Peyto Energy Trust announces fourth quarter and 2007 year end report to unitholders



    SYMBOL: PEY.UN - TSX

    CALGARY, March 5 /CNW/ - Peyto Energy Trust ("Peyto" or the "Trust") is a
leader in the exploration and development of natural gas in western Canada. By
design, the Trust's core areas are located in Alberta's premier gas
exploration area, the Deep Basin. Peyto is known for high quality, sweet
natural gas assets, low cost structure and an ability to profitably find and
develop new natural gas reserves, year after year. This performance is
evidenced by an annual and five year average return on equity of 41% and 46%,
respectively. Peyto is proud to present the operating and financial results
for the fourth quarter and 2007 fiscal year.

    
    The following summarizes certain attributes of the Trust at year end.

    -   Long reserve life - Proved Producing 13 years, Total Proved 16 years,
        Proved plus Probable 21 years
    -   High revenue natural gas - $47.48/boe before hedging, $53.56/boe
        after hedging
    -   Low operating costs (including transportation) - $3.14/boe
    -   High operating netback - $41.06/boe
    -   Low base general and administrative costs - $0.94/boe
    -   High operatorship - over 95% of production
    -   Low cash distribution ratio - 64% of fourth quarter 2007 funds from
        operations
    -   Low debt to funds from operations ratio - 1.65 times (net debt,
        before provision for future performance based compensation, divided
        by annualized fourth 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 four and a half years ago
    -   Since inception, Peyto has raised a total of $406 million issuing
        units from treasury, accumulated earnings of $740 million, and
        distributed $622 million to unitholders.
    -   Transparent capital structure - no convertible debentures, no
        exchangeable shares, no stock options, no warrants

    The year 2007 was highlighted by improved efficiency and the successful
execution of a disciplined capital investment strategy. The following
summarizes certain performance highlights for the year.

    -   Value creation - invested $122 million in capital and created
        $569 million of Proved Producing and $465 million of Proved plus
        Probable undiscounted reserve value, translating into Net Present
        Value ("NPV") recycle ratios (as defined herein) of 4.7 and 3.8,
        respectively
    -   Net Asset value - the debt adjusted, NPV per unit of the Trust's
        Total Proved and Proved plus Probable oil and gas assets, discounted
        at 5%, was $23.80/unit and $30.77/unit, respectively in 2007
    -   Reserve growth per unit - Proved Producing reserves, grew 2% year
        over year
    -   Reserve life - Proved Producing reserve life grew from 12 years in
        2006 to 13 years in 2007, while Proved plus Probable reserve life
        grew from 20 to 21 years
    -   Distributions per unit - increased by 1% from $1.66 in 2006 to $1.68
        in 2007.
    -   Distribution life growth - increased from 23 years in 2006 to
        24 years in 2007 (based on undiscounted Proved Producing NPV and as
        defined herein)
    -   Annual production - decreased 10% from 22,873 boe/d in 2006 to
        20,669 boe/d in 2007
    -   Annual production per unit(1) - decreased 10% year over year and
        12% per debt adjusted unit
    -   Annual funds from operations per unit(1) - decreased 9% year over
        year and 11% per debt adjusted unit
    -   Cost of new reserves (Finding, Development & Acquisition "FD&A") -
        decreased 28% to $12.68/boe for Proved Producing, 52% to $9.42/boe
        for Total Proved and 46% to $9.38/boe for Proved Plus Probable
        (including change in Future Development Capital "FDC")
    -   Recycle ratio - Proved Producing 2.8, Total Proved 3.7, Proved Plus
        Probable 3.7
    -   Reserve replacement - Proved Producing 125%, Total Proved 175%,
        Proved Plus Probable 117%

    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)

    (1) Per unit results are adjusted for changes in net debt (including
        future performance based compensation) and equity. Net debt is
        converted to equity using the Dec 31 unit price of $16.90 for 2007
        and $17.70 for 2006.


    -------------------------------------------------------------------------
                      3 Months Ended                 12 Months Ended
                          Dec. 31          %            Dec. 31           %
                     2007        2006   Change      2007        2006   Change
    -------------------------------------------------------------------------
    Operations
    Production
      Natural gas
       (mcf/d)      104,749     112,296   (7)%     102,418     112,751   (9)%
      Oil & NGLs
       (bbl/d)        3,675       3,834   (4)%       3,599       4,081  (12)%
      Barrels of
       oil equiv-
       alent (boe/d
       at 6:1)       21,134      22,550   (6)%      20,669      22,873  (10)%
    Product prices
      Natural gas
       ($/mcf)         7.67        8.84  (13)%        8.42        8.46     -
      Oil & NGLs
       ($/bbl)        75.23       54.89    37%       67.88       61.00    11%
    Operating
     expenses
     ($/boe)           2.25        2.69  (16)%        2.57        2.16    19%
    Transportation
     ($/boe)           0.54        0.52     4%        0.57        0.58   (2)%
    Field netback
     ($/boe)          39.54       40.85   (3)%       41.06       39.25     5%
    General &
     administrative
     expenses
     ($/boe)           0.87        0.85     2%        0.94        0.48    96%
    Interest
     expense
     ($/boe)           3.19        2.72    17%        3.05        2.16    41%
    Financial
     ($000, except
     per unit)
    Revenue          99,387     110,696  (10)%     404,033     439,008   (8)%
    Royalties
     (net of ARTC)   17,080      19,271  (11)%      70,621      88,446  (20)%
    Funds from
     operations      68,976      77,360  (11)%     279,624     305,845   (9)%
    Funds from
     operations
     per unit          0.65        0.74  (12)%        2.65        2.93  (10)%
    Total
     distributions   44,399      44,206     -      177,548     173,755     2%
    Total
     distributions
     per unit          0.42        0.42     -         1.68        1.66     1%
      Payout ratio       64          57    12%          63          57    11%
    Cash
     distributions
     (net of DRIP)   44,399      44,206     -      177,548     158,204    12%
      Payout ratio       64          57    12%          63          52    21%
    Earnings         73,289      47,012    56%     208,884     195,228     7%
    Earnings per
     diluted unit      0.69        0.44    57%        1.98        1.86     6%
    Capital
     expenditures    35,546      28,413    25%     121,571     311,926  (61)%
    Weighted
     average
     trust units
     outstand-
     ing        105,712,364 105,251,394     -  105,712,364 104,554,322     1%
    As at December 31
    Net debt
     (before future
     compensation
     expense)                                      457,427     433,624     5%
    Unitholders'
     equity                                        528,992     489,712     8%
    Total assets                                 1,192,232   1,136,700     5%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net Earnings     73,289      47,012            208,884     195,228
    Items not
     requiring cash:
      Provision for
       (recovery of)
       performance
       based
       compensation    (371)    (10,340)               269     (10,149)
      Future income
       tax expense  (30,226)      7,981            (12,453)     27,357
      Depletion,
       depreciation
       and
       accretion     19,151      20,397             75,791      81,098
    Non-recurring
     items:
      Performance
       based
       compensation   7,133      12,310              7,133      12,310
    -------------------------------------------------------------------------
    Funds from
     operations(1)   68,976      77,360            279,624     305,845
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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. Peyto believes
        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.
    


    For some, Peyto's 2007 may seem rather unremarkable. Lower capital
expenditures and reduced activity resulted in 39 net wells drilled in 2007,
compared to 66 net wells the year before. Even though this reduced activity
resulted in 125% of the annual produced reserves being replaced, total average
production rate declined from 22,873 boe/d to 20,669 boe/d, from last year to
this year. In addition, natural gas prices (AECO Monthly) were down 5% from
$6.62/GJ in 2006 to $6.26/GJ in 2007. As was expected, however, the NPV of the
reserve assets was relatively unchanged from the previous year.
    What makes 2007 a remarkable year is the significant improvement in
Peyto's operating efficiency. Finding, Development and Acquisition ("FD&A")
costs for Proved Producing reserves dropped 28% to $12.68/boe while FD&A costs
for Total Proved reserves were down 52% to $9.42/boe. This improved efficiency
was not only evident in lower FD&A costs but also in increased operating
margins, and it ultimately translates into increased returns for unitholders.
It is Peyto's relentless focus on generating high rates of return that ensures
operating efficiencies are retained when business conditions could cause them
to be lost. The Peyto strategy has always been to invest capital into
internally generated ideas for the exploration and development of new Deep
Basin natural gas reserves. These investments have, throughout Peyto's nine
year history, generated substantial returns for shareholders and unitholders
alike. The following table highlights those returns.

    
    -------------------------------------------------------------------------
                                            2003   2004   2005   2006   2007
    -------------------------------------------------------------------------
    Return on Equity - ROE                   51%    46%    51%    43%    41%
    Return on Capital Employed - ROCE        18%    23%    29%    23%    20%
    Operating Margin(1)                      73%    72%    71%    75%    77%
    -------------------------------------------------------------------------
    (1) Return on Equity is earnings for the period divided by average
        unitholders equity
    (2) Return on Capital Employed is earnings before interest and tax for
        the period divided by total assets less current liabilities
    (3) Operating Margin is operating netback divided by sales price in $/boe
    

    The returns that were generated in 2007 were no different. They were
partly due to newly found and developed reserves and partly due to increasing
the value of the existing assets. For instance, a new pipeline contract for
transportation of liquids has reduced the trucking costs and increased Peyto's
product prices for the condensate and NGLs from the Oldman gas plant. This
arrangement has increased the value of the existing reserves. In addition,
Peyto's 100% owned and operated gas plants continue to generate third party
midstream revenues that improve the return on those specific capital
investments. Expertise among the Peyto team extends beyond the exploration and
development of new reserves, to the optimization and value realization of the
existing assets. In 2007, Peyto invested $122 million of capital, just 43% of
total funds from operations, yet the value of the producing asset base (Proved
Producing, Before Tax NPV, discounted at 5% "BT NPV5"per unit) grew by 2%.
    Peyto's strategy of reduced activity and improved capital efficiency
began in 2006 and was successfully executed throughout 2007. Retention of
financial flexibility and sustainability of distributions were primary goals.
Year end net debt of $457 million leaves close to $70 million of available
bank lines. Monthly distributions of $0.14/unit have been maintained since
their increase in February 2006. Also during that time period, base production
decline rates have lessened, requiring less capital to offset them. This trend
is expected to continue into the future, allowing more capital to effect
growth in total production rates.
    Since Peyto's inception, a total of $1.4 billion in capital has been
invested to build an asset that is worth $3.7 billion ($3.3 billion after
adjusting for debt, Proved plus Probable, BT NPV5). In doing so, Peyto
utilized $406 million of unitholders equity but has already returned to
unitholders that amount plus $216 million more.

    
    -------------------------------------------------------------------------
    Funding Sources for Capital Since Inception
     (from 1998 to 2007)                                ($000)    % of Total
    -------------------------------------------------------------------------
    Cash flow from projects found and
     developed by Peyto                             1,164,151             83%

    Net Equity (Equity issued of $406.3 million less
     Accumulated Distributions of $622.5 million)    (216,165)          (16)%

    Net Debt (year end 2007 excluding future
     performance-based compensation)                  457,427             33%
    -------------------------------------------------------------------------

    Total Capital Expenditures                      1,405,413            100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    As illustrated in the above table, cash flow generated from investments
has played a dominant role, while net equity has played a relatively minor
role in funding the capital expenditures since Peyto's inception nine years
ago.

