Peyto Energy Trust announces third quarter 2007 results



    SYMBOL: PEY.UN - TSX

    CALGARY, Nov. 7 /CNW/ - Peyto Energy Trust ("Peyto") is pleased to
present the operating and financial results for the third quarter of the 2007
fiscal year. Peyto is a conventional oil and gas business that builds tight
natural gas assets in Alberta's Deep Basin and produces one of the cleanest
burning fossil fuels available.
    Peyto is well known for owning high quality, sweet gas assets that
exhibit long reserve life, low operating costs and high revenue per boe. The
following summarizes the Trust's foundation:

    
    -   Long reserve life - Proved 14 years, Proved plus Probable 20 years,
        at the end of 2006
    -   Low operating costs - $2.48/boe, three months ending September 30,
        2007
    -   High revenue natural gas - $42.39/boe before hedging, $50.15/boe
        after hedging, three months ending September 30, 2007
    -   Low base general and administrative costs - $0.82/boe, three months
        ending September 30, 2007
    -   High field netback - $38.57/boe, three months ending September 30,
        2007
    -   High operatorship - operates over 95% of its production
    -   Cash distributions - cash distributions of $44.4 million were 71% of
        funds from operations for the three months ended September 30, 2007
    -   Low debt to funds from operations ratio - 1.7:1 (net debt, before
        provision for future compensation, divided by annualized third
        quarter 2007 funds from operations)
    -   Distribution growth - distributions have been increased 5 times; they
        have never decreased, and are now 87% higher than when the trust was
        formed in July, 2003
    -   Since inception, Peyto has raised a total of $406 million issuing
        units from treasury, accumulated earnings of $667 million, and
        distributed $578 million to unitholders
    -   Transparent capital structure - no convertible debentures, no
        exchangeable shares, no stock options, no warrants

    The third quarter was highlighted by sustained distributions, an
accelerated pace of capital investment and improved capital efficiency that
maintained Peyto's financial flexibility. The following summarizes performance
highlights of the business for the third quarter of 2007:

    -   Capital expenditures - $42.6 million was invested into finding and
        developing new natural gas reserves, up from $12.9 million in the
        previous quarter, but down from $71.2 million in Q3 2006. Capital
        expenditures for the first three quarters of 2007 were $86 million
        versus $284 million for the first three quarters of 2006, a reduction
        of 70%
    -   Production - decreased 16% from 23,422 boe/d in the third quarter of
        2006 to 19,740 boe/d in the third quarter of 2007
    -   Production per unit - decreased 18% per trust unit from the third
        quarter of 2006, after adjusting for debt and future unrealized
        performance based compensation
    -   Per unit funds from operations - decreased 13% from the previous year
        to $0.69/unit
    -   Commodity prices - natural gas prices, both before and after hedges,
        were lower in Q3 2007 with prices averaging $6.07/mcf and $7.61/mcf
        respectively versus $6.53/mcf and $7.81/mcf in Q3 2006
    -   Hedging - a $14.1 million gain for the three months ending
        September 30, 2007 was realized
    -   Distributions per unit were unchanged from the third quarter of 2006
        while the cash payout ratio increased to 71% from 61% in Q3 2006. A
        total of $44.4 million or $0.42 per unit was distributed to
        unitholders in the third quarter of 2007
    -   Net debt increased 2% from $431 million in Q3 2006 to $439 million in
        Q3 2007. This leaves available borrowing capacity of $86 million on
        bank lines of $525 million

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

    -------------------------------------------------------------------------
                  3 Months Ended Sep 30   %      9 Months Ended Sep 30   %
                     2007        2006   Change      2007        2006   Change
    -------------------------------------------------------------------------
    Operations
    Production
      Natural gas
       (mcf/d)       97,000     115,304  (16)%     101,632     112,905  (10)%
      Oil & NGLs
       (bbl/d)        3,573       4,205  (15)%       3,573       4,164  (14)%
      Barrels of oil
       equivalent
       (boe/d @
       6:1)          19,740      23,422  (16)%      20,512      22,982  (11)%
    Product prices
      Natural gas
       ($/mcf)         7.61        7.81   (3)%        8.68        8.33     4%
      Oil & NGLs
       ($/bbl)        70.51       64.50     9%       65.34       62.89     4%
    Operating
     expenses
     ($/boe)           2.48        1.90    31%        2.67        1.99    34%
    Transportation
     ($/boe)           0.58        0.58     0%        0.58        0.60   (3)%
    Field netback
     ($/boe)          38.57       36.58     5%       41.59       38.72     7%
    General &
     administrative
     expenses
     ($/boe)           0.82        0.55    49%        0.97        0.35   177%
    Interest expense
     ($/boe)           3.10        2.52    23%        3.00        1.97    52%

    Financial
     ($000, except
     per unit)

    Revenue          91,070     107,844  (16)%     304,646     328,313   (7)%
    Royalties (net
     of ARTC)        15,481      23,680  (35)%      53,541      69,175  (23)%
    Funds from
     operations      62,938      72,360  (13)%     210,647     228,485   (8)%
    Funds from
     operations
     per unit          0.60        0.69  (13)%        1.99        2.17   (8)%
    Total
     distributions   44,399      44,111     1%     133,148     129,549     3%
    Total
     distributions
     per unit          0.42        0.42     0%        1.26        1.24     2%
      Payout ratio       71          61    16%          63          57    11%
    Cash
     distributions
     (net of DRIP)   44,399      41,019     8%     133,148     113,999    17%
      Payout ratio       71          57    25%          63          50    26%
    Earnings         39,886      46,155  (14)%     135,594     148,216   (9)%
    Earnings per
     diluted unit      0.37        0.44  (16)%        1.28        1.42  (10)%
    Capital
     expenditures    42,598      71,223  (40)%      86,024     283,513  (70)%
    Weighted
     average
     trust units
     out-
     standing   105,712,364 104,924,702     1% 105,656,359 104,554,325     1%

    As at
     September 30
    Net debt
     (before future
     compensation
     expense)                                      439,325     431,097
    Unitholders'
     equity                                        507,744     481,863
    Total assets                                 1,164,561   1,110,547


    -------------------------------------------------------------------------
                                          3 Months Ended      9 Months Ended
                                              Sep 30              Sep 30
                                          2007      2006      2007      2006
    -------------------------------------------------------------------------
    Net Earnings                        39,886    46,155   135,594   148,216
    Items not requiring cash:
      Non-cash provision for (recovery
      of) performance based compensation   202    (2,005)      640       192
      Future income tax expense          4,808     7,821    17,774    19,376
      Depletion, depreciation and
       accretion                        18,042    20,389    56,639    60,701
    -------------------------------------------------------------------------
    Funds from operations (1)           62,938    72,360   210,647   228,485
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Funds from operations
    

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

    Quarterly Review

    During the third quarter, Peyto experienced improved capital efficiency
from lower service costs and reduced industry activity. Accordingly, Peyto
increased its pace of activity which resulted in $42.6 million being invested
into designing, drilling and building new producing gas assets in the Deep
Basin. Drilling and completions accounted for $31.5 million while wellsite
equipment, pipelines and facilities accounted for $10.1 million. Acquisition
of new land and seismic data made up the remaining $1.0 million.

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

    Funds from
     operations         62.9    69.3    78.4    77.4    72.4    77.5    78.6
    Distributions      -44.4   -44.4   -44.4   -44.2   -44.1   -43.9   -41.5
    Capital
     Expenditures      -42.6   -12.9   -30.5   -28.4   -71.2   -67.2  -145.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total              -24.1    12.0     3.5     4.7   -43.0   -33.6  -108.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    ---------------------------------
                             2005
    $ millions            Q4      Q3
    ---------------------------------

    Funds from
     operations         86.6    77.2
    Distributions      -36.8   -35.5
    Capital
     Expenditures     -107.6   -93.0
    ---------------------------------
    ---------------------------------
    Total              -57.8   -51.3
    ---------------------------------
    ---------------------------------
    

    In the third quarter, the Trust drilled 19 gross (13.9 net, 73% working
interest) gas wells, completed 27 gross (22.8 net) gas zones and brought 16
gross (13.6 net) zones on production. Many of these new zones were brought on
towards the latter part of the quarter and, as a result, were not fully able
to offset the base production decline. Production for the quarter averaged
19,740 boe/d, down from 20,509 boe/d in the second quarter.
    Despite spiking power prices in July, operating costs were $2.48/boe for
the third quarter and $2.67/boe for the year to date. Peyto continues to be
one of the lowest cost producers of natural gas in North America. Royalties
paid out, as a percentage of revenues, were 17% for the period or $8.52/boe.
    Natural gas prices for the third quarter averaged $7.61/mcf and liquids
prices averaged $70.51/bbl combining to deliver revenue of $50.15/boe versus
$50.05/boe in Q3 2006. The combination of high quality production and low
operating costs yielded very strong field netbacks of $38.57/boe, 5% higher
than a year ago.

    Activity Update

    To date in 2007, Peyto has drilled 45 gross (36 net) wells and brought on
production 48 gross (36.6 net) gas zones. The increased level of activity
since spring breakup has resulted in building over 3,500 boe/d of new
production for the year. Current production is approximately 21,000 boe/d.
Peyto's Chime pipeline is now operational and connects gas production from
this area to its Kakwa gas plant. Additional development in the Chime area
will now enjoy a much improved processing cost. Fourth quarter plans include
slightly reduced activity to maintain financial flexibility in light of softer
2007/08 winter gas prices relative to the gas price offered for the following
two seasons. Two to three drilling rigs will be focused primarily in the
Greater Sundance area while additional opportunities are finalized in new
expansion areas.

