualified personnel or management, stock market volatility and ability to
access sufficient capital from internal and external sources. Readers are
cautioned that the assumptions used in the preparation of such information,
although considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on forward-looking
statements. Peyto's actual results, performance or achievement could differ
materially from those expressed in, or implied by, these forward-looking
statements and, accordingly, no assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or occur, or if
any of them do so, what benefits Peyto will derive therefrom. Peyto disclaims
any intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or
otherwise.


    Management's discussion and analysis

    This Management's Discussion and Analysis ("MD&A") 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 of Peyto Energy Trust ("Peyto") for the year ended December 31,
2006. The consolidated financial statements have been prepared in accordance
with Canadian generally accepted accounting principles ("GAAP").
    The Trust was created by way of a Plan of Arrangement effective July 1,
2003 which reorganized Peyto Exploration & Development Corp. ("PEDC") from a
corporate entity into a trust. Accordingly, the consolidated financial
statements were reported on a continuity of interests basis. This discussion
provides management's analysis of Peyto's historical financial and operating
results and provides estimates of Peyto's future financial and operating
performance based on information currently available. Actual results will vary
from estimates and the variances may be significant. Readers should be aware
that historical results are not necessarily indicative of future performance.
This MD&A was prepared using information that is current as of August 7, 2007.
Additional information about Peyto, including the most recently filed annual
information form is available at www.sedar.com.

    Certain information set forth in this Management's Discussion and
Analysis, including management's assessment of the Trust's future plans and
operations, contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and uncertainties,
some of which are beyond these parties' control, including the impact of
general economic conditions, industry conditions, volatility of commodity
prices, currency fluctuations, imprecision of reserve estimates, environmental
risks, competition from other industry participants, the lack of availability
of qualified personnel or management, stock market volatility and ability to
access sufficient capital from internal and external sources. Readers are
cautioned that the assumptions used in the preparation of such information,
although considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on forward-looking
statements. Peyto's actual results, performance or achievement could differ
materially from those expressed in, or implied by, these forward-looking
statements and, accordingly, no assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or occur, or if
any of them do so, what benefits that Peyto will derive there from. Peyto
disclaims any intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or
otherwise.

    Management uses funds from operations to analyze the operating
performance of its energy assets. In order to facilitate comparative analysis,
funds from operations is defined throughout this report as earnings before
performance based compensation, non-cash and non-recurring expenses. We
believe that funds from operations is an important parameter to measure the
value of an asset when combined with reserve life. Funds from operations is
not a measure recognized by Canadian generally accepted accounting principles
("GAAP") and does not have a standardized meaning prescribed by GAAP.
Therefore, funds from operations, as defined by Peyto, may not be comparable
to similar measures presented by other issuers, and investors are cautioned
that funds from operations should not be construed as an alternative to net
earnings, cash flow from operating activities or other measures of financial
performance calculated in accordance with GAAP. Funds from operations cannot
be assured and future distributions may vary.
    To the best of our knowledge, Peyto's foreign ownership level currently
stands at approximately 30 percent, well below the level that would jeopardize
Peyto's status as a mutual fund trust under current or proposed legislation.

    All references are to Canadian dollars unless otherwise indicated.
Natural gas volumes recorded in thousand cubic feet (mcf) are converted to
barrels of oil equivalent (boe) using the ratio of six (6) thousand cubic feet
to one (1) barrel of oil (bbl).

    Federal Government's Trust Tax Legislation

    On June 12, 2007, Bill C-52 ("Bill") was enacted for Canadian GAAP. The
Bill enacts the October 31, 2006 proposals to impose a new tax on
distributions from flow-through entities, including publicly traded income
trusts. This has not resulted in any change in the consolidated future income
tax calculation.
    Under this Bill, existing income trusts will be subject to the new
measures commencing in their 2011 taxation year, following a four-year grace
period. In simplified terms, under the proposed tax plan, income distributions
will first be taxed at the trust level at a special rate estimated to be
31.5%. Income distributions to individual unitholders will then be treated as
dividends from a Canadian corporation and eligible for the dividend tax
credit. Income distributions to corporations resident in Canada will be
eligible for full deduction as tax free intercorporate dividends. Tax-deferred
accounts (RRSPs, RRIFs and Pension Plans) will continue to pay no tax on
distributions. Non-resident unitholders will be taxed on distributions at the
non-resident withholding tax rate for dividends. The net impact on Canadian
taxable investors is expected to be minimal because they can take advantage of
the dividend tax credit. However, as a result of the 31.5% Distribution Tax at
the trust level, distributions to tax-deferred accounts will be reduced by
approximately 31.5%, and distributions to non-residents will be reduced by
approximately 26.5%. Peyto is currently assessing the proposals and the
potential implications to the Trust. Structural alternatives will continue to
be reviewed to ensure that Peyto's structure is as efficient as possible.

    Climate Change Programs

    On March 8, 2007, the Alberta government introduced legislation to reduce
greenhouse gas emission intensity. Bill 3 states that facilities emitting more
than 100,000 tonnes of greenhouse gases per year must reduce their emissions
intensity by 12 per cent over the average emissions levels of 2003, 2004 and
2005; if they are not able to do so, these facilities will be required to pay
$15 per tonne for every tonne above the 12 per cent target, beginning on
July 1, 2007. At this time, the Trust has determined that there is currently
no impact of this legislation on Peyto's existing facilities ownership.
    In April 2007, the Federal Government announced a new climate change plan
that calls for greenhouse gas emissions to be reduced by 20 per cent below
current levels by 2020. Firms may employ the following strategies to achieve
the targets. They will be able to:

    
    -   make in-house reductions;
    -   take advantage of domestic emissions trading;
    -   purchase offsets;
    -   use the Clean Development Mechanism under the Kyoto Protocol; and,
    -   invest in a technology fund.
    

    The Trust is waiting for additional information so as to fully assess
what impact, if any, this new legislation will have on our operations.

    United States Proposed Changes to Qualifying Dividends

    A bill was introduced into United States Congress on March 23, 2007 that
could deny qualified dividend income treatment to the distributions made by
the Trust to its U.S. unitholders. The bill is in the first step of the
legislative process and it is uncertain whether it will eventually be passed
into law in its current form. If the bill is passed in its current form,
distributions received by U.S. unitholders would no longer qualify for the
15 per cent qualified dividend tax rate.

    OVERVIEW

    Peyto is a Canadian energy trust involved in the development and
production of natural gas in Alberta's deep basin. As at December 31, 2006,
the total proved plus probable reserves were 163.5 million barrels of oil
equivalent with a reserve life of 20 years as evaluated by the independent
petroleum engineers. Production is weighted approximately 83% natural gas and
17% natural gas liquids and oil.
    The Peyto model is designed to deliver growth in its value, assets,
production and income, all on a per unit basis. The model is built around
three key principles:

    
    -   Use technical expertise to achieve the best return on capital
        employed, through the development of internally generated drilling
        projects.
    -   Maintain a low payout ratio designed to efficiently fund a growing
        inventory of drilling projects.
    -   Build an asset base which is made up of high quality long life
        natural gas reserves.
    

    Operating results over the last eight years indicate that these
principles have been successfully implemented. This business model makes Peyto
a truly unique energy trust.


    
    QUARTERLY FINANCIAL INFORMATION
    -------------------------------------------------------------------------
                                               2007                2006
    ($000 except per unit amounts)         Q2        Q1        Q4        Q3
    -------------------------------------------------------------------------
    Total revenue (net of  royalties)   83,017    92,499    91,425    84,164
    Funds from operations               69,345    78,364    77,360    72,360
      Per unit - basic                    0.66      0.74      0.74      0.69
      Per unit - diluted                  0.66      0.74      0.74      0.69
    Earnings (loss)                     38,825    56,883    47,012    46,155
      Per unit - basic                    0.37      0.54      0.44      0.44
      Per unit - diluted                  0.37      0.54      0.44      0.44
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                               2006                2005
    ($000 except per unit amounts)         Q2        Q1        Q4        Q3
    -------------------------------------------------------------------------
    Total revenue (net of  royalties)   88,515    86,459    94,111    84,912
    Funds from operations               77,507    78,617    86,607    77,179
      Per unit - basic                    0.74      0.76      0.85      0.78
      Per unit - diluted                  0.74      0.76      0.85      0.78
    Earnings (loss)                     56,768    45,293    60,745    37,702
      Per unit - basic                    0.54      0.44      0.60      0.38
      Per unit - diluted                  0.54      0.44      0.60      0.38
    -------------------------------------------------------------------------

    RESULTS OF OPERATIONS

    Production
    -------------------------------------------------------------------------
                                      Three Months Ended   Six Months Ended
                                            June 30             June 30
                                        2007      2006      2007      2006
    -------------------------------------------------------------------------
    Natural gas (mmcf/d)                 101.8     112.5     104.0     111.7
    Oil & natural gas liquids (bbl/d)    3,540     4,145     3,574     4,144
    Barrels of oil equivalent (boe/d)   20,509    22,892    20,904    22,758
    -------------------------------------------------------------------------

    Natural gas production averaged 101.8 mmcf/d in the second quarter of
2007, 9 percent lower than the 112.5 mmcf/d reported for the same period in
2006. Oil and natural gas liquids production averaged 3540 bbl/d, a decrease
of 15 percent from 4,145 bbl/d reported in the prior year. Second quarter
production decreased 10 percent from 22,892 boe/d to 20,509 boe/d. The
production decreases are attributable to Peyto's reduced drilling program and
natural resource declines.

