True Energy Trust announces third quarter 2007 financial results



    TSX: TUI.UN

    CALGARY, Nov. 8 /CNW/ - (TSX: TUI.UN) True Energy Trust ("True" or the
"Trust") announces its financial and operating results for the three and nine
months ended September 30, 2007. Highlights from the quarter include:

    
    -   In the third quarter of 2007, monthly distributions of $0.08 per unit
        were declared and paid on August 15, 2007, September 17, 2007 and
        October 15, 2007. The Board has announced it has set a distribution
        policy for the fourth quarter of 2007 at a monthly rate of $0.08 per
        unit, subject to monthly confirmation, based on current commodity
        prices, hedging program, production volumes and market conditions.
        This strategy for the distribution level is consistent with providing
        a balance between providing income to unit holders and funding for
        True's capital program.

    -   True generated average sales volumes for the third quarter of 2007 of
        14,096 boe/d as compared to 13,248 boe/d for the same period in 2006,
        representing a 6% increase. Sales volumes decreased 18% from second
        quarter 2007 volumes. In addition to the property dispositions
        completed during the first nine months of 2007, third party plant
        turnarounds and other operational challenges resulted in lower sales
        volumes in the quarter. Based upon field estimates, current
        production is approximately 15,500 boe/d and increasing.

    -   Cash flow from operations(*) for the third quarter of 2007 was
        $17.5 million on gross sales of $50.5 million compared to cash flow
        from operations of $23.2 million on gross sales of $54.3 million for
        the same period in 2006. The decrease in cash flow for the 2007 third
        quarter was primarily the result of lower realized natural gas and
        overall crude oil, condensate and NGL commodity prices, offset by
        marginally higher production volumes as compared to the same period
        in 2006. In comparison, cash flow from operations for the second
        quarter of 2007 was $34.2 million on gross sales of $75.0 million.

    -   Three additional minor property dispositions closed in the third
        quarter for net proceeds of $3.8 million.

    -   Execution of the Kerrobert steam assisted gravity drainage ("SAGD")
        project is on track. Steam injection commenced in late September and
        after an initial "warm-up" phase, the four thermal production wells
        are now configured for fluid production. Oil production on these
        wells is expected to ramp up during the remainder of the fourth
        quarter, reaching a peak rate of approximately 500 bbls/d per well
        pair late in 2007 or early in first quarter 2008, thereby increasing
        total heavy oil production in the Kerrobert area to approximately
        4,000 bbls/d.

    -   True recently entered into three new commodity price risk management
        contracts: 1) an oil collar with a West Texas Intermediate ("WTI")
        reference crude oil price floor of US$65.00 per barrel and a price
        ceiling of US$82.00 per barrel on 1,000 barrels per day for the
        second quarter of 2008 through to the fourth quarter of 2008; and
        2) two AECO reference price natural gas fixed price contracts at
        $6.65 per GJ on a total of 15,546 GJ per day for the period of
        January 1, 2008 through December 31, 2008. Currently, the Trust has
        hedged volumes of 2,000 bbls/d of crude oil and 15,055 GJ/d of
        natural gas for the fourth quarter 2007, 2,000 bbls/d of crude oil
        and 20,546 GJ/d of natural gas for the first quarter of 2008, and
        2,000 bbls/d of crude oil and 15,546 GJ/d of natural gas for the
        second to fourth quarters of 2008.

    -   On October 25, 2007, the Alberta government introduced a significant
        increase to royalty terms for Alberta's oil and gas sector, effective
        in 2009, as explained more fully in the Management's Discussion and
        Analysis of this report. Higher royalties undoubtedly reduce project
        economics and the consequent impact on future capital is yet to be
        determined. The overall impact of the new Alberta royalty regime on
        True's operations is mitigated by True's Saskatchewan properties and
        lower shallow gas royalty rates associated with True's natural gas
        weighted production portfolio. As a result, the new Alberta royalty
        rate increases are not anticipated to have a material impact on
        True's operations.

    -   Over the past year, the energy sector has been impacted by an
        increasing number of new pressures. Among these are government policy
        changes such as the new taxation to eliminate the majority of income
        trusts, reduced capital investment incentives, lofty environmental
        targets, onerous regulatory restrictions, and most recently,
        increases in the royalty burden associated with "Alberta's New
        Royalty Framework." As a natural gas weighted Trust, True is faced
        with operating in the current reduced natural gas price environment
        with indications that 2008 will be similar. Despite a robust global
        crude oil environment, much of the positive impact is being offset by
        a strengthening Canadian dollar. True is committed to continuous
        improvement in its cost structure and the prudent allocation of
        capital. True is focused on improving netbacks, increasing reserve
        life and looking at opportunities to increase unit holder value.

    (*) Refer to note (2) in the highlights section of the third quarter
        report in respect of the term "cash flow from operations".

    True's third quarter report is presented below.


                                 HIGHLIGHTS

    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30            September 30
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    FINANCIAL (unaudited)

    (CDN$000s except unit and
    per unit amounts)
    Revenue (before royalties
     and hedging(1))              50,547      54,263     196,734     143,663
    Cash flow from
     operations(2)                17,478      23,225      81,658      58,606
      Per basic trust unit         $0.22       $0.52       $1.10       $1.48
      Per diluted trust unit(3)    $0.22       $0.50       $1.09       $1.45
    Net income (loss)            (17,003)      1,652     (23,833)     17,154
      Per basic trust unit        $(0.21)      $0.04      $(0.32)      $0.43
      Per diluted trust unit(3)   $(0.21)      $0.04      $(0.32)      $0.43
    Distributions declared        19,132      36,846      54,374      90,767
      Per unit                     $0.24       $0.72       $0.72       $2.16
    -------------------------------------------------------------------------
    Exploration and development   11,311      33,438      72,655      73,267
    Corporate and
     property acquisitions           139      12,728       1,493      12,920
    -------------------------------------------------------------------------
    Capital expenditures - cash   11,450      46,166      74,148      86,187
    Property dispositions - cash  (3,806)          -     (31,275)    (24,514)
    Corporate acquisitions
     and other - non-cash            116     436,811        (197)    484,767
    -------------------------------------------------------------------------
    Total capital
     expenditures - net            7,760     482,977      42,676     546,440
    -------------------------------------------------------------------------
    Long-term debt               159,212     108,890     159,212     108,890
    Convertible debentures        79,021      81,379      79,021      81,379
    Working capital
     deficiency (excess)          (4,380)     55,490      (4,380)     55,490
    -------------------------------------------------------------------------
    Total net debt               233,853     245,759     233,853     245,759
    -------------------------------------------------------------------------
    Total assets                 909,876   1,302,418     909,876   1,302,418
    Unitholders' equity          485,075     778,767     485,075     778,767
    -------------------------------------------------------------------------
    OPERATING

    Daily sales volumes
      Crude oil
       and NGLs        (bbls/d)    3,958       5,648       5,316       4,602
      Natural gas       (mcf/d)   60,827      45,598      67,364      43,656
      Total oil
       equivalent       (boe/d)   14,096      13,248      16,544      11,878
    Average prices
      Crude oil
       and NGLs         ($/bbl)    50.54       55.35       46.94       50.71
      Crude oil and
       NGLs (including
       hedging(1))      ($/bbl)    44.07       54.98       45.81       50.34
      Natural gas       ($/mcf)     5.44        6.02        6.82        6.61
      Natural gas
       (including
       hedging(1))      ($/mcf)     6.07        6.02        7.33        6.61
      Total oil
       equivalent       ($/boe)    37.68       44.31       42.87       43.95
      Total oil
       equivalent
       (including
       hedging(1))      ($/boe)    38.57       44.15       44.57       43.81
    Statistics
      Operating netback ($/boe)    15.76       23.66       22.73       23.47
      Operating netback
       (including
       hedging(1))      ($/boe)    16.65       23.50       24.42       23.33
      Production
       expenses         ($/boe)    13.13        8.58       11.46        8.93
      General &
       administrative   ($/boe)     3.26        2.12        2.98        2.77
      Royalties as a
       % of sales after
       transportation                21%         25%         18%         24%

    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30            September 30
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    TRUST UNITS

    Trust units outstanding   79,715,595  69,321,703  79,715,595  69,321,703
    Trust unit incentive
     rights outstanding        6,086,832   5,516,500   6,086,832   5,516,500
    Units issuable for
     exchangeable shares         316,547     272,264     316,547     272,264
    Units issuable for
     convertible debentures    5,390,625   5,390,625   5,390,625   5,390,625
    -------------------------------------------------------------------------
    Diluted trust units
     outstanding              91,509,599  80,501,092  91,509,599  80,501,092
    Diluted weighted
     average trust units(3)   79,714,539  45,207,091  74,528,093  39,821,616

    -------------------------------------------------------------------------
    TRUST UNIT TRADING STATISTICS

    (CDN$, except volumes)
     based on intra-day trading
    High                            6.10       15.64        7.47       21.30
    Low                             4.51       10.32        4.51       10.32
    Close                           4.95       10.58        4.95       10.58
    Average daily volume         364,661     364,342     469,513     328,137
    -------------------------------------------------------------------------
    

    (1) The Trust has entered into various commodity risk management
    contracts which are considered to be economic hedges. As disclosed in
    note 3 of the unaudited interim financial statements, effective
    January 1, 2007, the Trust no longer applies hedge accounting to these
    contracts. As such, these contracts are revalued to fair value at the end
    of each reporting date. This results in recognition of unrealized gains
    or losses over the term of these contracts which is reflected each
    reporting period until these contracts are settled, at which time
    realized gains or losses are recorded.

    (2) The highlights section contains the term "cash flow from operations",
    which should not be considered an alternative to, or more meaningful than
    cash flow from operating activities as determined in accordance with
    Canadian generally accepted accounting principles ("GAAP") as an
    indicator of the Trust's performance. Therefore reference to diluted cash
    flow from operations or cash flow from operations per trust unit may not
    be comparable with the calculation of similar measures for other
    entities. Management uses cash flow from operations to analyze operating
    performance and leverage and considers cash flow from operations to be a
    key measure as it demonstrates the Trust's ability to generate the cash
    necessary to fund future capital investments and to repay debt. The
    reconciliation between cash flow from operations and cash flow from
    operating activities can be found in the Management Discussion and
    Analysis ("MD&A"). Cash flow from operations per trust unit is calculated
    using the diluted weighted average number of trust units for the period.

    (3) In computing weighted average diluted earnings per trust unit for the
    three month period ended September 30, 2007 nil (2006: 272,264) trust
    units were added to the 79,714,539 (2006: 44,934,827) weighted average
    number of trust units outstanding during the period for the dilutive
    effect of exchangeable shares and convertible debentures. A total of
    316,547 (2006: nil) exchangeable shares, 6,086,832 (2006: 3,103,033)
    trust incentive units and 5,390,625 (2006: 5,390,625) trust units
    issuable pursuant to conversion of convertible debentures were excluded
    from the calculation of diluted earnings per trust unit for the three
    month period ended September 30, 2007 as they were not dilutive.

    In computing weighted average diluted earnings per trust unit for the
    nine month period ended September 30, 2007 nil (2006: 272,264) trust
    units were added to the 74,528,093 (2006: 39,549,352) weighted average
    number of trust units outstanding during the period for the dilutive
    effect of exchangeable shares and convertible debentures. A total of
    316,547 (2006: nil) exchangeable shares, 6,086,832 (2006: 721,377) trust
    incentive units and 5,390,625 (2006: 5,390,625) trust units issuable
    pursuant to conversion of convertible debentures were excluded from the
    calculation of diluted earnings per trust unit for the nine month period
    ended September 30, 2007 as they were not dilutive. To calculate weighted
    average diluted cash flow from operations for the nine month period ended
    September 30, 2007, 316,547 exchangeable shares were added to the
    denominator, resulting in diluted weighted average trust units of
    74,844,639 under this calculation.

    
                            REPORT TO UNITHOLDERS
    

    During the third quarter of 2007, the Trust focused on completion of the
Kerrobert steam assisted gravity drainage ("SAGD") project, optimization of
field operations during a period of significant third party plant turnaround
impact, and continued execution of our disposition program. Accomplishments
for the third quarter ended September 30, 2007 include:

    Distributions

    In the third quarter of 2007, monthly distributions of $0.08 per unit
were declared and paid on August 15, 2007, September 17, 2007 and October 15,
2007. The Board has announced it has set a distribution policy for the fourth
quarter of 2007 at a monthly rate of $0.08 per unit, subject to monthly
confirmation, based on current commodity prices, hedging program, production
volumes and market conditions. This go-forward strategy for the distribution
level is consistent with providing a balance between providing income to unit
holders and funding for True's capital program.

    Production

    2007 third quarter sales volumes averaged 14,096 boe/d as compared to
13,248 boe/d for the same period in 2006, representing a 6% increase. For the
nine month period ended September 30, 2007, sales volumes averaged
16,544 boe/d as compared to 11,878 boe/d for the same period in 2006. Sales
volumes in the third quarter were down 18% from the second quarter 2007
volumes. This takes into account the disposition of certain properties and
third party turnarounds during the quarter, as well as further negative prior
period net adjustments of approximately 600 boe/d. During the month of
September 2007, a major third party plant turnaround in the Willesden Green
area of West Central Alberta affected approximately 1,400 boe/d of production
for approximately 26 days, 12 days longer than anticipated.
    While the extraordinary declines due to various performance issues that
were experienced during the second quarter of 2007 at the Mantario heavy oil
property have not continued, quarter over quarter averages were negatively
impacted approximately by 250 boe/d. During the third quarter of 2007, True
participated in 2 gross (1.5 net) heavy oil wells in the Mantario area. The
results of the infill drilling program are encouraging and have assisted in
stabilizing the decline in this compartmentalized reservoir. The two wells
were placed on production via single well batteries at the end of the third
quarter of 2007 and are each currently producing approximately 100 boe/d net.
The Trust will continue to pursue further infill drilling potential at
Mantario.
    2 gross (0.6 net) third party operated wells from first quarter 2007
drilling in the Ferrier area were completed and tied in late in the third
quarter of 2007. Current production from these wells total approximately
60 boe/d net. A further 3 gross (0.6) net third party operated wells are
anticipated to be completed during the fourth quarter.
    Regulatory issues in Alberta impacted approximately 700 boe/d during the
third quarter of 2007. In July 2007 the Trust was informed by the Alberta
Energy and Utilities Board ("AEUB") that applications for natural gas
production from 2 wells in the Cold Lake oil sands area had not been made by
the previous operator. An internal review of all the Trust's wells within Oil
Sands Designated areas discovered further deficiencies and resulted in a
requirement to self disclose the non-compliance to the AEUB. The affected
wells and the Trust's Two Hills facility - 180 boe/d - were shut-in until the
necessary approvals were received on September 26, 2007. In the Doris area
re-licensing of a pipeline impacted 175 boe/d until October 18, 2007. In the
Brazeau area, Good Production Practice ("GPP") approval was received
September 6, 2007 allowing the Trust to increase production rates from the
affected light oil pool by approximately 500 boe/d above the previously
established allowable rate. Due to a third party equipment failure, volumes
could not be increased until mid-September 2007.
    Execution of the Kerrobert SAGD project is on track. During the first
quarter of 2007, True completed its Phase 1 drilling campaign consisting of
five cold producers and four thermal wells. SAGD facility upgrades continued
throughout the second and third quarters of 2007. The steam injection
commenced in late September and after an initial "warm-up" phase the four
thermal production wells are now configured for fluid production. Oil
production from these thermal wells is expected to ramp up during the
remainder of the fourth quarter and reach the anticipated peak rates of
approximately 500 bbls/d per well pair late in 2007 or early in the first
quarter of 2008, thereby increasing total heavy oil production in the
Kerrobert area to approximately 4,000 bbls/d.

    
    Reconciliation of Q3 average sales volumes to current estimated
    ---------------------------------------------------------------
    production                                           (In boe/d)
    ----------                                           ----------
    Q3 2007 average sales volumes                           14,100
    Regulatory issues impacting Q3                             700
    Plant turnarounds impacting Q3                             400
    Recent well completions                                    260
    Other                                                       40
    ---------------------------------------------------------------
    Current production estimate                             15,500
    

    Based upon field estimates, current production is approximately 15,500
boe/d and increasing. Further focus on recompletion, optimization, and tie-in
potential, in conjunction with response from the Kerrobert SAGD expansion
start-up is anticipated to provide significant production growth prior to the
end of the 2007 year. The Trust is anticipating 2007 annual average volumes of
approximately 16,500 boe/d.