    Marketing

    US working gas in storage is currently at the high end of the five year
range. This has set the upcoming winter price for natural gas around
US$8.50/mmbtu in New York. Unfortunately, this is not the price received in
Alberta. After adjusting for currency exchange and transportation from Alberta
to New York, the gas price is reduced to approximately CDN$7.00/mmbtu. The
recent strength of the Canadian dollar has increased the price gap between
these two receipt points. Despite this negative currency effect, the natural
gas price offered in Alberta for this winter is still higher than the monthly
average gas price received in three of the last four winters.
    Consistent with our marketing strategy, Peyto has committed to forward
sell 91,500 barrels of crude oil at an average price of $78.55 per barrel and
9,320,000 gigajoules (GJ) of natural gas at an average price of $8.05 per GJ
or $9.42 per mcf. The high heat content nature of Peyto's gas production
generates this 17% premium price by volume. Had these contracts been closed on
September 30, 2007, the Trust would have realized a gain of $18.5 million.

    Alberta's New Royalty Framework

    On October 25, 2007, the Provincial Government of Alberta announced a new
royalty framework. The new framework incorporated some of the recommendations
from the Alberta Royalty Review Panel's September report which was entitled
"Our Fair Share." The new royalty framework outlines new royalty rates for all
oil and gas produced in the Province starting January 1, 2009. In almost all
cases and for all foreseeable commodity prices, the government take will
increase. Effectively, 100% of Peyto's reserve assets are located in Alberta
and will be subject to the new royalty rates. Peyto has evaluated the new
royalty rates, inclusive of depth factor adjustments, against the current
production and at current gas prices, and has determined that they should have
a minor negative impact on cashflow but an immaterial impact on the overall
producing net asset value.
    In its 9 year history, Peyto has invested over $1.4 billion in capital
projects in Alberta. Those investments have employed thousands of oilfield
workers every year in the greater Edson and Hinton areas. As a result of those
investments and by taking those risks, Peyto has found and developed gas
reserves that have already paid over $400 million in royalties and may
ultimately pay in excess of $1.6 billion. "As long as Alberta remains good for
Peyto, Peyto will remain good for Alberta."

    Outlook

    In Alberta, industry utilization of services remains low, putting
pressure on the service sector to continue reducing rates. This ongoing cost
savings is improving Peyto's return on capital investment, and will ultimately
assist in offsetting the additional royalty burden, thus allowing Peyto to
maintain its pace of activity. The Peyto team continues to add to the
abundance of Deep Basin drilling prospects already in inventory and, as
capital efficiency improves, available leverage can be employed to accelerate
those opportunities. Peyto's financial flexibility has been tested and proven
over the last few quarters, supported by the quality of the underlying assets.
The total production base is stabilizing, which means less capital is required
to maintain production and grow reserves. The sustainability of the Peyto
model is becoming self evident. Unitholders are encouraged to visit the Peyto
website at www.peyto.com where there is a wealth of information designed to
inform and educate investors.

    Conference Call and Webcast

    A conference call will be held with the senior management of Peyto to
answer questions with respect to the 2007 third quarter results on Thursday,
November 8, 2007 at 9:00 a.m. Mountain Standard Time (MST), 11:00 a.m. Eastern
Standard Time (EST). To participate, please call 1-416-644-3422 (Toronto area)
or 1-800-731-5319 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 21249902 followed by the pound key. The
replay will be available at 11:00 a.m. MST, 1:00 p.m. EST Thursday,
November 8, 2007 until midnight EST on Thursday, November 15, 2007. The
conference call can also be accessed through the internet at
http://www.newswire.ca/en/webcast/viewEvent.cgi?eventID=2043140 . After this
time the conference call will be archived on the Peyto Energy Trust website at
www.peyto.com.

    Darren Gee
    President and CEO
    November 7, 2007

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


    Management's discussion and analysis

    This Management's Discussion and Analysis ("MD&A") should be read in
conjunction with the unaudited interim consolidated financial statements for
the period ended September 30, 2007 and the audited consolidated financial
statements of Peyto Energy Trust ("Peyto") for the year ended December 31,
2006. The consolidated financial statements have been prepared in accordance
with Canadian generally accepted accounting principles ("GAAP").
    The Trust was created by way of a Plan of Arrangement effective July 1,
2003 which reorganized Peyto Exploration & Development Corp. ("PEDC") from a
corporate entity into a trust. Accordingly, the consolidated financial
statements were reported on a continuity of interests basis. This discussion
provides management's analysis of Peyto's historical financial and operating
results and provides estimates of Peyto's future financial and operating
performance based on information currently available. Actual results will vary
from estimates and the variances may be significant. Readers should be aware
that historical results are not necessarily indicative of future performance.
This MD&A was prepared using information that is current as of November 6,
2007. Additional information about Peyto, including the most recently filed
annual information form is available at www.sedar.com.
    Certain information set forth in this Management's Discussion and
Analysis, including management's assessment of the Trust's future plans and
operations, contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and uncertainties,
some of which are beyond these parties' control, including the impact of
general economic conditions, industry conditions, volatility of commodity
prices, currency fluctuations, imprecision of reserve estimates, environmental
risks, competition from other industry participants, the lack of availability
of qualified personnel or management, stock market volatility and ability to
access sufficient capital from internal and external sources. Readers are
cautioned that the assumptions used in the preparation of such information,
although considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on forward-looking
statements. Peyto's actual results, performance or achievement could differ
materially from those expressed in, or implied by, these forward-looking
statements and, accordingly, no assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or occur, or if
any of them do so, what benefits that Peyto will derive there from. Peyto
disclaims any intention or obligation to update or revise any forward-looking
statements, whether as a result of new information, future events or
otherwise.
    Management uses funds from operations to analyze the operating
performance of its energy assets. In order to facilitate comparative analysis,
funds from operations is defined throughout this report as earnings before
performance based compensation, non-cash and non-recurring expenses. We
believe that funds from operations is an important parameter to measure the
value of an asset when combined with reserve life. Funds from operations is
not a measure recognized by Canadian generally accepted accounting principles
("GAAP") and does not have a standardized meaning prescribed by GAAP.
Therefore, funds from operations, as defined by Peyto, may not be comparable
to similar measures presented by other issuers, and investors are cautioned
that funds from operations should not be construed as an alternative to net
earnings, cash flow from operating activities or other measures of financial
performance calculated in accordance with GAAP. Funds from operations cannot
be assured and future distributions may vary.
    To the best of our knowledge, Peyto's foreign ownership level currently
stands at approximately 33 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 Government Crown Royalty Regime Change

    On October 25, 2007, the Provincial Government of Alberta announced a new
royalty framework. The new framework incorporated some of the recommendations
from the Alberta Royalty Review Panel's September Report which was entitled
"Our Fair Share." The new royalty framework outlines new royalty rates for all
oil and gas produced in the Province starting January 1, 2009. In almost all
cases, and for all foreseeable commodity prices, the government take will be
increased. Effectively, 100% of Peyto's reserve assets are located in Alberta
and are subject to the new royalty rates. Peyto has evaluated the new royalty
rates, inclusive of depth factor adjustments, against the current production
and at current gas prices, and has determined that they should have a minor
negative impact on cashflow but an immaterial impact on producing net asset
value.

    Federal Government's Trust Tax Legislation

    On June 12, 2007, Bill C-52 ("Bill") was enacted for Canadian GAAP. The
Bill enacts the October 31, 2006 proposals to impose a new tax on
distributions from flow-through entities, including publicly traded income
trusts. This has not resulted in any change in the consolidated future income
tax calculation.
    Under this Bill, existing income trusts will be subject to the new
measures commencing in their 2011 taxation year, following a four-year grace
period. In simplified terms, under the proposed tax plan, income distributions
will first be taxed at the trust level at a special rate estimated to be
31.5%. Income distributions to individual unitholders will then be treated as
dividends from a Canadian corporation and eligible for the dividend tax
credit. Income distributions to corporations resident in Canada will be
eligible for full deduction as tax free intercorporate dividends. Tax-deferred
accounts (RRSPs, RRIFs and Pension Plans) will continue to pay no tax on
distributions. Non-resident unitholders will be taxed on distributions at the
non-resident withholding tax rate for dividends. The net impact on Canadian
taxable investors is expected to be minimal because they can take advantage of
the dividend tax credit. However, as a result of the 31.5% Distribution Tax at
the trust level, distributions to tax-deferred accounts will be reduced by
approximately 31.5%, and distributions to non-residents will be reduced by
approximately 26.5%. Pursuant to the October 30, 2007 mini-budget, these rates
may be decreased by 2%. Peyto is currently assessing the proposals and the
potential implications to the Trust. Structural alternatives will continue to
be reviewed to ensure that Peyto's structure is as efficient as possible.