    Capital Expenditures

    Net capital expenditures for 2007 totaled $122 million, a decrease of 61%
from 2006, continuing a strategy of reduced activity in response to service
cost inflation. Substantially all of the capital was directed to well-related
activity with 80% associated with drilling and completions and 18% associated
with wellsite equipment and pipelines. One significant infrastructure
investment during the year was a 15 km pipeline which connected gas reserves
in the Chime area to Peyto's Kakwa gas plant resulting in reduced processing
costs. Minor amounts were spent on land and seismic, reflective of an
increased concentration of development activity. None of the 2007 capital was
spent in the higher priced acquisition market. The following table summarizes
capital expenditures for the year.

    
    -------------------------------------------------------------------------
                             2007               2006         Since Inception

    Capital                      % of               % of               % of
     Expenditures       ($000)   Total     ($000)   Total     ($000)   Total
    -------------------------------------------------------------------------
    Land                   984      -      13,253      4%     41,980      3%
    Seismic              1,799      2%      8,944      3%     35,055      3%
    Drilling &
     Completion
     - Exploratory &
     Development        96,908     80%    227,585     73%  1,026,435     73%
    Production
     Equipment,
     Facilities &
     Pipelines          21,834     18%     61,961     20%    270,029     19%
    Acquisitions &
     Dispositions            -      -           -      -      30,856      2%
    Office Equipment        46      -         183      -       1,086      -
    -------------------------------------------------------------------------
    Total              121,571    100%    311,926    100%  1,405,441    100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    During the year, 48 gross (39 net) gas wells were drilled, 76 gross
(63 net) zones were completed and 67 gross (54 net) zones were brought on
production. Reduced service costs and increased efficiency of operations is
evidenced by comparing the total capital per net well, year by year. The total
capital per net well in 2007 of $3.1 million represents a reduction of 34%
from $4.7 million per net well in 2006. As in past years, the average depth of
Peyto's new wells increased another 35m to 2,641m, as drilling prospects
continue to evolve to include deeper Cretaceous zones. Most wells have at
least two and sometimes three prospective gas bearing zones for development.

    Reserves

    During 2007, the Trust was again successful in adding high quality, long
life reserves with the drill bit. The following table illustrates the change
in reserve volumes and net present value of future cash flow, discounted at
5%, before income tax using forecast pricing.

    
    -------------------------------------------------------------------------
                                       As at December 31
                                                                    % Change
                                                                    Per Unit
                                                                     (NPV(5)
                                                               %      debt
                                         2007      2006     Change  adjusted)
    -------------------------------------------------------------------------
    Reserves
    BOE 6:1 (mstb)
    Proved Producing                   99,226    97,181         2%        2%
    Total Proved                      124,328   118,681         5%        5%
    Proved + Probable Additional      164,759   163,464         1%        1%

    Net Present Value ($million)
    Discounted at 5%
    Proved Producing                    2,515     2,462         2%        2%
    Total Proved                        2,966     2,869         3%        3%
    Proved + Probable Additional        3,703     3,679         1%        0%
    -------------------------------------------------------------------------
    Note: Based on the Paddock Lindstrom & Associates report effective
    December 31, 2007. The Paddock Lindstrom and Associates Ltd. price
    forecast is available at www.padlin.com. For more information on Peyto's
    reserves, refer to the Press Release dated February 13, 2008 announcing
    the 2007 Year End Reserve Report which is available on the website at
    www.peyto.com . The complete statement of reserves data and required
    reporting in compliance with NI 51-101 will be included in Peyto's Annual
    Information Form to be released in March 2008.
    

    Value Creation

    Peyto's primary objective is to build upon the per unit value of its
energy resources so that income delivered to unitholders can be sustained, and
increased over time. Each year's investment success is quantified by measuring
the value created during the year compared to the capital invested. This
investment success is then used as justification for re-investment of
unitholders' capital. At Peyto's request and for the benefit of unitholders,
the independent engineers have run last year's Net Present Value (NPV),
against this year's price forecast to eliminate the change in value
attributable to commodity prices. This approach isolates the value created by
the Peyto team from the value created by the change in commodity prices. In
2007, $569 million of Proved Producing and $465 million of Proved plus
Probable undiscounted reserve value was created from $122 million in capital.
Relative to the enterprise value, this amount of net value creation represents
a significant growth rate. The following table, using forecast prices and
costs as at December 31, 2007, breaks out the value created by Peyto's capital
investments and reconciles the changes in debt adjusted NPV of future net
revenues.

    
    -------------------------------------------------------------------------
                                                                  Proven +
                                  Proven           Total          Probable
                                 Producing         Proven        Additional
               ($millions)
              Discounted at      0%      5%      0%      5%      0%      5%
    -------------------------------------------------------------------------
    Net Present Value at
     Beginning of Year
     ($millions)              $4,066  $2,029  $4,961  $2,435  $7,059  $3,245
    Dec. 31, 2006 Evaluation
     using PLA Jan. 1, 2007
     price forecast,
     debt adjusted
    -------------------------------------------------------------------------
      Per Unit Outstanding
       at Dec. 31, 2006
       ($/unit)               $38.53  $19.22  $47.01  $23.08  $66.88  $30.75
    -------------------------------------------------------------------------

      2007 sales (revenue
       less royalties and
       operating costs)        ($310)  ($310)  ($310)  ($310)  ($310)  ($310)
      Net Change due to
       price forecasts
       (using PLA Jan 1,
       2008 price forecast)     ($82)   ($50)   ($94)   ($64)   ($92)   ($86)
      Net Change due to
       discoveries
       (additions,
       extensions, transfers,
       revisions)               $569    $395    $675    $454    $465    $403
                              -----------------------------------------------
                              -----------------------------------------------
    Net Present Value at End
     of Year ($millions)      $4,243  $2,064  $5,232  $2,516  $7,122  $3,253
    Dec. 31, 2007 Evaluation
     using PLA Jan. 1, 2008
     price forecast, debt
     adjusted
    -------------------------------------------------------------------------
      Per Unit Outstanding
       at Dec. 31, 2007
       ($/unit)               $40.14  $19.53  $49.49  $23.80  $67.37  $30.77
    -------------------------------------------------------------------------
    

    Performance Measures

    There are a number of performance measures that are used in the oil and
gas industry in an attempt to evaluate how profitably capital has been
invested. Peyto believes that the value analysis presented above is the best
determination of profitability as it compares the value of what was created
relative to what was invested, or what is termed, the NPV recycle ratio. This
is because the NPV of an oil and gas asset takes into consideration the
reserves, the production forecast, the future royalties and operating costs,
future capital and the current commodity price outlook. In 2007, the Proved
plus Probable NPV recycle ratio remained at 3.8 times, as in 2006. This means
for each dollar invested, the Peyto team was able to create 3.8 new dollars of
Proved plus Probable reserve value.

    
    -------------------------------------------------------------------------
                                                Dec 31,    Dec 31,
    2007 Value Creation                           2007       2006   % Change
    -------------------------------------------------------------------------
    NPV Recycle Ratio
      Proved Producing                             4.7        2.9        62%
      Total Proved                                 5.5        2.9        90%
      Proved + Probable                            3.8        3.8         0%
    -------------------------------------------------------------------------
    -   NPV (net present value) recycle ratio is calculated by dividing the
        undiscounted NPV of reserves added in the year by the total capital
        cost for the period (eg. Proved Producing ($569/$122)=
        4.7).
    

    As is expected with the producing profile of tight gas reservoirs, the
reserve life increased year over year in all of the reserve categories. The
Proved plus Probable reserve life grew from 20 years at the end of 2006 to
21 years at the end of 2007. Along with this reserve life growth was a growth
in the assets that fund distributions. The distribution life grew from 23
years to 24 years for the Proved Producing category, increasing the
sustainability of Peyto's distributions. Also presented are other measures for
comparative purposes, such as FD&A, recycle ratio and reserve replacement
ratio, but it is cautioned that they are incomplete and on their own do not
measure investment success.

    
    -------------------------------------------------------------------------
                                                Proved      Total   Proved +
    Performance Ratios                       Producing     Proved   Probable
    -------------------------------------------------------------------------
    Reserve life index (years)
      Q4 2007 average production
       - 21,134 boe/d                               13         16         21

    Finding, development and acquisition
     costs ($/boe)
      2007 (Incl. change in future
       development capital, "FDC")              $12.68      $9.42      $9.38
      2006 (Incl. change in FDC)                $17.67     $19.66     $17.39
      3 year average (2005-2007 incl.
       change in FDC)                           $14.90     $14.80     $13.98

    Reserve replacement ratio                      1.3        1.7        1.2

    Recycle ratio (Incl. change in FDC)            2.8        3.7        3.7

    Distribution life (years)                       24         29         40
    -------------------------------------------------------------------------
    -   FD&A (finding, development and acquisition) costs are used as a
        measure of capital efficiency and are calculated by dividing the
        capital costs for the period, including the change in undiscounted
        future development capital ("FDC"), by the change in the reserves,
        incorporating revisions and production, for the same period
        (eg. Total Proved ($121,600+$2,648)/(124,328-118,681+7,544)
        =$9.42).
    -   The reserve life index is calculated by dividing the reserves (in
        boes) in each category by the annualized average production rate in
        boe/year (eg. Proved Producing 99,226/(21.134(*)365)=13).
        Peyto believes that the most accurate way to evaluate the current
        reserve life is by dividing the proved developed producing reserves
        by the actual fourth quarter average production. For comparative
        purposes, Peyto believes the proved developed producing reserve life
        provides the best measure of sustainability.
    -   The distribution life index is calculated by dividing the debt
        adjusted undiscounted NPV (in millions$) by the Q4 annualized
        distribution (in million$/year) (eg. Proved Producing
        ($4,694-$450.4)/($44.4(*)4) = 24 years).
    -   Recycle ratio is calculated by dividing the field net back per boe,
        before hedging, by the FD&A costs for the period (eg. Proved
        Producing ($41.06/boe-$6.08/boe)/$12.68/boe = 2.8). In
        Peyto's opinion, it can be a very good measure of investment
        performance as long as the replacement barrel is of equivalent
        quality as the produced barrel. Because the recycle ratio is
        comparing the netback from existing reserves to the cost of finding
        new reserves it may not accurately indicate investment success.
    -   The reserve replacement ratio is determined by dividing the yearly
        change in reserves before production by the actual annual production
        for the year (eg. Total Proved ((124,291-118,681+7,544)/7,544)
        =1.7).
    