    Financial

    Cash flow from operations for the third quarter was $17.5 million on
gross sales of $50.5 million compared to cash flow from operations of
$23.2 million on gross sales of $54.3 million for the same period in 2006. The
decrease in cash flow for the 2007 third quarter was primarily the result of
lower realized natural gas and overall crude oil, condensate and NGL commodity
prices, offset by marginally higher production volumes as compared to the same
period in 2006.
    Cash flow from operations for the nine month period ended September 30,
2007 was $81.7 million on gross sales of $196.7 million compared to cash flow
from operations of $58.6 million on gross sales of $143.7 million for the same
period in 2006.
    The net loss for the 2007 third quarter was $17.0 million compared to net
income of $1.7 million in the third quarter of 2006. The net loss for the nine
month period ended September 30, 2007 was $23.8 million compared to net income
of $17.2 million for the same period in 2006. This is primarily reflective of
increased cash flow from operations for the nine month period, offset by a
lower future tax recovery and by higher depletion, depreciation and accretion
charges.

    Dispositions

    Dispositions during the third quarter of 2007 consisted of the sale of
three separate minor northern Alberta properties, which are outside of the
Trust's core areas for future development. These property sales closed during
the months of July and August with net proceeds after adjustments of
approximately $3.8 million used to pay down debt. The Trust continues to
evaluate further divestiture opportunities, in keeping with its principles of
core area focus and operating high working interest production.

    Liquidity

    True's net debt as at September 30, 2007 was $233.9 million, representing
$159.2 million outstanding on the credit facility, $79.0 million in
convertible debentures (liability component) and net of the balance of working
capital.
    The existing credit facility consists of a $15 million demand operating
facility provided by one Canadian bank and a $175 million extendible revolving
term credit facility syndicated by two Canadian chartered banks, a U.S. bank,
a Canadian financial institution and one institutional lender. As at
September 30, 2007, there is approximately $31 million undrawn under these
lending facilities.
    The revolving period on the term credit facility ends on June 30, 2008,
unless extended for a further 364 day period. The borrowing base was renewed
effective August 31, 2007 and is currently scheduled for renewal on March 31,
2008.
    In August 2007, True received Toronto Stock Exchange approval for its
normal course issuer bid ("NCIB") for the repurchase of its trust units from
August 28, 2007 to August 27, 2008, entitling the Trust to purchase up to
approximately 7.8 million of its outstanding trust units. During the third
quarter of 2007, no units were repurchased. Future repurchases will be
dependent on excess cash available after consideration of the Trust's priority
uses of cash.
    True has continued its active commodity price risk management program.
True recently entered into three new commodity price risk management
contracts: 1) an oil collar with a West Texas Intermediate ("WTI") reference
crude oil price floor of US$65.00 per barrel and a price ceiling of US$82.00
per barrel on 1,000 barrels per day for the second quarter of 2008 through to
the fourth quarter of 2008; and 2) two AECO reference price natural gas fixed
price contracts at $6.65 per GJ on a total of 15,546 GJ per day for the period
of January 1, 2008 through December 31, 2008. As of November 8, 2007, the
Trust has hedged volumes of 2,000 bbls/d of crude oil and 15,055 GJ/d of
natural gas for the fourth quarter 2007, 2,000 bbls/d of crude oil and
20,546 GJ/d of natural gas for the first quarter of 2008, and 2,000 bbls/d of
crude oil and 15,546 GJ/d of natural gas for the second to fourth quarters of
2008. The Trust will continue its hedging strategies focusing on maintaining
sufficient cash flow to fund True's unitholder distributions and capital
program.

    Alberta Government Announces New Royalty Framework

    The Alberta Government recently has provided some details with respect to
its intentions for oil & gas royalties in the province. The newly proposed
Alberta royalty regime is to take effect in 2009 and in response to the
recommendations of the recent Alberta Royalty Review Panel. True is continuing
to assess the impact of the new royalty regime on its ongoing Alberta
operations. The actual impact will be determined based on the actual
legislation as well as production rates, drilling depths, commodity prices,
product mix and the percentage of production from Alberta after January 1,
2009. True's current operations and production are weighted approximately 58%
to Alberta; 40% to Saskatchewan and 2% to British Columbia. The overall impact
on the new Alberta royalty regime is mitigated by True's Saskatchewan
properties and the lower shallow gas Alberta natural gas rate royalty
production in True's Alberta conventional oil and gas production portfolio.
True is weighted approximately 80% to natural gas production in Alberta.
Higher royalties undoubtedly reduce project economics and the consequent
impact on future capital is yet to be determined but the increases are not
anticipated to have a material impact on True's operations.
    The proposed royalty changes are very sensitive to production rate and
natural gas prices. The majority of True's current Alberta wells are in the
500m to 1000m depth range and typically produce at lower rates. Based on
publicly available information in respect of the New Royalty Framework, and by
re-running True's reserves evaluated at December 31, 2006 and using the same
assumptions including pricing (an average of consultants forecast prices as at
January 1, 2007), True estimates that the proposed royalty rates would result
in a positive revision to True's net present value of future net revenues from
reserves, as at December 31, 2006, (based upon a 10% discount factor) of
approximately 0.8% and a 0.8% increase in net reserves (working interest and
royalty interests in reserves after deducting royalty obligations), as at
December 31, 2006. Based on the foregoing, the New Royalty Framework would
result in a positive revision to True's net asset value, as at December 31,
2006, of approximately 1%.
    Over the past year, the energy sector has been impacted by an increasing
number of new pressures. Among these are government policy changes such as the
new taxation to eliminate the majority of income trusts, reduced capital
investment incentives, lofty environmental targets, onerous regulatory
restrictions, and most recently, increases in the royalty burden associated
with "Alberta's New Royalty Framework." As a natural gas weighted Trust, True
is faced with operating in the current reduced natural gas price environment
with indications that 2008 will be similar. Despite a robust global crude oil
environment, much of the positive impact is being offset by a strengthening
Canadian dollar. True is committed to continuous improvement in its cost
structure and the prudent allocation of capital. True is focused on improving
netbacks, increasing reserve life and looking at opportunities to increase
unit holder value.

    2008 True Budget

    Gas prices continue to show volatility with lack of cold weather and the
current supply/demand imbalance. Given the current natural gas price outlook,
coming into the winter drilling season, True plans to reduce its first quarter
2008 winter drilling activity compared to the first quarter of 2007. True's
first quarter 2008 capital program will not exceed $10 million which compares
to a front end loaded 2007 capital program of approximately $50 million in
first quarter 2007. True will continue to take a balanced approach to the
priority use of cash flow between level of distributions and size of its 2008
capital program. Given the nature of True's lands and their inherent advantage
of year round access, True will spread its 2008 capital program more evenly
through the full year of 2008 to take advantage of reduced service costs
during non-peak times. True will focus on increasing its farm-out activity in
non-core areas. If the 2008 outlook for commodity prices improves, True would
plan to increase its capital spending in third and fourth quarters of 2008.

    Personnel Announcements

    Further to our press release dated August 20, 2007, True announced my
appointment as Chief Executive Officer and Director of True following the
resignation of Paul R. Baay as True's Chairman and Chief Executive Officer.
William C. (Mickey) Dunn, current Lead Independent Director of True, has
reassumed his role as Chairman of the Board and Mr. Baay remains as a director
of True. On behalf of the Board, I would like to thank Mr. Baay for his many
years of dedicated service since founding True in September of 2000.

    Wayne M. Chorney
    President, CEO and COO
    November 8, 2007

    
                     MANAGEMENT'S DISCUSSION AND ANALYSIS
    

    November 8, 2007 - The following Management's Discussion and Analysis of
financial results as provided by the management of True Energy Trust ("True"
or the "Trust") should be read in conjunction with the unaudited interim
consolidated financial statements and selected notes for the three and nine
months ended September 30, 2007 and 2006 and the audited consolidated
financial statements and Management's Discussion and Analysis for the years
ended December 31, 2006 and 2005 for the Trust. This commentary is based on
information available to, and is dated November 8, 2007. The financial data
presented is in accordance with Canadian generally accepted accounting
principles ("GAAP") in Canadian dollars, except where indicated otherwise.

    CONVERSION: The term barrels of oil equivalent ("boe") may be misleading,
particularly if used in isolation. A boe conversion ratio of six thousand
cubic feet of natural gas to one barrel of oil equivalence (6 mcf/bbl) is
based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead. All boe
conversions in this report are derived from converting gas to oil in the ratio
of six thousand cubic feet of gas to one barrel of oil.

    NON-GAAP MEASURES: This Management's Discussion and Analysis contains the
term "cash flow from operations", which should not be considered an
alternative to, or more meaningful than "cash flow from operating activities"
as determined in accordance with Canadian GAAP as an indicator of the Trust's
performance. Therefore reference to diluted cash flow from operations or cash
flow from operations per unit may not be comparable with the calculation of
similar measures for other entities. Management uses cash flow from operations
to analyze operating performance and leverage and considers cash flow from
operations to be a key measure as it demonstrates the Trust's ability to
generate the cash necessary to fund future capital investments and to repay
debt. The reconciliation between cash flow from operations and cash flow from
operating activities can be found in the Management's Discussion and Analysis.
Cash flow from operations per unit is calculated using the diluted weighted
average number of units for the period.
    This Management's Discussion and Analysis also contains the term
"distributable cash" which is not a recognized measure under Canadian GAAP.
Management uses distributable cash to refer to the determination of cash
available for distribution to unitholders. True's method of calculating these
measures may differ from other entities, and accordingly, may not be
comparable to the measures used by other trusts or companies. This
Management's Discussion and Analysis also contains other terms such as net
debt and operating netbacks, which are not recognized measures under Canadian
GAAP. Management believes these measures are useful supplemental measures of
firstly, the total amount of current and long-term debt and secondly, the
amount of revenues received after royalties and operating costs. Readers are
cautioned, however, that these measures should not be construed as an
alternative to other terms such as current and long-term debt or net earnings
determined in accordance with GAAP as measures of performance. True's method
of calculating these measures may differ from other entities, and accordingly,
may not be comparable to measures used by other trusts or companies.
    Additional information relating to the Trust, including the Trust's
Annual Information Form, is available on SEDAR at www.sedar.com.

    FORWARD-LOOKING STATEMENTS: Certain information contained herein may
contain forward-looking statements including management's assessment of future
plans and operations, impact of, and timing of certain projects, timing of and
effects of drilling, tie-in and completion of wells, timing of and the effect
of third party plant turnarounds, the effect of government announcements,
proposals and legislation, plans regarding hedging, wells to be drilled,
expected or anticipated production rates, the weighting of production between
different commodities, commodity prices, exchange rates, expected levels of
royalty rates, production expenses, transportation costs and other costs and
expenses, distributions and taxability of distributions, capital expenditures
and the nature of capital expenditures and the timing and method of financing
thereof, may constitute forward-looking statements under applicable securities
laws and necessarily involve risks including, without limitation, risks
associated with oil and gas exploration, development, exploitation,
production, marketing and transportation, loss of markets, volatility of
commodity prices, currency fluctuations, imprecision of reserve estimates,
environmental risks, competition from other producers, inability to retain
drilling rigs and other services, incorrect assessment of the value of
acquisitions, failure to realize the anticipated benefits of acquisitions,
delays resulting from or inability to obtain required regulatory approvals and
ability to access sufficient capital from internal and external sources. The
recovery and reserve estimates of True's reserves provided herein are
estimates only and there is no guarantee that the estimated reserves will be
recovered. Events or circumstances may cause actual results to differ
materially from those predicted, as a result of the risk factors set out and
other known and unknown risks, uncertainties, and other factors, many of which
are beyond the control of True. The reader is cautioned not to place undue
reliance on this forward-looking information. As a consequence, actual results
may differ materially from those anticipated in the forward-looking
statements. Readers are cautioned that the foregoing list of factors is not
exhaustive. Additional information on these and other factors that could
effect True's operations and financial results are included in reports on file
with Canadian securities regulatory authorities and may be accessed through
the SEDAR website (www.sedar.com), at True's website
(www.trueenergytrust.com). Furthermore, the forward-looking statements
contained herein are made as at the date hereof and True does not undertake
any obligation to update publicly or to revise any of the included
forward-looking statements, whether as a result of new information, future
events or otherwise, except as may be required by applicable securities laws.
    The reader is further cautioned that the preparation of financial
statements in accordance with GAAP requires management to make certain
judgments and estimates that affect the reported amounts of assets,
liabilities, revenues and expenses. Estimating reserves is also critical to
several accounting estimates and requires judgments and decisions based upon
available geological, geophysical, engineering and economic data. These
estimates may change, having either a negative or positive effect on net
earnings as further information becomes available, and as the economic
environment changes.

    Net Income (Loss) and Cash Flow from Operations

    True generated cash flow from operations of $17.5 million ($0.22 per
diluted unit) for the three months ended September 30, 2007, down 25% from the
$23.2 million ($0.50 per diluted unit) for the third quarter of 2006. The
decrease in cash flow for the 2007 third quarter was primarily the result of
lower realized natural gas and overall crude oil, condensate and NGL commodity
prices, offset by marginally higher production volumes as compared to the same
period in 2006. Cash flow from operations for the nine month period ended
September 30, 2007 was $81.7 million ($1.09 per diluted unit), up 39% from the
$58.6 million ($1.45 per diluted unit) for the same period in 2006.
    The net loss for the 2007 third quarter was $17.0 million compared to net
income of $1.7 million in third quarter of 2006. The net loss for the nine
month period ended September 30, 2007 was $23.8 million compared to net income
of $17.2 million for the same period in 2006. This is primarily reflective of
increased cash flow from operations for the nine month period, offset by a
lower future tax recovery and by higher depletion, depreciation and accretion
charges.

    
    Cash Flow From Operations and Net Income
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
    ($000s, except per                  September 30,           September 30,
     unit amounts)                  2007        2006        2007        2006
    -------------------------------------------------------------------------

    Cash flow from operations     17,478      23,225      81,658      58,606
      Basic   ($/unit)              0.22        0.52        1.10        1.48
      Diluted ($/unit)              0.22        0.50        1.09        1.45

    Net income (loss)            (17,003)      1,652     (23,833)     17,154
      Basic   ($/unit)             (0.21)       0.04       (0.32)       0.43
      Diluted ($/unit)             (0.21)       0.04       (0.32)       0.43
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Reconciliation of Cash Flow from Operations and Distributions

    Distributable cash is determined by aggregating various amounts received,
including interest income on notes of subsidiaries and other interest income
received or receivable, income generated under net profits interest, royalty,
other permitted investments and dividends and other distributions on
securities of subsidiaries, after deduction of all expenses and liabilities of
the Trust. The portion of distributable cash declared payable to unitholders
on any distribution date is determined on recommendation of the Board of
Directors of True Energy Inc., as administrator of the Trust.

    
    Reconciliation of Cash Flow from Operations and Distributions
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
    ($000s, except per                  September 30,           September 30,
     unit amounts)                  2007        2006        2007        2006
    -------------------------------------------------------------------------
    Cash flow from operations     17,478      23,225      81,658      58,606
    Change in non-cash
     working capital              (2,598)     20,284     (21,842)      4,375
    -------------------------------------------------------------------------
    Cash flow from operating
     activities                   14,880      43,509      59,816      62,981
    Cash withheld to fund
     capital expenditures, net
     of disposition proceeds      (7,644)    (46,166)    (42,873)    (61,673)
    Funding from DRIP                  -      20,760           -      35,824
    Net proceeds from issue
     of trust units                  (11)          -      54,375           -
    Proceeds from issue of
     convertible debentures,
     net of issue costs                -           -           -      82,227
    Bank borrowings (debt
     repayment) and working
     capital changes              11,907      18,743     (16,944)    (28,592)
    -------------------------------------------------------------------------
    Distributions declared        19,132      36,846      54,374      90,767
    Accumulated distributions,
     beginning of period         176,958      71,282     141,716      17,361
    -------------------------------------------------------------------------
    Accumulated distributions,
     end of period               196,090     108,128     196,090     108,128
    -------------------------------------------------------------------------
    Distributions per unit for
     outstanding units in the
     period                         0.24        0.72        0.72        2.16
    Accumulated distributions
     per unit, beginning of
     period                         3.60        1.92        3.12        0.48
    -------------------------------------------------------------------------
    Accumulated distributions
     per unit, end of period        3.84        2.64        3.84        2.64
    -------------------------------------------------------------------------
    

    The Premium Distribution(TM) Reinvestment, Distribution Reinvestment and
Optional Trust Unit Purchase Plan ("DRIP") was implemented effective March 27,
2006. Funds reinvested in the Trust through this plan were available to fund
capital and other expenditures. On November 16, 2006, the Trust announced the
suspension of equity available for reinvestment under DRIP until further
notice.