    Climate Change Programs

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

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

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

    United States Proposed Changes to Qualifying Dividends

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

    OVERVIEW

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

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

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

    QUARTERLY FINANCIAL INFORMATION
    -------------------------------------------------------------------------
                                                     2007                2006
    ($000 except per unit amounts)          Q3        Q2        Q1        Q4
    -------------------------------------------------------------------------
    Total revenue (net of royalties)    75,589    83,017    92,499    91,425
    Funds from operations               62,938    69,345    78,364    77,360
      Per unit - basic                    0.60      0.66      0.74      0.74
      Per unit - diluted                  0.60      0.66      0.74      0.74
    Earnings (loss)                     39,886    38,825    56,883    47,012
      Per unit - basic                    0.37      0.37      0.54      0.44
      Per unit - diluted                  0.37      0.37      0.54      0.44
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                                     2006                2005
    ($000 except per unit amounts)          Q3        Q2        Q1        Q4
    -------------------------------------------------------------------------
    Total revenue (net of royalties)    84,164    88,515    86,459    94,111
    Funds from operations               72,360    77,507    78,617    86,607
      Per unit - basic                    0.69      0.74      0.76      0.85
      Per unit - diluted                  0.69      0.74      0.76      0.85
    Earnings (loss)                     46,155    56,768    45,293    60,745
      Per unit - basic                    0.44      0.54      0.44      0.60
      Per unit - diluted                  0.44      0.54      0.44      0.60
    -------------------------------------------------------------------------


    RESULTS OF OPERATIONS

    Production
    -------------------------------------------------------------------------
                                       Three Months ended   Nine Months ended
                                              Sep 30              Sep 30
                                          2007      2006      2007      2006
    -------------------------------------------------------------------------
    Natural gas (mmcf/d)                  97.0     115.3     101.6     112.9
    Oil & natural gas liquids (bbl/d)    3,573     4,205     3,573     4,164
    Barrels of oil equivalent (boe/d)   19,740    23,422    20,512    22,982
    -------------------------------------------------------------------------
    

    Natural gas production averaged 97.0 mmcf/d in the third quarter of 2007,
16 percent lower than the 115.3 mmcf/d reported for the same period in 2006.
Oil and natural gas liquids production averaged 3,573 bbl/d, a decrease of 15
percent from 4,205 bbl/d reported in the prior year. Third quarter production
decreased 16 percent from 23,422 boe/d to 19,740 boe/d. The production
decreases are attributable to Peyto's reduced drilling program and natural
resource declines.

    
    Commodity Prices
    -------------------------------------------------------------------------
                                       Three Months ended   Nine Months ended
                                              Sep 30              Sep 30
                                          2007      2006      2007      2006
    -------------------------------------------------------------------------
    Natural gas ($/mcf)                   6.07      6.53      7.47      7.64
    Hedging - gas ($/mcf)                 1.54      1.28      1.21      0.69
    -------------------------------------------------------------------------
    Natural gas - after hedging ($/mcf)   7.61      7.81      8.68      8.33
    -------------------------------------------------------------------------

    Oil and natural gas liquids ($/bbl)  69.56     65.29     63.22     65.38
    Hedging - oil ($/bbl)                 0.95     (0.79)     2.12     (2.49)
    -------------------------------------------------------------------------
    Oil and natural gas liquids -
     after hedging ($/bbl)               70.51     64.50     65.34     62.89
    -------------------------------------------------------------------------
    Total Hedging ($/boe)                 7.76      6.14      6.38      2.95
    -------------------------------------------------------------------------

    Peyto's natural gas price, before hedging gains, averaged $6.07/mcf during
the third quarter of 2007, a decrease of 7 percent from $6.53/mcf reported for
the equivalent period in 2006. Oil and natural gas liquids prices before
hedging gains averaged $69.56/bbl up 7 percent from $65.29/bbl a year earlier.
Hedging activity for the third quarter of 2007 accounted for $7.76/boe of
Peyto's price achieved.

    Revenue
    -------------------------------------------------------------------------
                                       Three Months ended   Nine Months ended
                                              Sep 30              Sep 30
    ($000)                                2007      2006      2007      2006
    -------------------------------------------------------------------------
    Natural gas                         54,116    69,347   207,229   235,500
    Oil and natural gas liquids         22,866    25,259    61,671    74,324
    Hedging gain (loss)                 14,088    13,238    35,746    18,489
    -------------------------------------------------------------------------
    Total revenue                       91,070   107,844   304,646   328,313
    -------------------------------------------------------------------------

    For the three months ended September 30, 2007, gross revenue decreased
16 percent to $91.1 million from $107.8 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        Nine Months ended
                                     Sep 30                   Sep 30
                               2007   2006  $million    2007   2006  $million
    -------------------------------------------------------------------------
    Total Revenue, Sept 30,
     2006                                     107.8                    328.3
    -------------------------------------------------------------------------
      Revenue change due to:
    -------------------------------------------------------------------------
        Natural gas
          Volume (mmcf)      8,924  10,348    (11.3) 27,746  30,823    (25.6)
          Price ($/mcf)      $7.61   $7.96     (3.1)  $8.68   $8.33      9.7
        Oil & NGL
          Volume (mbbl)        329     381     (3.5)    976   1,137    (10.2)
          Price ($/bbl)     $70.51  $66.94      1.2  $65.34  $62.89      2.4
    -------------------------------------------------------------------------
    Total Revenue, Sept 30,
     2007                                      91.1                    304.6
    -------------------------------------------------------------------------

    Royalties

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

    -------------------------------------------------------------------------
                                       Three Months ended   Nine Months ended
                                              Sep 30              Sep 30
    ($000 except per unit amounts)        2007      2006      2007      2006
    -------------------------------------------------------------------------
    Royalties                           15,481    23,805    53,541    69,425
    ARTC                                     -      (125)        -      (250)
    -------------------------------------------------------------------------
                                        15,481    23,680    53,541    69,175
    -------------------------------------------------------------------------
    % of sales                            17.0        22      17.6        21
    $/boe                                 8.52     10.99      9.56     11.03
    -------------------------------------------------------------------------
    

    For the third quarter of 2007, royalties averaged $8.52/boe or
approximately 17.0 percent of Peyto's total petroleum and natural gas sales.
The royalty rate expressed as a percentage of sales, will fluctuate from
period to period due to the fact that the Alberta Reference Price can differ
significantly from the commodity prices obtained by the Trust and that hedging
gains and losses are not subject to royalties. As average per well production
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 our
crown royalty rate. Effective January 1, 2007, the Alberta Government
discontinued the Alberta Royalty Tax Credit ("ARTC") program. In the 9 year
history of the company, Peyto has invested over $1.4 billion in capital
projects and has found and developed gas reserves that have paid over
$400 million in royalties.

    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   Nine Months ended
                                              Sep 30              Sep 30
                                          2007      2006      2007      2006
    -------------------------------------------------------------------------
    Operating costs ($000)
    Field expenses                       6,476     6,245    21,297    18,404
    Processing and gathering income     (1,976)   (2,161)   (6,321)   (5,939)
    -------------------------------------------------------------------------
    Total operating costs                4,500     4,084    14,976    12,465
    -------------------------------------------------------------------------
    $/boe                                 2.48      1.90      2.67      1.99
    -------------------------------------------------------------------------

    Transportation                       1,045     1,256     3,245     3,767
    -------------------------------------------------------------------------
    $/boe                                 0.58      0.58      0.58      0.60
    -------------------------------------------------------------------------

    Operating costs were $4.5 million in the third quarter of 2007 compared to
$4.1 million during the same period a year earlier. Transportation expense
remained constant. On a unit-of-production basis, operating costs averaged
$2.48/boe in the third quarter of 2007 compared to $1.90/boe for the third
quarter of 2006.

    Netbacks
    -------------------------------------------------------------------------
                                       Three Months ended   Nine Months ended
                                              Sep 30              Sep 30
    ($/boe)                               2007      2006      2007      2006
    -------------------------------------------------------------------------
    Sale Price                           50.15     50.05     54.40     52.34
    Less:
      Royalties                           8.52     10.99      9.56     11.03
      Operating costs                     2.48      1.90      2.67      1.99
      Transportation                      0.58      0.58      0.58      0.60
    -------------------------------------------------------------------------
    Field netback                        38.57     36.58     41.59     38.72
    General and administrative            0.82      0.55      0.97      0.35
    Interest on long-term debt            3.10      2.52      3.00      1.97
    Cash netback                         34.65     33.51     37.62     36.40
    -------------------------------------------------------------------------

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

    General and Administrative Expenses
    -------------------------------------------------------------------------
                                       Three Months ended   Nine Months ended
                                              Sep 30              Sep 30
                                          2007      2006      2007      2006
    -------------------------------------------------------------------------
    G&A expenses ($000)                  2,536     2,556     5,059     6,971
    Overhead recoveries                 (1,053)   (1,362)   (2,167)   (4,762)
    -------------------------------------------------------------------------
    Net G&A expenses                     1,483     1,194     5,428     2,209
    -------------------------------------------------------------------------
    $/boe                                 0.82      0.55      0.97      0.35
    -------------------------------------------------------------------------

    General and administrative expenses before overhead recoveries decreased
1% from $2.6 million in the third quarter of 2006 to $2.5 million for the same
period in 2007. Net of overhead recoveries associated with the capital
expenditures program, general and administrative costs increased to $0.82 per
boe in the third quarter of 2007 from $0.55 per boe in the third quarter of
2006. Third quarter 2007 overhead recoveries were 23% lower than third quarter
2006 recoveries due to the reduction in capital expenditures.