    Quarterly Review

    Daily production for the three months ending December 31, 2007 averaged
105 mmcf of natural gas and 3,675 barrels of oil and natural gas liquids.
Reductions in production and commodity prices decreased funds from operations
from $77.4 million in Q4 2006 to $69.0 million in Q4 2007. Peyto's commodity
prices, net of hedging, decreased by 13% to average $7.67 per mcf of natural
gas, and increased by 37% to average $75.23 per barrel of oil and natural gas
liquids. The high heating value of Peyto's gas resulted in a 17% premium when
converted from gigajoules at the AECO price hub to mcf.
    Operating costs averaged $2.25/boe in the fourth quarter of 2007 compared
to $2.69/boe for the fourth quarter of 2006. Operating costs have continued to
fall throughout 2007 as a result of reductions in chemical consumption,
electrical costs, and third party processing charges. Year after year, Peyto
continues to lead the industry with its low operating costs.
    Capital expenditures for the quarter totaled $35.5 million, an increase
from the previous year, reflecting increased confidence in the reduced cost
structure and improved returns. Consistent with past strategy, only the
premium opportunities attracted Peyto's capital dollars. As usual,
well-related activity made up 98% of this capital, with drilling and
completion costs accounting for $29.7 million while facilities and tie-ins
accounted for $5.3 million. Peyto spent $0.5 million on land and seismic in
the quarter.

    Activity Update

    To date in 2008, Peyto has drilled 11 gross gas wells (8.9 net) and
completed 7 gross zones (5.9 net). Drilling activity has been split between
the winter access areas in Kakwa and the year round access areas in Sundance.
    Natural gas prices have recently shown significant strength. Summer
prices have risen from $6.80/GJ to over $8.00/GJ. Next winter prices have
risen from $7.50/GJ to over $8.50/GJ. If realized, these prices will provide
Peyto with greater funds to invest in drilling ideas. Consistent with Peyto's
marketing strategy, the Trust has already forward sold 65,000 GJ for the
summer at $7.01/GJ or $8.20/mcf (based on historical heat content) and
45,000 GJ for next winter at $7.72/GJ or $9.04/mcf. These forward sales
provide security for distributions and capital programs while at the same time
capturing prices that are the second highest ever seen for those periods.

    Marketing

    By design, Peyto's marketing strategy smoothes out short term
fluctuations in the price of natural gas through future sales. This is done by
selling approximately 30% of the natural gas, net of royalties, on the daily
and monthly spot markets while the other 70% is hedged. These future sales are
meant to be methodical and consistent and to avoid speculation. In general,
this approach will show hedging losses when short term prices climb and
hedging gains when short term prices fall. Over the long run Peyto expects to
break even on forward sales. Cumulative gains since Peyto began its hedging
strategy are $52 million. This hedging approach creates a forward average
price typically made up of fifteen to twenty transactions placed over a
12 month period. Peyto generally sells its contracts in either the 7 month
summer or the 5 month winter season.
    Peyto's natural gas price before hedging averaged $6.57/mcf during the
fourth quarter of 2007, a decrease of 7% from $7.08/mcf reported for the
equivalent period in 2006. Oil and natural gas liquids prices averaged
$76.67/bbl up 49% from $51.60/bbl a year earlier. Hedging activity for the
fourth quarter of 2007 increased Peyto's achieved price by $5.19/boe. The
fourth quarter hedging gain was $10.1 million, for an annual total gain of
$45.8 million, as compared to the 2006 hedging gain of $37.8 million. The
following table shows commodity prices and revenue before and after hedging.

    
    -------------------------------------------------------------------------
    Commodity Prices                  Three Months ended  Twelve Months ended
                                            Dec. 31             Dec. 31
                                         2007      2006      2007      2006
    -------------------------------------------------------------------------
    Natural gas ($/mcf)                   6.57      7.08      7.24      7.50
    Hedging - gas ($/mcf)                 1.10      1.76      1.18      0.96
    -------------------------------------------------------------------------
    Natural gas - after hedging ($/mcf)   7.67      8.84      8.42      8.46
    -------------------------------------------------------------------------

    Oil and natural gas liquids($/bbl)   76.67     51.60     66.68     62.11
    Hedging - oil ($/bbl)                (1.44)     3.29      1.20     (1.11)
    -------------------------------------------------------------------------
    Oil and natural gas liquids -
     after hedging ($/bbl)               75.23     54.89     67.88     61.00
    -------------------------------------------------------------------------
    Total Hedging ($/boe)                 5.19      9.30      6.08      4.53
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Revenue                           Three Months ended  Twelve Months ended
                                            Dec. 31             Dec. 31
    ($000)                               2007      2006      2007      2006
    -------------------------------------------------------------------------
    Natural gas                         63,374    73,192   270,602   308,692
    Oil and natural gas liquids         25,923    18,200    87,594    92,523
    Hedging gain (loss)                 10,090    19,304    45,837    37,793
    -------------------------------------------------------------------------
    Total revenue                       99,387   110,696   404,033   439,008
    -------------------------------------------------------------------------
    

    As at December 31, 2007, Peyto had committed to the forward sale of
45,500 barrels of crude oil at an average price of $78.85 per barrel and
12.5 million gigajoules (GJ) of natural gas at an average price of $7.34 per
GJ. Based on the historical heating value of Peyto's natural gas, the price
per mcf of the forward sale will be $8.59, which is 2% higher than the price
Peyto realized in 2007.

    Performance Based Compensation

    When Peyto converted to a trust in July, 2003, a performance based
compensation plan was adopted. Performance based compensation was established
to compensate employees for per unit market and reserve value growth. The
market based component replaced the stock option plan. It was designed to be
less costly, more transparent, more tax efficient for the unitholders and to
provide better alignment with unitholders' objectives. The reserve value
component was meant to compensate employees based on per unit growth of the
Proved Producing reserve value, more conservatively discounted at 8%,
independent of increases due to commodity prices. A more detailed discussion
of Peyto's market and reserve value based compensation plan is available on
the website.
    Total performance based compensation paid in 2007 was $7.1 million
(market component - $0 million; reserve value component - $7.1 million). As a
testament to the effectiveness of the reserve value component, greater
compensation was awarded in 2007 than in 2006, despite a 61% reduction in
capital spending. This is due to the much improved efficiency and increased
value creation on a per unit basis. After the performance based compensation
payment, private placements are offered to Peyto employees and consultants.
Unlike typical option plans, the employees of Peyto have voluntarily chosen to
re-invest 96% of the after tax proceeds into Peyto Trust units at an
undiscounted market price. At Peyto, there is a high degree of ownership at
all levels; Board, Executive and Employee. It is through ownership that the
Peyto's team is best aligned with unitholders' interests.

    Sustainable Distributions

    As a growth oriented, sustainable trust, Peyto's primary objective is to
grow the resources from which sustainable distributions for unitholders are
generated. As of December 31, 2007, cumulative distributions to unitholders
totaled $622.5 million or $6.195 per unit (adjusted for 2 for 1 split). Since
converting to a trust, 81% of the unit price at the time of conversion has
been returned while increasing the reserves per unit by 53% and the production
per unit by 23%.

    Outlook

    Peyto is now into its tenth year of operations with an inventory of
opportunities greater than ever before. The strategy for value creation
remains the same today as it did the day Peyto started. It is to generate
tight gas drilling ideas that will spawn predictable and repeatable results;
execute on these ideas to find and develop new reserves; operate and process
the produced volumes at industry leading operating margins; optimize that
operation over time to maximize value; and, ultimately, to measure investment
success on the rate of return on capital deployed, and the resultant impact on
per unit value creation.
    Commodity prices have set the stage for an exciting year in 2008. Cost
reductions have been achieved and profitability has been increased. The
challenge now becomes one of increasing the scale of the business again, while
keeping that profitability intact. Peyto has been successful in doing just
that in the past and is confident it can be done again in the future. If one
understands the value of one's own capital and is interested in understanding
the value of Peyto, please visit the Peyto website at www.peyto.com where a
wealth of information can be found, designed to educate and inform investors
who understand value and real returns.
    The current Vice-President of Exploration, Ken Veres, will be retiring
effective March 31, 2008. On behalf of the directors, staff and unitholders,
Peyto would like to thank Mr. Veres for his contribution over the last three
years and wish him all the best in his retirement. At this time, there are no
plans to replace this position as Peyto has a wealth of existing geotechnical
experience to facilitate the ongoing success of our exploration strategies.

    National Instrument 51-101 Cautionary Statements

    The Canadian Securities Administrators have implemented standards of
disclosure for reporting issuers engaged in upstream oil and gas activities
effective December 31, 2003. The disclosure standards referred to as National
Instrument ("NI") 51-101 establish a regime of continuous disclosure for oil
and gas companies and include specific reporting requirements.

    
    -   Peyto's year-end reserve report summarized herein is compliant with
        NI 51-101. Under NI 51-101's revised reserve definitions and
        evaluation standards, proved plus probable reserves represent a "best
        estimate" and hence for years prior to 2003, are compared to
        "established" reserves which were comprised of proved plus 50 percent
        of probable reserves.
    -   The term "boes" may be misleading particularly if used in isolation,
        a boe conversion ratio of 6 mcf : 1 barrel is based on an energy
        equivalency conversion method primarily applicable at the burner tip
        and does not represent a value equivalency at the wellhead
    -   It should not be assumed that the discounted net present values
        represent the fair market value of the reserves.
    -   Due to the effects of aggregation, the estimate of reserves and
        future net revenue for individual properties may not reflect the same
        confidence level as estimates of reserves and future net revenue for
        all properties.
    -   The aggregate of the exploration and development costs incurred in
        the most recent financial year, and the change during that year in
        estimated future development costs, generally will not reflect total
        finding and development costs related to reserve additions for that
        year.
    

    Conference Call and Webcast

    A conference call will be held with the senior management of Peyto to
answer questions with respect to the 2007 fourth quarter and full year
financial results on Thursday, March 6th, 2008, at 9:00 a.m. Mountain Standard
Time (MST), or 11:00 a.m. Eastern Standard Time (EST). To participate, please
call 1-416-644-3424 (Toronto area) or 1-800-588-4942 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 21264765 followed by the pound key (No.). The replay will be
available at 11:00 a.m. MST, 1:00 p.m. EST Thursday, March 6th, 2008 until
midnight EST on Thursday, March 13th, 2008. The conference call can also be
accessed through the internet at
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=2188340. After this
time the conference call will be archived on the Peyto Energy Trust website at
www.peyto.com.

    Annual General Meeting

    The Trust's Annual General Meeting of Unitholders is scheduled for
2:30 p.m. on Tuesday, May 13, 2008 at the Telus Convention Centre, Mcleod Hall
B/C, 120 - 9th Avenue SE, Calgary, Alberta.

    Darren Gee
    President and Chief Executive Officer
    March 5, 2008

    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 benefitst 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.

    The Toronto Stock Exchange has neither approved nor disapproved the
    information contained herein.


    Management's discussion and analysis

    This Management's Discussion and Analysis ("MD&A") should be read in
conjunction with the audited consolidated financial statements of Peyto Energy
Trust ("Peyto") for the years ended December 31, 2007 and 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 March 4, 2008.
Additional information about Peyto, including the most recently filed annual
information form is available at www.sedar.com.
    On January 1, 2008, Peyto completed an internal reorganization. As a
result of this reorganization, all of the oil and gas assets of Peyto are now
held in the Peyto Energy Limited Partnership. Peyto Energy Administration
Corp. is the administrator of Peyto and Peyto Operating Trust, and PEDC is the
general partner of the Partnership. Certain subsidiaries of Peyto were
amalgamated pursuant to the internal reorganization.
    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. Peyto
believes 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.
    Peyto's foreign ownership level currently stands at approximately
34 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).