    Commodity Prices
    -------------------------------------------------------------------------
                                      Three Months Ended   Six Months Ended
                                            June 30             June 30
                                        2007      2006      2007      2006
    -------------------------------------------------------------------------
    Natural gas ($/mcf)                   8.10      6.80      8.14      8.22
    Hedging - gas ($/mcf)                 0.49      1.16      1.05      0.38
    -------------------------------------------------------------------------
    Natural gas - after hedging ($/mcf)   8.59      7.96      9.19      8.60
    -------------------------------------------------------------------------

    Oil and natural gas liquids($/bbl)   63.19     69.03     60.00     65.41
    Hedging - oil ($/bbl)                 2.46     (2.09)     2.71     (3.36)
    -------------------------------------------------------------------------
    Oil and natural gas liquids
     - after hedging ($/bbl)             65.65     66.94     62.71     62.05
    -------------------------------------------------------------------------
    Total Hedging ($/boe)                 2.85      5.32      5.72      1.27
    -------------------------------------------------------------------------

    Peyto's natural gas price before hedging gains averaged $8.10/mcf during
the second quarter of 2007, an increase of 19 percent from $6.80/mcf reported
for the equivalent period in 2006. Oil and natural gas liquids prices before
hedging gains averaged $63.19/bbl down 8 percent from $69.03/bbl a year
earlier. Hedging activity for the second quarter of 2007 accounted for
$2.85/boe of Peyto's price achieved.

    Revenue
    -------------------------------------------------------------------------
                                      Three Months Ended   Six Months Ended
                                            June 30             June 30
    ($000)                              2007      2006      2007      2006
    -------------------------------------------------------------------------
    Natural gas                         75,078    69,635   153,113   166,153
    Oil and natural gas liquids         20,358    26,036    38,805    49,064
    Hedging gain (loss)                  5,314    11,080    21,658     5,251
    -------------------------------------------------------------------------
    Total revenue                      100,750   106,751   213,576   220,468
    -------------------------------------------------------------------------

    For the three months ended June 30, 2007, gross revenue decreased
6 percent to $100.8 million from $106.8 million for the same period in 2006. 
The decrease in revenue for the period was a result of decreased production
volumes as detailed in the following table:

    -------------------------------------------------------------------------
                              Three Months ended        Six Months ended
                                    June 30                  June 30
                             2007   2006  $million    2007   2006  $million
    -------------------------------------------------------------------------
    Total Revenue,
     June 30, 2006                            106.8                    220.5
    -------------------------------------------------------------------------
      Revenue change due to:
    -------------------------------------------------------------------------
        Natural gas
          Volume (mmcf)      9,265  10,236     (7.7) 18,821  20,215    (12.0)
          Price ($/mcf)      $8.59   $7.96      5.8   $9.19   $8.60     11.1
       Oil & NGL
          Volume (mbbl)        322     377     (3.7)    647     750     (6.4)
          Price ($/bbl)     $65.65  $59.79     (0.4) $62.71  $62.06      0.4
    -------------------------------------------------------------------------
    Total Revenue,
     June 30, 2007                            100.8                    213.6
    -------------------------------------------------------------------------

    Royalties

    Royalties are paid to the owners of the mineral rights with whom leases
are held, including the provincial government of Alberta. Alberta gas crown
royalties are invoiced on the Crown's share of production based on a monthly
established Alberta Reference Price. The Alberta Reference Price is a monthly
weighted average price of gas consumed in Alberta and gas exported from
Alberta reduced for transportation and marketing allowances.

    -------------------------------------------------------------------------
                                      Three Months Ended   Six Months Ended
                                            June 30             June 30
    ($000 except per unit amounts)      2007      2006      2007      2006
    -------------------------------------------------------------------------
    Royalties                           17,734    18,361    38,060    45,744
    ARTC                                     -      (125)        -      (250)
    -------------------------------------------------------------------------
                                        17,734    18,236    38,060    45,494
    -------------------------------------------------------------------------
    % of sales                            17.6      17.2      17.8      20.7
    $/boe                                 9.50      8.75     10.06     10.47
    -------------------------------------------------------------------------
    

    For the second quarter of 2007, royalties averaged $9.50/boe or
approximately 17.6 percent of Peyto's total petroleum and natural gas sales.
The royalty rate expressed as a percentage of sales, will fluctuate from
period to period due to the fact that the Alberta Reference Price can differ
significantly from the commodity prices obtained by the Trust and that hedging
gains and losses are not subject to royalties. As average per well production
rate declines, the associated effective Crown Royalty rate will decrease. In
addition, Peyto receives Deep Gas Royalty Holiday or Marginal Deep Gas Well
Program benefits which further decrease our crown royalty rate. Effective
January 1, 2007, the Alberta Government discontinued the Alberta Royalty Tax
Credit ("ARTC") program.

    Operating Costs & Transportation

    The Trust's operating expenses include all costs with respect to
day-to-day well and facility operations. Processing and gathering income
related to joint venture and third party gas reduces operating expenses.

    
    -------------------------------------------------------------------------
                                      Three Months Ended   Six Months Ended
                                            June 30             June 30
                                        2007      2006      2007      2006
    -------------------------------------------------------------------------
    Operating costs ($000)
    Field expenses                       7,714     6,252    14,821    11,260
    Processing and gathering income     (2,676)   (1,546)   (4,345)   (2,878)
    -------------------------------------------------------------------------
    Total operating costs                5,038     4,706    10,476     8,382
    -------------------------------------------------------------------------
    $/boe                                 2.70      2.26      2.77      2.03
    -------------------------------------------------------------------------

    Transportation                       1,071     1,237     2,200     2,511
    -------------------------------------------------------------------------
    $/boe                                 0.57      0.59      0.58      0.61
    -------------------------------------------------------------------------
    

    Operating costs were $5.0 million in the second quarter of 2007 compared
to $4.7 million during the same period a year earlier. Transportation expense
remained relatively constant and was lower on a per boe basis. On a
unit-of-production basis, operating costs averaged $2.70/boe in the second
quarter of 2007 compared to $2.26/boe for the second quarter of 2006.

    Netbacks

    Field netbacks represent the profit margin associated with the production
and sale of petroleum and natural gas. The primary factors that produce
Peyto's strong netbacks are a low cost structure and the high heat content of
the natural gas that results in higher commodity prices.

    
    -------------------------------------------------------------------------
                                      Three Months Ended   Six Months Ended
                                            June 30             June 30
    ($/boe)                             2007      2006      2007      2006
    -------------------------------------------------------------------------
    Sale Price                           53.98     51.24     56.45     53.50
    Less:
      Royalties                           9.50      8.75     10.06     10.47
      Operating costs                     2.70      2.26      2.77      2.03
      Transportation                      0.57      0.59      0.58      0.61
    -------------------------------------------------------------------------
    Field netback                        41.21     39.64     43.04     40.39
    General and administrative            1.10      0.43      1.04      0.25
    Interest on long-term debt            2.95      2.00      2.96      1.69
    Cash netback                         37.16     37.20     39.04     38.45
    -------------------------------------------------------------------------


    General and Administrative Expenses
    -------------------------------------------------------------------------
                                      Three Months Ended   Six Months Ended
                                            June 30             June 30
                                        2007      2006      2007      2006
    -------------------------------------------------------------------------
    G&A expenses ($000)                  2,522     2,362     5,059     4,415
    Overhead recoveries                   (461)   (1,473)   (1,114)   (3,400)
    -------------------------------------------------------------------------
    Net G&A expenses                     2,061       889     3,945     1,015
    -------------------------------------------------------------------------
    $/boe                                 1.10      0.43      1.04      0.25
    -------------------------------------------------------------------------

    General and administrative expenses before overhead recoveries increased
6% from $2.4 million in the second quarter of 2006 to $2.5 million for the
same period in 2007. Net of overhead recoveries associated with the capital
expenditures program, general and administrative costs increased to
$1.10 per boe in the second quarter of 2007 from $0.43 per boe in the second
quarter of 2006. Second quarter 2007 overhead recoveries were 69% lower than
second quarter 2006 recoveries due to the reduction in capital expenditures.