    Interest Expense
    -------------------------------------------------------------------------
                                       Three Months ended   Nine Months ended
                                              Sep 30              Sep 30
                                          2007      2006      2007      2006
    -------------------------------------------------------------------------
    Interest expense ($000)              5,623     5,432    16,809    12,374
    $/boe                                 3.10      2.52      3.00      1.97
    -------------------------------------------------------------------------
    

    Third quarter 2007 interest expense was $5.6 million or $3.10/boe
compared to $5.4 million or $2.52/boe a year earlier. During the third quarter
of 2007, average debt levels were $412 million as compared to $341 million in
the third quarter of 2006. Interest rates continue to be favorable and are not
expected to increase substantially in the short-term. The average interest
rate for the third quarter of 2007 was 5.6% compared to 4.8% for the third
quarter of 2006.

    Depletion, Depreciation and Accretion

    The 2007 third quarter provision for depletion, depreciation and
accretion totaled $18.0 million as compared to $20.4 million in 2006. On a
unit-of-production basis, depletion, depreciation and accretion costs averaged
$9.93/boe as compared to $9.46/boe in 2006.

    Income Taxes

    The current provision for future income tax was $17.8 million (2006 -
$19.4 million). Peyto's trust structure is unique and was designed to provide
for discretion at the operating trust level to distribute taxable income to
the Trust. Resource pools are generated from the capital program, which are
available to offset current and future income tax liabilities. Unitholders
benefit as the Trust may use these resource pools to increase the tax free
return of capital component of the cash distributions.

    MARKETING

    Commodity Price Risk Management

    Effective January 1, 2007, the Trust adopted the Canadian Institute of
Chartered Accountants ("CICA") Section 3855, "Financial Instruments -
Recognition and Measurement," Section 3865, "Hedges," Section 1530,
"Comprehensive Income" and Section 3861, "Financial Instruments - Disclosure
and Presentation." The Trust has adopted these standards retroactively without
restatement and the comparative interim consolidated financial statements have
not been restated. Transition amounts have been recorded in retained earnings
or accumulated other comprehensive income ("AOCI"). See Note 2 to the
Consolidated Financial Statements.
    The Trust is a party to certain off balance sheet derivative financial
instruments, including fixed price contracts. The Trust enters into these
forward contracts with well established counter-parties for the purpose of
protecting a portion of its future revenues from the volatility of oil and
natural gas prices. During the third quarter of 2007, a hedging gain of
$14.1 million was recorded as compared to $13.2 million in the third quarter
of 2006. A summary of contracts outstanding in respect of the hedging
activities are as follows:

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


                                                                  Weighted
                                                                   Average
    Natural Gas                                                     Price
    Period Hedged                       Type      Daily Volume      (CAD)
    -------------------------------------------------------------------------
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $8.60/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.50/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.25/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.51/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.50/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.60/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.60/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.80/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.50/GJ
    April 1 to October 31, 2007      Fixed price     5,000 GJ      $7.70/GJ
    April 1, 2007 to March 31, 2008  Fixed price     5,000 GJ      $8.35/GJ
    April 1, 2007 to March 31, 2008  Fixed price     5,000 GJ      $8.90/GJ
    Nov 1, 2007 to March 31, 2008    Fixed price     5,000 GJ      $8.85/GJ
    Nov 1, 2007 to March 31, 2008    Fixed price     5,000 GJ      $9.06/GJ
    Nov 1, 2007 to March 31, 2008    Fixed price     5,000 GJ      $9.10/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, 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
    

    As at September 30, 2007, the Trust had committed to the future sale of
91,500 barrels of crude oil at an average price of $78.55 per barrel and
9,320,000 gigajoules (GJ) of natural gas at an average price of $8.05 per GJ
or $9.42 per mcf based on the historical heating value of Peyto's natural gas.
Had these contracts been closed on September 30, 2007, the Trust would have
realized a gain in the amount of $18.5 million.

    Commodity Price Sensitivity

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

    Currency Risk Management

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

    Interest Rate Risk Management

    The Trust is exposed to interest rate risk in relation to interest
expense on its revolving demand facility. Currently we have not entered into
any agreements to manage this risk. At September 30, 2007, the increase or
decrease in earnings for each 100 bps change in interest rate paid on the
outstanding revolving demand loan amounts to approximately $4.0 million per
annum.