    Alberta's New Royalty Framework

    On October 25, 2007 the Alberta Government released a new Royalty
Framework pertaining to royalties on oil and gas resources including oil
sands, conventional oil and gas, and coalbed methane. This new framework was
scheduled to take effect on January 1, 2009 and was based on the Alberta
government's response to the recommendations put forth by the Alberta Royalty
Review Panel.
    On February 4, 2008, the Alberta Premier, Ed Stelmach, dissolved the
provincial legislature and called for a provincial election for March 3, 2008.
As the detailed legislation containing the new royalty framework was not
passed, the succeeding government is now responsible for implementing any
changes to the existing royalty scheme. Until that time, Peyto continues to
operate under the existing Alberta royalty guidelines. Also in the interim,
Alberta Energy continues to evaluate the "unintended consequences" of the
proposed new framework and may provide future recommendations for
modification. Should the succeeding government implement the royalty framework
that was announced in October 2007, the impact to Peyto's reserves and their
NPV is not expected to be material but there may be a minor negative impact on
cashflow.

    Federal Government's Trust Tax Legislation

    On June 12, 2007, Bill C-52 (the "SIFT Rules") enacted the October 31,
2006 proposal to impose a new tax on distributions from flow-through entities,
including publicly traded income trusts. Under the SIFT Rules, 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 the Federal Corporate rate and applicable
provincial corporate rate. 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 tax at the
trust level, distributions to tax-deferred accounts and non-residents will be
reduced. On the basis of proposed legislation it is anticipated that the tax
will be 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 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. For additional information, please
refer to the February 27, 2008 press release "2007 United States Tax
Information".

    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, 2007,
the total Proved plus Probable reserves were 164.8 million barrels of oil
equivalent with a reserve life of 21 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 with the objective to deliver growth in its
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 nine years indicate that these principles
have been successfully implemented. This business model makes Peyto a truly
unique energy trust.

    ANNUAL FINANCIAL INFORMATION

    The following is a summary of selected financial information of the Trust
for the periods indicated. Reference should be made to the audited
consolidated financial statements of the Trust, which are available at
www.sedar.com.

    
    -------------------------------------------------------------------------
    Year Ended December 31                       2007       2006       2005
    ($000 except per unit amounts)
    -------------------------------------------------------------------------
    Total revenue (before royalties)           404,033    439,008    431,695
    Funds from operations                      279,624    305,845    296,970
      Per unit - basic                            2.65       2.93       3.01
      Per unit - diluted                          2.65       2.93       3.01
    Earnings                                   208,884    195,228    161,568
      Per unit - basic                            1.98       1.86       1.64
      Per unit - diluted                          1.98       1.86       1.64
    Total assets                             1,192,232  1,136,700    944,927
    Total long-term debt                       430,000    420,000    180,000
    Cash distributions per unit                   1.68       1.66       1.39
    -------------------------------------------------------------------------


    QUARTERLY FINANCIAL INFORMATION

    -------------------------------------------------------------------------
                                                           2007
    ($000 except per unit amounts)              Q4      Q3      Q2      Q1
    -------------------------------------------------------------------------
    Total revenue (net of royalties)          82,307  75,589  83,017  92,499
    Funds from operations                     68,976  62,938  69,345  78,364
      Per unit - basic                          0.65    0.60    0.66    0.74
      Per unit - diluted                        0.65    0.60    0.66    0.74
    Earnings                                  73,289  39,886  38,825  56,883
      Per unit - basic                          0.69    0.37    0.37    0.54
      Per unit - diluted                        0.69    0.37    0.37    0.54
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                           2006
    ($000 except per unit amounts)              Q4      Q3      Q2      Q1
    -------------------------------------------------------------------------
    Total revenue (net of royalties)          91,425  84,164  88,515  86,459
    Funds from operations                     77,360  72,360  77,507  78,617
      Per unit - basic                          0.74    0.69    0.74    0.76
      Per unit - diluted                        0.74    0.69    0.74    0.76
    Earnings                                  47,012  46,155  56,768  45,293
      Per unit - basic                          0.44    0.44    0.54    0.44
      Per unit - diluted                        0.44    0.44    0.54    0.44
    -------------------------------------------------------------------------


    RESULTS OF OPERATIONS

    Production
    -------------------------------------------------------------------------
                                      Three Months ended  Twelve Months ended
                                            Dec. 31             Dec. 31
                                         2007      2006      2007      2006
    -------------------------------------------------------------------------
    Natural gas (mmcf/d)               104,749   112,296   102,418   112,751
    Oil & natural gas liquids (bbl/d)    3,675     3,834     3,599     4,081
    Barrels of oil equivalent (boe/d)   21,134    22,550    20,669    22,873
    -------------------------------------------------------------------------
    

    Natural gas production averaged 104.7 mmcf/d in the fourth quarter of
2007, 7 percent lower than the 112.3 mmcf/d reported for the same period in
2006. Oil and natural gas liquids production averaged 3,675 bbl/d, a decrease
of 4 percent from 3,834 bbl/d reported in the prior year. Production for the
year decreased 10 percent from 22,873 boe/d to 20,669 boe/d. The production
decreases are attributable to Peyto's reduced drilling program and natural
production declines.

    
    Commodity Prices
    -------------------------------------------------------------------------
                                      Three Months ended  Twelve Months ended
                                            Dec. 31             Dec. 31
                                         2007      2006      2007      2006
    -------------------------------------------------------------------------
    Natural gas ($/mcf)                   6.57      7.08      7.24      7.50
    Hedging - gas ($/mcf)                 1.10      1.76      1.18      0.96
    -------------------------------------------------------------------------
    Natural gas - after hedging ($/mcf)   7.67      8.84      8.42      8.46
    -------------------------------------------------------------------------

    Oil and natural gas liquids($/bbl)   76.67     51.60     66.68     62.11
    Hedging - oil ($/bbl)                (1.44)     3.29      1.20     (1.11)
    -------------------------------------------------------------------------
    Oil and natural gas liquids -
     after hedging ($/bbl)               75.23     54.89     67.88     61.00
    -------------------------------------------------------------------------
    Total Hedging ($/boe)                 5.19      9.30      6.08      4.53
    -------------------------------------------------------------------------

    Peyto's natural gas price before hedging averaged $6.57/mcf during the
fourth quarter of 2007, a decrease of 7 percent from $7.08/mcf reported for
the equivalent period in 2006. Oil and natural gas liquids prices averaged
$76.67/bbl up 49 percent from $51.60/bbl a year earlier. Average natural gas
prices for the year were down 3 percent at $7.24/mcf while oil and natural gas
liquids prices were up 7 percent at $66.68/bbl compared to 2006. Hedging
activity for fiscal 2007 increased Peyto's price achieved by $6.08/boe.

    Revenue
    -------------------------------------------------------------------------
                                      Three Months ended  Twelve Months ended
                                            Dec. 31             Dec. 31
    ($000)                               2007      2006      2007      2006
    -------------------------------------------------------------------------
    Natural gas                         63,374    73,192   270,602   308,692
    Oil and natural gas liquids         25,923    18,200    87,594    92,523
    Hedging gain (loss)                 10,090    19,304    45,837    37,793
    -------------------------------------------------------------------------
    Total revenue                       99,387   110,696   404,033   439,008
    -------------------------------------------------------------------------

    For the three months ended December 31, 2007, gross revenue decreased
10 percent to $99.4 million from $110.7 million for the same period in 2006.
The decrease in revenue for the period was a result of decreased production
volumes and lower natural gas prices as detailed in the following table:

    -------------------------------------------------------------------------
                                 Three Months ended      Twelve Months ended
                                      Dec. 31                 Dec. 31
                               2007    2006  $million  2007    2006  $million
    -------------------------------------------------------------------------
    Total Revenue,
     Dec 31, 2006                              110.7                   439.0
    -------------------------------------------------------------------------
      Revenue change due to:
    -------------------------------------------------------------------------
      Natural gas
        Volume (mmcf)           9637  10,331    (6.1) 37,382  41,154   (31.9)
        Price ($/mcf)           7.67   $8.84   (11.3)   8.42   $8.46    (1.5)
      Oil & NGL
        Volume (mbbl)            338     353    (0.8)  982.5   1,490   (10.7)
        Price ($/bbl)          75.23  $54.89     6.9   67.88  $61.00     9.0
    -------------------------------------------------------------------------
    Total Revenue,
     Dec 31, 2007                               99.4                   404.0
    -------------------------------------------------------------------------

    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  Twelve Months ended
                                            Dec. 31             Dec. 31
                                         2007      2006      2007      2006
    -------------------------------------------------------------------------
    Royalties, net of ARTC ($000)       17,080    19,271    70,621    88,446
    % of sales                              17        18        18        21
    $/boe                                 8.78      9.29      9.36     10.59
    -------------------------------------------------------------------------
    

    For the fourth quarter of 2007, royalties averaged $8.78/boe or
approximately 17 percent of Peyto's total petroleum and natural gas sales.
Royalties for the year were 18 percent of sales in 2007 compared to 21 percent
in 2006. 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 rates decline, the associated effective Crown Royalty rate will
decrease. In addition, Peyto will receive Deep Gas Royalty Holiday or Marginal
Deep Gas Well Program benefits until December 31, 2008, which further decrease
the 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  Twelve Months ended
                                            Dec. 31             Dec. 31
                                         2007      2006      2007      2006
    -------------------------------------------------------------------------
    Operating costs ($000)
    Field expenses                       7,136     7,361    28,433    25,765
    Processing and gathering income     (2,753)   (1,780)   (9,074)   (7,719)
    -------------------------------------------------------------------------
    Total operating costs                4,383     5,581    19,359    18,046
    -------------------------------------------------------------------------
    $/boe                                 2.25      2.69      2.57      2.16
    -------------------------------------------------------------------------

    Transportation                       1,052     1,089     4,296     4,856
    -------------------------------------------------------------------------
    $/boe                                 0.54      0.52      0.57      0.58
    -------------------------------------------------------------------------
    

    Operating costs were $4.4 million in the fourth quarter of 2007 compared
to $5.6 million during the same period a year earlier. On a unit of production
basis, operating costs averaged $2.25/boe in the fourth quarter of 2007
compared to $2.69/boe for the fourth quarter of 2006. Operating costs for the
year averaged $2.57/boe in 2007 compared to $2.16/boe in 2006. Operating costs
were down over the course of the year as a result of reductions in chemical
consumption, electrical costs, and third party processing charges. At the
beginning of October, production from the Chime area was rerouted from costly
third party processing to Peyto's wholly owned Kakwa facility. Transportation
expense remained constant.

    Netbacks

    Operating 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 its natural gas that results in higher commodity prices.