    Sales Volumes

    2007 third quarter sales volumes averaged 14,096 boe/d as compared to
13,248 boe/d for the same period in 2006, representing a 6% increase. For the
nine month period ended September 30, 2007, sales volumes averaged
16,544 boe/d as compared to 11,878 boe/d for the same period in 2007. Sales
volumes in the second quarter decreased 18% from the first quarter 2007
volumes. This takes into account the disposition of certain properties and
third party turnarounds during the quarter, as well as further negative prior
period net adjustments of approximately 600 boe/d. During the month of
September a major third party plant turnaround in the Willesden Green area of
West Central Alberta affected approximately 1,400 boe/d of production for
approximately 26 days, 12 days longer than anticipated.
    While the extraordinary declines due to various performance issues that
were experienced during the second quarter at the Mantario heavy oil property
have not continued, quarter over quarter averages were negatively impacted
approximately by 250 boe/d. During the third quarter of 2007, True
participated in 2 gross (1.5 net) heavy oil wells in the Mantario area. The
results of the infill drilling program are encouraging and have assisted in
stabilizing the decline in this compartmentalized reservoir. The two wells
were placed on production via single well batteries at the end of the third
quarter of 2007 and are each currently producing approximately 100 boe/d net.
The Trust will continue to pursue further infill drilling potential at
Mantario.
    2 gross (0.6 net) third party operated wells from first quarter drilling
in the Ferrier area were completed and tied in late in the third quarter.
Current production from these wells total approximately 60 boe/d net. A
further 3 gross (0.6) net third party operated wells are anticipated to be
completed during the fourth quarter.
    Regulatory issues in Alberta impacted approximately 700 boe/d during the
third quarter of 2007. In July 2007 the Trust was informed by the Alberta
Energy and Utilities Board ("AEUB") that applications for natural gas
production from 2 wells in the Cold Lake oil sands area had not been made by
the previous operator. An internal review of all the Trust's wells within Oil
Sands Designated areas discovered further deficiencies and resulted in a
requirement to self disclose the non-compliance to the AEUB. The affected
wells and the Trust's Two Hills facility - 180 boe/d - were shut-in until the
necessary approvals were received on September 26, 2007. In the Doris area
re-licensing of a pipeline impacted 175 boe/d until October 18, 2007. In the
Brazeau area, Good Production Practice ("GPP") approval was received
September 6, 2007 allowing the Trust to increase production rates from the
affected light oil pool by approximately 500 boe/d above the previously
established allowable rate. Due to a third party equipment failure, volumes
could not be increased until mid-September 2007.
    Execution of the Kerrobert SAGD project is on track. During the first
quarter of 2007, True completed its Phase 1 drilling campaign consisting of
five cold producers and four thermal wells. SAGD facility upgrades continued
throughout the second and third quarters of 2007. The steam injection
commenced in late September and after an initial "warm-up" phase the four
thermal production wells are now configured for fluid production. Oil
production from these thermal wells is expected to ramp up during the
remainder of the fourth quarter and reach the anticipated peak rates of
approximately 500 bbls/d per well pair late in 2007 or early in the first
quarter of 2008, thereby increasing total heavy oil production in the
Kerrobert area to approximately 4,000 bbls/d.
    Based upon field estimates, current production is approximately 15,500
boe/d and increasing. Further focus on recompletion, optimization, and tie-in
potential, in conjunction with response from the Kerrobert SAGD expansion
start-up is anticipated to provide significant production growth prior to the
end of the 2007 year. The Trust is anticipating 2007 annual average volumes of
approximately 16,500 boe/d.
    For the three month period ended September 30, 2007, the weighting
towards natural gas sales averaged 72% compared to 57% in the same period in
2006. For the nine month period ended September 30, 2007, the weighting
towards natural gas averaged 67% compared to 61% for the same period in 2006.
Heavy oil sales made up 21% of total production for the third quarter of 2007
compared to 34% in the same period in 2006. In comparison, heavy oil sales
made up 18% of total sales in the second quarter of 2007. The September 2006
acquisition of Prairie Schooner Petroleum Ltd. ("Prairie Schooner") added
significant natural gas volumes which has increased the natural gas production
weighting since that date. Currently, the Trust estimates that the weighting
towards natural gas production is approximately 65%.

    
    Sales Volumes
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    Natural gas         (mcf/d)   60,827      45,598      67,364      43,656
    -------------------------------------------------------------------------

    Heavy oil          (bbls/d)    3,001       4,557       3,466       3,127

    Light oil and
     condensate        (bbls/d)      531         834       1,261       1,200

    NGLs               (bbls/d)      426         257         589         275

    -------------------------------------------------------------------------
    Total crude oil
     and NGLs          (bbls/d)    3,958       5,648       5,316       4,602

    -------------------------------------------------------------------------
    Total boe/d          (6:1)    14,096      13,248      16,544      11,878
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Sales of natural gas averaged 60.8 mmcf/d for the third quarter of 2007,
compared to 45.6 mmcf/d in 2006, an increase of 33%. In comparison, natural
gas volumes averaged 69.5 mmcf/d for the second quarter of 2007. The third
party plant turnaround at the Willesden Green area during the third quarter
was a significant factor contributing to the reduction in natural gas volumes
from the second to third quarter of 2007. Regulatory issues at the Two Hills
facility and a Doris area pipeline relicensing also contributed to lower
natural gas sales in the quarter.
    Crude oil and NGL sales for the third quarter of 2007 averaged 3,958
bbls/d down 30% from average sales of 5,648 bbls/d in the same period of 2006.
A significant portion of this 2007 third quarter over 2006 quarter decrease
was due to the performance issues encountered in the earlier part of 2007 from
the Mantario heavy oil property. In comparison, crude oil and NGL sales for
the second quarter of 2007 were 5,546 bbls/d; the decrease from the second
quarter of 2007 was primarily due to a reduction in oil volumes related to
2007 property dispositions, further quarter over quarter decreases of
approximately 250 boe/d of heavy oil production at Mantario, as well as
certain negative prior period crude oil and NGL sales volume adjustments of
approximately 800 boe/d.

    
    Commodity Prices

    Average Commodity Prices
    -------------------------------------------------------------------------
                               Three months ended          Nine months ended
                                         Sept. 30,                  Sept. 30,
                          2007     2006  % Change    2007     2006  % Change
    -------------------------------------------------------------------------

    Exchange rate
     (US$/Cdn$)          0.9560   0.8921        7   0.9050   0.8830        2

    Natural gas:
    NYMEX (US$/mmbtu)      6.24     6.17        1     7.02     6.91        2
    AECO spot ($/mcf)      5.14     5.61       (8)    6.52     6.37        2
    True's average
     price ($/mcf)         5.44     6.02      (10)    6.82     6.61        3
    True's average
     price (including
     hedging) ($/mcf)      6.07     6.02        1     7.33     6.61       11

    Crude oil:
    WTI (US$/bbl)         75.15    70.63        6    66.19    68.24       (3)
    Edmonton par
     - light oil ($/bbl)  80.70    79.73        1    73.69    76.06       (3)
    Bow River -
     medium/heavy
     oil ($/bbl)          55.61    51.64        8    52.01    45.18       15
    Hardisty Heavy
     - heavy oil ($/bbl)  47.43    51.61       (8)   39.35    45.20      (13)
    True's average
     prices ($/bbl)
      Light crude oil,
       condensate,
       and NGLs           76.37    69.68       10    59.64    63.61       (6)
      Light crude oil,
       condensate and
       NGLs (including
       hedging)           49.61    67.80      (27)   56.40    62.47      (10)
      Heavy crude oil     42.30    51.92      (19)   40.17    44.62      (10)
      Total crude oil
       and NGLs           50.34    55.35       (9)   46.94    50.71       (7)
      Total crude oil
       and NGLs
       (including
       hedging)           44.07    54.98      (20)   45.81    50.34       (9)
    -------------------------------------------------------------------------
    

    True's natural gas is primarily sold on the daily spot market. During
third quarter of 2007, the AECO Spot reference price decreased by 8% compared
to the same period in 2006. True's average sales price before transportation
and hedging for the third quarter of 2007 averaged $5.44/mcf for its natural
gas, 10% less than the $6.02/mcf received in 2006. In comparison, True's
average sales price for natural gas averaged $7.60/mcf for the second quarter
of 2006.
    For heavy crude oil, True received an average price before transportation
of $42.30/bbl during the third quarter of 2007, a decrease of 19% over 2006
prices. The Bow River reference price increased by 8% and the Hardisty Heavy
reference price decreased by 8% over the same period. The majority of True's
heavy crude oil density ranges between 11 and 16 degrees API consistent with
the Hardisty Heavy reference price. In comparison, True received an average
heavy oil price of $43.01/bbl for the second quarter of 2007.
    For light oil, condensate and NGLs, True recorded an average $76.37/bbl
before hedging during the third quarter of 2007, 10% higher than the average
price received in 2006. During this same period, the Edmonton par price
increased by 1%. In comparison, True received an average oil price for light
oil, condensate and NGLs of $60.59/bbl in the second quarter of 2007. True's
realized price increased 26% from the second quarter to the third quarter of
2007, whereas the Edmonton par price increased by 11% over the same period. A
portion of this difference was due to prior period negative light oil and
condensate volume adjustments with corresponding lower prices, as well as the
impact of average condensate prices realized of approximately $85.00/bbl in
the third quarter.

    Revenue

    Revenue before other income for the third quarter of 2007 was
$48.9 million, 10% less than the $54.0 million in the same period of 2006. The
lower revenue for the third quarter of 2007 was primarily the result of lower
realized natural gas and overall crude oil, condensate and NGL commodity
prices despite higher natural gas volumes and the lower production volumes for
crude oil, condensate and NGLs in the quarter.

    
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Light crude oil,
     condensate and NGLs           6,724       6,994      30,118      25,611
    Heavy oil                     11,680      21,768      38,009      38,098
    -------------------------------------------------------------------------
    Crude oil and NGLs            18,404      28,762      68,127      63,709
    Natural gas                   30,455      25,241     125,495      78,816
    -------------------------------------------------------------------------
    Total revenue before other    48,859      54,003     193,622     142,525
    Other                          1,688         260       3,112       1,138
    -------------------------------------------------------------------------
    Total revenue before
     royalties and hedging        50,547      54,263     196,734     143,663
    Gain (loss) on commodity
     contracts                     1,156        (188)      7,670        (461)
    -------------------------------------------------------------------------
    Total revenue before
     royalties                    51,703      54,075     204,404     143,202
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Financial Instruments

    The Trust has a formal risk management policy which permits management to
use specified price risk management strategies for up to 50% of crude oil,
natural gas and NGL production including fixed price contracts, costless
collars and the purchase of floor price options and other derivative financial
instruments to reduce the impact of price volatility and ensure minimum prices
for a maximum of eighteen months beyond the current date. The program is
designed to provide price protection on a portion of the Trust's future
production in the event of adverse commodity price movement, while retaining
significant exposure to upside price movements. By doing this, the Trust seeks
to provide a measure of stability to cash distributions, as well as, to ensure
True realizes positive economic returns from its capital developments and
acquisition activities.
    As of November 8, 2007, the Trust has hedged volumes of 2,000 bbls/d of
crude oil and 15,055 GJ/d of natural gas for the fourth quarter 2007, 2,000
bbls/d of crude oil and 20,546 GJ/d of natural gas for the first quarter of
2008, and 2,000 bbls/d of crude oil and 15,546 GJ/d of natural gas for the
second to fourth quarters of 2008. The Trust will continue its hedging
strategies focusing on maintaining sufficient cash flow to fund True's
unitholder distributions and capital program.
    A summary of the hedge volumes and average prices by quarter currently
outstanding is shown in the following tables (see Note 19 to the consolidated
financial statements for a detailed disclosure of all commodity contracts in
place as at November 8, 2007):

    
    Crude oil and liquids     Average Volumes (bbls/d)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
                                             Q4 2007     Q1 2008  Q2-Q4 2008
    -------------------------------------------------------------------------
    Costless collars                           2,000       2,000       2,000
    -------------------------------------------------------------------------
    Total bbls/d                               2,000       2,000       2,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average Price (US$/bbl WTI)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
                                             Q4 2007     Q1 2008  Q2-Q4 2008
    -------------------------------------------------------------------------
    Collar ceiling price                       75.00       75.00       82.00
    Collar floor price                         65.00       65.00       65.00
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Natural gas     Average Volumes (GJ/d)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
                                             Q4 2007     Q1 2008  Q2-Q4 2008
    -------------------------------------------------------------------------
    Costless collars                           8,370       5,000           -
    Fixed                                      6,685      15,546      15,546
    -------------------------------------------------------------------------
    Total GJ/d                                15,055      20,546      15,546
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average Price ($/GJ AECO C)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
                                             Q4 2007     Q1 2008  Q2-Q4 2008
    -------------------------------------------------------------------------
    Collar ceiling price                        9.20        9.05           -
    Collar floor price                          7.40        8.00           -
    Fixed                                       7.03        6.65        6.65
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The following is a summary of the gain (loss) on commodity contracts for
the three and nine months ended September 30, 2007:

    Commodity contracts
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    ($000s)                    Crude Oil     Natural     Q3 2007     Q3 2006
                               & Liquids         Gas       Total       Total
    -------------------------------------------------------------------------
    Realized cash gain
     (loss) on contracts(1)         (101)      4,165       4,064        (188)
    Unrealized gain (loss)
     on contracts                 (2,255)       (653)     (2,908)          -
    -------------------------------------------------------------------------
    Total gain (loss) on
     commodity contracts          (2,356)      3,512       1,156        (188)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    ($000s)                    Crude Oil     Natural    YTD 2007    YTD 2006
                               & Liquids         Gas       Total       Total
    -------------------------------------------------------------------------
    Realized cash gain
     (loss) on contracts(2)          962       6,128       7,090        (461)
    Unrealized gain (loss)
     on contracts                 (2,598)      3,178         580           -
    -------------------------------------------------------------------------
    Total gain (loss) on
     commodity contracts          (1,636)      9,306       7,670        (461)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Includes crude oil and natural gas commodity contract premiums
        expensed in the period and the amortization of prior year crude oil
        and natural gas commodity contract premiums of a total $0.3 million
        for the three month period ended September 30, 2007.

    (2) Includes crude oil and natural gas commodity contract premiums
        expensed in the period and the amortization of prior year crude oil
        and natural gas commodity contract premiums of a total $3.7 million
        for the nine month period ended September 30, 2007.
    

    Effective January 1, 2007, new accounting standards were implemented
relating to financial instruments. The impacts of adopting the new standards
are reflected in the Trust's results for the nine month period September 30,
2007. Prior year comparative financial statements have not been restated. For
a description of the new accounting standards and the impact on the Trust's
financial statements of adopting such rules, including the impact on the
Trust's prepaid expenses, deferred financing charges, long-term debt,
convertible debentures and unrealized gains on commodity contracts, refer to
note 3 of the unaudited interim consolidated financial statements of the Trust
for the nine months ended September 30, 2007.

    Royalties

    For the three months ending September 30, 2007, total royalties were
$9.7 million, compared to $13.0 million incurred in the same period in 2006.
Overall royalties as a percentage of revenue (after transportation costs) in
the third quarter of 2007 were 21%, compared with 25% in the same period in
2006. The second quarter of 2007 includes the impact of the reversal of
certain over accruals for heavy crude oil and natural gas royalties from prior
periods of approximately $5.3 million. Based upon the latest and most
up-to-date information and experience, it was determined that certain prior
period royalty accrual estimates were overstated by approximately 2% per month
on average as a percentage of revenue after transportation costs. Royalties
for the nine months ended September 30, 2007 averaged 18% compared to 24% in
the prior period in 2006, primarily a result of this adjustment in the second
quarter.