    LIQUIDITY AND CAPITAL RE

SOURCES Funds from Operations ------------------------------------------------------------------------- Three Months ended Nine Months ended Sep 30 Sep 30 ($000) 2007 2006 2007 2006 ------------------------------------------------------------------------- Net earnings 39,886 46,155 135,594 148,216 Items not requiring cash: Non-cash provision for performance based compensation 202 (2,005) 640 192 Future income tax expense 4,808 7,821 17,774 19,376 Depletion, depreciation & accretion 18,042 20,389 56,639 60,701 ------------------------------------------------------------------------- Funds from operations 62,938 72,360 210,647 228,485 ------------------------------------------------------------------------- For the third quarter ended September 30, 2007, funds from operations totaled $62.9 million or $0.60 per unit, as compared to $72.4 million, or $0.69 per unit during the same period in 2006. Peyto's policy is to maintain a sustainable distribution to unitholders, retaining the balance to fund its growth oriented capital expenditures program. Earnings and cash flow are highly sensitive to changes in commodity prices, exchange rates and other factors that are beyond Peyto's control. Current volatility in commodity prices creates uncertainty as to the funds from operations and capital expenditure budget. Accordingly, results are assessed throughout the year and operational plans revised as necessary to reflect the most current information. Revenues will be impacted by drilling success and production volumes as well as external factors such as the market prices for natural gas and crude oil and the exchange rate of the Canadian dollar relative to the US dollar. Bank Debt The Trust has an extendible revolving term credit facility with a syndicate of financial institutions in the amount of $525 million including a $505 million revolving facility and a $20 million operating facility. Available borrowings are limited by a borrowing base, which is based on the value of petroleum and natural gas assets as determined by the lenders. The loan is reviewed annually and may be extended at the option of the lender for an additional 364 day period. If not extended, the revolving facility will automatically convert to a one year and one day non-revolving term loan. The loan has therefore been classified as long-term on the balance sheet. The average borrowing rate for the third quarter of 2007 was 5.6% (2006 - 4.8%). At September 30, 2007, $410 million was drawn under the facility. Working capital liquidity is maintained by drawing from and repaying the unutilized credit facility as needed. At September 30, 2007, the working capital deficit was $10.9 million. Peyto believes funds generated from operations, together with borrowings under the credit facility and proceeds from equity issued will be sufficient to finance current operations and planned capital expenditure program. The total amount of capital invested in 2007 will be driven by the number and quality of projects generated. Capital will only be invested if it meets the long term objectives of the Trust. The majority of the capital program will involve drilling, completion and tie-in of lower risk development gas wells. Peyto's rapidly scaleable business model has the flexibility to match planned capital expenditures to actual cash flow. Capital Peyto implemented a Distribution Reinvestment Plan ("DRIP") effective with the March 2005 distribution whereby eligible unitholders may elect to reinvest their monthly cash distributions in additional trust units at a 5% discount to market price. On November 21, 2005 the DRIP plan was amended to incorporate an Optional Trust Unit Purchase Plan ("OTUPP") which provides unitholders enrolled in the DRIP with the opportunity to purchase additional trust units from treasury using the same pricing as the DRIP. Both the DRIP and the OTUPP were suspended effective August 31, 2006 due to unfavorable market conditions. On March 15, 2007 the Trust completed a private placement of 175,780 trust units to employees and consultants for net proceeds of $2,824,785. These trust units were issued on March 15, 2007. On March 15, 2007, subsequent to the issuance of these units, 105,712,364 trust units were outstanding (December 31, 2006 - 105,251,394). Authorized: Unlimited number of voting trust units Issued and Outstanding: Trust Units (no par value) Number of Amount ($000) Shares/Units $ ------------------------------------------------------------------------- Balance, December 31, 2005 102,333,847 328,736 Trust units issued by private placement 1,393,940 34,378 Trust units issued pursuant to DRIP 690,387 16,301 Trust units issued pursuant to OTUPP 833,220 19,019 Balance, December 31, 2006 105,251,394 398,434 Trust units issued by private placement 460,970 7,867 ------------------------------------------------------------------------- Balance, September 30, 2007 105,712,364 406,301 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Performance Based Compensation The Trust awards performance based compensation to employees and key consultants annually. The performance based compensation is comprised of market and reserve value based components. The reserve value based component is 4% of the incremental increase in value, if any, as adjusted to reflect changes in debt, equity and distributions, of proved producing reserves calculated using a constant price at December 31 of the current year and a discount rate of 8%. This methodology can generate interim results which vary significantly from the final compensation paid. No provision for the reserve value based component was recorded for the first three quarters of 2007. Under the market based component, rights with a three year vesting period are allocated to employees and key consultants. The number of rights outstanding at any time is not to exceed 6% of the total number of trust units outstanding. At December 31 of each year, all vested rights are automatically cancelled and, if applicable, paid out in cash. Compensation is calculated as the number of vested rights multiplied by the total of the market appreciation (over the price at the date of grant) and associated distributions of a trust unit for that period. For rights vesting in 2007 and 2008, a tax factor of 1.333 will then be applied to determine the amount to be paid. Commencing 2009, no tax factor will be applied to determine the amount paid. Based on the five day weighted average trading price of the trust units for the period ended September 30, 2007, compensation costs related to 4.2 million non-vested rights (4% of the total number of trust units outstanding), with an average grant price of $21.93, are $202,000. The Trust records a non-cash provision for future compensation expense over the life of the rights. The cumulative provision is $640,000. Capital Expenditures Net capital expenditures for the third quarter of 2007 totaled $42.6 million. Exploration and development related activity represented $31.5 million or 74% of the total, while expenditures on facilities, gathering systems and equipment totaled $10.1 million or 24% of the total. The following table summarizes capital expenditures for the quarter. ------------------------------------------------------------------------- Three Months ended Nine Months ended Sep 30 Sep 30 ($000) 2007 2006 2007 2006 ------------------------------------------------------------------------- Land 555 575 997 13,253 Seismic 477 790 1,322 8,361 Drilling - Exploratory & Development 31,455 51,489 67,166 204,808 Production Equipment, Facilities & Pipelines 10,096 18,351 16,516 56,925 Acquisitions & Dispositions - - - - Office Equipment 15 18 23 166 ------------------------------------------------------------------------- Total Capital Expenditures 42,598 71,223 86,024 283,513 ------------------------------------------------------------------------- Distributions ------------------------------------------------------------------------- Three Months ended Nine Months ended Sep 30 Sep 30 2007 2006 2007 2006 ------------------------------------------------------------------------- Funds from operations ($000) 62,938 72,360 210,647 227,485 Total distributions ($000) 44,399 44,111 133,148 129,549 Total distributions per unit ($) 0.42 0.42 1.26 1.24 Payout ratio (%) 71 61 63 57 Cash distributions ($000) (net of DRIP) 44,399 41,019 133,148 113,999 Payout ratio (%) 71 57 63 50 ------------------------------------------------------------------------- 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 Nine Months ended Sep 30 Sep 30 ($000) 2007 2006 2007 2006 ------------------------------------------------------------------------- Opening accumulated earnings 626,862 437,987 531,154 335,926 Net earnings for the period 39,886 46,155 135,594 148,216 ------------------------------------------------------------------------- Total accumulated earnings 666,748 484,142 666,748 484,142 Total accumulated distributions (578,066) (400,712) (578,066) (400,712) ------------------------------------------------------------------------- Accumulated earnings per Balance Sheet 88,682 83,430 88,682 83,430 ------------------------------------------------------------------------- Since inception, Peyto has accumulated earnings of $666.7 million and distributed $578.1 million to unitholders. Contractual Obligations The Trust is committed to payments under operating leases for office space as follows: ------------------------------------------------------------------------- ($000) $ ------------------------------------------------------------------------- 2007 238 2008 1,096 2009 1,097 2010 1,097 2011 1,097 ------------------------------------------------------------------------- 4,625 ------------------------------------------------------------------------- ------------------------------------------------------------------------- RELATED PARTY TRANSACTIONS An officer of the Trust is a partner of a law firm that provides legal services to the Trust. The fees charged are based on standard rates and time spent on matters pertaining to the Trust and its subsidiaries. INCOME TAXES The following sets out a general discussion of the Canadian and US tax consequences of holding Peyto units as capital property. The summary is not exhaustive in nature and is not intended to provide legal or tax advice. Unitholders or potential Unitholders should consult their own legal or tax advisors as to their particular tax consequences. Canadian Taxpayers The Trust qualifies as a mutual fund trust under the Income Tax Act (Canada) and, accordingly, Trust units are qualified investments for RRSPs, RRIFs, RESPs and DPSPs. Each year, the Trust is required to file an income tax return and any taxable income of the Trust is allocated to unitholders. Unitholders are required to include in computing income their pro-rata share of any taxable income earned by the Trust in that year. An investor's adjusted cost base (ACB) in a trust unit equals the purchase price of the unit less any non-taxable cash distributions received from the date of acquisition. To the extent the unitholders' ACB is reduced below zero, such amount will be deemed to be a capital gain to the unitholder and the unitholders' ACB will be brought to nil. During the third quarter of 2007, the Trust paid distributions to the unitholders in the amount of $44.4 million (2006 - $44.1 million) in accordance with the following schedule: Production Period Record Date Distribution Date Per Unit ------------------------------------------------------------------------- January 2007 January 31, 2007 February 15, 2007 $0.14 February 2007 February 28, 2007 March 15, 2007 $0.14 March 2007 March 31, 2007 April 13, 2007 $0.14 April 2007 April 30, 2007 May 15, 2007 $0.14 May 2007 May 31, 2007 June 15, 2007 $0.14 June 2007 June 30, 2007 July 13, 2007 $0.14 July 2007 July 31, 2007 August 15, 2007 $0.14 August 2007 August 31, 2007 September 14, 2007 $0.14 September 2007 September 30, 2007 October 15, 2007 $0.14 US Taxpayers US unitholders who receive cash distributions are subject to a 15 percent Canadian withholding tax, applied to the taxable portion of the distributions as computed under Canadian tax law. US taxpayers may be eligible for a foreign tax credit with respect to Canadian withholding taxes paid. The taxable portion of the cash distributions, if any, is determined by the Trust in relation to its current and accumulated earnings and profit using US tax principles. The taxable portion so determined, is considered to be a dividend for US tax purposes. The non-taxable portion of the cash distributions is a return of the cost (or other basis). The cost (or other basis) is reduced by this amount for computing any gain or loss from disposition. However, if the full amount of the cost (or other basis) has been recovered, any further non-taxable distributions should be reported as a gain. A bill was introduced into United States Congress on March 23, 2007 that could deny qualified dividend income treatment to the distributions made by the Trust to its U.S. unitholders. The bill is in the first step of the legislative process and it is uncertain whether it will eventually be passed into law in its current form. If the bill is passed in its current form, distributions received by