    
    -------------------------------------------------------------------------
                                      Three Months ended  Twelve Months ended
                                            Dec. 31             Dec. 31
    ($/boe)                              2007      2006      2007      2006
    -------------------------------------------------------------------------
    Sale Price                           51.12     53.35     53.56     52.58
    Less:
      Royalties                           8.78      9.29      9.36     10.59
      Operating costs                     2.25      2.69      2.57      2.16
      Transportation                      0.54      0.52      0.57      0.58
    -------------------------------------------------------------------------
    Operating netback                    39.55     40.85     41.06     39.25
    General and administrative            0.87      0.85      0.94      0.48
    Interest on long-term debt            3.19      2.72      3.05      2.16
    -------------------------------------------------------------------------
    Cash netback                         35.49     37.28     37.07     36.61
    -------------------------------------------------------------------------


    General and Administrative Expenses
    -------------------------------------------------------------------------
                                      Three Months ended  Twelve Months ended
                                            Dec. 31             Dec. 31
                                         2007      2006      2007      2006
    -------------------------------------------------------------------------
    G&A expenses ($000)                  2,648     2,426    10,242     9,397
    Overhead recoveries                   (950)     (669)   (3,117)   (5,431)
    -------------------------------------------------------------------------
    Net G&A expenses                     1,698     1,757     7,125     3,966
    -------------------------------------------------------------------------
    $/boe                                 0.87      0.85      0.94      0.48
    -------------------------------------------------------------------------
    

    General and administrative expenses before overhead recoveries remained
relatively constant in the fourth quarter of 2007, as compared to the same
period in 2006. Net of overhead recoveries associated with the capital
expenditures program, general and administrative costs increased to $0.87 per
boe in the fourth quarter of 2007, from $0.85 per boe in the fourth quarter of
2006. Fourth quarter 2007 capital overhead recoveries were 42% higher than
fourth quarter 2006 recoveries but were down 43% on an annual basis. General
and administrative expenses for 2007 averaged $0.94/boe in 2007 compared to
$0.48 in 2006.

    
    Interest Expense
    -------------------------------------------------------------------------
                                      Three Months ended  Twelve Months ended
                                            Dec. 31             Dec. 31
                                         2007      2006      2007      2006
    -------------------------------------------------------------------------
    Interest expense ($000)              6,198     5,638    23,007    18,011
    $/boe                                 3.19      2.72      3.05      2.16
    -------------------------------------------------------------------------
    

    2007 interest expense was $23.0 million or $3.05/boe compared to
$18.0 million or $2.16/boe a year earlier. Average bank debt for 2007 was
$405 million as compared to $360 million for 2006. Interest rates continue to
be favorable and are not expected to increase substantially in the short term.

    Depletion, Depreciation and Accretion

    The 2007 provision for depletion, depreciation and accretion totaled
$75.8 million as compared to $81.2 million in 2006. On a unit of production
basis, depletion, depreciation and accretion costs averaged $10.05/boe as
compared to $9.71/boe in 2006. Increases or decreases in the depletion rate on
a unit of production basis are influenced by the reserves added through
Peyto's drilling program.

    Income Taxes

    The current provision for recovery of future income tax was $12.5 million
in 2007 down from an expense of $27.4 million in 2006. Included in the 2007
provision was a recovery of $31.0 million recorded in the fourth quarter (2006
expense - $8.0 million). This reduction of future income tax liability is due
to the reduction in tax rates for future years at the trust level. 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. The capital
program generates resource pools 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. At December 31, 2007 the Trust has tax pools of approximately
$660.1 million (December 31, 2006 - $670.8 million) available for deduction
against future income.

    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 2007, a hedging gain of $45.8 million was recorded
as compared to a hedging gain of $37.8 million in 2006. A summary of contracts
outstanding in respect of the hedging activities are as follows:

    
    Crude Oil                                                        Price
    Period Hedged                        Type      Daily Volume      (CAD)
    -------------------------------------------------------------------------
    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


    Natural Gas                                                      Price
    Period Hedged                        Type      Daily Volume      (CAD)
    -------------------------------------------------------------------------
    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       $9.10/GJ
    Nov 1, 2007 to March 31, 2008     Fixed price    5,000 GJ       $8.55/GJ
    Nov 1, 2007 to March 31, 2008     Fixed price    5,000 GJ       $6.40/GJ
    Nov 1, 2007 to March 31, 2008     Fixed price    5,000 GJ       $6.30/GJ
    Dec 1, 2007 to March 31, 2008     Fixed price    5,000 GJ       $6.70/GJ
    April 1 to October 31, 2008       Fixed price    5,000 GJ       $7.85/GJ
    April 1 to October 31, 2008       Fixed price    5,000 GJ       $6.60/GJ
    April 1 to October 31, 2008       Fixed price    5,000 GJ       $6.40/GJ
    April 1 to October 31, 2008       Fixed price    5,000 GJ       $6.60/GJ
    April 1 to October 31, 2008       Fixed price    5,000 GJ       $6.80/GJ
    April 1 to October 31, 2008       Fixed price    5,000 GJ       $7.05/GJ
    April 1 to October 31, 2008       Fixed price    5,000 GJ       $7.20/GJ
    April 1 to October 31, 2008       Fixed price    5,000 GJ       $7.10/GJ
    April 1 to October 31, 2008       Fixed price    5,000 GJ       $7.20/GJ
    April 1 to October 31, 2008       Fixed price    5,000 GJ       $7.40/GJ
    April 1, 2008 to March 31, 2009   Fixed price    5,000 GJ       $6.82/GJ
    Nov 1, 2008 to March 31, 2009     Fixed price    5,000 GJ       $7.25/GJ
    Nov 1, 2008 to March 31, 2009     Fixed price    5,000 GJ       $7.50/GJ
    Nov 1, 2008 to March 31, 2009     Fixed price    5,000 GJ       $7.60/GJ
    Nov 1, 2008 to March 31, 2009     Fixed price    5,000 GJ       $8.00/GJ
    Nov 1, 2008 to March 31, 2009     Fixed price    5,000 GJ       $8.25/GJ
    Nov 1, 2008 to March 31, 2009     Fixed price    5,000 GJ       $8.40/GJ
    Nov 1, 2008 to March 31, 2009     Fixed price    5,000 GJ       $8.65/GJ
    

    As at December 31, 2007, the Trust had committed to the future sale of
45,500 barrels of crude oil at an average price of $78.85 per barrel and
12,465,000 gigajoules (GJ) of natural gas at an average price of $7.34 per GJ
or $8.59 per mcf based on the historical heating value of Peyto's natural gas.
Had these contracts been closed on December 31, 2007, the Trust would have
realized a gain in the amount of $7.4 million.