    Interest Expense
    -------------------------------------------------------------------------
                                      Three Months Ended   Six Months Ended
                                            June 30             June 30
                                        2007      2006      2007      2006
    -------------------------------------------------------------------------
    Interest expense ($000)              5,502     4,176    11,186     6,942
    $/boe                                 2.95      2.00      2.96      1.69
    -------------------------------------------------------------------------
    

    Second quarter 2007 interest expense was $5.5 million or $2.95/boe
compared to $4.2 million or $2.00/boe a year earlier. During the second
quarter of 2007, average debt levels were $414 million as compared to
$310 million in the second quarter of 2006. Interest rates continue to be
favorable and are not expected to increase substantially in the short-term.
The average interest rate for the second quarter of 2007 was 5.5% compared to
4.4% for the second quarter of 2006. While interest rates increased slightly
over this time period, the increase in rate was primarily due to the Trust's
higher debt to EBITDA ratio.

    Depletion, Depreciation and Accretion

    The 2007 second quarter provision for depletion, depreciation and
accretion totaled $18.8 million as compared to $20.5 million in 2006. On a
unit-of-production basis, depletion, depreciation and accretion costs averaged
$10.05/boe as compared to $9.86/boe in 2006.

    Income Taxes

    The current provision for future income tax was $13.0 million (2006 -
$11.6 million). Peyto's trust structure is unique and was designed to provide
for discretion at the operating trust level to distribute taxable income to
the Trust. Resource pools are generated from the capital program, which are
available to offset current and future income tax liabilities. Unitholders
benefit as the use of these resource pools increases the tax free return of
capital component of the cash distributions.

    MARKETING

    Commodity Price Risk Management

    Effective January 1, 2007, the Trust adopted the Canadian Institute of
Chartered Accountants ("CICA") Section 3855, "Financial Instruments -
Recognition and Measurement," Section 3865, "Hedges," Section 1530,
"Comprehensive Income" and Section 3861, "Financial Instruments - Disclosure
and Presentation." The Trust has adopted these standards retroactively without
restatement and the comparative interim consolidated financial statements have
not been restated. Transition amounts have been recorded in retained earnings
or accumulated other comprehensive income ("AOCI"). See Note 2 to the
Consolidated Financial Statements.
    The Trust is a party to certain off balance sheet derivative financial
instruments, including fixed price contracts. The Trust enters into these
forward contracts with well established counter-parties for the purpose of
protecting a portion of its future revenues from the volatility of oil and
natural gas prices. During the second quarter of 2007, a hedging gain of
$5.3 million was recorded as compared to $11.1 million in the second quarter
of 2006. A summary of contracts outstanding in respect of the hedging
activities are as follows:

    
                                                                  Weighted
                                                                   Average
    Crude Oil                                                       Price
    Period Hedged                       Type      Daily Volume      (CAD)
    -------------------------------------------------------------------------
    July 1 to September 30, 2007     Fixed price     200 bbl      $87.61/bbl
    July 1 to September 30, 2007     Fixed price     200 bbl      $88.20/bbl
    July 1 to September 30, 2007     Fixed price     200 bbl      $77.12/bbl
    October 1 to December 31, 2007   Fixed price     200 bbl      $77.51/bbl
    October 1 to December 31, 2007   Fixed price     300 bbl      $78.75/bbl
    January 1 to March 31, 2008      Fixed price     200 bbl      $78.55/bbl
    January 1 to March 31, 2008      Fixed price     300 bbl      $79.05/bbl


                                                                  Weighted
                                                                   Average
    Natural Gas                                                     Price
    Period Hedged                       Type      Daily Volume      (CAD)
    -------------------------------------------------------------------------
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $8.60/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.50/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.25/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.51/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.50/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.60/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.60/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.80/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.50/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.70/GJ
    April 1, 2007 to March 31, 2008  Fixed price     5,000 GJ      $8.35/GJ
    April 1, 2007 to March 31, 2008  Fixed price     5,000 GJ      $8.90/GJ
    Nov 1, 2007 to March 31, 2008    Fixed price     5,000 GJ      $8.85/GJ
    Nov 1, 2007 to March 31, 2008    Fixed price     5,000 GJ      $9.06/GJ
    Nov 1, 2007 to March 31, 2008    Fixed price     5,000 GJ      $9.06/GJ
    Nov 1, 2007 to March 31, 2008    Fixed price     5,000 GJ      $8.55/GJ
    April 1 to October 31, 2008      Fixed price     5,000 GJ      $7.85/GJ
    

    As at June 30, 2007, the Trust had committed to the future sale of
146,700 barrels of crude oil at an average price of $80.72 per barrel and
13,010,000 gigajoules (GJ) of natural gas at an average price of $8.17 per GJ
or $9.55 per mcf based on the historical heating value of Peyto's natural gas.
Had these contracts been closed on June 30, 2007, the Trust would have
realized a gain in the amount of $21.9 million.

    Commodity Price Sensitivity

    Low operating costs, low distribution ratio and long reserve life reduce
Peyto's sensitivity to changes in commodity prices.

    Currency Risk Management

    The Trust is exposed to fluctuations in the Canadian/US dollar exchange
ratio since the natural gas and oil sales are effectively priced in US dollars
and converted to Canadian dollars. In the short term, this risk is mitigated
indirectly as a result of a commodity hedging strategy that is conducted at
Canadian prices. Over the long term, the Canadian dollar tends to rise as oil
prices rise. There is a similar correlation between oil and gas prices.
Currently Peyto has not entered into any agreements to further manage this
specific risk.

    Interest Rate Risk Management

    The Trust is exposed to interest rate risk in relation to interest
expense on its revolving demand facility. Currently we have not entered into
any agreements to manage this risk. At June 30, 2007, the increase or decrease
in earnings for each 100 bps change in interest rate paid on the outstanding
revolving demand loan amounts to approximately $4.1 million per annum.