    
    -------------------------------------------------------------------------
    Royalties by Commodity Type   Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s, except where noted)     2007        2006        2007        2006
    -------------------------------------------------------------------------
    Light crude oil,
     condensate and NGLs           2,212       1,837       6,749       4,848
      $/bbl                        25.12       18.30       13.36       12.04
      Average light crude oil,
       condensate, and NGLs
       royalty rate (%)               33          27          22          19

    Heavy Oil                      1,278       5,738       4,214       9,350
      $/bbl                         4.63       13.68        4.45       10.95
      Average heavy oil royalty
       rate (%)                       11          28          11          26

    Natural Gas                    6,237       5,450      23,459      19,125
      $/mcf                         1.01        0.97        1.28        1.60
      Average natural gas
       royalty rate (%)               21          22          19          25

    -------------------------------------------------------------------------
    Total                          9,727      13,025      34,422      33,323
    -------------------------------------------------------------------------
      $/boe                         7.50       10.69        7.62       10.27
    -------------------------------------------------------------------------
      Average total royalty
       rate (%)                       21          25          18          24
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Royalties, by Type
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Crown royalties, net of ARTC   6,499       5,213      19,732      18,107
    Indian Oil and Gas Canada
     royalties                       544         972       3,855       2,385
    Freehold & GORR                2,684       6,840      10,835      12,831
    -------------------------------------------------------------------------
    Total                          9,727      13,025      34,422      33,323
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Expenses
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Production                    17,024      10,458      51,774      28,946
    Transportation                 1,671       1,682       4,791       4,145
    General and administrative     4,232       2,583      13,468       8,990
    Interest and financing
     charges                       4,422       2,793      13,542       6,403
    Unit-based compensation          869       1,824       3,256       4,875
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Expenses per boe
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($ per boe)                     2007        2006        2007        2006
    -------------------------------------------------------------------------
    Production                     13.13        8.58       11.46        8.93
    Transportation                  1.29        1.38        1.06        1.28
    General and administrative      3.26        2.12        2.98        2.77
    Interest and financing
     charges                        3.41        2.29        3.00        1.97
    Unit-based compensation         0.67        1.50        0.72        1.50
    -------------------------------------------------------------------------
    

    Production Expenses

    For the three months ended September 30, 2007, production expenses
totaled $17.0 million, compared to $10.5 million recorded in 2006. During the
third quarter of 2007, production expenses averaged $13.13/boe, compared to
$8.58/boe over the same period in 2006. For the second quarter, production
expenses averaged $12.69/boe. The large increase in third quarter costs on a
boe basis was mainly due to a significant fixed component of production
expenses and the combination of substantially reduced production volumes in
the third quarter. Also, included in the third quarter was approximately
$1.8 million ($1.37/boe) of costs related to prior periods; excluding this
impact, production expenses for the quarter would have been approximately
$11.76/boe.
    For the nine month period ended September 30, 2007, production expenses
averaged $11.46/boe, compared to $8.93/boe. Production expenses for the nine
month period ended September 30, 2007 include approximately $3.7 million
($0.82/boe) of costs related to prior periods, including primarily additional
costs recognized in the second quarter of 2007; excluding this impact,
production expenses for the year-to-date period would have been approximately
$10.64/boe.
    Production expenses are expected to increase in the fourth quarter of
2007 as additional natural gas input costs are required to operate the
Kerrobert SAGD facility after startup. To mitigate expected increases in
natural gas fuel costs through the first quarter of 2008, True has negotiated
two fixed price fuel purchase contracts as follows: 1) 1,000 GJ/day of natural
gas at $4.65/GJ for the month of October 2007; and 2) 2,000 GJ/day of natural
gas for $6.415/GJ for the months of November 2007 to March 2008.

    
    Production Expenses, by Commodity Type
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s, except where noted)     2007        2006        2007        2006
    -------------------------------------------------------------------------
    Light crude oil,
     condensate and NGLs           1,524         852       6,292       5,221
      $/bbl                        17.31        8.48       12.45       12.96

    Heavy oil                      4,067       3,453      15,084       7,354
      $/bbl                        14.73        8.23       15.93        8.61

    Natural gas                   11,433       6,153      30,398      16,371
      $/mcf                         2.04        1.47        1.65        1.37

    -------------------------------------------------------------------------
    Total                         17,024      10,458      51,774      28,946
    -------------------------------------------------------------------------
      $/boe                        13.13        8.58       11.46        8.93
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Transportation

    Transportation costs are expected to be approximately 2 to 3% of gross
revenues for the 2007 year. For the third quarter of 2007, transportation
costs averaged 3% as anticipated.

    Operating Netback

    For the third quarter of 2007, corporate field operating netback (before
hedging) was $15.76/boe compared to $23.66/boe in 2006. This was the result of
decreased natural gas and crude oil, condensate and NGL commodity prices,
higher operating costs experienced in the current quarter, offset by reduced
average royalties. By comparison, corporate field operating netback (before
hedging) for the second quarter of 2007 was $26.79/boe. After including
hedging activities, corporate field operating netback for the third quarter
was $16.65/boe compared to $23.50/boe in 2006.

    
    Field Operating Netback - Corporate (before hedging)
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($/boe)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Sales                          37.68       44.31       42.87       43.95
    Transportation                 (1.29)      (1.38)      (1.06)      (1.28)
    Royalties                      (7.50)     (10.69)      (7.62)     (10.27)
    Production expense            (13.13)      (8.58)     (11.46)      (8.93)
    -------------------------------------------------------------------------
    Field operating netback        15.76       23.66       22.73       23.47
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Field operating netback for natural gas for the third quarter of 2007
decreased 34% to $2.05/mcf, compared to $3.12/mcf for 2006, reflecting the
weaker natural gas prices experienced in addition to higher production costs,
offset by lower royalties. By comparison, the field operating netback for
natural gas was $4.12/mcf for the second quarter of 2007. After including
hedging activities, field operating netback for natural gas for the third
quarter of 2007 was $2.67/mcf compared to $3.12/mcf in 2006.

    
    Field Operating Netback - Natural Gas (before hedging)
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                        September 30,           September 30,
    ($/mcf)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Sales                           5.44        6.02        6.82        6.61
    Transportation                 (0.24)      (0.13)      (0.22)      (0.16)
    Royalties                      (1.11)      (1.30)      (1.28)      (1.60)
    Production expense             (2.04)      (1.47)      (1.65)      (1.37)
    -------------------------------------------------------------------------
    Field operating netback         2.05        3.12        3.67        3.48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Field operating netback for crude oil and NGLs averaged $24.71/bbl for
the third quarter of 2007, down 22% compared to $30.32/bbl for 2006, compared
to a 9% decrease in the crude oil and NGLs sales price. After including
hedging activities, field operating netback for crude oil and NGLs for the
third quarter of 2007 was $18.24/boe compared to $29.96/boe in 2006.

    
    Field Operating Netback - Crude Oil and NGLs (before hedging)
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($/bbl)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Sales                          50.54       55.35       46.94       50.71
    Transportation                 (0.89)      (2.17)      (0.44)      (1.77)
    Royalties                      (9.59)     (14.58)      (7.56)     (11.30)
    Production expense            (15.35)      (8.28)     (14.73)     (10.01)
    -------------------------------------------------------------------------
    Field operating netback        24.71       30.32       24.21       27.63
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    General and Administrative

    Net general and administrative ("G&A") expenses for the three and nine
months ended September 30, 2007 were $4.2 million and $13.5 million,
respectively, compared to $2.6 million and $9.0 million, respectively, for the
same periods in 2006.
    The increase in the G&A expense for the respective 2007 periods as
compared to the same periods in 2006 is consistent with the increase in
staffing levels, higher compensation and other administrative costs as a
result of two acquisitions completed in 2006. G&A in the third quarter of 2007
includes severance costs of approximately $0.4 million. On a per boe basis,
G&A expenses were $3.26/boe for the third quarter compared to $2.78/boe for
the second quarter of 2007. The increase in G&A on a per boe basis is
consistent with reduced sales volumes experienced during the third quarter.

    
    General and Administrative Expenses
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s, except where noted)     2007        2006        2007        2006
    -------------------------------------------------------------------------
    Gross expenses                 5,551       3,500      17,833      12,430
    Capitalized                     (863)       (562)     (2,677)     (1,984)
    Recoveries                      (456)       (355)     (1,688)     (1,456)
    -------------------------------------------------------------------------
    Net expenses                   4,232       2,583      13,468       8,990
    -------------------------------------------------------------------------
    Net expenses,
     per unit ($/boe)               3.26        2.12        2.98        2.77
    -------------------------------------------------------------------------
    

    G&A expenses for the nine month period ended September 30, 2007 do not
include the costs of the March 30, 2007 Special Meeting, which are presented
separately on the Statement of Income and discussed in the Special Meeting
Costs section of this report.

    Interest and Financing Charges

    True recorded $4.4 million of interest and financing charges in the three
months ended September 30, 2007 compared to $2.8 million in the same period of
2006. For the nine months ended September 30, 2007, interest and financing
charges were $13.5 million compared to $6.4 million in the same period in
2006. The increase in interest and financing charges for both the three and
nine month periods ended September 30, 2007 compared to the same periods in
2006 is consistent with the increase in bank debt. True's net debt at
September 30, 2007 of $233.9 million includes the $79.0 million liability
portion of convertible debentures, $159.2 million of bank debt and net of the
balance of working capital.

    
    Interest and Financing Charges
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s, except where noted)     2007        2006        2007        2006
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Interest and
     financing charges             4,422       2,793      13,542       6,403
    Interest and
     financing charges ($/boe)      3.40        2.29        3.00        1.97

    Net debt including
     convertible debentures
     at quarter end              233,853     245,759     233,853     245,759
    Debt to periods cash flow
     from operations ratio
     annualized                     3.3x        2.6x        2.1x        3.1x

    Net debt excluding
     convertible debentures
     at quarter end              154,832     164,380     154,832     164,380
    Debt to periods cash flow
     from operations ratio
     annualized                     2.2x        1.8x        1.4x        2.1x
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Unit-Based Compensation

    Non-cash unit-based compensation expense for the three and nine months
ended September 30, 2007 was $0.9 million and $3.3 million, respectively,
compared to $1.8 million and $4.9 million in 2006, respectively. The decrease
in the 2007 expense for both periods reflects reduced incentive rights being
granted in the first nine months of 2007, compared to the same period in 2006,
in addition to a reduction in the estimated weighted average fair value of
incentive rights granted for more recent options.

    Capital Expenditures

    True invested $11.3 million on exploration and development activities
during the third quarter of 2007, compared to $33.4 million in the same period
in 2006. Following the execution of True's extensive Q1 2007 drilling program
of 34 (24.0 net) wells, the main focus for the second and third quarters of
2007 was on completions and tie-ins of first quarter drills and further
upgrades to the Kerrobert SAGD facility. During the third quarter of 2007,
True successfully drilled 2 (1.5 net) heavy oil wells in the Mantario area in
Saskatchewan.

    
    Capital Expenditures
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Lease acquisitions and
     retention                       358       1,694       1,860       4,226
    Geological and geophysical       263         736       3,727       1,597
    Drilling and
     completion costs              8,798      19,055      57,718      49,062
    Facilities and equipment       1,892      11,953       9,350      18,382
    -------------------------------------------------------------------------
      Exploration and
       development                11,311      33,438      72,655      73,267
    Corporate and property
     acquisitions                    139      12,728       1,493      12,920
    -------------------------------------------------------------------------
      Total capital
       expenditures - cash        11,450      46,166      74,148      86,187
    Property dispositions - cash  (3,806)          -     (31,275)    (24,514)
    -------------------------------------------------------------------------
      Total net capital
       expenditures - cash         7,644      46,166      42,873      61,673
    -------------------------------------------------------------------------
    Corporate acquisitions
     - non-cash                        -     435,346           -     482,875
    Other - non-cash(1)              116       1,465        (197)      1,892
    -------------------------------------------------------------------------
    Corporate acquisitions
     and other                       116     436,811        (197)    484,767
    -------------------------------------------------------------------------
      Total capital expenditures   7,760     482,977      42,676     546,440
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Other includes current period's asset retirement obligations and unit
        based compensation capitalized.
    

    True holds an extensive land base. At September 30, 2007, True has
approximately 557,000 net undeveloped acres of land of its total developed and
undeveloped net acreage position of 963,000 net acres in Saskatchewan,
Alberta, and British Columbia.
    Dispositions during the first nine months of 2007 consist of six separate
oil and gas property sales involving areas outside of the Trust's core areas
for future development, including three additional minor northern Alberta
property sales which closed in the third quarter. During the third quarter of
2007, True closed on the Shane property sale in July and the Monias and
Rainbow properties in August. The net proceeds received on these property
sales after adjustments was an aggregate of $3.8 million.
    The Trust continues to evaluate further opportunities with its
divestiture program.
    At the end of the third quarter of 2007, the Trust had committed to drill
a total of 2 wells in Alberta with varying commitment dates up to the end of
the first quarter of 2008 pursuant to various farm-in agreements with oil and
gas companies. True expects to satisfy these various drilling commitments at
an estimated cost for True's interest of approximately $2.8 million.

    Depletion, Depreciation and Accretion

    Depletion, depreciation and accretion (site restoration) expense for the
third quarter of 2007 was $38.9 million, compared to the $29.1 million for the
same period in 2006, reflecting the acquisition of Prairie Schooner in
September 2006 in conjunction with increased production volumes and True's
active drilling program over 2006 and 2007. True's DD&A rate for the third
quarter of 2007 of $29.99/boe was higher than $29.11/boe DD&A rate for the
second quarter of 2007, which reflects the adjustment to reserves after 2007
property dispositions.
    For the nine month period ended September 30, 2007, True has excluded
from the depletion calculation $38.4 million for undeveloped land and
$46.9 million for estimated salvage.

    
    Depletion, Depreciation and Accretion Costs
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s, except where noted)     2007        2006        2007        2006
    -------------------------------------------------------------------------
    Depletion and Depreciation    38,347      28,763     130,116      85,057
    Accretion                        543         297       1,581         715
    -------------------------------------------------------------------------
      Total                       38,890      29,060     131,697      85,802
    -------------------------------------------------------------------------
    Per unit ($/boe)               29.99       23.84       29.16       26.46
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    The Trust's independent reserve report effective December 31, 2006 is
summarized in its Annual Information Form which can be found at www.sedar.com.

    Ceiling Test

    The Trust calculates a ceiling test quarterly and annually whereby the
carrying value of petroleum and natural gas properties is compared to
estimated future cash flow from the production of proved reserves. The ceiling
test is performed in accordance with the requirements of the Canadian
Institute of Chartered Accountants ("CICA") AcG-16 "Oil and Gas Accounting -
Full Cost, a two step process.
    The Trust performed a ceiling test calculation at September 30, 2007
resulting in undiscounted cash flows from proved reserves and the unproved
properties not exceeding the carrying value of oil and gas assets.
Consequently, True performed stage two of the ceiling test assessing whether
discounted future cash flows from the production of proved plus probable
reserves plus the carrying cost of unproved properties, net of any impairment
allowance, exceeds the carrying value of its petroleum and natural gas
properties. No impairment in oil and gas assets was identified.
    The ceiling test calculation will be updated on an annual basis based
upon the latest available data, including but not limited to an updated
external reserve engineering report which incorporates a full evaluation of
reserves and the latest commodity pricing deck. Estimating reserves is very
complex, requiring many judgments based on available geological, geophysical,
engineering and economic data. Changes in these judgments could have a
material impact on the estimated reserves. These estimates may change, having
either a negative or positive effect on net earnings as further information
becomes available, and as the economic environment changes. Changes in these
judgments and estimates could have a material impact on the calculation of the
ceiling test.
    At September 30, 2007, the Trust calculated the ceiling test using
weighted average prices of $42.15/bbl for heavy oil, $68.65/bbl for light and
medium gravity oil, and $42.62/bbl for NGLs, and $7.57/mcf for natural gas.

    Special Meeting Costs

    On January 15, 2007, the Trust announced its proposal to convert into an
intermediate exploration and production company (the "Reorganization").
Pursuant to the Reorganization, it was contemplated that holders of trust
units of the Trust would receive an equal number of common shares of a newly
formed corporation that will hold the assets previously held directly or
indirectly by the Trust. The exchangeable shares were also to be exchanged for
common shares based on the conversion ratio thereof. The Reorganization was
subject to all required regulatory approvals and securityholder approval by at
least 66 2/3% of the votes cast by unitholders of the Trust and holders of the
exchangeable shares. At the Special and Annual Meeting held on March 30, 2007,
the special resolution related to the Reorganization was not approved. As a
result, the plan of arrangement was not approved.
    The Trust incurred $3.8 million in costs for legal, financial advisory,
accounting, unitholder solicitation services, printing, mailing and other
expenses that are included as special meeting costs within the statement of
income for the nine month period ended September 30, 2007.

    Asset Retirement Obligations

    As at September 30, 2007, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $27.7 million, compared to $25.5 million at
September 30, 2006, for future abandonment and reclamation of the Trust's
properties. For the nine month period ended September 30, 2007, the ARO
increased by $1.1 million total as a result of accretion expense of $1.6
million, and $0.4 million net changes in estimates and liabilities incurred on
development activities, offset by $0.9 million of liabilities released on
dispositions.

    Income Taxes

    For the first nine months of 2007, the Trust has recorded capital tax
expense of $1.5 million compared to $2.4 million expensed in the same period
in 2006. Capital taxes are based on debt and equity levels of the Trust at the
end of the year in addition to a resource surcharge component of provincial
taxes calculated as a percentage of revenues. In the second quarter of 2006,
the federal government enacted legislation that eliminates federal capital
tax, retroactive to January 1, 2006. As a result, capital taxes on a
go-forward basis are based on only provincial capital taxes.
    Future income taxes arise from differences between the accounting and tax
bases of the Trust's assets and liabilities. For the first nine months of
2007, the Trust recognized a future income tax recovery of $30.0 million
compared to a recovery of $49.0 million in the same period in 2006. The larger
recovery for the 2006 period was primarily reflective of more significant
enacted tax rate reductions in 2006. On April 10, 2006 the Alberta government
enacted a decrease of 1.5 percent to the provincial corporate tax rate. In
addition, on June 6, 2006 the federal government enacted a two percent
decrease to the federal corporate tax rate from January 1, 2008 to January 1,
2010 and an elimination of the 1.12 percent federal surtax at January 1, 2008.
In addition, on June 12, 2007, the federal government further reduced the
general corporate tax rate by 0.5 percent starting 2011.
    Under our current structure, the operating entities make interest and
royalty payments to the Trust, which transfers taxable income to the Trust to
eliminate income subject to corporate and other income taxes in the operating
entities. With the new legislation, such amounts transferred to the Trust
could be taxable beginning in 2011 as distributions will no longer be
deductible for income tax purposes. At that time, True could claim tax pools
in its operating companies, reduce the income transferred to the Trust, and
pay all or a portion of distributions as a return of capital basis. Until
2011, under the terms of its Trust indenture, the Trust is required to
distribute amounts equal to at least its taxable income. In the event that the
Trust has undistributed taxable income in a taxation year (prior to 2011), an
additional special taxable distribution, subject to certain withholding taxes,
would be required by the terms of its trust indenture.
    The estimate of future taxes is based on the current tax status of the
Trust. Future events, which could materially affect future income taxes such
as acquisitions and dispositions and modifications to the distribution policy,
are not reflected under Canadian GAAP until the events occur and the related
legal requirements have been fulfilled. As a result, future changes to the tax
legislation could lead to a material change in the recorded amount of future
income taxes.
    The new legislation is not expected to directly affect our cash flow
levels and distribution policies until 2011 at the earliest.