    Commodity Price Sensitivity

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

    Currency Risk Management

    The Trust is exposed to fluctuations in the Canadian/US dollar exchange
ratio since 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 in
Canadian currency. 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 there are no agreements to
manage this risk. At December 31, 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 Twelve Months ended Dec. 31 Dec. 31 ($000 except per unit amounts) 2007 2006 2007 2006 ------------------------------------------------------------------------- Net earnings 73,289 47,012 208,884 195,228 Items not requiring cash: Provision for (recovery of) performance based compensation (371) (10,340) 269 (10,149) Future income tax expense (30,226) 7,980 (12,453) 27,357 Depletion, depreciation & accretion 19,151 20,397 75,791 81,098 Non-recurring items: Market and reserve value performance based compensation 7,133 12,311 7,133 12,311 ------------------------------------------------------------------------- Funds from operations 68,976 77,360 279,624 305,845 ------------------------------------------------------------------------- Funds from operations per unit 0.65 0.74 2.65 2.93 ------------------------------------------------------------------------- For the quarter ended December 31, 2007, funds from operations totaled $69.0 million or $0.65 per unit, as compared to $77.3 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. 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 2007 was 5.7% (2006 - 5.0%). At December 31, 2007, $430 million was drawn under the facility. Working capital liquidity is maintained by drawing from and repaying the unutilized credit facility as needed. At December 31, 2007, the working capital deficit was $22.3 million. Peyto believes that funds generated from operations, together with borrowings under the credit facility and proceeds from equity issued will be sufficient to finance current operations and the planned capital expenditure program. The total amount of capital invested in 2008 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 December 31, 2007, 105,712,364 trust units were outstanding (December 31, 2006 - 105,251,394). Authorized: Unlimited number of voting trust units Issued and Outstanding: Trust Units (no par value) Amount ($000) Number of 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, December 31, 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%. ------------------------------------------------------------------------- ($millions except unit values) 2007 2006 Change ------------------------------------------------------------------------- Net present value of proved producing reserves at 8% based on constant Paddock Lindstrom 2008 price forecast 1,725.0 1,708.0 Net debt before performance based compensation (450.3) (433.6) 2007 distributions - (177.5) --------------------------------- Net value 1,274.7 1,096.9 177.8 Equity adjustment factor(*) 100% ----------- Equity adjusted increase in value 177.8 ----------- 2007 reserve value based compensation at 4% 7.1 ------------------------------------------------------------------------- ------------------------------------------------------------------------- (*) Equity adjustment factor is calculated as the percent increase in value per unit divided by the total percent increase in value 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 2008, a tax factor of 1.333 will then be applied to determine the amount to be paid. Commencing for rights vesting in 2009, no tax factor will be applied to determine the amount paid. The 2007 market based component was based on 1.2 million vested rights at an average grant price of $24.16, average cumulative distributions of $4.73 and the five day weighted average closing price of $16.48. The total amount expensed under these plans was as follows: ------------------------------------------------------------------------- 2007 2006 ($000) $ $ ------------------------------------------------------------------------- Market based compensation 13 8,491 Reserve value based compensation 7,120 4,570 Recovery of prior year unpaid reserve bonus - (750) ------------------------------------------------------------------------- Total 7,133 12,311 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Liability for future market based compensation as at December 31, 2007 related to $3.0 million non-vested rights with an average grant price of $21.04 were $269,000 (2006 - nil). Capital Expenditures Net capital expenditures for the fourth quarter of 2007 totaled $35.5 million. Exploration and development related activity represented $29.7 million or 84% of the total, while expenditures on facilities, gathering systems and equipment totaled $5.3 million or 15% of the total. The following table summarizes capital expenditures for the year. ------------------------------------------------------------------------- Three Months ended Twelve Months ended Dec. 31 Dec. 31 ($000) 2007 2006 2007 2006 ------------------------------------------------------------------------- Land - - 984 13,253 Seismic 464 583 1,799 8,944 Drilling - Exploratory & Development 29,734 22,777 96,908 227,585 Production Equipment, Facilities & Pipelines 5,326 5,036 21,834 61,961 Acquisitions & Dispositions - - - - Office Equipment 22 17 46 183 ------------------------------------------------------------------------- Total Capital Expenditures 35,546 28,413 121,571 311,926 ------------------------------------------------------------------------- Cash Distributions ------------------------------------------------------------------------- Three Months ended Twelve Months ended Dec. 31 Dec. 31 2007 2006 2007 2006 ------------------------------------------------------------------------- Funds from operations ($000) 68,976 77,360 279,624 305,845 Total distributions ($000) 44,399 44,206 177,548 173,755 Total distributions per unit ($) 0.42 0.42 1.68 1.66 Payout ratio (%) 64 57 63 57 Cash distributions ($000) (net of DRIP) 44,399 44,206 177,548 158,204 Payout ratio (%) 64 57 63 52 ------------------------------------------------------------------------- Peyto's strategy is to maintain a sustainable distribution that is well balanced with its 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. Accumulated Earnings and Distributions ------------------------------------------------------------------------- Three Months ended Twelve Months ended Dec. 31 Dec. 31 ($000) 2007 2006 2007 2006 ------------------------------------------------------------------------- Opening accumulated earnings 666,749 484,142 531,154 335,926 Net earnings for the period 73,289 47,012 208,884 195,228 ------------------------------------------------------------------------- Total accumulated earnings 740,038 531,154 740,038 531,154 Total accumulated distributions (622,466) (400,712) (622,466) (444,918) ------------------------------------------------------------------------- Accumulated earnings per Balance Sheet 117,572 83,430 117,572 86,236 ------------------------------------------------------------------------- Since inception, Peyto has accumulated earnings of $740.0 million and distributed $622.5 million to unitholders. Contractual Obligations The Trust is committed to payments under operating leases for office space as follows: ------------------------------------------------------------------------- ($000) $ ------------------------------------------------------------------------- 2008 1,097 2009 1,097 2010 1,097 2011 1,097 ------------------------------------------------------------------------- 4,388 ------------------------------------------------------------------------- ------------------------------------------------------------------------- GUARANTEES/OFF BALANCE SHEET ARRANGEMENTS The Trust is a party to certain off balance sheet derivative financial instruments, including fixed price contracts as discussed further in the Hedging section. 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. For the year ended December 31, 2007, legal fees totaled $1.1 million. 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. For 2007, the Trust paid distributions to the unitholders in the amount of $177.5 million (2006 - $173.8 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 14, 2007 $0.14 July 2007 July 31, 2007 August 15, 2007 $0.14 August 2007 August 31, 2007 September 15, 2007 $0.14 September 2007 September 30, 2007 October 13, 2007 $0.14 October 2007 October 31, 2007 November 15, 2007 $0.14 November 2007 November 30, 2007 December 15, 2007 $0.14 December 2007 December 31, 2007 January 15, 2008 $0.14 ------- $1.68 ------- ------- 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 depends 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 an 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 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 utilize appropriate technology in 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 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 are able to respond to changes as they occur. The petroleum and natural gas industry is subject to both environmental regulations and an increased environmental awareness. Peyto has reviewed its environmental risks and is, to the best of its knowledge, in compliance with the appropriate environmental legislation and have determined that there is no current material impact on 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, if appropriate, 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 Chief Financial Officer ("CFO"), 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 continues to evaluate 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 CFO. Based on this evaluation, the CEO and CFO 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 OVER FINANCIAL REPORTING Internal controls have been designed to provide reasonable assurance regarding the reliability of the Trust's financial reporting and the preparation of financial statements together with the other financial information for external purposes in accordance with the Canadian GAAP. The Trust's Chief Executive Officer and Chief Financial Officer have designed or caused to be designed under their supervision internal controls over financial reporting related to the Trust, including its consolidated subsidiaries. The Trust's Chief Executive Officer and Chief Financial Officer are required to cause the Trust to disclose herein any change in the Trust's internal control over financial reporting that occurred during the Trust's most recent interim period that materially affected, or is reasonably likely to materially affect the Trust's internal control over financial reporting. No material changes were identified in the Trust's internal control of financial reporting during the year ended December 31, 2007, that had materially affected, or are reasonably likely to materially affect, the Trust's internal control of financial reporting. It should be noted that a control system, including the Trust's disclosure and internal controls and procedures, no matter how well conceived, can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud. 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, 2007 were audited by independent petroleum engineers Paddock Lindstrom & Associates Ltd. Paddock has been evaluating reserves in this area and for Peyto for 9 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 year end independent reserves evaluation which was completed in January 2008. 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. RECENT ACCOUNTING PRONOUNCEMENTS As of January 1, 2008, the Trust adopted 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 additional disclosures required. As of January 1, 2008, the Trust adopted 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 additional disclosures required. As of January 1, 2009, the Trust will be required to adopt new CICA Handbook Section 3064 "Goodwill and Intangible Assets" which replaces Section 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs." Various changes have been made to other standards to be consistent with the new Section 3064, which establishes standards for the recognition, measurement, presentation and disclosure of goodwill and of intangible assets. Standards concerning goodwill are unchanged from the standards in the previous Section 3062. The Trust is assessing the impact of this new standard on its consolidated financial statements, however, the adoption is not expected to have a material impact on its consolidated financial statements. 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 Q4 Q3 Q2 Q1 ------------------------------------------------------------------------- Operations Production Natural gas (mcf/d) 104,749 97,000 101,812 106,183 Oil & NGLs (bbl/d) 3,675 3,573 3,540 3,607 Barrels of oil equivalent (boe/d @ 6:1) 21,134 19,740 20,509 21,305 Average product prices Natural gas ($/mcf) 7.67 7.61 8.59 9.77 Oil & natural gas liquids ($/bbl) 75.23 70.51 65.65 59.79 Average operating expenses ($/boe) 2.25 2.48 2.70 2.84 Average transportation costs ($/boe) 0.54 0.58 0.57 0.59 Field netback ($/boe) 39.54 38.57 41.21 44.82 General & administrative expense ($/boe) 0.87 0.82 1.10 0.98 Interest expense ($/boe) 3.19 3.10 2.95 2.96 Financial ($000 except per unit) Revenue 99,387 91,070 100,750 112,825 Royalties (net of ARTC) 17,080 15,482 17,734 20,326 Funds from operations 68,976 62,938 69,345 78,364 Funds from operations per unit 0.65 0.60 0.66 0.74 Total distributions 44,399 44,399 44,399 44,350 Total distributions per unit 0.42 0.42 0.42 0.42 Payout ratio 64% 71% 64% 57% Cash distributions (net of DRIP) 44,399 44,399 44,399 44,350 Payout ratio 64% 71% 64% 57% Earnings 73,289 39,886 38,825 56,883 Earnings per diluted unit 0.69 0.37 0.37 0.54 Capital expenditures 35,546 42,598 12,949 30,478 Weighted average trust units outstanding 105,712,364 105,712,364 105,712,364 105,542,484 ----------------------------------------------- 2006 Q4 Q3 ----------------------------------------------- Operations Production Natural gas (mcf/d) 112,296 115,304 Oil & NGLs (bbl/d) 3,834 4,205 Barrels of oil equivalent (boe/d at 6:1) 22,550 23,422 Average product prices Natural gas ($/mcf) 8.84 7.81 Oil & natural gas liquids ($/bbl) 54.89 64.50 Average operating expenses ($/boe) 2.69 1.90 Average transportation costs ($/boe) 0.52 0.58 Field netback ($/boe) 40.85 36.58 General & administrative expense ($/boe) 0.85 0.55 Interest expense ($/boe) 2.72 2.52 Financial ($000 except per unit) Revenue 110,696 107,844 Royalties (net of ARTC) 19,271 23,680 Funds from operations 77,360 72,360 Funds from operations per unit 0.74 0.69 Total distributions 44,206 44,111 Total distributions per unit 0.42 0.42 Payout ratio 57% 61% Cash distributions (net of DRIP) 44,206 41,019 Payout ratio 57% 57% Earnings 47,012 46,155 Earnings per diluted unit 0.44 0.44 Capital expenditures 28,413 71,223 Weighted average trust units outstanding 105,251,394 104,924,702 Peyto Energy Trust Consolidated Balance Sheets ($000) December 31, December 31, 2007 2006 ------------------------------------------------------------------------- Assets Current Cash 20,547 10,806 Accounts receivable 47,728 53,418 Due from private placements (Note 7) - 5,042 Financial derivative assets (Notes 3 and 13) 7,405 - Prepaid expenses and deposits 5,020 2,681 ------------------------------------------------------------------------- 80,700 71,947 Property, plant and equipment (Note 4) 1,111,532 1,064,753 ------------------------------------------------------------------------- 1,192,232 1,136,700 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Liabilities and Unitholders' Equity Current Accounts payable and accrued liabilities 85,923 70,836 Cash distributions payable 14,800 14,735 Provision for future performance based compensation 16 - Future income taxes (Note 12) 2,285 - ------------------------------------------------------------------------- 103,024 85,571 ------------------------------------------------------------------------- Long-term debt (Note 5) 430,000 420,000 Provision for future performance based compensation 253 - Asset retirement obligations (Note 6) 6,766 5,767 Future income taxes (Note 12) 123,197 135,650 ------------------------------------------------------------------------- 560,216 561,417 ------------------------------------------------------------------------- Unitholders' equity Unitholders' capital (Note 7) 406,301 398,434 Units to be issued (Note 7) - 5,042 Accumulated earnings (Note 8) 117,572 86,236 Accumulated other comprehensive income 5,119 - ------------------------------------------------------------------------- 528,992 489,712 ------------------------------------------------------------------------- 