    LIQUIDITY AND CAPITAL RE

SOURCES Funds from Operations ------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30 June 30 ($000) 2007 2006 2007 2006 ------------------------------------------------------------------------- Net Earnings 38,825 56,768 95,709 102,061 Items not requiring cash: Non-cash provision for performance based compensation 431 (2,626) 438 2,196 Future income tax expense 11,326 2,878 12,965 11,556 Depletion, depreciation & accretion 18,763 20,487 38,597 40,311 ------------------------------------------------------------------------- Funds from operations 69,345 77,507 147,709 156,124 ------------------------------------------------------------------------- For the second quarter ended June 30, 2007, funds from operations totaled $69.3 million or $0.66 per unit, as compared to $77.5 million, or $0.74 per unit during the same period in 2006. Peyto's policy is to maintain a sustainable distribution to unitholders, retaining the balance to fund its growth oriented capital expenditures program. Earnings and cash flow are highly sensitive to changes in commodity prices, exchange rates and other factors that are beyond Peyto's control. Current volatility in commodity prices creates uncertainty as to the funds from operations and capital expenditure budget. Accordingly, results are assessed throughout the year and operational plans revised as necessary to reflect the most current information. Revenues will be impacted by drilling success and production volumes as well as external factors such as the market prices for natural gas and crude oil and the exchange rate of the Canadian dollar relative to the US dollar. Bank Debt The Trust has an extendible revolving term credit facility with a syndicate of financial institutions in the amount of $525 million including a $505 million revolving facility and a $20 million operating facility. Available borrowings are limited by a borrowing base, which is based on the value of petroleum and natural gas assets as determined by the lenders. The loan is reviewed annually and may be extended at the option of the lender for an additional 364 day period. If not extended, the revolving facility will automatically convert to a one year and one day non-revolving term loan. The loan has therefore been classified as long-term on the balance sheet. The average borrowing rate for the second quarter of 2007 was 5.5% (2006 - 4.4%). While interest rates increased slightly over this time period, the increase in rate was primarily due to the Trust's higher debt to earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) ratio. At June 30, 2007, $410 million was drawn under the facility. Working capital liquidity is maintained by drawing from and repaying the unutilized credit facility as needed. At June 30, 2007, the working capital surplus was $16.6 million. Peyto believes funds generated from operations, together with borrowings under the credit facility and proceeds from equity issued will be sufficient to finance current operations and planned capital expenditure program. The total amount of capital invested in 2007 will be driven by the number and quality of projects generated. Capital will only be invested if it meets the long term objectives of the Trust. The majority of the capital program will involve drilling, completion and tie-in of low risk development gas wells. Peyto has the flexibility to match planned capital expenditures to actual cash flow. Capital Peyto implemented a Distribution Reinvestment Plan ("DRIP") effective with the March 2005 distribution whereby eligible unitholders may elect to reinvest their monthly cash distributions in additional trust units at a 5% discount to market price. On November 21, 2005 the DRIP plan was amended to incorporate an Optional Trust Unit Purchase Plan ("OTUPP") which provides unitholders enrolled in the DRIP with the opportunity to purchase additional trust units from treasury using the same pricing as the DRIP. Both the DRIP and the OTUPP were suspended effective August 31, 2006 due to unfavorable market conditions. On March 15, 2007 the Trust completed a private placement of 175,780 trust units to employees and consultants for net proceeds of $2,824,785. These trust units were issued on March 15, 2007. On March 15, 2007, subsequent to the issuance of these units, 105,712,364 trust units were outstanding (December 31, 2006 - 105,251,394). Authorized: Unlimited number of voting trust units Issued and Outstanding: Number of Amount Trust Units (no par value) Shares/Units $ ($000) ------------------------------------------------------------------------- Balance, December 31, 2005 102,333,847 328,736 Trust units issued by private placement 1,393,940 34,378 Trust units issued pursuant to DRIP 690,387 16,301 Trust units issued pursuant to OTUPP 833,220 19,019 Balance, December 31, 2006 105,251,394 398,434 Trust units issued by private placement 460,970 7,867 ------------------------------------------------------------------------- Balance, June 30, 2007 105,712,364 406,301 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Performance Based Compensation The Trust awards performance based compensation to employees and key consultants annually. The performance based compensation is comprised of market and reserve value based components. The reserve value based component is 4% of the incremental increase in value, if any, as adjusted to reflect changes in debt, equity and distributions, of proved producing reserves calculated using a constant price at December 31 of the current year and a discount rate of 8%. This methodology can generate interim results which vary significantly from the final compensation paid. No provision for the reserve value based component was recorded for the first half of 2007. Under the market based component, rights with a three year vesting period are allocated to employees and key consultants. The number of rights outstanding at any time is not to exceed 6% of the total number of trust units outstanding. At December 31 of each year, all vested rights are automatically cancelled and, if applicable, paid out in cash. Compensation is calculated as the number of vested rights multiplied by the total of the market appreciation (over the price at the date of grant) and associated distributions of a trust unit for that period. For rights vesting in 2007 and 2008, a tax factor of 1.333 will then be applied to determine the amount to be paid. Commencing 2009, no tax factor will be applied to determine the amount paid. Based on the five day weighted average trading price of the trust units for the period ended June 30, 2007, compensation costs related to 4.1 million non-vested rights (4% of the total number of trust units outstanding), with an average grant price of $22.01, are $431,000. The Trust records a non-cash provision for future compensation expense over the life of the rights. The cumulative provision is $438,000. Capital Expenditures Net capital expenditures for the second quarter of 2007 totaled $12.9 million. Exploration and development related activity represented $11.2 million or 87% of the total, while expenditures on facilities, gathering systems and equipment totaled $1.7 million or 13% of the total. The following table summarizes capital expenditures for the quarter. ------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30 June 30 ($000) 2007 2006 2007 2006 ------------------------------------------------------------------------- Land 74 2,047 441 12,678 Seismic 602 2,434 845 7,571 Drilling - Exploratory & Development 10,572 52,330 35,712 153,317 Production Equipment, Facilities & Pipelines 1,699 10,332 6,420 38,574 Acquisitions & Dispositions - - - - Office Equipment 2 52 8 149 ------------------------------------------------------------------------- Total Capital Expenditures 12,949 67,195 43,426 212,289 ------------------------------------------------------------------------- Distributions ------------------------------------------------------------------------- Three Months Ended Six Months Ended June 30 June 30 2007 2006 2007 2006 ------------------------------------------------------------------------- Funds from operations ($000) 69,345 77,507 147,709 156,124 Total distributions ($000) 44,399 43,921 88,750 85,439 Total distributions per unit ($) 0.42 0.42 0.84 0.82 Payout ratio (%) 64 57 60 55 Cash distributions ($000) (net of DRIP) 44,399 38,315 88,750 72,980 Payout ratio (%) 64 49 60 47 ------------------------------------------------------------------------- Peyto's strategy is to maintain a sustainable distribution that is well balanced with the business needs and high quality assets, while offering the prospect of growth into the future. The Board of Directors is prepared to adjust the payout levels to achieve the desired distributions while maintaining an appropriate capital structure. For Canadian income tax purposes distributions made are considered a combination of income and return of capital. The portion that is return of capital reduces the adjusted cost base of the units. Contractual Obligations The Trust is committed to payments under operating leases for office space as follows: ------------------------------------------------------------------------- ($000) $ ------------------------------------------------------------------------- 2007 476 2008 1,097 2009 1,097 2010 1,097 2011 1,097 ------------------------------------------------------------------------- 4,864 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RELATED PARTY TRANSACTIONS An officer of the Trust is a partner of a law firm that provides legal services to the Trust. The fees charged are based on standard rates and time spent on matters pertaining to the Trust and its subsidiaries. INCOME TAXES The following sets out a general discussion of the Canadian and US tax consequences of holding Peyto units as capital property. The summary is not exhaustive in nature and is not intended to provide legal or tax advice. Unitholders or potential Unitholders should consult their own legal or tax advisors as to their particular tax consequences. Canadian Taxpayers The Trust qualifies as a mutual fund trust under the Income Tax Act (Canada) and, accordingly, Trust units are qualified investments for RRSPs, RRIFs, RESPs and DPSPs. Each year, the Trust is required to file an income tax return and any taxable income of the Trust is allocated to unitholders. Unitholders are required to include in computing income their pro-rata share of any taxable income earned by the Trust in that year. An investor's adjusted cost base (ACB) in a trust unit equals the purchase price of the unit less any non-taxable cash distributions received from the date of acquisition. To the extent the unitholders' ACB is reduced below zero, such amount will be deemed to be a capital gain to the unitholder and the unitholders' ACB will be brought to nil. During the second quarter of 2007, the Trust paid distributions to the unitholders in the amount of $44.4 million (2006 - $43.9 million) in accordance with the following schedule: Production Period Record Date Distribution Date Per Unit ------------------------------------------------------------------------- January 2007 January 31, 2007 February 15, 2007 $0.14 February 2007 February 28, 2007 March 15, 2007 $0.14 March 2007 March 31, 2007 April 13, 2007 $0.14 April 2007 April 30, 2007 May 15, 2007 $0.14 May 2007 May 31, 2007 June 15, 2007 $0.14 June 2007 June 30, 2007 July 13, 2007 $0.14 US Taxpayers US unitholders who receive cash distributions are subject to a 15 percent Canadian withholding tax, applied to the taxable portion of the distributions as computed under Canadian tax law. US taxpayers may be eligible for a foreign tax credit with respect to Canadian withholding taxes paid. The taxable portion of the cash distributions, if any, is determined by the Trust in relation to its current and accumulated earnings and profit using US tax principles. The taxable portion so determined, is considered to be a dividend for US tax purposes. The non-taxable portion of the cash distributions is a return of the cost (or other basis). The cost (or other basis) is reduced by this amount for computing any gain or loss from disposition. However, if the full amount of the cost (or other basis) has been recovered, any further non-taxable distributions should be reported as a gain. A bill was introduced into United States Congress on March 23, 2007 that could deny qualified dividend income treatment to the distributions made by the Trust to its U.S. unitholders. The bill is in the first step of the legislative process and it is uncertain whether it will eventually be passed into law in its current form. If the bill is passed in its current form, distributions received by U.S. unitholders would no longer qualify for the 15 per cent qualified dividend tax rate. US unitholders are advised to seek legal or tax advice from their professional advisors. RISK MANAGEMENT Investors who purchase units are participating in the net funds from operations from a portfolio of western Canadian crude oil and natural gas producing properties. As such, the funds from operations paid to investors and the value of the units are subject to numerous risks inherent in the oil and natural gas industry. Expected funds from operations depend largely on the volume of petroleum and natural gas production and the price received for such production, along with the associated costs. The price received for oil depends on a number of factors, including West Texas Intermediate oil prices, Canadian/US currency exchange rates, quality differentials and Edmonton par oil prices. The price received for natural gas production is primarily dependent on current Alberta market prices. Peyto's marketing strategy is designed to smooth out short term fluctuations in the price of both natural gas and natural gas liquids through future sales. It is meant to be methodical and consistent, and to avoid speculation. Although Peyto's focus is on internally generated drilling programs, any acquisition of oil and natural gas assets depends on assessment of value at the time of acquisition. Incorrect assessments of value can adversely affect distributions to unitholders and the value of the units. Peyto employs experienced staff on its team and performs appropriate levels of due diligence on the analysis of acquisition targets, including a detailed examination of reserve reports; if appropriate, re-engineering of reserves for a large portion of the properties to ensure the results are consistent; site examinations of facilities for environmental liabilities; detailed examination of balance sheet accounts; review of contracts; review of prior year tax returns and modeling of the acquisition to attempt to ensure accretive results to the unitholders. Inherent in development of the existing oil and gas reserves are the risks, among others, of drilling dry holes, encountering production or drilling difficulties or experiencing high decline rates in producing wells. To minimize these risks, Peyto employs experienced staff to evaluate and operate wells and utilizes appropriate technology in its operations. In addition, prudent work practices and procedures, safety programs and risk management principles, including insurance coverage protect the Trust against certain potential losses. The value of Peyto's units is based on, among other things, the underlying value of the oil and natural gas reserves. Geological and operational risks can affect the quantity and quality of reserves and the cost of ultimately recovering those reserves. Lower oil and gas prices increase the risk of write-downs on our oil and gas property investments. In order to mitigate this risk, proven and probable oil and gas reserves are evaluated each year by a firm of independent reservoir engineers. The Reserves Committee of the Board of Directors reviews and approves the reserve report. Access to markets may be restricted at times by pipeline or processing capacity. These risks are minimized by controlling as much of the processing and transportation activities as possible and ensuring transportation and processing contracts are in place with reliable cost efficient counter- parties. The petroleum and natural gas industry is subject to extensive controls, regulatory policies and income and resource taxes imposed by various levels of government. These regulations, controls and taxation policies are amended from time to time. Peyto has no control over the level of government intervention or taxation in the petroleum and natural gas industry. The Trust operates in such a manner to ensure, to the best of its knowledge that it is in compliance with all applicable regulations and is able to respond to changes as they occur. Crown royalty rates assessed on the Trust's oil and natural gas production are set by the government of the Province of Alberta. These rates are subject to review and modification from time to time. The petroleum and natural gas industry is subject to both environmental regulations and an increased environmental awareness. Environment risks have been reviewed and to the best of Peyto's knowledge, the Trust is in compliance with environmental legislation. Currently, there is no current material impact on Peyto's operations. Peyto is subject to financial market risk. In order to maintain substantial rates of growth, the Trust must continue reinvesting in, drilling for or acquiring petroleum and natural gas. The capital expenditure program is funded primarily through funds from operations, debt and equity. DISCLOSURE CONTROLS AND PROCEDURES Disclosure controls and procedures are designed to provide reasonable assurance that all relevant information is gathered and reported to senior management, including the Chief Executive Officer ("CEO") and Vice President, Finance ("VPF"), on a timely basis so that appropriate decisions can be made regarding public disclosure. As of the end of the period covered by this report, Peyto's management evaluated the effectiveness of the design and operation of its disclosure controls and procedures, under the supervision of, and with the participation of the CEO and VPF. Based on this evaluation, the CEO and VPF have concluded that Peyto's disclosure controls and procedures, as defined in Multilateral Instrument 52-109, Certification of Disclosure in Issuers Annual and Interim Filings are effective to ensure that material information relating to Peyto is made known to management on a timely basis and is included in this report. Internal Controls Update Peyto 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 first six months of 2007. CRITICAL ACCOUNTING ESTIMATES Reserve Estimates Estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent to the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is an analytical process of estimating underground accumulations of oil and natural gas that can be difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future royalties and operating costs, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Trust's oil and natural gas properties and the rate of depletion of the oil and natural gas properties as well as the calculation of the reserve value based compensation. Actual production, revenues and expenditures with respect to the Trust's reserves will likely vary from estimates, and such variances may be material. The Trust's estimated quantities of proved and probable reserves at December 31, 2006 were audited by independent petroleum engineers Paddock Lindstrom & Associates Ltd. Paddock has been evaluating reserves in this area and for Peyto for 8 consecutive years. Depletion and Depreciation Estimate The full cost method of accounting for petroleum and natural gas operations is followed whereby all costs of exploring for and developing petroleum and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical costs, carrying charges on non- producing properties, costs of drilling both productive and non-productive wells and overhead charges directly related to acquisition, exploration and development activities. All costs of exploring for and developing petroleum and natural gas reserves, together with the costs of production equipment, are depleted and depreciated on the unit-of-production method based on estimated gross proven reserves. Petroleum and natural gas reserves and production are converted into equivalent units based upon estimated relative energy content (6 mcf to 1 barrel of oil). Costs of acquiring unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proven reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Full Cost Accounting Ceiling Test The carrying value of property, plant and equipment is reviewed at least annually for impairment. Impairment occurs when the carrying value of the assets is not recoverable by the future undiscounted cash flows. The ceiling test is based on estimates of proved reserves, production rates, estimated future petroleum and natural gas prices and costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Any impairment would be charged as additional depletion and depreciation expense. Asset Retirement Obligation The asset retirement obligation is estimated based on existing laws, contracts or other policies. The fair value of the obligation is based on estimated future costs for abandonment and reclamation discounted at a credit adjusted risk free rate. The liability is adjusted each reporting period to reflect the passage of time and for revisions to the estimated future cash flows, with the accretion charged to earnings. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Future Market Performance Based Compensation The provision for future market based compensation is estimated based on current market conditions, distribution history and on the assumption that all outstanding rights will be paid out according to the vesting schedule. The conditions at the time of vesting could vary significantly from the current conditions and may have a material effect on the calculation. Reserve Value Performance Based Compensation The reserve value based compensation is calculated using the 2006 year end independent reserves evaluation which was completed in January 2007. A quarterly provision for the reserve value based compensation is calculated using estimated proved producing reserve additions adjusted for changes in debt, equity and distributions. Actual proved producing reserves additions and forecasted commodity prices could vary significantly from those estimated and may have a material effect on the calculation. Income Taxes The determination of the Trust's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded. Effect of Change in Accounting Policies Effective January 1, 2007, the Trust adopted the revised recommendations of CICA section 1506, "Accounting Changes". The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance was effective for all changes in accounting polices, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007. When the Trust has not applied a new primary source of GAAP that has been issued, but is not effective, the Trust will disclose the fact along with information relevant to assessing the possible impact that application of the new primary source of GAAP will have on the financial statements in the period of initial application. As of January 1, 2008, the Trust will be required to adopt two new CICA Handbook Sections, Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation" which will replace current Section 3861. The new standards require disclosure of the significance of financial instruments to an entity's financial statements, the risks associated with the financial instruments, and how those risks are managed. The new presentation standard essentially carries forward the current presentation requirements. The Trust is assessing the impact of these new standards on its consolidated financial statements and anticipates the main impact will be in terms of additional disclosures required. As of January 1, 2008, the Trust will be required to adopt CICA handbook Section 1535 "Capital Disclosures:, which requires entities to disclose their objectives, policies and processes for management of capital, and in addition, whether the entity has complied with any externally imposed capital requirements. The Trust is assessing the impact of this new standard on its consolidated financial statements and anticipates the main impact will be in terms of additional disclosures required. ADDITIONAL INFORMATION Additional information relating to Peyto Energy Trust can be found on SEDAR at www.sedar.com and www.peyto.com. Quarterly information ---------------------------------------------------------- 2007 Q2 Q1 ---------------------------------------------------------- Operations Production Natural gas (mcf/d) 101,812 106,183 Oil & NGLs (bbl/d) 3,540 3,607 Barrels of oil equivalent (boe/d @ 6:1) 20,509 21,305 Average product prices Natural gas ($/mcf) 8.59 9.77 Oil & natural gas liquids ($/bbl) 65.65 59.79 $/BOE Average sale price ($/boe) 53.98 58.84 Average royalties paid ($/boe) 9.50 10.59 Average operating expenses ($/boe) 2.70 2.84 Average transportation costs ($/boe) 0.57 0.59 Field netback ($/boe) 41.21 44.82 General & administrative expense ($/boe) 1.10 0.98 Interest expense ($/boe) 2.95 2.96 Cash netback ($/boe) 37.16 40.88 Financial ($000 except per unit) Revenue 100,750 112,825 Royalties (net of ARTC) 17,734 20,326 Funds from operations 69,345 78,364 Funds from operations per unit 0.66 0.74 Total distributions 44,399 44,350 Total distributions per unit 0.42 0.42 Payout ratio 64% 57% Cash distributions (net of DRIP) 44,399 44,350 Payout ratio 64% 57% Earnings 38,825 56,833 Earnings per diluted unit 0.37 0.54 Capital expenditures 12,949 30,478 Weighted average trust units outstanding 105,712,364 105,542,484 ------------------------------------------------------------------------- 2006 Q4 Q3 Q2 ------------------------------------------------------------------------- Operations Production Natural gas (mcf/d) 112,296 115,304 112,484 Oil & NGLs (bbl/d) 3,834 4,205 4,145 Barrels of oil equivalent (boe/d @ 6:1) 22,550 23,422 22,892 Average product prices Natural gas ($/mcf) 8.84 7.81 7.96 Oil & natural gas liquids ($/bbl) 54.89 64.50 66.94 $/BOE Average sale price ($/boe) 53.35 50.05 51.24 Average royalties paid ($/boe) 9.29 10.99 8.75 Average operating expenses ($/boe) 2.69 1.90 2.26 Average transportation costs ($/boe) 0.52 0.58 0.59 Field netback ($/boe) 40.85 36.58 39.64 General & administrative expense ($/boe) 0.85 0.55 0.43 Interest expense ($/boe) 2.72 2.52 2.00 Cash netback ($/boe) 37.28 33.51 37.21 Financial ($000 except per unit) Revenue 110,696 107,844 106,751 Royalties (net of ARTC) 19,271 23,680 18,236 Funds from operations 77,360 72,360 77,507 Funds from operations per unit 0.74 0.69 0.74 Total distributions 44,206 44,111 43,921 Total distributions per unit 0.42 0.42 0.42 Payout ratio 57% 61% 57% Cash distributions (net of DRIP) 44,206 41,019 38,315 Payout ratio 57% 57% 49% Earnings 47,012 46,155 56,768 Earnings per diluted unit 0.44 0.44 0.54 Capital expenditures 28,413 71,223 67,195 Weighted average trust units outstanding 105,251,394 104,924,702 104,472,570 Peyto Energy Trust Consolidated Balance Sheets ($000) (unaudited) June 30, December 31, 2007 2006 $ $ ------------------------------------------------------------------------- Assets Current Cash 11,224 10,806 Accounts receivable (Note 10) 43,783 53,418 Financial derivative asset (Note 10) 21,919 - Due from private placements - 5,042 Prepaid expenses and deposits 3,459 2,681 ------------------------------------------------------------------------- 80,385 71,947 Property, plant and equipment (Note 3) 1,070,204 1,064,753 ------------------------------------------------------------------------- 1,150,589 1,136,700 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Liabilities and Unitholders' Equity Current Accounts payable and accrued liabilities 48,931 70,836 Cash distributions payable 14,800 14,735 Provision for future performance based compensation 60 - ------------------------------------------------------------------------- 63,791 85,571 ------------------------------------------------------------------------- Long-term debt (Note 4) 410,000 420,000 Provision for future performance based compensation 378 - Asset retirement obligations 6,389 5,767 Future income taxes (Note 5) 155,380 135,650 ------------------------------------------------------------------------- 572,147 561,417 ------------------------------------------------------------------------- Unitholders' equity Unitholders' capital (Note 6) 406,301 398,434 Units to be issued (Note 6) - 5,042 Accumulated earnings 93,195 86,236 Accumulated other comprehensive income (Notes 2, 10) 15,155 - ------------------------------------------------------------------------- 514,651 489,712 ------------------------------------------------------------------------- 1,150,589 1,136,700 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes On behalf of the Board: (signed) "Michael MacBean" (signed) "Darren Gee" Director Director Peyto Energy Trust Consolidated Statements of Earnings ($000 except per unit amounts) (unaudited) Three Months Ended Six Months Ended June 30 June 30 2007 2006 2007 2006 $ $ $ $ ------------------------------------------------------------------------- Revenue Petroleum and natural gas sales, net 83,017 88,515 175,516 174,974 ------------------------------------------------------------------------- Expenses Operating (Note 8) 5,038 4,706 10,476 8,382 Transportation 1,071 1,237 2,200 2,511 General and administrative (Note 9) 2,061 889 3,945 1,015 Future performance based compensation provision 431 (2,626) 438 2,196 Interest on long term debt 5,502 4,176 11,186 6,942 Depletion, depreciation and accretion (Note 3) 18,763 20,487 38,597 40,312 ------------------------------------------------------------------------- 32,866 28,869 66,842 61,358 ------------------------------------------------------------------------- Earnings before taxes 50,151 59,646 108,674 113,616 ------------------------------------------------------------------------- Taxes Future income tax expense (Note 5) 11,326 2,878 12,965 11,556 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net earnings for the period 38,825 56,768 95,709 102,060 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Earnings per unit (Note 6) Basic 0.37 0.54 0.91 0.98 Diluted 0.37 0.54 0.91 0.98 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Comprehensive Income ($000 except per unit amounts) (unaudited) Three Months Ended Six Months Ended June 30 June 30 2007 2006 2007 2006 $ $ $ $ ------------------------------------------------------------------------- Net earnings for the period 38,825 56,768 95,709 102,060 Other comprehensive income (loss) Change in unrealized gains on cash flow hedges, net of tax 9,650 - (4,166) - Realized gain (loss) on cash flow hedges, net of tax 3,674 - (4,120) - ------------------------------------------------------------------------- Comprehensive Income (Note 2) 52,149 56,768 87,423 102,060 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Accumulated Earnings and Accumulated Other Comprehensive Income ($000) (unaudited) Three Months Ended Six Months Ended June 30 June 30 2007 2006 2007 2006 $ $ $ $ ------------------------------------------------------------------------- Accumulated earnings, beginning of period 98,769 68,539 86,236 64,763 Net earnings for the period 38,825 56,768 95,709 102,060 Distributions (Note 7) (44,399) (43,921) (88,750) (85,439) ------------------------------------------------------------------------- Accumulated earnings, end of period 93,195 81,386 93,195 81,386 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Accumulated other comprehensive income, beginning of period 1,831 - - - Adoption of financial instruments, net of tax (Notes 2,10) - - 23,442 - Other comprehensive income (Notes 2,10) 13,324 - (8,287) - ------------------------------------------------------------------------- Accumulated other comprehensive income, end of period 15,155 - 15,155 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Cash Flows ($000) (unaudited) Three Months Ended Six Months Ended June 30 June 30 2007 2006 2007 2006 $ $ $ $ ------------------------------------------------------------------------- Cash provided by (used in) Operating Activities Net earnings for the period 38,825 56,768 95,709 102,060 Items not requiring cash: Future income tax expense 11,326 2,878 12,965 11,556 Depletion, depreciation and accretion 18,763 20,487 38,597 40,312 Change in non-cash working capital related to operating activities (40) 2,268 (996) (28,718) ------------------------------------------------------------------------- 68,874 82,401 146,275 125,210 ------------------------------------------------------------------------- Financing Activities Issue of trust units, net of costs and DRIP - 112 2,825 17,067 Cash distribution paid (net of DRIP) (44,399) (38,315) (88,750) (72,980) Increase (decrease) in bank debt (5,000) 90,000 (10,000) 210,000 Change in non-cash working capital related to financing activities - 9,610 