    Enactment of the Tax on Income Trusts

    On June 12, 2007, the legislation implementing the new tax (the "SIFT
tax") on publicly traded income trusts and limited partnerships, referred to
as "Specified investment flow-through" ("SIFTs") entities (Bill C-52) received
third reading in the House of Commons and on June 22, 2007, Bill C-52 received
Royal assent. As a result, the tax was considered to be enacted for accounting
purposes in June 2007, which resulted in a $1.2 million future income tax
recovery amount being recorded to reflect current temporary differences
between the book and tax basis of assets and liabilities expected to be
remaining in the Trust in 2011. The SIFT tax announcement and the related
future income tax recovery did not affect cash flow or distributions and is
not expected to affect distribution policies until 2011 at the earliest.
    SIFTs are certain publicly traded income and royalty trusts and limited
partnerships including True. For SIFTs in existence on October 31, 2006 the
SIFT tax will be effective in 2011, unless certain rules related to "undue
expansion" are not adhered to. Under the guidance provided, True can increase
its equity by approximately $737 million between now and 2011 without
prematurely triggering the SIFT tax.
    Under the SIFT tax, distributions will not be deductible for income tax
purposes by SIFTs in 2011 and thereafter and any trust level taxable income
will be taxed at an approximate of the corporate income tax rate. The
resultant distributions will be considered taxable dividends to unitholders,
generally eligible for the dividend tax credit. Distributions representing a
return of capital will continue to be an adjustment to a unitholder's adjusted
cost base of trust units.
    The True Board of Directors and Management continue to review the impact
of this tax on business strategy. At the present time, True believes some or
all of the following actions will or could result due to the enactment of the
SIFT tax:
    
    -   If structural or other similar changes are not made, the after-tax
        distribution yield in 2011 to taxable Canadian investors will remain
        approximately the same, however, the distribution yield in 2011 to
        tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.)
        and foreign investors would fall by an estimated 31.5 percent and
        26.5 percent, respectively;
    -   A portion of True's cash flow could be allocated to the payment of
        the SIFT tax, or other forms of tax, and would not be available for
        distribution or re-investment;
    -   True could convert to a corporate structure to facilitate investing a
        higher proportion or all of its cash flow in exploration and
        development projects. Such a conversion and change to capital
        programs could result in a significant reduction to or elimination of
        distributions and/or dividends;
    -   True might determine that it is more economic to remain in the trust
        structure, at least for a period of time, and shelter its taxable
        income using tax pools and pay all or a portion of its distributions
        on a return of capital basis, likely at a lower payout ratio.
        Further, as the SIFT tax rate exceeds the corporate income tax rate
        that would be applicable to True, some corporate tax might be paid
        resulting in all or a portion of distributions being paid on a return
        of capital basis at a lower payout ratio.
    

    The Trust is reviewing all organizational structures and alternatives to
minimize the impact of the SIFT tax on our unitholders. While there can be no
assurance that the negative effect of the tax can be minimized or eliminated,
True and its advisors will continue to work diligently on these issues.
    The table below, provided by the Government of Canada in a backgrounder
accompanying its October 31, 2006 announcement, shows a simplified comparison
of the effects of the changes to investor tax rates in 2011:

    
                                      Current System         Proposed System
                         ----------------------------------------------------
                                                          Income
                                                         portion
                          Income portion        Large   of trust       Large
                                of trust  corporation    distrib corporation
    Investor               distributions   (dividend)    -utions   (dividend)
    -------------------------------------------------------------------------
    Taxable Canadian
     individuals(1)                  46%         46%       45.5%       45.5%
    Canadian tax-exempt investors     0%         32%       31.5%       31.5%
    Taxable U.S. investors(2)        15%         42%       41.5%       41.5%
    -------------------------------------------------------------------------

    (1) All rates in the table are as of 2011, and include both entity- and
        investor-level tax (as applicable). Rates for "taxable Canadian
        individuals" assume that top personal income tax rates apply and that
        provincial governments increase their dividend tax credit for
        dividends of large corporations.

    (2) Canadian taxes only. U.S. tax will also apply in most cases, net of
        any foreign tax credits.
    

    As at September 30, 2007, the operating subsidiaries and the Trust itself
have a total future income tax liability balance of $94.0 million. Canadian
GAAP requires that a future income tax liability be recorded when the book
value of assets exceeds the balance of tax pools.
    At September 30, 2007 the Trust and operating subsidiaries of the Trust
had approximately $501 million, net of partnership deferrals, in tax pools
available for deduction against future income as follows:

    
    -------------------------------------------------------------------------
                                                       Operating
                                                          subsid
    ($000s)                                    Trust     -iaries       Total
    -------------------------------------------------------------------------
    Intangible resource pools (net of
     partnership deferrals)                   15,000     309,000     324,000
    Undepreciated capital cost                     -     137,000     137,000
    Loss carryforwards (expire
     through 2026)                                 -      29,000      29,000
    Unit issue costs                           6,000       5,000      11,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
                                              21,000     480,000     501,000
    

    Distributions

    Trust unitholders who held their trust units throughout the first nine
months of 2007 received distributions of $0.72 per unit. For the nine month
period ended September 30, 2007 the Trust declared $54.4 million in total
distributions as follows:

    
    -------------------------------------------------------------------------
    ($000s, except per unit amount)                 Distribution
    Nine month period ended September 30, 2007          Per Unit       Total
    -------------------------------------------------------------------------
    Distributions declared                                $ 0.72    $ 54,374
    -------------------------------------------------------------------------
    

    Distribution Paid History(1)

    Distributions comprise a taxable portion and a return of capital portion
(tax deferred). The return of capital component reduces the cost basis of the
trust units held, as described below. For additional information, please see
our website at www.trueenergytrust.com.

    
    -------------------------------------------------------------------------
                                       Distributions     Taxable   Return of
    Calendar Year                           per unit     Portion     Capital
    -------------------------------------------------------------------------
    2005 (two months)(2)                     $ 0.480     $ 0.456     $ 0.024
    2006(3)                                    2.640       2.033       0.607
    -------------------------------------------------------------------------
    Cumulative to Dec. 31, 2006              $ 3.120     $ 2.489     $ 0.631
    -------------------------------------------------------------------------
    2007 year to date                          0.720          (3)         (3)
    -------------------------------------------------
    Cumulative to Sept. 30, 2007             $ 3.840
    -------------------------------------------------------------------------

    (1) Applies to unitholders who are residents of Canada and hold their
        trust units as capital property.
    (2) Based upon the distributions paid in the 2005 calendar year, after
        the November 2, 2005 Arrangement with TKE Energy Trust.
    (3) The majority of the distributions paid in 2007 to Canadian
        unitholders will be taxable. U.S. unitholders will also be taxable.
        Any non-taxable amounts will be treated as a tax deferred return of
        capital, or an adjustment to the cost base of the units. Actual
        taxable amounts may vary depending on actual distributions and are
        dependent upon production, commodity prices and funds flow
        experienced throughout the year. The approximate taxable portion of
        2007 distributions to Canadian unitholders is currently estimated to
        be between 90 to 100%.

        In consultation with its U.S. tax advisors, True believes that its
        trust units should be "qualified dividends" for U.S. federal
        purposes. As such, the portion of distributions made during 2007 that
        are considered dividends for U.S. federal purposes should qualify for
        the reduced rate of tax applicable to long-term capital gains.
        Unitholders or potential unitholders should consult their own legal
        or tax advisors as to their particular income tax consequences of
        holding True units. Please view our March 7, 2007 press release
        addressing this.
    

    Monthly Distributions

    Actual distributions paid and declared per trust unit along with relevant
payment dates for 2007 to date are as follows:

    
    -------------------------------------------------------------------------
                                                                Distribution
    Ex-distribution Date   Record Date         Payment Date         per unit
    -------------------------------------------------------------------------
    December 27, 2006      December 31, 2006   January 15, 2007     $ 0.12
    January 29, 2007       January 31, 2007    February 15, 2007      0.12
    February 26, 2007      February 28, 2007   March 15, 2007         0.12
    April 26, 2007         April 30, 2007      May 15, 2007           0.08
    May 29, 2007           May 31, 2007        June 15, 2007          0.08
    June 27, 2007          June 29, 2007       July 16, 2007          0.08
    July 27, 2007          July 31, 2007       August 15, 2007        0.08
    August 29, 2007        August 31, 2007     September 17, 2007     0.08
    September 26, 2007     September 28, 2007  October 15, 2007       0.08
    October 29, 2007       October 31, 2007    November 15, 2007      0.08
    November 28, 2007(1)   November 30, 2007   December 17, 2007      0.08(2)
    December 27, 2007(1)   December 31, 2007   January 15, 2008       0.08(2)
    -------------------------------------------------------------------------

    (1) Anticipated ex-distribution dates for November and December. These
        dates are subject to change and/or confirmation by the Toronto Stock
        Exchange and will be confirmed by monthly press release.
    (2) Subject to confirmation, the Management and Board of the Trust
        continuously assess distribution levels, in light of current
        commodity prices, hedge positions, production volumes, market
        conditions and other factors, and announces the distribution per unit
        amount on a monthly basis.
    

    During the first nine months of 2007, the distributions were funded
directly from cash flows from operating activities.
    On January 15, 2007, the Trust announced its intention to convert to a
growth oriented, dividend paying intermediate exploration and production
company (the "Reorganization"), which was voted upon by securityholders at an
Annual and Special Meeting (the "Meeting") held on March 30, 2007. Further as
announced on February 15, 2007, the Board of True determined that no
distribution would be declared for the month of March 2007, which would
normally have been paid on April 16, 2007 to unitholders of record as at
March 30, 2007, pending the consideration of the Reorganization at the
Meeting. As a result of the outcome of the Meeting, wherein the Reorganization
was not approved, True remains a trust.
    In the second and third quarters of 2007, monthly distributions of $0.08
per unit were declared and paid. Further, the Board has announced it has set a
distribution policy for the fourth quarter of 2007 at a monthly rate of $0.08
per unit, subject to monthly confirmation, based on current commodity prices,
hedging program, production volumes and market conditions. This go-forward
strategy for the distribution level is consistent with providing a balance
between providing income to unitholders and funding for True's capital program
required to further develop its land base.

    Foreign Ownership Update

    Based on information from Trust records and information provided by
intermediaries holding Trust units for others, The Trust estimates that, as of
October 19, 2007 approximately 29 percent of Unitholders are non-Canadian
residents with the remaining 71 percent being Canadian residents. True's trust
indenture provides that not more than 40 percent of its trust units can be
held by non-Canadian residents.

    Liquidity and Capital Resources

    True's net debt as at September 30, 2007 was $233.9 million, representing
$159.2 million outstanding on the credit facility, $79.0 million in
convertible debentures (liability component) and net of the balance of working
capital.
    During the nine month period ended September 30, 2007, the Trust has
reduced its net debt by approximately $42.0 million. As at September 30, 2007,
working capital was $4.4 million compared to a working capital deficiency of
$36.4 million at December 31, 2006. This was achieved as a result of many
factors including the proceeds received from the Trust's May 31, 2007 equity
offering, proceeds received from six property dispositions, maintaining
sustainable distributions compared to cash flows from operations for the year
and capital expenditure requirements in the period and continued execution of
the Trust's hedging program.
    The current credit facility consists of a $15 million demand operating
facility provided by one Canadian bank and a $175 million extendible revolving
term credit facility syndicated by two Canadian chartered banks, a U.S. bank,
a Canadian financial institution and one institutional lender. The revolving
period on the revolving term credit facility ends on June 29, 2008, unless
extended for a further 364 day period. Should the facilities not be renewed
they convert to 366 day non-revolving term facilities on the renewal date. The
borrowing base was renewed effective August 31, 2007 and is currently
scheduled for renewal on March 31, 2008. Further details of the credit
facilities are disclosed in note 7 of the consolidated financial statements.
As at September 30, 2007, there is approximately $31 million undrawn under
these lending facilities.
    Management expects to be able to fund its capital expenditure program for
the remainder of 2007 using cash flow from operations, available credit
facilities, the proceeds from the expected sale of certain non-core assets,
and the maintenance of sustainable distributions. If cash flows are other than
projected, capital expenditure levels are expected to be adjusted. The
practice of continually monitoring spending opportunities in comparison to
expected cash flow levels allows for adjustments to the capital program as
required.
    On June 15, 2006 the Trust completed a bought deal public offering of
86,250 7.5% convertible unsecured subordinated debentures at a price of $1,000
per Debenture for aggregate gross proceeds of $86,250,000.
    The debentures have a face value of $1,000 per debenture and a maturity
date of June 30, 2011. The debentures bear interest at an annual rate of 7.50%
payable semi-annually on June 30 and December 31 in each year commencing
December 31, 2006. The debentures are convertible at anytime at the option of
the holders into trust units of the Trust at a conversion price of $16.00 per
trust unit. The Trust will have the right to redeem all or a portion of the
debentures at a price of $1,050 per debenture after June 30, 2009 and on or
before June 30, 2010 and at a price of $1,025 per debenture after June 30,
2010 and before the maturity date. Upon maturity or redemption of the
debentures, the Trust may, subject to notice and regulatory approval, pay the
outstanding principal and premium (if any) on the debentures in cash or
through the issue of additional trust units at 95% of the weighted average
trading price of the trust units.
    As at October 31, 2007 the Trust had outstanding a total of 6,029,497
incentive units exercisable at an average exercise price of $10.82 per unit,
390,813 exchangeable shares (convertible, as at October 31, 2007 into an
aggregate of 321,647 trust units, subject to further adjustments based on
distributions made on trust units) and 79,715,595 trust units.
    On February 13, 2007, True announced it had identified certain small,
non-core properties, for possible disposition. The Trust closed on two
dispositions at the end of the first quarter and one disposition in the second
quarter, and three additional dispositions in the third quarter. The proceeds
were used to fund capital expenditures and pay down debt. The Trust will
continue to evaluate opportunities under its divestiture program.

    Business Prospects and Outlook

    Since its formation in September 2000, True Energy Inc. has experienced
significant growth in its production and land base. The Trust continues to
develop its core assets and conduct some exploration programs utilizing its
large inventory of geological prospects. In addition, the Trust will continue
to explore potential acquisition opportunities. Currently, the Trust's
producing properties are located in Saskatchewan, Alberta and British
Columbia.
    Following the results of the Special and Annual Meeting held on March 30,
2007, True remains a trust. Therefore, the focus will continue to be
maintaining sufficient cash flow to provide a balance between unitholder
distributions and funding of the Trust's capital program.
    Late in September 2006, the Trust completed the purchase of a facility in
the Kerrobert, Saskatchewan area and wells which has allowed the Trust to
implement a steam assisted gravity drainage ("SAGD") project. Execution of the
Kerrobert SAGD project is on track. During the first quarter of 2007, True
completed its Phase 1 drilling campaign consisting of five cold producers and
four thermal wells. SAGD facility upgrades continued throughout the second and
third quarters of 2007. The steam injection commenced in late September and
after an initial "warm-up" phase the four thermal production wells are now
configured for fluid production. Oil production from these thermal wells is
expected to ramp up during the during the remainder of the fourth quarter and
reach the anticipated peak rates of approximately 500 bbls/d per well pair
late in 2007 or early in the first quarter of 2008, thereby increasing total
heavy oil production in the Kerrobert area to approximately 4,000 bbls/d.
    Based upon field estimates, current production is approximately
15,500 boe/d and increasing. Further focus on recompletion, optimization, and
tie-in potential, in conjunction with response from the Kerrobert SAGD
expansion start-up is anticipated to provide significant production growth
prior to the end of the 2007 year. The Trust is anticipating 2007 annual
average volumes of approximately 16,500 boe/d, weighted approximately 65%
towards natural gas.
    True further anticipates the US$/Cdn.$ exchange rate to average 1.00
through remainder of the 2007 year.
    The Trust continues to maintain a large undeveloped land base of
approximately 0.8 million (0.6 million net) acres and has identified a
multi-year drilling inventory of over 375 net locations.
    Gas prices continue to show volatility with lack of cold weather and the
current supply/demand imbalance. Given the current natural gas price outlook,
coming into the winter drilling season, True plans to reduce its first quarter
2008 winter drilling activity compared to the first quarter of 2007. True's
first quarter 2008 capital program will not exceed $10 million which compares
to a front end loaded 2007 capital program of approximately $50 million in
first quarter 2007. True will continue to take a balanced approach to the
priority use of cash flow between level of distributions and size of its 2008
capital program. Given the nature of True's lands and their inherent advantage
of year round access, True will spread its 2008 capital program more evenly
through the full year of 2008 to take advantage of reduced service costs
during non-peak times. True will focus on increasing its farm-out activity in
non-core areas. If the 2008 outlook for commodity prices improves, True would
plan to increase its capital spending in third and fourth quarters of 2008.