1,192,232 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) For the years ended December 31, 2007 2006 ------------------------------------------------------------------------- Revenue Petroleum and natural gas sales, net 333,411 350,562 ------------------------------------------------------------------------- Expenses Operating (Note 9) 19,359 18,046 Transportation 4,296 4,856 General and administrative (Note 10) 7,125 3,966 Performance based compensation (Note 11) 7,133 12,311 Future performance based compensation 269 (10,149) Interest on long term debt 23,007 18,011 Depletion, depreciation and accretion (Notes 4 and 6) 75,791 81,098 ------------------------------------------------------------------------- 136,980 128,139 ------------------------------------------------------------------------- Earnings before taxes 196,431 222,423 ------------------------------------------------------------------------- Taxes Future income tax expense (Note 12) (12,453) 27,357 Capital tax expense - (162) ------------------------------------------------------------------------- (12,453) 27,195 ------------------------------------------------------------------------- Net earnings for the year 208,884 195,228 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Earnings per unit (Note 7) Basic 1.98 1.86 Diluted 1.98 1.86 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Comprehensive Income ($000) For the years ended December 31, 2007 2006 ------------------------------------------------------------------------- Net earnings for the year 208,884 195,228 Other comprehensive income (loss) Change in unrealized gain on cash flow hedges, net of tax of $2,178 4,880 - Realized (gain) loss on cash flow hedges, net of tax $10,356 (23,202) - ------------------------------------------------------------------------- Comprehensive Income (Note 3) 190,562 195,228 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Accumulated Earnings and Accumulated Other Comprehensive Income ($000) For the years ended December 31, 2007 2006 ------------------------------------------------------------------------- Accumulated earnings, beginning of year 86,236 64,763 Net earnings for the year 208,884 195,228 Distributions (Note 8) (177,548) (173,755) ------------------------------------------------------------------------- Accumulated earnings, end of year 117,572 86,236 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Accumulated other comprehensive income, beginning of year - - Adoption of financial instruments, net of tax of $10,463 (Notes 3 and 13) 23,441 - Other comprehensive income (Notes 3 and 13) (18,322) - ------------------------------------------------------------------------- Accumulated other comprehensive income, end of year 5,119 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Cash Flows ($000) For the years ended December 31, 2007 2006 $ $ ------------------------------------------------------------------------- Cash provided by (used in) Operating Activities Net earnings for the year 208,884 195,228 Items not requiring cash: Future performance based compensation 269 (10,149) Future income tax expense (12,453) 27,357 Depletion, depreciation and accretion 75,791 81,098 Change in non-cash working capital related to operating activities (Note 14) 16,215 (37,489) ------------------------------------------------------------------------- 288,706 256,045 ------------------------------------------------------------------------- Financing Activities Issue of trust units, net of costs 2,825 30,857 Cash distributions paid (net of DRIP) (177,548) (158,204) Increase in bank debt 10,000 240,000 Change in non-cash working capital related to financing activities (Note 14) 5,107 25,613 ------------------------------------------------------------------------- (159,616) 138,266 ------------------------------------------------------------------------- Investing Activities Additions to property, plant and equipment (121,571) (311,926) Change in non-cash working capital related to investing activities (Note 14) 2,222 (71,579) ------------------------------------------------------------------------- (119,349) (383,505) ------------------------------------------------------------------------- Net increase (decrease) in cash 9,741 10,806 Cash, beginning of year 10,806 - ------------------------------------------------------------------------- Cash, end of year 20,547 10,806 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Notes to Consolidated Financial Statements December 31, 2007 and 2006 1. Nature of Operations Peyto Energy Trust (the "Trust") is an unincorporated open-ended limited purpose trust established under the laws of the Province of Alberta. The Trust indirectly owns all of the securities of Peyto Exploration & Development Corp. ("Peyto") which entitles the Trust to receive all cash flow available for distribution from the business of Peyto after debt service payments, maintenance capital expenditures and other cash requirements. The unitholders of the Trust are entitled to receive cash distributions paid by the Trust and are entitled to one vote for each Trust unit held at unitholder meetings. The Trust units trade on the TSX under the symbol "PEY.UN". The Trust's principal business activity is the exploration for and development and production of petroleum and natural gas in western Canada. 2. Summary of Significant Accounting Policies These consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles. Because a precise determination of many assets and liabilities is dependent upon future events, the preparation of periodic financial statements necessarily involves the use of estimates and approximations. Accordingly, actual results could differ from those estimates. The financial statements have, in management's opinion, been properly prepared within reasonable limits of materiality and within the framework of the Trust's accounting policies summarized below. These financial statements include the accounts of the Trust and its wholly owned subsidiaries, Peyto and Peyto Operating Trust ("POT"). Joint operations The Trust conducts a portion of its petroleum and natural gas exploration, development and production activities jointly with others and, accordingly, these consolidated financial statements reflect only the Trust's proportionate interest in such activities. Property, plant and equipment The Trust follows the full cost method of accounting for its petroleum and natural gas properties. All costs related to the acquisition, exploration and development of petroleum and natural gas reserves are capitalized. Such costs include lease acquisition costs, geological and geophysical costs, carrying charges of non-producing properties, costs of drilling both productive and non-productive wells, the cost of petroleum and natural gas production equipment and overhead charges related to exploration and development activities. All other general and administrative costs are expensed as incurred. The Trust evaluates its petroleum and natural gas assets to determine that the costs are recoverable and do not exceed the fair value of the properties ("ceiling test"). The costs are assessed to be recoverable if the sum of the undiscounted cash flows expected from the production of proved reserves plus the cost of unproved properties, less impairment, exceed the carrying value of the oil and gas assets. If the carrying value of the petroleum and natural gas properties is not determined to be recoverable, an impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves plus the cost of unproved properties. The cash flows are estimated using the future product prices and costs and are discounted using a risk-free rate. Proceeds from the disposition of petroleum and natural gas properties are applied against capitalized costs except for dispositions that would change the rate of depletion and depreciation by 20% or more, in which case a gain or loss would be recorded. All costs of acquisition, exploration and development of petroleum and natural gas reserves (net of salvage value) and estimated costs of future development of proved undeveloped reserves are depleted and depreciated using the unit of production method based on estimated gross proved reserves as determined by independent engineers. For purposes of the depletion and depreciation calculation, relative volumes of petroleum and natural gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Costs of unproved properties are initially excluded from petroleum and natural gas properties for the purpose of calculating depletion. When proved reserves are assigned to the property or it is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion. Depreciation of gas plants and related facilities is calculated on a straight-line basis over a 20-year term. Office furniture and equipment are depreciated over their estimated useful lives at declining balance rates between 20% and 30%. Asset retirement obligations The Trust records a liability for the fair value of legal obligations associated with the retirement of long-lived tangible assets in the period in which they are incurred, normally when the asset is purchased or developed. On recognition of the liability there is a corresponding increase in the carrying amount of the related asset known as the asset retirement cost, which is depleted on a unit-of- production basis over the life of the reserves. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings, and for revisions to the estimated future cash flows. Actual costs incurred upon settlement of the obligations are charged against the liability. Hedging The Trust uses derivative financial instruments from time to time to hedge its exposure to commodity price fluctuations. The Trust does not enter into derivative financial instruments for trading or speculative purposes. All derivative financial instruments are initiated within the guidelines of the Trust's risk management policy. This includes linking all derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Trust enters into hedges of its exposure to petroleum and natural gas commodity prices by entering into crude oil and natural gas swap contracts, options or collars, when it is deemed appropriate. These derivative contracts, accounted for as hedges, are recognized on the balance sheet. Realized gains and losses on these contracts are recognized in petroleum and natural gas revenue and cash flows in the same period in which the revenues associated with the hedged transaction are recognized. Premiums paid or received are deferred and amortized to earnings over the term of the contract. For financial derivative contracts settling in future periods, a financial asset or liability is recognized in the balance sheet and measured at fair value, with changes in fair value recognized in other comprehensive income. Revenue recognition Petroleum and natural gas sales are recognized as revenue when title passes to purchasers, normally at pipeline delivery point for natural gas and at the wellhead for crude oil. Measurement uncertainty The amounts recorded for depletion and depreciation of property, plant and equipment, the asset retirement obligation and the ceiling test calculation are based on estimates of gross proved reserves, production rates, petroleum and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future years could be significant. Future income taxes The Trust follows the liability method of tax allocation. Under this method future income tax assets and liabilities of its subsidiaries are determined based on differences between financial reporting and income tax bases of assets and liabilities, and are measured using substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse. 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. 3. 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 retrospectively without restatement. 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. As at January 1, 2007, the Trust has made the following classifications: --------------------------------------------------------------------- Financial Assets & Liabilities Category --------------------------------------------------------------------- Cash Held for trading --------------------------------------------------------------------- Accounts Receivable Loans & receivables --------------------------------------------------------------------- Due from Private Placement Loans & receivables --------------------------------------------------------------------- Accounts Payable & Accrued Liabilities Other Liabilities --------------------------------------------------------------------- Provision for Future Performance Based Compensation Other Liabilities --------------------------------------------------------------------- Cash Distributions Payable Other Liabilities --------------------------------------------------------------------- Long Term Debt Other Liabilities --------------------------------------------------------------------- Risk Management Contracts Held for trading --------------------------------------------------------------------- b) Derivative Instruments and Hedging Activities Derivative instruments are utilized by the Trust to manage market risk against 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 to be treated as a financial derivative. 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 Handbook 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 of the period of change. 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 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 additional disclosures required. As of January 1, 2009, the Trust will be required to adopt new CICA Handbook Section 3064 "Goodwill and Intangible Assets" which replaces Section 3062 "Goodwill and Other Intangible Assets" and Section 3450 "Research and Development Costs." Various changes have been made to other standards to be consistent with the new Section 3064, which establishes standards for the recognition, measurement, presentation and disclosure of goodwill and of intangible assets. Standards concerning goodwill are unchanged from the standards in the previous Section 3062. The Trust is assessing the impact of this new standard on its consolidated financial statements, however, the adoption is not expected to have a material impact on its consolidated financial statements. 4. Property, Plant and Equipment ($000) 2007 2006 --------------------------------------------------------------------- Property, plant and equipment 1,410,767 1,288,616 Accumulated depletion and depreciation (299,235) (223,863) --------------------------------------------------------------------- 1,111,532 1,064,753 --------------------------------------------------------------------- --------------------------------------------------------------------- At December 31, 2007 costs of $37,825,472 (December 31, 2006 - $38,939,577) related to undeveloped land have been excluded from the depletion and depreciation calculation. The Trust performed a ceiling test calculation at December 31, 2007 resulting in the undiscounted cash flows from proved reserves plus the cost of unproved properties, less impairment, exceeding the carrying value of petroleum and natural gas assets. The impairment test was calculated at December 31, 2007 using the following independent engineering consultant's forecasted prices: There- after 2008 2009 2010 2011 2012 (2) --------------------------------------------------------------------- Edmonton Ref Price ($CDN/bbl)(1) 88.75 86.73 82.70 80.67 78.65 +2% --------------------------------------------------------------------- AECO ($CDN/mmbtu) 6.80 7.28 7.43 7.58 7.73 +2% --------------------------------------------------------------------- (1) Future prices incorporated a $1.00 US/CDN exchange rate. (2) Percentage change of 2.0% represents the change in future prices each year after 2012 to the end of the reserve life. 5. Long-Term Debt The Trust has a syndicated $525 million extendible revolving credit facility with a stated term date of April 30, 2008. 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 cash flow ratio that range from prime to prime plus 0.75% for debt to earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) ratios 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. The average borrowing rate for 2007 was 5.7% (2006 - 5.0%). 