U.S. unitholders would no longer qualify for the 15 per cent qualified dividend tax rate. US unitholders are advised to seek legal or tax advice from their professional advisors. RISK MANAGEMENT Investors who purchase units are participating in the net funds from operations from a portfolio of western Canadian crude oil and natural gas producing properties. As such, the funds from operations paid to investors and the value of the units are subject to numerous risks inherent in the oil and natural gas industry. Expected funds from operations depend largely on the volume of petroleum and natural gas production and the price received for such production, along with the associated costs. The price received for oil depends on a number of factors, including West Texas Intermediate oil prices, Canadian/US currency exchange rates, quality differentials and Edmonton par oil prices. The price received for natural gas production is primarily dependent on current Alberta market prices. Peyto's marketing and risk management strategy is designed to smooth out short term fluctuations in the price of both natural gas and natural gas liquids through future sales. It is meant to be methodical and consistent, and to avoid speculation. Although Peyto's focus is on internally generated drilling programs, any acquisition of oil and natural gas assets depends on assessment of value at the time of acquisition. Incorrect assessments of value can adversely affect distributions to unitholders and the value of the units. Peyto employs experienced staff on its team and performs appropriate levels of due diligence on the analysis of acquisition targets, including a detailed examination of reserve reports; if appropriate, re-engineering of reserves for a large portion of the properties to ensure the results are consistent; site examinations of facilities for environmental liabilities; detailed examination of balance sheet accounts; review of contracts; review of prior year tax returns and modeling of the acquisition to attempt to ensure accretive results to the unitholders. Inherent in development of the existing oil and gas reserves are the risks, among others, of drilling dry holes, encountering production or drilling difficulties or experiencing high decline rates in producing wells. To minimize these risks, Peyto employs experienced staff to evaluate and operate wells and utilizes appropriate technology in its operations. In addition, prudent work practices and procedures, safety programs and risk management principles, including insurance coverage protect the Trust against certain potential losses. The value of Peyto's units is based on, among other things, the underlying value of the oil and natural gas reserves. Geological and operational risks can affect the quantity and quality of reserves and the cost of ultimately recovering those reserves. Lower oil and gas prices increase the risk of write-downs on our oil and gas property investments. In order to mitigate this risk, proven and probable oil and gas reserves are evaluated each year by a firm of independent reservoir engineers. The Reserves Committee of the Board of Directors reviews and approves the reserve report. Access to markets may be restricted at times by pipeline or processing capacity. These risks are minimized by controlling as much of the processing and transportation activities as possible and ensuring transportation and processing contracts are in place with reliable cost efficient counter-parties. The petroleum and natural gas industry is subject to extensive controls, regulatory policies and income and resource taxes imposed by various levels of government. These regulations, controls and taxation policies are amended from time to time. Peyto has no control over the level of government intervention or taxation in the petroleum and natural gas industry. The Trust operates in such a manner to ensure, to the best of its knowledge that it is in compliance with all applicable regulations and is able to respond to changes as they occur. Crown royalty rates assessed on the Trust's oil and natural gas production are set by the government of the Province of Alberta. These rates are subject to review and modification from time to time. The petroleum and natural gas industry is subject to both environmental regulations and an increased environmental awareness. Environment risks have been reviewed and to the best of Peyto's knowledge, the Trust is in compliance with environmental legislation. Currently, there is no current material impact on Peyto's operations. Peyto is subject to financial market risk. In order to maintain substantial rates of growth, the Trust must continue reinvesting in, drilling for or acquiring petroleum and natural gas. The capital expenditure program is funded primarily through funds from operations, debt and equity. DISCLOSURE CONTROLS AND PROCEDURES Disclosure controls and procedures are designed to provide reasonable assurance that all relevant information is gathered and reported to senior management, including the Chief Executive Officer ("CEO") and Vice President, Finance ("VPF"), on a timely basis so that appropriate decisions can be made regarding public disclosure. As of the end of the period covered by this report, Peyto's management evaluated the effectiveness of the design and operation of its disclosure controls and procedures, under the supervision of, and with the participation of the CEO and VPF. Based on this evaluation, the CEO and VPF have concluded that Peyto's disclosure controls and procedures, as defined in Multilateral Instrument 52-109, Certification of Disclosure in Issuers Annual and Interim Filings are effective to ensure that material information relating to Peyto is made known to management on a timely basis and is included in this report. Internal Controls Update Peyto is required to comply with Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings". The 2007 certificate requires that the Trust disclose in the interim MD&A any changes in the Trust's internal control over financial reporting that occurred during the period that has materially affected, or is reasonably likely to materially affect the Trust's internal control over financial reporting. The Trust confirms that no such changes were made to the internal controls over financial reporting during the first nine months of 2007. CRITICAL ACCOUNTING ESTIMATES Reserve Estimates Estimates of oil and natural gas reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent to the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is an analytical process of estimating underground accumulations of oil and natural gas that can be difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future royalties and operating costs, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk recovery, and estimates of the future net cash flows expected there from may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of the Trust's oil and natural gas properties and the rate of depletion of the oil and natural gas properties as well as the calculation of the reserve value based compensation. Actual production, revenues and expenditures with respect to the Trust's reserves will likely vary from estimates, and such variances may be material. The Trust's estimated quantities of proved and probable reserves at December 31, 2006 were audited by independent petroleum engineers Paddock Lindstrom & Associates Ltd. Paddock has been evaluating reserves in Peyto's areas of operation and for Peyto for 8 consecutive years. Depletion and Depreciation Estimate The full cost method of accounting for petroleum and natural gas operations is followed whereby all costs of exploring for and developing petroleum and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical costs, carrying charges on non producing properties, costs of drilling both productive and non productive wells and overhead charges directly related to acquisition, exploration and development activities. All costs of exploring for and developing petroleum and natural gas reserves, together with the costs of production equipment, are depleted and depreciated on the unit of production method based on estimated gross proven reserves. Petroleum and natural gas reserves and production are converted into equivalent units based upon estimated relative energy content (6 mcf to 1 barrel of oil). Costs of acquiring unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proven reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Full Cost Accounting Ceiling Test The carrying value of property, plant and equipment is reviewed at least annually for impairment. Impairment occurs when the carrying value of the assets is not recoverable by the future undiscounted cash flows. The ceiling test is based on estimates of proved reserves, production rates, estimated future petroleum and natural gas prices and costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Any impairment would be charged as additional depletion and depreciation expense. Asset Retirement Obligation The asset retirement obligation is estimated based on existing laws, contracts or other policies. The fair value of the obligation is based on estimated future costs for abandonment and reclamation discounted at a credit adjusted risk free rate. The liability is adjusted each reporting period to reflect the passage of time and for revisions to the estimated future cash flows, with the accretion charged to earnings. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material. Future Market Performance Based Compensation The provision for future market based compensation is estimated based on current market conditions, distribution history and on the assumption that all outstanding rights will be paid out according to the vesting schedule. The conditions at the time of vesting could vary significantly from the current conditions and may have a material effect on the calculation. Reserve Value Performance Based Compensation The reserve value based compensation is calculated using the 2006 year end independent reserves evaluation which was completed in January 2007. A quarterly provision for the reserve value based compensation is calculated using estimated proved producing reserve additions adjusted for changes in debt, equity and distributions. Actual proved producing reserves additions and forecasted commodity prices could vary significantly from those estimated and may have a material effect on the calculation. Income Taxes The determination of the Trust's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded. Effect of Change in Accounting Policies Effective January 1, 2007, the Trust adopted the revised recommendations of CICA section 1506, "Accounting Changes." The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance was effective for all changes in accounting polices, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007. When the Trust has not applied a new primary source of GAAP that has been issued, but is not effective, the Trust will disclose the fact along with information relevant to assessing the possible impact that application of the new primary source of GAAP will have on the financial statements in the period of initial application. As of January 1, 2008, the Trust will be required to adopt two new CICA Handbook Sections, Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation" which will replace current Section 3861. The new standards require disclosure of the significance of financial instruments to an entity's financial statements, the risks associated with the financial instruments, and how those risks are managed. The new presentation standard essentially carries forward the current presentation requirements. The Trust is assessing the impact of these new standards on its consolidated financial statements and anticipates the main impact will be in terms of additional disclosures required. As of January 1, 2008, the Trust will be required to adopt CICA handbook Section 1535 "Capital Disclosures", which requires entities to disclose their objectives, policies and processes for management of capital, and in addition, whether the entity has complied with any externally imposed capital requirements. The Trust is assessing the impact of this new standard on its consolidated financial statements and anticipates the main impact will be in terms of additional disclosures required. ADDITIONAL INFORMATION Additional information relating to Peyto Energy Trust can be found on SEDAR at www.sedar.com and www.peyto.com. Quarterly information ------------------------------------------------------------------------- 2007 2006 Q3 Q2 Q1 Q4 Q3 ------------------------------------------------------------------------- Operations Production Natural gas (mcf/d) 97,000 101,812 106,183 112,296 115,304 Oil & NGLs (bbl/d) 3,573 3,540 3,607 3,834 4,205 Barrels of oil equivalent (boe/d @ 6:1) 19,740 20,509 21,305 22,550 23,422 Average product prices Natural gas ($/mcf) 7.61 8.59 9.77 8.84 7.81 Oil & natural gas liquids ($/bbl) 70.51 65.65 59.79 54.89 64.50 $/BOE Average sale price ($/boe) 50.15 53.98 58.84 53.35 50.05 Average royalties paid ($/boe) 8.52 9.50 10.59 9.29 10.99 Average operating expenses ($/boe) 2.48 2.70 2.84 2.69 1.90 Average transportation costs ($/boe) 0.58 0.57 0.59 0.52 0.58 Field netback ($/boe) 38.57 41.21 44.82 40.85 36.58 General & administrative expense ($/boe) 0.82 1.10 0.98 0.85 0.55 Interest expense ($/boe) 3.10 2.95 2.96 2.72 2.52 Cash netback ($/boe) 34.65 37.16 40.88 37.28 33.51 Financial ($000 except per unit) Revenue 91,070 100,750 112,825 110,696 107,844 Royalties (net of ARTC) 15,481 17,734 20,326 19,271 23,680 Funds from operations 62,938 69,345 78,364 77,360 72,360 Funds from operations per unit 0.60 0.66 0.74 0.74 0.69 Total distributions 44,399 44,399 44,350 44,206 44,111 Total distributions per unit 0.42 0.42 0.42 0.42 0.42 Payout ratio 71% 64% 57% 57% 61% Cash distributions (net of DRIP) 44,399 44,399 44,350 44,206 41,019 Payout ratio 71% 64% 57% 57% 57% Earnings 39,886 38,825 56,833 47,012 46,155 Earnings per diluted unit 0.37 0.37 0.54 0.44 0.44 Capital expenditures 42,598 12,949 30,478 28,413 71,223 Weighted average trust units out- standing 105,712,364 105,712,364 105,542,484 105,251,394 104,924,702 Peyto Energy Trust Consolidated Balance Sheets ($000) (unaudited) September 30, December 31, 2007 2006 $ $ ------------------------------------------------------------------------- Assets Current Cash 4,467 10,806 Accounts receivable (Note 10) 42,746 53,418 Financial derivative assets (Note 10) 18,457 - Due from private placements - 5,042 Prepaid expenses and deposits 3,909 2,681 ------------------------------------------------------------------------- 69,579 71,947 Property, plant and equipment (Note 3) 1,094,982 1,064,753 ------------------------------------------------------------------------- 1,164,561 1,136,700 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Liabilities and Unitholders' Equity Current Accounts payable and accrued liabilities 65,648 70,836 Cash distributions payable 14,800 14,735 Provision for future performance based compensation 68 - ------------------------------------------------------------------------- 80,516 85,571 ------------------------------------------------------------------------- Long-term debt (Note 4) 410,000 420,000 Provision for future performance based compensation 572 - Asset retirement obligations 6,610 5,767 Future income taxes (Note 5) 159,119 135,650 ------------------------------------------------------------------------- 576,301 561,417 ------------------------------------------------------------------------- Unitholders' equity Unitholders' capital (Note 6) 406,301 398,434 Units to be issued (Note 6) - 5,042 Accumulated earnings 88,682 86,236 Accumulated other comprehensive income (Notes 2, 10) 12,761 - ------------------------------------------------------------------------- 507,744 489,712 ------------------------------------------------------------------------- 1,164,561 1,136,700 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes On behalf of the Board: (signed) "Michael MacBean" (signed) "Darren Gee" Director Director Peyto Energy Trust Consolidated Statements of Earnings ($000 except per unit amounts) (unaudited) Three Months Ended Nine Months Ended September 30 September 30 2007 2006 2007 2006 $ $ $ $ ------------------------------------------------------------------------- Revenue Oil & gas sales 91,070 107,844 304,646 328,313 Royalties (net of ARTC) (15,481) (23,680) (53,541) (69,175) ------------------------------------------------------------------------- Petroleum and natural gas sales, net 75,589 84,164 251,105 259,138 ------------------------------------------------------------------------- Expenses Operating (Note 8) 4,500 4,084 14,976 12,465 Transportation 1,045 1,256 3,245 3,767 General and administrative (Note 9) 1,483 1,194 5,428 2,209 Future performance based compensation provision 202 (2,005) 640 192 Interest on long term debt 5,623 5,432 16,809 12,374 Depletion, depreciation and accretion (Note 3) 18,042 20,389 56,639 60,701 ------------------------------------------------------------------------- 30,895 30,350 97,737 91,708 ------------------------------------------------------------------------- Earnings before taxes 44,694 53,814 153,368 167,430 ------------------------------------------------------------------------- Taxes Future income tax expense (Note 5) 4,808 7,821 17,774 19,376 Capital tax expense - (162) - (162) ------------------------------------------------------------------------- 7,659 19,214 ------------------------------------------------------------------------- Net earnings for the period 39,886 46,155 135,594 148,216 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Earnings per unit (Note 6) Basic 0.37 0.44 1.28 1.42 Diluted 0.37 0.44 1.28 1.42 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Comprehensive Income ($000 except per unit amounts) (unaudited) Three Months Ended Nine Months Ended September 30 September 30 2007 2006 2007 2006 $ $ $ $ ------------------------------------------------------------------------- Net earnings for the period 39,886 46,155 135,594 148,216 Other comprehensive income (loss) Change in unrealized gain on cash flow hedges, net of tax 5,177 - 11,108 - Realized (gain) loss on cash flow hedges, net of tax (7,571) - (21,788) - ------------------------------------------------------------------------- Comprehensive Income (Note 2) 37,492 46,155 124,914 148,216 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Accumulated Earnings and Accumulated Other Comprehensive Income ($000) (unaudited) Three Months Ended Nine Months Ended September 30 September 30 2007 2006 2007 2006 $ $ $ $ ------------------------------------------------------------------------- Accumulated earnings, beginning of period 93,195 81,386 86,235 64,763 Net earnings for the period 39,886 46,155 135,594 148,216 Distributions (Note 7) (44,399) (44,111) (133,149) (129,549) ------------------------------------------------------------------------- Accumulated earnings, end of period 88,682 83,430 88,682 83,430 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Accumulated other comprehensive income, beginning of period 15,155 - - - Adoption of financial instruments, net of tax (Notes 2,10) - - 23,441 - Other comprehensive income (Notes 2,10) (2,394) - (10,680) - ------------------------------------------------------------------------- Accumulated other comprehensive income, end of period 12,761 - 12,761 - ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Consolidated Statements of Cash Flows ($000) (unaudited) Three Months Ended Nine Months Ended September 30 September 30 2007 2006 2007 2006 $ $ $ $ ------------------------------------------------------------------------- Cash provided by (used in) Operating Activities Net earnings for the period 39,886 46,155 135,594 148,216 Items not requiring cash: Future income tax expense 4,808 7,821 17,774 19,376 Depletion, depreciation and accretion 18,042 20,389 56,639 60,701 Change in non-cash working capital related to operating activities 10,163 (6,166) 9,167 (34,884) ------------------------------------------------------------------------- 72,899 68,199 219,174 193,409 ------------------------------------------------------------------------- Financing Activities Issue of trust units, net of costs and DRIP - 8,748 2,825 25,815 Cash distribution paid (net of DRIP) (44,399) (41,019) (133,149) (113,999) Increase (decrease) in bank debt - 10,000 (10,000) 220,000 Change in non-cash working capital related to financing activities - 1,390 5,107 30,656 ------------------------------------------------------------------------- (44,399) (20,881) (135,217) 162,472 ------------------------------------------------------------------------- Investing Activities Additions to property, plant and equipment (42,598) (71,223) (86,024) (283,513) Change in non-cash working capital related to investing activities 7,341 26,353 (4,272) (66,081) ------------------------------------------------------------------------- (35,257) (44,870) (90,296) (349,594) ------------------------------------------------------------------------- Net increase (decrease) in cash (6,757) 2,448 (6,339) 6,287 Cash, beginning of period (Note 11) 11,224 3,839 10,806 - ------------------------------------------------------------------------- Cash, end of period 4,467 6,287 4,467 6,287 ------------------------------------------------------------------------- ------------------------------------------------------------------------- See accompanying notes Peyto Energy Trust Notes to Consolidated Financial Statements (unaudited) September 30, 2007 and 2006 1. Summary of Significant Accounting Policies The unaudited interim consolidated financial statements of Peyto Energy Trust (the "Trust") follow the same accounting policies as the most recent annual audited consolidated financial statements except as disclosed in Note 2. The interim consolidated financial statement note disclosures do not include all of those required by Canadian generally accepted accounting principles ("GAAP") applicable for annual financial statements. Accordingly, these interim financial statements should be read in conjunction with the 2006 audited consolidated financial statements. These financial statements include the accounts of Peyto Energy Trust and its wholly owned subsidiaries, Peyto Exploration & Development Corp. and Peyto Operating Trust. 2. Changes in Accounting Policies Effective January 1, 2007, the Trust adopted the Canadian Institute of Chartered Accountants ("CICA") Section 3855, "Financial Instruments - Recognition and Measurement," Section 3865, "Hedges," Section 1530, "Comprehensive Income" and Section 3861, "Financial Instruments - Disclosure and Presentation." The Trust has adopted these standards retroactively without restatement and the comparative interim consolidated financial statements have not been restated. Transition amounts have been recorded in retained earnings or accumulated other comprehensive income ("AOCI"). Accumulated other comprehensive income is included on the balance sheet as a separate component of Unitholders' equity, and includes the effective gains and losses on derivative instruments designated as cash flow hedges. a) Financial Instruments All financial instruments must initially be recognized at fair value on the balance sheet. The Trust has classified each financial instrument into the following categories: "held for trading" and "available for sale" financial assets and financial liabilities; "loans or receivables"; and "other financial liabilities". Subsequent measurement of the financial instruments is based on their classification. Unrealized gains and losses on held for trading financial instruments are recognized in earnings. Gains and losses on available for sale financial assets are recognized in other comprehensive income and are transferred to earnings when the asset is settled. The other categories of financial instruments are recognized at amortized cost using the effective interest rate method. b) Derivative Instruments and Hedging Activities Derivative instruments are utilized by the Trust to manage market risk against the volatility in commodity prices. The Trust's policy is not to utilize derivative instruments for speculative purposes. The Trust has chosen to designate its existing derivative instruments as cash flow hedges. The Trust assesses on an ongoing basis, whether the derivatives that are used as cash flow hedges are highly effective in offsetting changes in cash flows of hedged items. All derivative instruments are recorded on the balance sheet at fair value in either accounts receivable or accrued liabilities. The effective portion of the gains and losses is recorded in other comprehensive income until the hedged transaction is recognized in earnings. When the earnings impact of the underlying hedged transaction is recognized in the consolidated statement of earnings, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings. Any hedge ineffectiveness is immediately recognized in earnings. The fair values of forward contracts are based on forward market prices. c) Embedded Derivatives An embedded derivative is a component of a contract that causes some of the cash flows of the combined instrument to vary in a way similar to a stand-alone derivative. This causes some or all of the cash flows that otherwise would be required by the contract to be modified according to a specified variable, such as interest rate, financial instrument price, commodity price, foreign exchange rate, a credit rating or credit index, or other variables. The Trust has no contracts containing embedded derivatives. d) Comprehensive Income Comprehensive income consists of net earnings and other comprehensive income ("OCI"). OCI comprises the change in the fair value of the effective portion of the derivatives used as hedging items in a cash flow hedge. "Accumulated other comprehensive income" is a new equity category comprised of the cumulative amounts of OCI. Effect of Change in Accounting Policies Effective January 1, 2007, the Trust adopted the revised recommendations of CICA section 1506, "Accounting Changes." The new recommendations permit voluntary changes in accounting policy only if they result in financial statements which provide more reliable and relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The guidance was effective for all changes in accounting polices, changes in accounting estimates and corrections of prior period errors initiated in periods beginning on or after January 1, 2007. When the Trust has not applied a new primary source of GAAP that has been issued, but is not effective, the Trust will disclose the fact along with information relevant to assessing the possible impact that application of the new primary source of GAAP will have on the financial statements in the period of initial application. As of January 1, 2008, the Trust will be required to adopt two new CICA Handbook Sections, Section 3862 "Financial Instruments - Disclosures" and Section 3863 "Financial Instruments - Presentation" which will replace current Section 3861. The new standards require disclosure of the significance of financial instruments to an entity's financial statements, the risks associated with the financial instruments, and how those risks are managed. The new presentation standard essentially carries forward the current presentation requirements. The Trust is assessing the impact of these new standards on its consolidated financial statements and anticipates the main impact will be in terms of additional disclosures required. As of January 1, 2008, the Trust will be required to adopt CICA handbook Section 1535 "Capital Disclosures:, which requires entities to disclose their objectives, policies and processes for management of capital, and in addition, whether the entity has complied with any externally imposed capital requirements. The Trust is assessing the impact of this new standard on its consolidated financial statements and anticipates the main impact will be in terms of additional disclosures required. 