    Business Risks and Uncertainties

    The reader is advised that True continues to be subject to various types
of business risks and uncertainties as described in the Management Discussion
and Analysis in the Trust's December 31, 2006 Annual Report and the Trust's
Annual Information Form. In addition, the Trust is also subject to the
following business risks and uncertainties:

    Environmental Regulation and Risk

    All phases of the oil and natural gas business present environmental
risks and hazards and are subject to environmental regulation pursuant to a
variety of federal, provincial and local laws and regulations. Compliance with
such legislation can require significant expenditures and a breach may result
in the imposition of fines and penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in
stricter standards and enforcement, larger fines and liability and potentially
increased capital expenditures and operating costs. In 2002, the Government of
Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to
reduce its greenhouse gas emissions to specified levels. There has been much
public debate with respect to Canada's ability to meet these targets and the
Government's strategy or alternative strategies with respect to climate change
and the control of greenhouse gases. Implementation of strategies for reducing
greenhouse gases whether to meet the limits required by the Protocol or as
otherwise determined could have a material impact on the nature of oil and
natural gas operations, including those of the Trust.
    In Alberta, the reduction emission guidelines outlined the Climate Change
and Emissions Management Amendment Act (the "Act") came into effect July 1,
2007. Alberta facilities emitting more than 100,000 tonnes of greenhouse gases
a year must reduce their emissions intensity by 12 per cent. Industries have
three options to choose from in order to meet the reduction requirements
outlined in the Act, and these are: (a) by making improvement to operations
that result in reductions; (b) by purchasing emission credits from other
sectors or facilities that have emissions below the 100,000 tonne threshold
and are voluntarily reducing their emissions; or (c) by contributing to the
Climate Change and Emissions Management Fund. Industries can either choose one
of these options or a combination thereof. On April 26, 2007, the Federal
Government released its Action Plan to Reduce Greenhouse Gases and Air
Pollution (the "Action Plan"), also known as ecoACTION which includes the
Regulatory Framework for Air Emissions. This Action Plan covers not-only large
industry, but regulates the fuel efficiency of vehicles and the strengthening
of energy standards for a number of energy-using products. Given the evolving
nature of the debate related to climate change and the control of greenhouse
gases and resulting requirements, it is not currently possible to predict
either the nature of those requirements or the impact on the Trust and its
operations and financial condition.

    Announcement on the Alberta Royalty and Tax Regime

    On October 25, 2007, the Alberta Government released The New Royalty
Framework which summarizes the government's decision on Alberta's new royalty
regime pertaining to oil and gas resources, including oil sands, conventional
oil and gas and coalbed methane. This was in response to recommendations
recently put forth by an Alberta Royalty Review Panel. This new royalty regime
will take effect on January 1, 2009. The actual impact will be determined
based on the actual legislation as well as production rates, drilling depths,
commodity prices, product mix and the percentage of production from Alberta
after January 1, 2009.
    The proposed royalty changes are very sensitive to production rate and
natural gas prices. The majority of True's current Alberta wells are in the
500m to 1000m depth range and typically produce at lower rates. Based on
publicly available information in respect of the New Royalty Framework, and by
re-running True's reserves evaluated at December 31, 2006 and using the same
assumptions including pricing (an average of consultants forecast prices as at
January 1, 2007), True estimates that the proposed royalty rates would result
in a positive revision to True's net present value of future net revenues from
reserves ,as at December 31, 2006, (based upon a 10% discount factor) of
approximately 0.8% and a 0.8% increase in net reserves (working interest and
royalty interests in reserves after deducting royalty obligations), as at
December 31, 2006. Based on the foregoing, the New Royalty Framework would
result in a positive revision to True's net asset value, as at December 31,
2006, of approximately 1%.
    True is continuing to assess the impact on its ongoing Alberta
operations. While the Trust cannot determine the full potential impact of
these changes to the royalty rate on its operations at this time, it is
anticipated that the impact will not be material to True given True's current
weighting of Alberta production to total corporate production, as well as
True's production in Alberta being primarily in shallow natural gas wells.

    Critical Accounting Estimates

    The reader is advised that the critical accounting estimates, policies,
and practices as described in the Management Discussion and Analysis in the
Trust's December 31, 2006 Annual Report continue to be critical in determining
True's unaudited financial results as at September 30, 2007. Except as
described in Note 3 of the attached unaudited interim consolidated financial
statements, there were no changes in accounting policies for the nine month
period ended September 30, 2007.
    In September 2007, the Accounting Standards Board ("AcSB") issued a
bulletin relating to the transition to International Financial Reporting
Standards ("IFRS") from Canadian GAAP and based on work undertaken to date, no
significant impediments to adopting IFRS by the proposed transition date have
been identified. True is monitoring industry discussion regarding the
implications of the replacement of the CICA's Accounting Guideline 16 with
IFRS 6, which is expected to have major implications for True's full cost
accounting policies. The AcSB expects to be in a position to confirm by
March 31, 2008 whether the transition date for adopting IFRS will be
January 1, 2011.

    Legal, Environmental Remediation and Other Contingent Matters

    The Trust reviews legal, environmental remediation and other contingent
matters to both determine whether a loss is probable based on judgment and
interpretation of laws and regulations and determine that the loss can
reasonably be estimated. When the loss is determined, it is charged to
earnings. The Trust's management monitor known and potential contingent
matters and make appropriate provisions by charges to earnings when warranted
by the circumstances.

    Controls and Procedures

    Disclosure Controls and Procedures

    Disclosure controls and procedures have been designed to provide
reasonable assurance that material information relating to the Trust,
including its consolidated subsidiaries, is made know to the Trust's Chief
Executive Officer and Chief Financial Officer by others within those entities,
particularly during the period in which the annual and interim filings are
being prepared.

    Internal Controls over Financial Reporting

    The Trust's Chief Executive Officer and Chief Financial Officer have
designed or caused to be designed under their supervision internal controls
over financial reporting to provide reasonable assurance regarding the
reliability of the Trust's financial reporting and the preparation of
financial statements for external purposes in accordance with the Canadian
GAAP.
    The Trust's Chief Executive Officer and Chief Financial Officer are
required to cause the Trust to disclose herein any change in the Trust's
internal control over financial reporting that occurred during the Trust's
most recent interim period that has materially affected, or is reasonably
likely to materially affect, the Trust's internal control over financial
reporting. No material changes in the Trust's internal control over financial
reporting were identified during the three months ended September 30, 2007,
that has materially affected, or are reasonably likely to materially affect,
the Trust's internal control over financial reporting.
    It should be noted that a control system, including the Trust's
disclosure and internal controls and procedures, no matter how well conceived,
can provide only reasonable, but not absolute, assurance that the objectives
of the control system will be met and it should not be expected that the
disclosure and internal controls and procedures will prevent all errors or
fraud.

    Standardized Distributable Cash

    The Canadian Securities Administrators recently revised and re-issued
National Policy 41-201 "Income Trusts and Other Indirect Offerings", which
includes disclosures regarding distributable cash for Income Trusts. Further,
the Canadian Institute of Chartered Accountants ("CICA") issued the
Interpretive Release "Standardized Distributable Cash in Income Trusts and
Other Flow-Through Entities: Guidance on Preparation and Disclosure" (the
"Release") in July 2007, which is required for the third quarter of 2007. In
the new guidance, sustainability concepts are discussed and standardized
distributable cash is defined as cash flow from operating activities less
adjustments for productive capacity maintenance, long-term unfunded
contractual obligations and the effect of any foreseeable financing matters,
related to debt covenants, which could impair True's ability to pay
distributions or maintain productive capacity. This Management Discussion and
Analysis is in all material respects in accordance with the recommendations
provided in CICA's Release.

    
    -------------------------------------------------------------------------
                                  Three months ended       Nine months ended
    ($000s, except per                  September 30,           September 30,
     indicators)                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    Net income (loss)            (17,003)      1,652     (23,833)     17,154
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash flow from operating
     activities                   14,880      43,509      59,816      62,981
    Productive capacity
     maintenance(1)              (11,331)    (33,438)    (72,655)    (73,267)
    -------------------------------------------------------------------------
    Standardized distributable
     cash                          3,549      10,071     (12,839)    (10,286)
    Proceeds on sale of
     property, plant and
     equipment                     3,806           -      31,275      24,514
    Funding from DRIP                  -      20,760           -      35,824
    Net proceeds from issue of
     trust units                     (11)          -      54,375           -
    Proceeds from issue of
     convertible debentures,
     net of issue costs                -           -           -      82,227
    Bank borrowings
     (debt repayment) and
     working capital changes
     and other                    11,788       6,015     (18,437)    (41,512)
    -------------------------------------------------------------------------
    Cash Distributions
     declared                     19,132      36,846      54,374      90,767
    Accumulated distributions,
     beginning of period         176,958      71,282     141,716      17,361
    -------------------------------------------------------------------------
    Accumulated distributions,
     end of period               196,090     108,128     196,090     108,128
    -------------------------------------------------------------------------
    Standardized distributable
     cash per unit - basic         $0.04       $0.15      ($0.16)     ($0.14)
    Standardized distributable
     cash per unit - diluted       $0.04       $0.13      ($0.14)     ($0.13)
    -------------------------------------------------------------------------
    Standardized distributable
     cash payout ratio(2)           5.39        3.66         N/A         N/A
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Distributions declared
     per unit                      $0.24       $0.72       $0.72       $2.16
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Excess (shortfall) of net
     income over cash
     distributions declared      (36,135)    (35,194)    (78,207)    (73,613)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Excess (shortfall) of cash
     flow from operating
     activities over cash
     distributions declared       (4,252)      6,663       5,442     (27,786)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Please refer to the discussion of productive capacity maintenance
        below
    (2) Represents cash distributions declared divided by standardized
        distributable cash
    

    True strives to fund both distributions and maintenance capital primarily
from cash flow. True's 2007 capital budget was initially set at approximately
40% to 50% of annual cash flow. Property dispositions, equity issues or
additional borrowings may be required from time to time to fund a portion of
the distributions and/or capital expenditures to maintain or increase
productive capacity may be required based on forecast levels of cash flow,
capital efficiency and debt levels.
    Productive capacity is the amount of capital funds required in a period
for an enterprise to maintain its ability to generate future cash flow from
operating activities at a constant level. As commodity prices can be volatile
and short-term variations in production levels are often experienced in the
oil and gas industry, True defines production capacity as production on a
barrel of oil equivalent basis. A quantifiable measure for these short-term
variations is not objectively determinable or verifiable due to various
factors including the inability to distinguish natural production declines
from the effect of production additions resulting from capital and
optimization programs, and the effect of temporary production interruptions.
As a result, the adjustment for productive capacity maintenance in True's
calculation of standardized distributable cash is True's capital expenditures
excluding the cost of any asset acquisition, corporate asset acquisitions or
proceeds of any asset disposition. True believes that its capital programs
based on 40% to 50% of forecast cash flow including its current view of True's
assets and opportunities and True's outlook for commodity prices and industry
conditions in the medium term, should be sufficient to maintain True's
productive capacity in the medium term. True sets its hurdle rates for
evaluating potential development and optimization projects according to these
parameters. Due to the risks inherent in the oil and natural gas industry,
particularly True's exploration and development activities and inherent
variations in commodity prices, there can be no assurance that capital
programs, whether limited to excess of cash flow over distributions or not,
will be sufficient to maintain or increase True's production levels or cash
flow from operating activities. True's capital expenditures and production can
be impacted by the timing of the capital program and spring break up
associated with certain operating areas of its properties. As True strives to
maintain sufficient credit facilities and appropriate levels of bank debt,
this seasonality is not expected to influence True's distribution policies.
    True's calculation of standardized distributable cash has no adjustment
for long-term unfunded contractual obligations. True's only long-term unfunded
contractual obligation at this time is for asset retirement obligations.
True's abandonment obligations are being funded on an annual basis. Our
maintenance capital amount includes an amount for abandonment expenditures
incurred during the period. True currently has no financing restrictions on
distributions arising from compliance with its debt covenants. True regularly
monitors its current forecast debt levels to ensure debt covenants are not
exceeded.
    Distributions typically exceed net income as a result of non-cash items
such as unit-based compensation, depletion, depreciation and accretion,
unrealized loss (gain) on commodity contracts, and future income tax expense
(recovery). These non-cash items generally result in a reduction to net
income, with no impact to cash flow from operating activities. Therefore,
distributions will exceed net income in most periods. In the event
distributions exceed cash flow from operating activities and the requirements
of True's capital program, the shortfall will typically be funded by a
combination of available bank facilities, equity or debt issues, or the sale
proceeds from non-core assets.
    The board of directors and management regularly review the level of
distributions. The board considers a number of factors, including expectations
of future current commodity prices, hedge positions, production volumes,
capital expenditure requirements, market conditions, the availability of debt
and equity capital and other factors. As a result of the volatility in
commodity prices, changes in production levels and capital expenditure
requirements, there can be no certainty that True will be able to maintain
current levels of distributions and distributions can and may fluctuate in the
future.

    
    ($000s, except per indicators)                     To September 30, 2007
    -------------------------------------------------------------------------
    Cumulative distributable cash from operations(1)                  15,590
    Proceeds on sale of property, plant and equipment                 55,789
    Funding from DRIP                                                 42,909
    Net proceeds from issue of trust units                            54,375
    Proceeds from issue of convertible debentures,
     net of issue costs                                               82,227
    Bank borrowings (debt repayment) and working
     capital changes and other                                       (54,800)
    -------------------------------------------------------------------------
    Cumulative cash distributions declared(1)                        196,090
    -------------------------------------------------------------------------
    Standardized distributable cash payout ratio(2)                    12.58
    -------------------------------------------------------------------------
    (1) Subsequent to the November 2, 2005 reverse takeover of TKE Energy
        Trust
    (2) Represents cumulative distributions declared divided by cumulative
        standardized distributable cash
    

    Sensitivity Analysis

    The table below shows sensitivities to cash flow as a result of product
price and operational changes. This is based on actual prices received for the
three month period ended September 30, 2007 and average production volumes of
14,096 boe/d during that period, as well as the same level of debt outstanding
at September 30, 2007. Diluted weighted average trust units is based upon the
third quarter of 2007. These sensitivities are approximations only, and not
necessarily valid under other significantly different production levels or
product mixes. Hedging activities can significantly affect these
sensitivities. Changes in any of these parameters will affect cash flow as
shown in the table below:

    
    -------------------------------------------------------------------------
                                                                  Cash Flow
                                                                       from
                                              Cash Flow from     Operations
                                                  Operations    Per Diluted
                                                 (annualized)          Unit
    -------------------------------------------------------------------------
    Sensitivity Analysis                              ($000s)            ($)
    -------------------------------------------------------------------------
    Change of US $1/bbl WTI                            1,300           0.02
    Change of $0.10/ mcf                               1,800           0.02
    Change of US $0.01 Cdn/US exchange rate              800           0.01
    Change in prime of 1%                              1,600           0.02
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Selected Quarterly Consolidated Information

    The following table sets forth selected consolidated financial information
of the Trust for the most recently completed quarters ending at the third
quarter of 2007.