6. Asset Retirement Obligations The total future asset retirement obligations are estimated by management based on the Trust's net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods. The Trust has estimated the net present value of its total asset retirement obligations to be $6.8 million as at December 31, 2007 (2006 - $5.8 million) based on a total future liability of $25.9 million (2006 - $23.1 million). These payments are expected to be made over the next 50 years. The Trust's credit adjusted risk free rate of 7% and an inflation rate of 2% were used to calculate the present value of the asset retirement obligations. The following table reconciles the change in asset retirement obligations: ($000) 2007 2006 --------------------------------------------------------------------- Balance, beginning of year 5,767 4,729 Increase in liabilities 581 686 Accretion expense 418 352 --------------------------------------------------------------------- Balance, end of year 6,766 5,767 --------------------------------------------------------------------- --------------------------------------------------------------------- 7. Unitholders' Capital Authorized: Unlimited number of voting trust units Issued and Outstanding Trust Units (no par value) ($000) Number of Units Amount --------------------------------------------------------------------- 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, December 31, 2007 105,712,364 406,301 --------------------------------------------------------------------- --------------------------------------------------------------------- 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. Units to be Issued At December 31, 2007, there were no trust units to be issued. On December 31, 2006 the Trust completed a private placement of 285,190 trust units to employees and consultants for net proceeds of $5,042,159. These trust units were issued on January 12, 2007. Per Unit Amounts Earnings per unit have been calculated based upon the weighted average number of units outstanding during the year of 105,712,364 (2006 - 104,554,325). There are no dilutive instruments outstanding. Redemption of Units The Trust Units are redeemable at any time on demand by the holders thereof. Upon receipt of proper notice to redeem Trust Units by the Trust, the holder thereof shall only be entitled to receive a price per Trust Unit equal to the lesser of: (a) 90% of the market price of the Trust Units on the principal market on which the Trust Units are quoted for trading during the 10 trading day period commencing immediately after the date on which the Trust Units are tendered to the Trust for redemption; and (b) the closing market price on the principal market on which the Trust Units are quoted for trading on the date that the Trust Units are so tendered for redemption. 8. Accumulated Cash Distributions During the year, the Trust paid distributions to the unitholders in the aggregate amount of $177.5 million (2006 - $173.8 million total; $158.2 million cash) 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 14, 2007 $0.14 July 2007 July 31, 2007 August 15, 2007 $0.14 August 2007 August 31, 2007 September 15, 2007 $0.14 September 2007 September 30, 2007 October 13, 2007 $0.14 October 2007 October 31, 2007 November 15, 2007 $0.14 November 2007 November 30, 2007 December 15, 2007 $0.14 December 2007 December 31, 2007 January 15, 2008 $0.14 Accumulated Earnings and Distributions ($000) 2007 2006 --------------------------------------------------------------------- Opening accumulated earnings 531,154 335,926 Net earnings for the year 208,884 195,228 --------------------------------------------------------------------- Total accumulated earnings 740,038 531,154 Total accumulated distributions (622,466) (444,918) --------------------------------------------------------------------- Accumulated earnings 117,572 86,236 --------------------------------------------------------------------- 9. 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. ($000) 2007 2006 Field expenses 28,433 25,765 Processing and gathering income (9,074) (7,719) --------------------------------------------------------------------- Total operating costs 19,359 18,046 --------------------------------------------------------------------- --------------------------------------------------------------------- 10. General and Administrative Expenses General and administrative expenses are reduced by operating and capital overhead recoveries from operated properties. ($000) 2007 2006 --------------------------------------------------------------------- General and Administrative expenses 10,242 9,397 Overhead recoveries (3,117) (5,431) --------------------------------------------------------------------- Net General and Administrative expenses 7,125 3,966 --------------------------------------------------------------------- 11. Performance Based Compensation The Trust awards performance based compensation to employees and key consultants annually. The performance based compensation is comprised of market and reserve value based components. The reserves value based component is 4% of the incremental increase in value, if any, as adjusted to reflect changes in debt, equity and distributions, of proved producing reserves calculated using a constant price at December 31 of the current year and a discount rate of 8%. --------------------------------------------------------------------- ($millions except unit values) 2007 2006 Change --------------------------------------------------------------------- Net present value of proved producing reserves @ 8% based on constant Paddock Lindstrom 2008 price forecast 1,725.0 1,708.0 Net debt before performance based compensation (450.3) (433.6) 2007 distributions - (177.5) ------------------------------- Net value 1,274.7 1,096.9 177.8 Equity adjustment factor(*) 100% --------- Equity adjusted increase in value 177.8 --------- 2007 reserve value based compensation @ 4% 7.1 --------------------------------------------------------------------- --------------------------------------------------------------------- (*) Equity adjustment factor is calculated as the percent increase in value per unit divided by the total percent increase in value 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 2008, a tax factor of 1.333 will then be applied to determine the amount to be paid. Commencing for rights vesting in 2009, no tax factor will be applied to determine the amount paid. The 2007 market based component was based on 1.2 million vested rights at an average grant price of $24.16, average cumulative distributions of $4.73 and the five day weighted average closing price of $16.48 (2006 - 1.5 million rights, average grant price of $18.77, average cumulative distributions of $3.86 per unit and five day weighted average closing price of $17.68). The total amount expensed under these plans was as follows: ($000) 2007 2006 Market based compensation 13 8,491 Reserve value based compensation 7,120 4,570 Recovery of prior year unpaid reserve bonus - (750) --------------------------------------------------------------------- Total 7,133 12,311 --------------------------------------------------------------------- --------------------------------------------------------------------- For the future market based component, compensation costs as at December 31, 2007 related to 3.0 million non-vested rights with an average grant price of $21.04 were $0.3 million (2006 - nil). 12. Future Income Taxes ($000) 2007 2006 --------------------------------------------------------------------- Earnings before income taxes 196,431 222,423 Statutory income tax rate 32.12% 36.75% --------------------------------------------------------------------- Expected income taxes 63,094 81,740 Increase (decrease) in income taxes from: Non-deductible crown charges - 10,328 Resource allowance - (11,812) Corporate income tax rate change (21,357) (2,397) Income attributed to the trust (51,933) (50,823) Change in valuation allowance for share issue costs (1,000) 1,000 Other (1,257) (679) --------------------------------------------------------------------- Future income tax expense (12,453) 27,357 --------------------------------------------------------------------- --------------------------------------------------------------------- The net future income tax liability is comprised of: ($000) 2007 2006 --------------------------------------------------------------------- Financial derivative assets 2,285 - --------------------------------------------------------------------- Current future income taxes 2,285 - --------------------------------------------------------------------- --------------------------------------------------------------------- Differences between tax base and reported amounts for depreciable assets 124,973 137,322 Accrued expenditures (85) - Provision for asset retirement obligation (1,691) (1,672) --------------------------------------------------------------------- Future income taxes 123,197 135,650 --------------------------------------------------------------------- --------------------------------------------------------------------- At December 31, 2007 the Trust has tax pools of approximately $660.1 million (December 31, 2006 - $670.8 million) available for deduction against future income. The Trust has approximately $2.0 million in unrecognized future income tax assets available to reduce future taxable income. 13. Financial Instruments The following summarizes the retrospective without restatement adoption adjustments that were required as at January 1, 2007. December 31, 2006 Adoption January 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 10,463 146,113 --------------------------------------------------------------------- Accumulated other comprehensive income - 23,441 23,441 --------------------------------------------------------------------- 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 December 31, 2007 is as follows: Weighted Crude Oil Daily Average Period Hedged Type Volume Price (CAD) --------------------------------------------------------------------- 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 Natural Gas Daily Average Period Hedged Type Volume Price (CAD) --------------------------------------------------------------------- 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 $9.10/GJ Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.55/GJ Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $6.40/GJ Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $6.30/GJ Dec 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $6.70/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.85/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $6.60/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $6.40/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $6.60/GJ April 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $6.82/GJ Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $7.25/GJ Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $7.50/GJ Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $7.60/GJ As at December 31, 2007, the Trust had committed to the future sale of 45,500 barrels of crude oil at an average price of $78.85 per barrel and 12,465,000 gigajoules (GJ) of natural gas at an average price of $7.34 per GJ or $8.59 per mcf based on the historical heating value of Peyto's natural gas. These contracts will generate revenue totaling $95.1 million. Based on the market's estimate of the future commodity prices as at December 31, 2007 the fair value of these contracts would be $87.7 million. Had these contracts been closed on December 31, 2007, the Trust would have realized a gain in the amount of $7.4 million. Subsequent to December 31, 2007 the Trust entered into the following contracts: Natural Gas Daily Price Period Hedged Type Volume (CAD) --------------------------------------------------------------------- April 1 to October 31, 2008 Fixed price 5,000 GJ $6.80/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.05/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.20/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.10/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.20/GJ April 1 to October 31, 2008 Fixed price 5,000 GJ $7.40/GJ April 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $7.05/GJ Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.00/GJ Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.25/GJ Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.40/GJ Nov 1, 2008 to March 31, 2009 Fixed price 5,000 GJ $8.65/GJ Fair Values of Financial Assets and Liabilities The Trust's financial instruments include cash, accounts receivable, due from private placements deposits, current liabilities, provision for future performance based compensation and long-term debt. At December 31, 2007, the carrying value of cash, accounts receivable, due from private placements deposits, current liabilities excluding future income tax 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 December 31, 2007, approximately 31% was due from one company (December 31, 2006 - 41%). Of the Trust's revenue for the year ended December 31, 2007 approximately 57% was received from two companies (December 31, 2006 - 59%). 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 due to the floating rate nature of the interest expense on its revolving demand facility. 14. Supplemental Cash Flow Information Changes in non-cash working capital balances ($000) 2007 2006 --------------------------------------------------------------------- Accounts receivable 5,690 29,376 Due from private placement 5,042 22,408 Prepaid expenses and deposits (2,339) (886) Accounts payable and accrued liabilities 15,087 (137,448) Capital taxes payable - (110) Cash distributions payable 64 3,205 --------------------------------------------------------------------- 23,544 (83,455) Attributable to financing activities 5,107 25,613 Attributable to investing activities 2,222 (71,579) --------------------------------------------------------------------- Attributable to operating activities 16,215 (37,489) --------------------------------------------------------------------- --------------------------------------------------------------------- 2007 2006 --------------------------------------------------------------------- Cash interest paid during the year 23,007 18,011 --------------------------------------------------------------------- --------------------------------------------------------------------- 15. Contingencies and Commitments a) Contingent Liability From time to time, Peyto is the subject of litigation arising out of its day-to-day operations. Damages claimed pursuant to such litigation, including the litigation discussed below, may be material or may be indeterminate and the outcome of such litigation may materially impact Peyto's financial position or results of operations in the period of settlement. 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 add a subsidiary as an additional Plaintiff and 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 the Trust's financial position or results of operations. b) Commitments The Trust is committed to payments under operating leases for office space as follows: ($000) --------------------------------------------------------------------- 2008 1,097 2009 1,097 2010 1,097 2011 1,097 --------------------------------------------------------------------- 4,388 --------------------------------------------------------------------- --------------------------------------------------------------------- 16. 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. For the year ended December 31, 2007, legal fees totaled $1,051,643 (2006 - $695,563). As at December 31, 2007, an amount due to this firm of $844,191 was included in accounts payables (2006 - $361,163) 17. Subsequent Event On January 1, 2008, the Trust completed an internal reorganization, whereby (1) all of the oil and gas assets of the Trust are now held in the newly formed Peyto Energy Limited Partnership (the "Partnership"), (2) Peyto Energy Administration Corp. is the administrator of the Trust and POT and (3) Peyto is the general partner of the Partnership. Certain subsidiaries of the Trust were amalgamated pursuant to the internal reorganization. Peyto Exploration & Development Corp. Information Officers Darren Gee Scott Robinson President and Chief Executive Officer Executive Vice President and Chief Operating Officer Glenn Booth Kathy Turgeon Vice President, Land Vice President, Finance and Chief Financial 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 Head Office 2900, 450 - 1st Street SW Calgary, AB T2P 5H1 Phone: 403.261.6081 Fax: 403.451.4100 Web: www.peyto.com Stock Listing Symbol: PEY.un Toronto Stock Exchange %SEDAR: 00019597E

For further information:

For further information: Head Office, 2900, 450 - 1st Street SW,
Calgary, AB, T2P 5H1, Phone: (403) 261-6081, Fax: (403) 451-4100, Web:
www.peyto.com

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PEYTO ENERGY TRUST

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