5,107 29,265 ------------------------------------------------------------------------- (49,399) 61,407 (90,818) 183,352 ------------------------------------------------------------------------- Investing Activities Additions to property, plant and equipment (12,949) (67,195) (43,426) (212,289) Change in non-cash working capital related to investing activities (5,828) (72,774) (11,613) (92,434) ------------------------------------------------------------------------- (18,777) (139,969) (55,039) (304,723) ------------------------------------------------------------------------- Net increase (decrease) in cash 698 3,839 418 3,839 Cash, beginning of period (Note 11) 10,526 - 10,806 - ------------------------------------------------------------------------- Cash, end of period 11,224 3,839 11,224 3,839 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Notes to Consolidated Financial Statements (unaudited) June 30, 2007 and 2006 1. Summary of Significant Accounting Policies The unaudited interim consolidated financial statements of Peyto Energy Trust (the "Trust") follow the same accounting policies as the most recent annual audited consolidated financial statements except as disclosed in Note 2. The interim consolidated financial statement note disclosures do not include all of those required by Canadian generally accepted accounting principles ("GAAP") applicable for annual financial statements. Accordingly, these interim financial statements should be read in conjunction with the 2006 audited consolidated financial statements. These financial statements include the accounts of Peyto Energy Trust and its wholly owned subsidiaries, Peyto Exploration & Development Corp. and Peyto Operating Trust. 2. Changes in Accounting Policies Effective January 1, 2007, the Trust adopted the Canadian Institute of Chartered Accountants ("CICA") Section 3855, "Financial Instruments - Recognition and Measurement," Section 3865, "Hedges," Section 1530, "Comprehensive Income" and Section 3861, "Financial Instruments - Disclosure and Presentation." The Trust has adopted these standards retroactively without restatement and the comparative interim consolidated financial statements have not been restated. Transition amounts have been recorded in retained earnings or accumulated other comprehensive income ("AOCI"). Accumulated other comprehensive income is included on the balance sheet as a separate component of Unitholders' equity, and includes the effective gains and losses on derivative instruments designated as cash flow hedges. a) Financial Instruments All financial instruments must initially be recognized at fair value on the balance sheet. The Trust has classified each financial instrument into the following categories: "held for trading" and "available for sale" financial assets and financial liabilities; "loans or receivables"; and "other financial liabilities". Subsequent measurement of the financial instruments is based on their classification. Unrealized gains and losses on held for trading financial instruments are recognized in earnings. Gains and losses on available for sale financial assets are recognized in other comprehensive income and are transferred to earnings when the asset is settled. The other categories of financial instruments are recognized at amortized cost using the effective interest rate method. b) Derivative Instruments and Hedging Activities Derivative instruments are utilized by the Trust to manage market risk against the volatility in commodity prices. The Trust's policy is not to utilize derivative instruments for speculative purposes. The Trust has chosen to designate its existing derivative instruments as cash flow hedges. The Trust assesses on an ongoing basis, whether the derivatives that are used as cash flow hedges are highly effective in offsetting changes in cash flows of hedged items. All derivative instruments are recorded on the balance sheet at fair value in either accounts receivable or accrued liabilities. The effective portion of the gains and losses is recorded in other comprehensive income until the hedged transaction is recognized in earnings. When the earnings impact of the underlying hedged transaction is recognized in the consolidated statement of earnings, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. Any hedge ineffectiveness is immediately recognized in earnings. The fair values of forward contracts are based on forward market prices. c) Embedded Derivatives An embedded derivative is a component of a contract that causes some of the cash flows of the combined instrument to vary in a way similar to a stand-alone derivative. This causes some or all of the cash flows that otherwise would be required by the contract to be modified according to a specified variable, such as interest rate, financial instrument price, commodity price, foreign exchange rate, a credit rating or credit index, or other variables. The Trust has no contracts containing embedded derivatives. d) Comprehensive Income Comprehensive income consists of net earnings and other comprehensive income ("OCI"). OCI comprises the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge. "Accumulated other comprehensive income" is a new equity category comprised of the cumulative amounts of OCI. Effect of Change in Accounting Policies Effective January 1, 2007, the Trust adopted the revised recommendations of CICA section 1506, "Accounting Changes." The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance was effective for all changes in accounting polices, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007. When the Trust has not applied a new primary source of GAAP that has been issued, but is not effective, the Trust will disclose the fact along with information relevant to assessing the possible impact that application of the new primary source of GAAP will have on the financial statements in the period of initial application. As of January 1, 2008, the Trust will be required to adopt two new CICA Handbook Sections, Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation" which will replace current Section 3861. The new standards require disclosure of the significance of financial instruments to an entity's financial statements, the risks associated with the financial instruments, and how those risks are managed. The new presentation standard essentially carries forward the current presentation requirements. The Trust is assessing the impact of these new standards on its consolidated financial statements and anticipates the main impact will be in terms of additional disclosures required. As of January 1, 2008, the Trust will be required to adopt CICA handbook Section 1535 "Capital Disclosures:, which requires entities to disclose their objectives, policies and processes for management of capital, and in addition, whether the entity has complied with any externally imposed capital requirements. The Trust is assessing the impact of this new standard on its consolidated financial statements and anticipates the main impact will be in terms of additional disclosures required. 3. Property, Plant and Equipment June 30, December 31, 2007 2006 ($000) $ $ --------------------------------------------------------------------- Property, plant and equipment 1,332,259 1,288,616 Accumulated depletion and depreciation (262,055) (223,863) --------------------------------------------------------------------- 1,070,204 1,064,753 --------------------------------------------------------------------- --------------------------------------------------------------------- At June 30, 2007 costs of $38.8 million (June 30, 2006 - $39.5 million) related to undeveloped land have been excluded from the depletion and depreciation calculation. 4. Long-Term Debt The Trust has a syndicated $525 million extendible revolving credit facility. The facility is made up of a $20 million working capital sub-tranche and a $505 million production line. The facilities are available on a revolving basis for a period of at least 364 days and upon the term out date may be extended for a further 364 day period at the request of the Trust, subject to approval by the lenders. In the event that the revolving period is not extended, the facility is available on a non-revolving basis for a one year term, at the end of which time the facility would be due and payable. Outstanding amounts on this facility bear interest at rates determined by the Trust's debt to earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) ratio that range from prime to prime plus 0.75% for debt to EBITDA ranging from less than 1:1 to greater than 2.5:1. A General Security Agreement with a floating charge on land registered in Alberta is held as collateral by the bank. 5. Income Taxes On June 22, 2007, Bill C-52 ("Bill") was enacted for Canadian GAAP. The Bill enacts the October 31, 2006 proposals to impose a new tax on distributions from flow-through entities, including publicly traded income trusts. This has not resulted in any change in the consolidated future income tax calculation. 6. Unitholders' Capital Authorized: Unlimited number of voting trust units Issued and Outstanding Trust Units (no par value) Number of Amount ($000) Shares/Units $ --------------------------------------------------------------------- Balance, December 31, 2005 102,333,847 328,736 Trust units issued by private placement 1,393,940 34,378 Trust units issued pursuant to DRIP 690,387 16,301 Trust units issued pursuant to OTUPP 833,220 19,019 --------------------------------------------------------------------- Balance, December 31, 2006 105,251,394 398,434 Trust units issued by private placement 460,970 7,867 --------------------------------------------------------------------- Balance, June 30, 2007 105,712,364 406,301 --------------------------------------------------------------------- --------------------------------------------------------------------- Units to be Issued On March 2, 2005, Peyto implemented a Distribution Reinvestment Plan ("DRIP"). On November 21, 2005 the DRIP plan was amended to incorporate an Optional Trust Unit Purchase Plan ("OTUPP") which provides unitholders enrolled in the DRIP with the opportunity to purchase additional trust units from treasury subject to certain limitations, using the same pricing as the DRIP. Both the DRIP and OTUPP were suspended August 31, 2006. Per Unit Amounts Earnings per unit have been calculated based upon the weighted average number of units outstanding for the three months ended June 30, 2007 of 105,712,364 (2006 - 104,472,570) and for the six months ended June 30, 2007 of 105,670,476 (2006 - 104,333,091). There are no dilutive instruments outstanding. 