    -------------------------------------------------------------------------
    2007 - Quarter ended (unaudited)
    ($000s, except per unit amounts)       March 31     June 30     Sept. 30
    -------------------------------------------------------------------------
    Revenues before royalties and hedging    71,196      74,991       50,547
    Cash flow from operations(1)             29,988      34,192       17,478
    Cash flow from operations per unit(1)
      Basic                                   $0.43       $0.47        $0.22
      Diluted                                 $0.42       $0.45        $0.22
    Net income (loss)                        (8,571)      1,741      (17,003)
    Net income (loss) per unit
      Basic                                  $(0.12)      $0.02       $(0.21)
      Diluted                                $(0.12)      $0.02       $(0.21)
    Net capital expenditures (cash)          28,103       7,126        7,644
    Distributions declared                   16,866      18,376       19,132
    Distributions per unit                    $0.24       $0.24        $0.24
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    2006 - Quarter ended
     (unaudited)
    ($000s, except per unit
     amounts)                   March 31     June 30    Sept. 30     Dec. 31
    -------------------------------------------------------------------------
    Revenues before royalties
     and hedging                  46,396      43,004      54,263      77,250
    Cash flow from operations(1)  18,995      16,386      23,225      31,785
    Cash flow from operations
     per unit(1)
      Basic                        $0.52       $0.44       $0.52       $0.45
      Diluted                      $0.52       $0.42       $0.50       $0.44
    Net income (loss)              3,259      12,243       1,652    (250,718)
    Net income (loss) per unit
      Basic                        $0.09       $0.43       $0.04      $(3.58)
      Diluted                      $0.09       $0.42       $0.04      $(3.58)
    Net capital expenditures
     (cash)                       22,585      (7,078)     46,166      30,341
    Distributions declared        26,150      27,771      36,846      33,588
    Distributions per unit         $0.72       $0.72       $0.72       $0.48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    2005 - Quarter ended
     (unaudited)(2)
    ($000s, except per unit
     amounts)                   March 31     June 30    Sept. 30     Dec. 31
    -------------------------------------------------------------------------
    Revenues before royalties
     and hedging                  22,441      33,663      44,510      61,056
    Cash flow from operations(1)  10,732      18,013      25,500      32,892
    Cash flow from operations
     per unit(1)
      Basic                        $0.63       $0.73       $1.04       $1.02
      Diluted                      $0.61       $0.72       $1.01       $1.00
    Net income (loss)              1,030       3,130       6,502       3,228
    Net income (loss) per unit
      Basic                        $0.06       $0.13       $0.26       $0.10
      Diluted                      $0.06       $0.13       $0.26       $0.10
    Net capital expenditures
     (cash)                       13,161      21,316      28,651      52,843
    Distributions declared             -           -           -      17,361
    Distributions per unit(2)          -           -           -       $0.48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) refer to "Non-GAAP Measures" in respect of the term "cash flow from
        operations" and "cash flows from operations per unit".
    (2) restated for changes in accounting policies and to reflect the
        consolidation of units effective November 2, 2005.
    

    The reasons for differences in results experienced from the second
quarter of 2007 to the third quarter of 2007 are described previously in this
report.
    The quarterly results as presented for 2005 and 2006 varied significantly
for two main reasons: 1) the timing of acquisitions during 2005 and 2006 and
2) changes in commodity prices over those periods.
    During 2005, True completed two acquisitions. The acquisition of Meridian
Energy Corporation was closed effective March 15, 2005 and the reverse
takeover of TKE Energy Trust closed on November 2, 2005. In addition, True
completed the purchases of Shellbridge Oil & Gas, Inc. and Prairie Schooner on
June 23, 2006 and September 22, 2006, respectively.
    True's revenue, net income, and cash flow from operations over 2005 and
2006 has reflected its production base after considering the timing of the
above noted acquisitions, the results of ongoing drilling activities, as well
as the changes in commodity prices, primarily that for natural gas. Beginning
in the first quarter of 2005 and continuing into the first quarter of 2006,
natural gas revenue was gradually increasing which resulted in a corresponding
increase in the Trust's petroleum and natural gas revenue, net income and cash
flow from operations in the period. This trend started to reverse in the
second quarter of 2006 with declining natural gas prices influencing a
corresponding relative decrease in the Trust's revenues, net income and cash
flows from operations.
    Net income also reflects an increase in DD&A rates since primarily since
the November 2005 reverse takeover of TKE Energy Trust offset by future tax
recoveries beginning in the same period. The increase in the Trust's DD&A rate
is due to an increase in its depletable base as a result of the acquisitions
and further capital spending. Future tax recoveries recognized since December
2005 result from additional interest deductions associated with True's new
Trust structure as well as reductions in rates for both federal and provincial
taxes which were enacted during 2006. Net income for the fourth quarter of
2006 is also reflective of a ceiling test write-down of $110.0 million and a
goodwill impairment charge of $169.8 million.

    
    TRUE ENERGY TRUST
    CONSOLIDATED BALANCE SHEETS
    As at September 30 and December 31 (unaudited)
    -------------------------------------------------------------------------
    ($000s)                                                 2007        2006
    -------------------------------------------------------------------------
    ASSETS
    Current assets
      Accounts receivable                             $   55,619  $   73,199
      Deposits and prepaid expenses                        5,691       7,928
      Capital taxes recoverable                              732           -
      Commodity contract asset (note 19)                   3,295           -
                                                      -----------------------
                                                          65,337      81,127
    Property, plant and equipment (note 6)               844,539     931,979
    Deferred financing charges (note 8)                        -       3,552
                                                      -----------------------
    Total assets                                      $  909,876  $1,016,658
                                                      -----------------------

    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities        $   51,982  $  107,431
      Distribution payable to unitholders                  6,377       8,433
      Capital taxes payable                                    -       1,513
      Current portion of obligations under
       capital lease                                           -         111
      Commodity contract liability (note 19)               2,598           -
                                                      -----------------------
                                                          60,957     117,488
    Long-term debt (note 7)                              159,212     157,904
    Convertible debentures (note 8)                       79,021      81,551
    Asset retirement obligations (note 9)                 27,708      26,605
    Future income taxes (note 14)                         93,975     123,861
                                                      -----------------------
    Total liabilities                                    420,873     507,409
                                                      -----------------------

    NON-CONTROLLING INTEREST
      Exchangeable shares of subsidiary (note 10)          3,928       4,153

    UNITHOLDERS' EQUITY
      Unitholders' capital (note 11)                     931,410     876,904
      Equity component of convertible debentures
       (note 8)                                            5,119       5,119
      Contributed surplus (note 12)                       16,355      12,818
      Deficit                                           (467,855)   (389,745)
      Accumulated other comprehensive income                  46           -
                                                      -----------------------
    Total unitholders' equity                            485,075     505,096
                                                      -----------------------
    Total liabilities and unitholders' equity         $  909,876  $1,016,658
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying selected notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
    For the three and nine months ended September 30 (unaudited)

                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    REVENUES
      Petroleum and natural
       gas sales               $  50,547   $  54,263   $ 196,734   $ 143,663
      Royalties                   (9,727)    (13,025)    (34,422)    (33,323)
      Gain (loss) on commodity
       contracts (note 19)         1,156        (188)      7,670        (461)
                               ----------------------------------------------
                                  41,976      41,050     169,982     109,879

    EXPENSES
      Production                  17,024      10,458      51,774      28,946
      Transportation               1,671       1,682       4,791       4,145
      General and administrative   4,232       2,583      13,468       8,990
      Interest and financing
       charges                     4,422       2,793      13,542       6,403
      Unit-based compensation
       (notes 11 and 12)             869       1,824       3,256       4,875
      Depletion, depreciation
       and accretion              38,890      29,060     131,697      85,802
      Special meeting costs
       (note 15)                       -           -       3,805           -
                               ----------------------------------------------
                                  67,108      48,400     222,333     139,161

    LOSS BEFORE TAXES            (25,132)     (7,350)    (52,351)    (29,282)

    TAXES (note 14)
      Capital taxes                  442         860       1,533       2,384
      Future income tax
       recovery                   (8,501)     (9,949)    (29,957)    (49,043)
                               ----------------------------------------------
                                  (8,059)     (9,089)    (28,424)    (46,659)

    NET INCOME (LOSS) BEFORE
     NON-CONTROLLING INTEREST    (17,073)      1,739     (23,927)     17,377
      Non-controlling interest
       (note 10)                     (70)         87         (94)        223
                               ----------------------------------------------
                               ----------------------------------------------

    NET INCOME (LOSS)            (17,003)      1,652     (23,833)     17,154
                               ----------------------------------------------

    Net changes in cash flow
     hedges (net of tax of
     $0.06 million and
     $1.8 million,
     respectively)                  (138)          -      (3,703)          -
                               ----------------------------------------------

    COMPREHENSIVE INCOME
     (LOSS)                    $ (17,141)  $   1,652   $ (27,536)  $  17,154
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Net income (loss) per
     trust unit
      Basic                       $(0.21)      $0.04      $(0.32)      $0.43
      Diluted                     $(0.21)      $0.04      $(0.32)      $0.43
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying selected notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
    For the three and nine months ended September 30 (unaudited)

                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    UNITHOLDERS' CAPITAL
      Balance, beginning of
       period                  $ 931,336   $ 506,377   $ 876,904   $ 418,968
      Issued for cash (net of
       issue costs of
       $3.1 million)                 (11)          -      54,375           -
      Issued to acquire
       Prairie Schooner
       (net of issue costs
       of $1.6 million)                -     341,089           -     341,089
      Issued to acquire
       Shellbridge (net of
       issue costs of
       $0.6 million                    -           -           -      67,668
      Exchangeable shares
       converted                      85           -         131       4,677
      Units issued pursuant
       to DRIP                         -      15,239           -      30,303
      Units to be issued
       pursuant to DRIP                -       5,521           -       5,521
                               ----------------------------------------------
      Balance, end of period     931,410     868,226     931,410     868,226
                               ----------------------------------------------

    EQUITY COMPONENT OF
     CONVERTIBLE DEBENTURES
      Balance, beginning of
       period                      5,119       5,119       5,119           -
      Conversion feature on
       convertible debentures
       issued                          -           -           -       5,119
                               ----------------------------------------------
      Balance, end of period       5,119       5,119       5,119       5,119

    CONTRIBUTED SURPLUS
      Balance, beginning
       of period                  15,407       8,724      12,818       5,127
      Unit-based compensation
       expense (note 12)             948       2,137       3,537       5,734
                               ----------------------------------------------
      Balance, end of period      16,355      10,861      16,355      10,861

    DEFICIT
      Balance, beginning
       of period                (431,720)    (70,245)   (389,745)    (31,826)
      Net income (loss)          (17,003)      1,652     (23,833)     17,154
      Impact of changes in
       accounting policy for
       financial instruments
       on January 1, 2007
       (net of tax of
       $0.05 million) (note 3)         -           -          97           -
      Distributions declared     (19,132)    (36,846)    (54,374)    (90,767)
                               ----------------------------------------------
      Balance, end of period    (467,855)   (105,439)   (467,855)   (105,439)

    ACCUMULATED OTHER
     COMPREHENSIVE INCOME
      Balance, beginning
       of period                     184           -           -           -
      Impact of new cash flow
       hedge accounting
       standards on January 1,
       2007 (net of tax of
       $1.8 million) (note 3)          -           -       3,749           -
      Reclassification to
       earnings of net
       hedging gains on
       commodity contracts
       (net of tax of
       $0.06 million and
       $1.8 million,
       respectively)                (138)          -      (3,703)          -
                               ----------------------------------------------
      Balance, end of period          46           -          46           -

    -------------------------------------------------------------------------
    TOTAL UNITHOLDERS' EQUITY  $ 485,075   $ 778,767   $ 485,075   $ 778,767
    -------------------------------------------------------------------------

    See accompanying selected notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF CASH FLOWS
    For the three and nine months ended September 30 (unaudited)

                                  Three months ended       Nine months ended
                                        September 30,           September 30,
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Cash provided by (used in):
    Cash flow from operating
     activities
    Net income (loss)          $ (17,003)  $   1,652   $ (23,833)  $  17,154
    Items not involving cash:
      Non-controlling interest
       (note 10)                     (70)         87         (94)        223
      Depletion, depreciation
       and accretion              38,890      29,060     131,697      85,802
      Unit-based compensation
       (note 12)                     869       1,824       3,256       4,875
      Unrealized loss (gain)
       on commodity contracts
       (note 19)                   2,908           -        (580)          -
      Amortization of deferred
       financing charges
       (note 8)                        -         201           -         236
      Accretion on convertible
       debentures (note 8)           385         211       1,169         248
      Future income taxes
       (recovery) (note 14)       (8,501)     (9,949)    (29,957)    (49,043)
      Capital taxes                    -         139           -        (889)
                               ----------------------------------------------
                                  17,478      23,225      81,658      58,606
      Change in non-cash
       working capital (note 13)  (2,598)     20,284     (21,842)      4,375
                               ----------------------------------------------
                                  14,880      43,509      59,816      62,981
    CASH FLOW FROM (USED IN)
     FINANCING ACTIVITIES
      Increase (decrease) in
       bank debt                  17,059      30,285       2,328     (19,246)
      Obligations under capital
       lease                           -         (45)       (111)       (143)
      Issuance of convertible
       debentures                      -           -           -      86,250
      Deferred financing
       charges                         -          34           -      (3,989)
      Issue of trust units
       for cash                        -           -      57,523           -
      Unit issue costs               (11)     (1,781)     (3,148)     (2,410)
      Payment of cash
       component of
       distributions             (19,131)    (15,146)    (56,429)    (52,641)
                               ----------------------------------------------
                                  (2,083)     13,347         163       7,821
      Change in non-cash
       working capital
       (note 13)                    (262)      1,255         (19)      2,148
                               ----------------------------------------------
                                  (2,345)     14,602         144       9,969
    CASH FLOW FROM (USED IN)
     INVESTING ACTIVITIES
      Additions to property,
       plant and equipment       (11,450)    (46,166)    (74,148)    (86,187)
      Corporate transaction
       costs                           -      (1,563)          -      (2,083)
      Proceeds on sale of
       property, plant and
       equipment                   3,806           -      31,275      24,514
                               ----------------------------------------------
                                  (7,644)    (47,729)    (42,873)    (63,756)
      Change in non-cash
       working capital
       (note 13)                  (4,891)    (10,382)    (17,087)    (14,412)
                               ----------------------------------------------
                                 (12,535)    (58,111)    (59,960)    (78,168)

      Cash acquired on
       corporate acquisition
       (note 5b)                       -           -           -       5,218

      Change in cash                   -           -           -           -

      Cash, beginning of period        -           -           -           -
    -------------------------------------------------------------------------

      Cash, end of period      $       -   $       -   $       -   $       -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying selected notes to the consolidated financial statements.



    SELECTED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

    September 30, 2007 and 2006 (unaudited)
    -------------------------------------------------------------------------

    1.  STRUCTURE OF THE TRUST

        True Energy Trust ("True" or the "Trust") is an open-ended,
        unincorporated investment trust governed by the laws of the Province
        of Alberta. Through a Plan of Arrangement (the "TKE Arrangement")
        that became effective on November 2, 2005, True Energy Inc. became
        the Trust.

        Pursuant to the TKE Arrangement, True Energy Inc. and TKE Energy
        Trust ("TKE") entered into a business combination whereby True Energy
        Inc. acquired TKE in a reverse takeover, thus creating True Energy
        Trust and a publicly listed exploration focused company, Vero Energy
        Inc.

        The purpose of the Trust is to indirectly explore for, develop and
        hold interests in petroleum and natural gas properties, through
        investments in securities of subsidiaries and net profits interests
        in oil and natural gas properties. The business of the Trust is
        carried on by True Energy Inc., its wholly owned subsidiary Marengo
        Exploration Ltd., True Oil & Gas Ltd., True Energy Partnership and
        TKE Energy Partnership. The Trust owns, directly and indirectly, 100%
        of the common shares, (excluding the exchangeable shares - see note
        10) of True Energy Inc., Marengo Exploration Ltd., True Oil & Gas
        Ltd. and 100% of the interests of True Energy Partnership and TKE
        Energy Partnership. The activities of True Energy Inc., Marengo
        Exploration Ltd., True Oil & Gas Ltd. and the partnerships, are
        financed through interest bearing notes from the Trust and third
        party debt as described in the notes to the financial statements.

        Pursuant to the terms of Net Profit Interest Agreements (the "NPI
        Agreements"), the Trust is entitled to a payment from True Energy
        Inc. and True Oil & Gas Ltd. each month equal to the amount by which
        99% of the gross proceeds from the sale of production exceed certain
        deductible expenditures (as defined). Under the terms of the NPI
        Agreements, deductible expenditures may include amounts, determined
        on a discretionary basis, to fund capital expenditures, to repay
        third party debt and to provide for working capital required to carry
        out the operations of True Energy Inc., Marengo Exploration Ltd.,
        True Oil & Gas Ltd., True Energy Partnership and TKE Energy
        Partnership, as applicable.

        The Trust will make distributions to the Unitholders in amounts equal
        to all or any part of the net income of the Trust earned from
        interest income on the notes and from the income generated under the
        NPI Agreements, and from any dividends paid on the common shares of
        True Energy Inc., less any expenses of the Trust including interest
        on the convertible debentures.

    2.  SIGNIFICANT ACCOUNTING POLICIES

        The interim consolidated financial statements of the Trust have been
        prepared by management in accordance with generally accepted
        accounting policies in Canada. The unaudited interim consolidated
        financial statements have been prepared following the same accounting
        policies and methods of computation as the consolidated financial
        statements for the fiscal year ended December 31, 2006, except as
        described in note 3. 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, the interim consolidated
        financial statements should be read in conjunction with the
        consolidated financial statements and the notes thereto contained in
        the Trust's annual report for the year ended December 31, 2006.