3. Property, Plant and Equipment September 30, December 31, 2007 2006 ($000) $ $ --------------------------------------------------------------------- Property, plant and equipment 1,375,070 1,288,616 Accumulated depletion and depreciation (280,088) (223,863) --------------------------------------------------------------------- 1,094,982 1,064,753 --------------------------------------------------------------------- --------------------------------------------------------------------- At September 30, 2007 costs of $38.6 million (September 30, 2006 - $39.0 million) related to undeveloped land have been excluded from the depletion and depreciation calculation. 4. Long-Term Debt The Trust has a syndicated $525 million extendible revolving credit facility. The facility is made up of a $20 million working capital sub-tranche and a $505 million production line. The facilities are available on a revolving basis for a period of at least 364 days and upon the term out date may be extended for a further 364 day period at the request of the Trust, subject to approval by the lenders. In the event that the revolving period is not extended, the facility is available on a non-revolving basis for a one year term, at the end of which time the facility would be due and payable. Outstanding amounts on this facility bear interest at rates determined by the Trust's debt to earnings before interest, taxes, depreciation, depletion and amortization (EBITDA) ratio that range from prime to prime plus 0.75% for debt to EBITDA ranging from less than 1:1 to greater than 2.5:1. A General Security Agreement with a floating charge on land registered in Alberta is held as collateral by the bank. 5. Income Taxes On June 22, 2007, Bill C-52 ("Bill") was enacted for Canadian GAAP. The Bill enacts the October 31, 2006 proposals to impose a new tax on distributions from flow-through entities, including publicly traded income trusts. This has not resulted in any change in the consolidated future income tax calculation. 6. Unitholders' Capital Authorized: Unlimited number of voting trust units Issued and Outstanding Trust Units (no par value) Number of Amount ($000) Shares/Units $ --------------------------------------------------------------------- Balance, December 31, 2005 102,333,847 328,736 Trust units issued by private placement 1,393,940 34,378 Trust units issued pursuant to DRIP 690,387 16,301 Trust units issued pursuant to OTUPP 833,220 19,019 --------------------------------------------------------------------- Balance, December 31, 2006 105,251,394 398,434 Trust units issued by private placement 460,970 7,867 --------------------------------------------------------------------- Balance, September 30, 2007 105,712,364 406,301 --------------------------------------------------------------------- --------------------------------------------------------------------- Units to be Issued On March 2, 2005, Peyto implemented a Distribution Reinvestment Plan ("DRIP"). On November 21, 2005 the DRIP plan was amended to incorporate an Optional Trust Unit Purchase Plan ("OTUPP") which provides unitholders enrolled in the DRIP with the opportunity to purchase additional trust units from treasury subject to certain limitations, using the same pricing as the DRIP. Both the DRIP and OTUPP were suspended August 31, 2006. Per Unit Amounts Earnings per unit have been calculated based upon the weighted average number of units outstanding for the three months ended September 30, 2007 of 105,712,364 (2006 - 104,924,702) and for the nine months ended September 30, 2007 of 105,656,359 (2006 - 104,554,325). There are no dilutive instruments outstanding. 7. Accumulated Distributions The Trust paid total distributions to the unitholders in the aggregate amount of $44.4 million in the three months ended September 30, 2007 of which all was settled in cash (2006 - total $44.1 million; cash $41.0 million and DRIP $3.1 million) and $133.1 million cash for the nine months ended September 30, 2007 (2006 - total $129.5 million; cash $114.0 million and DRIP $15.5 million) in accordance with the following schedule: Distribution Per Production Period Record Date Date Unit --------------------------------------------------------------------- January 2007 January 31, 2007 February 15, 2007 $0.14 February 2007 February 28, 2007 March 15, 2007 $0.14 March 2007 March 31, 2007 April 13, 2007 $0.14 April 2007 April 30, 2007 May 15, 2007 $0.14 May 2007 May 31, 2007 June 15, 2007 $0.14 June 2007 June 30, 2007 July 13, 2007 $0.14 July 2007 July 31, 2007 August 15, 2007 $0.14 August 2007 August 31, 2007 September 14, 2007 $0.14 September 2007 September 30, 2007 October 15, 2007 $0.14 8. Operating Expenses The Trust's operating expenses include all costs with respect to day-to-day well and facility operations. Processing and gathering income related to joint venture and third party natural gas reduces operating expenses. Three Months Ended Nine Months Ended September 30 September 30 2007 2006 2007 2006 ($000) $ $ $ $ --------------------------------------------------------------------- Field expenses 6,476 6,245 21,297 18,404 Processing and gathering income (1,976) (2,161) (6,321) (5,939) --------------------------------------------------------------------- Total operating costs 4,500 4,084 14,976 12,465 --------------------------------------------------------------------- --------------------------------------------------------------------- 9. General and Administrative Expenses General and administrative expenses are reduced by operating and capital overhead recoveries from operated properties. Three Months Ended Nine Months Ended September 30 September 30 2007 2006 2007 2006 ($000) $ $ $ $ --------------------------------------------------------------------- G&A expenses 2,536 2,556 5,059 6,971 Overhead recoveries (1,053) (1,362) (2,167) (4,762) --------------------------------------------------------------------- Net G&A expenses 1,483 1,194 5,428 2,209 --------------------------------------------------------------------- --------------------------------------------------------------------- 10. Financial Instruments As described in Note 2, on January 1, 2007, the Trust adopted the new CICA requirements relating to financial instruments. The following summarizes the retrospective without restatement adoption adjustments that were required as at January 1, 2007. December 31, January 1, 2006 Adoption 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 September 30, 2007 is as follows: Weighted Average Crude Oil Daily Price Period Hedged Type Volume (CAD) --------------------------------------------------------------------- October 1 to December 31, 2007 Fixed price 200 bbl $77.51/bbl October 1 to December 31, 2007 Fixed price 300 bbl $78.75/bbl January 1 to March 31, 2008 Fixed price 200 bbl $78.55/bbl January 1 to March 31, 2008 Fixed price 300 bbl $79.05/bbl Weighted Average Natural Gas Daily Price Period Hedged Type Volume (CAD) --------------------------------------------------------------------- April 1 to October 31, 2007 Fixed price 5,000 GJ $8.60/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.25/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.51/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.60/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.80/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.50/GJ April 1 to October 31, 2007 Fixed price 5,000 GJ $7.70/GJ April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.35/GJ April 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.90/GJ Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $8.85/GJ Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $9.06/GJ Nov 1, 2007 to March 31, 2008 Fixed price 5,000 GJ $9.10/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 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 As at September 30, 2007, the Trust had committed to the future sale of 91,500 barrels of crude oil at an average price of $78.55 per barrel and 9,320,000 gigajoules (GJ) of natural gas at an average price of $8.05 per GJ or $9.42 per mcf based on the historical heating value of Peyto's natural gas. Had these contracts been closed on September 30, 2007, the Trust would have realized a gain in the amount of $18.5 million. Subsequent to September 30, 2007 the Trust entered into the following contracts: Natural Gas Daily Price Period Hedged Type Volume (CAD) --------------------------------------------------------------------- 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 $6.40/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 Fair Values of Financial Assets and Liabilities The Trust's financial instruments include accounts receivable, financial derivative assets, current liabilities, provision for future performance based compensation and long term debt. At September 30, 2007, the carrying value of accounts receivable, financial derivative assets, current liabilities and provision for future performance based compensation approximate their fair 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 September 30, 2007, approximately 62% was due from three companies (September 30, 2006 - two companies, 59%). Of the Trust's revenue for the nine months ended September 30, 2007, approximately 94% was received from three companies (September 30, 2006 - two companies, 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 in relation to interest expense on its revolving demand facility. 11. Supplemental Cash Flow Information Three Months Ended Nine Months Ended September 30 September 30 2007 2006 2007 2006 ($000) $ $ $ $ --------------------------------------------------------------------- Cash interest paid during the period 5,623 5,432 16,809 12,374 --------------------------------------------------------------------- --------------------------------------------------------------------- 12. Contingencies and Commitments a) Contingent Liability From time to time, Peyto is the subject of litigation arising out of its day-to-day operations. While Peyto assesses the merits of each lawsuit and defends itself accordingly, Peyto may be required to incur significant expenses or devote significant resources to defending itself against such litigation. These claims are not currently expected to have a material impact on Peyto's financial position or results of operations. b) Commitments The Trust is committed to payments under operating leases for office space as follows: --------------------------------------------------------------------- ($000) $ --------------------------------------------------------------------- 2007 238 2008 1,096 2009 1,097 2010 1,097 2011 1,097 --------------------------------------------------------------------- 4,625 --------------------------------------------------------------------- --------------------------------------------------------------------- Peyto Exploration & Development Corp. Information Officers Darren Gee President and Chief Executive Officer Glenn Booth Vice-President, Land Scott Robinson Executive Vice-President and Chief Kathy Turgeon Operating Officer Vice-President, Finance Ken Veres Stephen Chetner Vice-President, Exploration Corporate Secretary Directors Ian Mottershead, Chairman Rick Braund Don Gray Brian Davis Michael MacBean Darren Gee Gregory Fletcher Auditors Deloitte & Touche LLP Solicitors Burnet, Duckworth & Palmer LLP Bankers Bank of Montreal Union Bank of California Royal Bank of Canada BNP Paribas Société Générale ATB Financial Fortis Capital (Canada) Ltd. Transfer Agent Valiant Trust Company Stock Listing Symbol: PEY.un Toronto Stock Exchange

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

Organization Profile

PEYTO ENERGY TRUST

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