7. Accumulated Distributions The Trust paid total distributions to the unitholders in the aggregate amount of $44.4 million in the three months ended June 30, 2007 of which all was settled in cash (2006 - total $43.9 million; cash $38.3 million and DRIP $5.6 million) and $88.7 million cash for the six months ended June 30, 2007 (2006 - total $85.4 million; cash $73.0 million and DRIP $12.4 million) in accordance with the following schedule: Production Period Record Date Distribution Date Per Unit --------------------------------------------------------------------- January 2007 January 31, 2007 February 15, 2007 $0.14 February 2007 February 28, 2007 March 15, 2007 $0.14 March 2007 March 31, 2007 April 13, 2007 $0.14 April 2007 April 30, 2007 May 15, 2007 $0.14 May 2007 May 31, 2007 June 15, 2007 $0.14 June 2007 June 30, 2007 July 13, 2007 $0.14 8. Operating Expenses The Trust's operating expenses include all costs with respect to day-to-day well and facility operations. Processing and gathering income related to joint venture and third party natural gas reduces operating expenses. Three Months Ended Six Months Ended June 30 June 30 2007 2006 2007 2006 ($000) $ $ $ $ --------------------------------------------------------------------- Field expenses 7,714 6,252 14,821 11,260 Processing and gathering income (2,676) (1,546) (4,345) (2,878) --------------------------------------------------------------------- Total operating costs 5,038 4,706 10,47 6 8,382 --------------------------------------------------------------------- --------------------------------------------------------------------- 9. General and Administrative Expenses General and administrative expenses are reduced by operating and capital overhead recoveries from operated properties. Three Months Ended Six Months Ended June 30 June 30 2007 2006 2007 2006 ($000) $ $ $ $ --------------------------------------------------------------------- G&A expenses 2,522 2,362 5,059 4,415 Overhead recoveries (461) (1,473) (1,114) (3,400) --------------------------------------------------------------------- Net G&A expenses 2,061 889 3,945 1,015 --------------------------------------------------------------------- --------------------------------------------------------------------- 10. Financial Instruments As described in Note 2, on January 1, 2007, the Trust adopted the new CICA requirements relating to financial instruments. The following summarizes the retrospective without restatement adoption adjustments that were required as at January 1, 2007. December January 31, 2006 Adoption 1, 2007 ($000) (As Reported) Adjustment (As Restated) --------------------------------------------------------------------- Consolidated Balance Sheets Assets --------------------------------------------------------------------- Financial derivative asset - 33,904 33,904 --------------------------------------------------------------------- Liabilities and Unitholders' Equity --------------------------------------------------------------------- Future income taxes 135,650 10,462 146,112 --------------------------------------------------------------------- Accumulated other comprehensive income - 23,442 23,442 --------------------------------------------------------------------- Commodity Price Risk Management The Trust is a party to certain off balance sheet derivative financial instruments, including fixed price contracts. The Trust enters into these contracts with well established counterparties for the purpose of protecting a portion of its future earnings and cash flows from operations from the volatility of petroleum and natural gas prices. The Trust believes the derivative financial instruments are effective as hedges, both at inception and over the term of the instrument, as the term and notional amount do not exceed the Trust's firm commitment or forecasted transaction and the underlying basis of the instrument correlates highly with the Trust's exposure. A summary of contracts outstanding in respect of the hedging activities at June 30, 2007 is as follows: Weighted Average Crude Oil Price Period Hedged Type Daily Volume (CAD) --------------------------------------------------------------------- July 1 to September 30, 2007 Fixed price 200 bbl $87.61/bbl July 1 to September 30, 2007 Fixed price 200 bbl $88.20/bbl July 1 to September 30, 2007 Fixed price 200 bbl $77.12/bbl October 1 to December 31, 2007 Fixed price 200 bbl $77.51/bbl October 1 to December 31, 2007 Fixed price 300 bbl $78.75/bbl January 1 to March 31, 2008 Fixed price 200 bbl $78.55/bbl January 1 to March 31, 2008 Fixed price 300 bbl $79.05/bbl Weighted Average Natural Gas Price Period Hedged Type Daily Volume (CAD) --------------------------------------------------------------------- April 1 to October 31, 2007 Fixed price 5,000 GJ $8.60/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.25/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.51/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.80/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.70/GJ April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.35/GJ April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.90/GJ Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.85/GJ Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $9.06/GJ Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $9.06/GJ Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.55/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.85/GJ As at June 30, 2007, the Trust had committed to the future sale of 146,700 barrels of crude oil at an average price of $80.72 per barrel and 13,010,000 gigajoules (GJ) of natural gas at an average price of $8.17 per GJ or $9.55 per mcf based on the historical heating value of Peyto's natural gas. Had these contracts been closed on June 30, 2007, the Trust would have realized a gain in the amount of $21.9 million. Fair Values of Financial Assets and Liabilities The Trust's financial instruments include accounts receivable, financial derivative assets, current liabilities, provision for future performance based compensation and long term debt. At June 30, 2007, the carrying value of accounts receivable, financial derivative assets, current liabilities and provision for future performance based compensation approximate their value due to their short term nature or method of determination. The carrying value of the long term debt approximates its fair value due to the floating rate of interest charged under the facilities. Credit Risk A substantial portion of the Trust's accounts receivable is with petroleum and natural gas marketing entities. The Trust generally extends unsecured credit to these companies, and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions and may accordingly impact the Trust's overall credit risk. Management believes the risk is mitigated by the size, reputation and diversified nature of the companies to which they extend credit. The Trust has not previously experienced any material credit losses on the collection of accounts receivable. Of the Trust's significant individual accounts receivable at June 30, 2007, approximately 89% was due from three companies (June 30, 2006 - two companies, 50%). Of the Trust's revenue for the six months ended June 30, 2007, approximately 86% was received from three companies (June 30, 2006 - two companies, 53%). The Trust may be exposed to certain losses in the event of non- performance by counter-parties to commodity price contracts. The Trust mitigates this risk by entering into transactions with counter-parties that have investment grade credit ratings. Interest rate risk The Trust is exposed to interest rate risk in relation to interest expense on its revolving demand facility. 11. Supplemental Cash Flow Information Three Months Ended Six Months Ended June 30 June 30 2007 2006 2007 2006 ($000) $ $ $ $ --------------------------------------------------------------------- Cash interest paid during the period 5,502 4,175 11,186 6,942 --------------------------------------------------------------------- --------------------------------------------------------------------- 12. Contingencies and Commitments a) Contingent Liability From time to time, Peyto is the subject of litigation arising out of its day-to-day operations. While Peyto assesses the merits of each lawsuit and defends itself accordingly, Peyto may be required to incur significant expenses or devote significant resources to defending itself against such litigation. These claims are not currently expected to have a material impact on Peyto's financial position or results of operations. Peyto has been named in a Statement of Claim issued by Canadian Natural Resources Limited and affiliates ("CNRL"), claiming $13 million in damages for alleged breaches of duty as operator of jointly owned properties, and an interim and permanent injunction to prevent Peyto from proceeding with the completion of a well on those properties. CNRL alleges that Peyto failed to take proper steps as operator of a joint well (the "Well") on lands that offset 100% Peyto owned lands. Peyto has filed a Statement of Defense defending the allegations set forth in the Statement of Claim. The injunction claimed by CNRL was to prevent Peyto from completing the Well at a target location which had been agreed upon by both parties. Although claimed in the Statement of Claim, CNRL did not apply for an interim injunction, and Peyto completed the Well as planned, but no commercial production was obtained. Affidavits of Records were filed in July, 2006 but CNRL had taken no steps to move the matter forward until February 14, 2007 when it proposed to amend its Statement of Claim to particularize further its allegations. Accordingly, it remains to be seen whether CNRL will proceed with the action. If the action goes ahead, Peyto intends to defend itself vigorously. Although the outcome of this matter is not determinable at this time, Peyto believes that this claim will not have a material adverse effect on Peyto's financial position or results of operations. b) Commitments The Trust is committed to payments under operating leases for office space as follows: --------------------------------------------------------------------- ($000) $ --------------------------------------------------------------------- 2007 476 2008 1,097 2009 1,097 2010 1,097 2011 1,097 --------------------------------------------------------------------- 4,864 --------------------------------------------------------------------- --------------------------------------------------------------------- Peyto Exploration & Development Corp. Information Officers Darren Gee Glenn Booth President and Chief Vice-President, Land Executive Officer Scott Robinson Kathy Turgeon Executive Vice-President and Chief Vice-President, Finance Operating Officer Ken Veres Stephen Chetner Vice-President, Exploration Corporate Secretary Directors Ian Mottershead, Chairman Rick Braund Don Gray Brian Davis Michael MacBean Darren Gee Gregory Fletcher Auditors Deloitte & Touche LLP Solicitors Burnet, Duckworth & Palmer LLP Bankers Bank of Montreal Union Bank of California Royal Bank of Canada BNP Paribas Société Générale ATB Financial Fortis Capital (Canada) Ltd. Transfer Agent Valiant Trust Company Stock Listing Symbol: PEY.un Toronto Stock Exchange %SEDAR: 00019597E

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PEYTO ENERGY TRUST

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