    3.  CHANGES IN ACCOUNTING POLICIES

        Effective January 1, 2007, True adopted accounting standards related
        to the new financial instruments accounting framework, which
        encompasses three new Canadian Institute of Chartered Accountant
        ("CICA") Handbook Sections: 3855 "Financial Instruments - Recognition
        and Measurement", 3865 "Hedges", and 1530 "Comprehensive Income".
        Handbook Section 3251 "Equity" was also effective for True on
        January 1, 2007. In accordance with these standards, prior period
        financial statements have not been restated.

        At January 1, 2007, the following adjustments were made to the
        balance sheet to adopt the new standards:

        ---------------------------------------------------------------------
        Increase (decrease) ($000s)                       At January 1, 2007
        ---------------------------------------------------------------------
        Commodity contract asset                                     $ 8,905
        Deposits and prepaid expenses
          Deferred commodity contract premiums    (3,310)
          Prepaid interest                        (1,020)
                                                  ---------------------------
                                                                      (4,330)
        Deferred financing charges                                    (3,552)
        Long-term debt                                                (1,020)
        Convertible debentures                                        (3,697)
        Future income tax liability                                    1,894
        Deficit, net of income taxes of $0.05 million                    (97)
        Accumulated other comprehensive income
          Cash flow hedges, net of income taxes of $1.8 million        3,749
        ---------------------------------------------------------------------

        a. Financial instruments - recognition and measurement

           This new standard requires all financial instruments within its
           scope, including all derivatives, to be recognized on the balance
           sheet initially at fair value. Subsequent measurement of all
           financial assets and liabilities except those held-for-trading and
           available for sale are measured at amortized cost determined using
           the effective interest rate method. Held-for-trading financial
           assets are measured at fair value with changes in fair value
           recognized in income. Available-for-sale financial assets are
           measured at fair value with changes in fair value recognized in
           comprehensive income and reclassified to income when derecognized
           or impaired. Changes to the measurement of existing financial
           assets and liabilities at the date of adoption were adjusted to
           either opening retained earnings or opening accumulated other
           comprehensive income as noted above.

        b. Derivatives

           The Trust continues to utilize financial derivatives and non-
           financial derivatives, such as commodity sales contracts requiring
           physical delivery, to manage the price risk attributable to
           anticipated sale of petroleum and natural gas production. Refer to
           note 18 to the Trust's 2006 annual financial statements for
           additional disclosure on the Trust's risk management objectives
           and policies.

           The Trust has elected to account for its commodity sales
           contracts, which were entered into and continue to be held for the
           purpose of receipt or delivery of non-financial items in
           accordance with its expected purchase, sale or usage requirements
           as executory contracts on an accrual basis rather than as
           derivatives. Prior to adoption of the new standards, physical
           receipt and delivery contracts did not fall within the scope of
           the definition of a financial instrument and were also accounted
           for as executory contracts.

           Subsequent changes in fair value of derivatives that are not
           designated or do not qualify for hedge accounting or normal
           purchase, sale or usage contracts are recognized in net income as
           incurred. For derivatives that are designated and qualify for cash
           flow hedge accounting at inception or the date of adoption, the
           effective portion of the change in fair value is recognized in
           other comprehensive income as incurred with the remaining portion
           of the change in fair value recognized in net income as incurred
           in the same financial statement caption as the hedged transaction.
           Net derivative gains (losses) in accumulated other comprehensive
           income are reclassified to net income in the same financial
           statement caption and future periods as the hedged transactions
           affect net income. Prior to adoption, financial derivatives which
           were designated and qualified for cash flow hedge accounting were
           recognized on an accrual basis.

           Prior to January 1, 2007, the Trust applied hedge accounting,
           under the former Accounting Guideline 13 standard, to its
           financial derivatives, being commodity price risk management
           contracts. On January 1, 2007, the Trust discontinued hedge
           accounting for all existing financial derivatives. As a result,
           the mark-to-market gain on these financial derivatives, net of
           existing unamortized deferred commodity contract premiums and the
           tax effect thereon was included in accumulated other comprehensive
           income as of January 1, 2007. These net derivative gains in
           accumulated other comprehensive income at January 1, 2007 will be
           reclassified to income in future periods as the original hedged
           transactions affect net earnings. From January 1, 2007 forward,
           the changes in fair value of such derivatives will be recognized
           in net income when incurred.

        c. Embedded derivatives

           On adoption, the Trust elected to recognize, as separate assets
           and liabilities, only those embedded derivatives in hybrid
           instruments issued, acquired or substantively modified after
           January 1, 2003. The Trust did not identify any material embedded
           derivatives which required separate recognition and measurement.

        d. Other comprehensive income

           The new standards require a statement of comprehensive income,
           which is comprised of net income and other comprehensive income
           which, for the Trust, relates to changes in gains or losses on
           derivatives that were previously designated as cash flow hedges.
           The Company has combined this new statement with the statement of
           income.

        e. Effective interest rate method

           Transaction costs attributable to financial instruments classified
           as other than held-for-trading are included in the recognized
           amount of the related financial instrument and recognized over the
           life of the resulting financial instrument. Prior to January 1,
           2007, transaction costs were recorded as deferred charges and
           recognized in net earnings on a straight-line basis over the life
           of the financial instrument. On adoption, transaction costs are
           recognized as if the effective interest rate method had always
           been applied whereby the amount recognized varies over the life of
           the financial instrument based on principal outstanding. For the
           Trust, this adoption required adjustments to prepaid expenses and
           long-term debt as disclosed in note 7 and to deferred financing
           costs and the debt component of convertible debentures as
           disclosed in note 8.

    4.  FUTURE CHANGES IN ACCOUNTING POLICIES

        a. Capital disclosures

           The CICA issued a new accounting standard, Section 1535 "Capital
           Disclosures", which requires the disclosure of both qualitative
           and quantitative information that provides users of financial
           statements with information to evaluate the entity's objective,
           policies and processes for managing capital. This new section is
           effective for the Trust beginning January 1, 2008.

        b. Financial instruments

           Two new accounting standards were issued by the CICA, Section 3862
           "Financial Instruments - Disclosures", and Section 3863 "Financial
           Instruments - Presentation. These sections will replace Section
           3861 "Financial Instruments - Disclosure and Presentation" once
           adopted. The objective of Section 3862 is to provide users with
           information to evaluate the significance of the financial
           instruments on the entity's financial position and performance,
           the nature and extent of risks arising from financial instruments,
           and how the entity manages those risks. The provisions of Section
           3863 deal with the classification of financial instruments,
           related interest, dividends, losses and gains, and the
           circumstances in which financial assets and financial liabilities
           are offset. These new sections are effective for the Trust
           beginning January 1, 2008.

    5.  ACQUISITIONS

        a. Acquisition of Prairie Schooner Petroleum Ltd.

           Effective September 22, 2006, the Trust's wholly owned subsidiary,
           True Energy Inc. ("True Energy"), entered into a business
           combination with Prairie Schooner Petroleum Ltd. ("Prairie
           Schooner") whereby True Energy acquired all of the issued and
           outstanding shares of Prairie Schooner pursuant to a plan of
           arrangement. The previous shareholders of Prairie Schooner
           received 1.22 trust units of the Trust for each outstanding
           Prairie Schooner share and outstanding options were exchanged for
           options ("replacement options") to purchase trust units adjusted
           for the exchange ratio and exercisable for ten business days
           following completion of the transaction (the "Transaction"). An
           aggregate of 25,759,563 trust units were issued pursuant to the
           Transaction (including on exercise of the replacement options).
           Concurrent with the business combination, True Energy and Prairie
           Schooner amalgamated on September 22, 2006 and continue as True
           Energy. The value of the transaction, based upon the adjusted
           weighted average trading price for trust units of the Trust for
           the five days prior to the transaction announcement on July 26,
           2006, of $13.31, was $344.4 million (including $1.6 million in
           transaction costs). The transaction was accounted for using the
           purchase method.

           The purchase price allocation resulted in an excess purchase price
           over the fair value of net identifiable assets acquired of
           approximately $71.6 million, which was reflected as goodwill. The
           accounts include the results of Prairie Schooner from
           September 22, 2006, the date Prairie Schooner shares were
           exchanged for trust units of the Trust. The purchase equation was
           adjusted at December 31, 2006 to reflect certain underaccruals for
           operating and capital expenditures relating to the period prior to
           September 22, 2006. As a result, accounts payable was increased by
           $3.6 million, the future tax liability was reduced by $1.9 million
           and goodwill was increased by $1.7 million. The purchase price
           equation is as follows:

           ($000's)
           ------------------------------------------------------------------
           Cost of acquisition:
             Trust units issued                                    $ 342,870
             True transaction costs                                    1,563
           ------------------------------------------------------------------
                                                                   $ 344,433
           ------------------------------------------------------------------

           Allocated at estimated fair values:
             Accounts receivable                                    $ 32,295
             Deposits and prepaid expenses                             1,075
             Property, plant and equipment                           435,346
             Goodwill                                                 71,601
             Bank debt                                               (67,373)
             Accounts payable and accrued liabilities                (42,636)
             Future income taxes                                     (73,467)
             Asset retirement obligations                            (12,408)
           ------------------------------------------------------------------
                                                                   $ 344,433
           ------------------------------------------------------------------
           ------------------------------------------------------------------


        b. Acquisition of Shellbridge Oil & Gas, Inc.

           Effective June 23, 2006, the Trust's wholly owned subsidiary, True
           Oil & Gas Ltd. ("True Oil & Gas"), entered into a business
           combination with Shellbridge Oil & Gas, Inc. ("Shellbridge")
           whereby True Oil & Gas acquired all of the issued and outstanding
           shares of Shellbridge pursuant to a plan of arrangement. The
           previous shareholders of Shellbridge received 0.14 trust units of
           the Trust for each outstanding Shellbridge share (the
           "Transaction"), resulting in the issuance of 4,389,366 trust
           units. Concurrent with the business combination, True Oil & Gas
           and Shellbridge amalgamated on June 23, 2006 and continue as True
           Oil & Gas. The value of the transaction, based upon the adjusted
           weighted average trading price for True Energy Trust units for the
           five days prior to the transaction announcement on April 11, 2006,
           of $15.56, was $68.8 million (including $0.5 million in
           transaction costs). The transaction was accounted for using the
           purchase method.

           The purchase price allocation resulted in an excess purchase price
           over the fair value of net identifiable assets acquired of
           approximately $24.0 million, which was reflected as goodwill. The
           accounts include the results of Shellbridge effective June 23,
           2006, the date Shellbridge shares were exchanged for trust units
           of the Trust.

           The purchase price equation is as follows:

           ($000's)
           ------------------------------------------------------------------
           Cost of acquisition:
             Trust units issued                                     $ 68,299
             True transaction costs                                      520
           ------------------------------------------------------------------
                                                                    $ 68,819
           ------------------------------------------------------------------
           Allocated at estimated fair values:
             Cash                                                    $ 5,218
             Accounts receivable                                      10,005
             Deposits and prepaid expenses                               161
             Property, plant and equipment                            47,529
             Goodwill                                                 24,017
             Accounts payable and accrued liabilities                (13,485)
             Future income taxes                                      (3,330)
             Asset retirement obligations                             (1,296)
           ------------------------------------------------------------------
                                                                    $ 68,819
           ------------------------------------------------------------------
           ------------------------------------------------------------------


        As at December 31, 2006, a goodwill impairment provision of
        $169.8 million was recorded to write-down the goodwill initially
        recognized from the above and previous year acquisitions.

    6.  PROPERTY, PLANT AND EQUIPMENT

        ($000s)
        ---------------------------------------------------------------------
                                                     Accumulated
                                                       depletion
                                                             and    Net book
        September 30, 2007                    Cost  depreciation       value
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                     $1,355,558     $ 513,809   $ 841,749
        Office furniture and equipment       4,080         1,290       2,790
        ---------------------------------------------------------------------
                                        $1,359,638     $ 515,099   $ 844,539
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        December 31, 2006
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                     $1,314,374     $ 384,110   $ 930,264
        Office furniture and equipment       2,588           873       1,715
        ---------------------------------------------------------------------
                                        $1,316,962     $ 384,983   $ 931,979
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        The Trust has excluded $38.4 million for undeveloped land and
        $46.9 million for estimated salvage from the depletion calculation
        during the nine month period ended September 30, 2007.

        For the nine month period ended September 30, 2007, the Trust
        capitalized $3.1 million of general and administrative expenses and
        $0.3 million of unit-based compensation expense directly related to
        exploration and development activities.

    7.  LONG-TERM DEBT

        The Trust has a $15 million demand operating facility provided by one
        Canadian bank and $175 million extendible revolving term credit
        facility syndicated by two Canadian chartered banks, a U.S. bank, a
        Canadian financial institution and one institutional lender. Amounts
        borrowed under the credit facility bear interest at a floating rate
        based on the applicable Canadian prime rate, U.S. base rates, LIBOR
        rates, plus between 0% and 1.95%, depending on the types of
        borrowings and the Trust's debt to cash flow ratio. Security is
        provided by a $400 million debenture containing a first ranking
        security interest on all of the Trust's assets. The credit facility
        is secured against all the assets of True Energy Inc., the Trust and
        all material subsidiaries. True has provided a negative pledge and
        undertaking to provide fixed charges over major petroleum and natural
        gas reserves in certain circumstances. A standby fee is charged on
        between 0.125% and 0.400% on the undrawn portion of the facility,
        depending on the Trust's debt to cash flow ratio.

        As a consequence of adopting new financial instruments standards
        effective January 1, 2007 as described in note 3, the Trust has made
        certain adjustments to the presentation of prepaid interest.
        Previously, this amount was included in deposits and prepaid
        expenses, however, under the new standard effective January 1, 2007
        this amount, being $0.8 million at September 30, 2007, is now netted
        against long-term debt and amortized on the effective interest basis.

        As at September 30, 2007, there was $10.0 million outstanding under
        the operating facility and $149 million outstanding under the
        revolving term credit facility. As at September 30, 2007, there is
        approximately $31 million undrawn under the facility.

        The borrowing base was renewed effective August 31, 2007 and is
        currently scheduled for renewal on or before March 31, 2008.

        The revolving period on the new revolving term credit facility ends
        on June 28, 2008, unless extended for a further 364 day period.
        Should the facilities not be renewed they convert to 366 day non-
        revolving term facilities on the renewal date. Payment will not be
        required under the revolving term facility for more than 365 days
        from the balance sheet date and as at September 30, 2007 there is
        sufficient availability under the revolving term credit facility to
        also cover the operating facility and, as such, the entire credit
        facility has been classified as long-term.

    8.  CONVERTIBLE DEBENTURES

        On June 15, 2006, the Trust completed a public offering of
        86,250 7.5% convertible unsecured subordinated debentures at a price
        of $1,000 per debenture for aggregate gross proceeds of $86,250,000.

        The convertible debentures have a face value of $1,000 per debenture
        and a maturity date of June 30, 2011. The convertible debentures bear
        interest at an annual rate of 7.50% payable semi-annually on June 30
        and December 31 in each year commencing December 31, 2006. The
        debentures are convertible at anytime at the option of the holders
        into trust units of the Trust at a conversion price of $16.00 per
        Trust unit. The Trust will have the right to redeem all or a portion
        of the debentures at a price of $1,050 per debenture after June 30,
        2009 and on or before June 30, 2010 and at a price of $1,025 per
        debenture after June 30, 2010 and before the maturity date. Upon
        maturity or redemption of the debentures, the Trust may, subject to
        notice and regulatory approval, pay the outstanding principal and
        premium (if any) on the debentures in cash or through the issue of
        additional Trust units at 95% of a weighted average trading price of
        the Trust units.

        The debentures were initially recorded at the fair value of the
        obligation without the conversion feature. This fair value to make
        future payments of principal and interest was initially determined to
        be $81.1 million. The difference between the principal amount of
        $86.3 million and the fair value of the obligation is $5.1 million
        and has been recorded in unitholders' equity as the fair value of the
        conversion feature of the debentures. Issue costs of $4.0 million
        were classified as deferred financing charges, and prior to
        January 1, 2007, were amortized on a straight-line basis over the
        term of the debentures. As a consequence of adopting new financial
        instruments standards effective January 1, 2007 as described in note
        3, the Trust made certain adjustments to deferred financing charges
        and the debt component of convertible debentures as noted in the
        tables below. The debt component of the convertible debentures will
        accrete up to the principal balance at maturity. The accretion and
        the interest paid are expensed as interest and financing charges in
        the consolidated statement of operations.

        The following table shows the convertible debenture activities for
        the nine month period ended September 30, 2007 and the year ended
        December 31, 2006:

        Convertible debentures
        ---------------------------------------------------------------------
                                                          Debt       Equity
                                         Number of   Component    Component
                                        Debentures      ($000s)      ($000s)
        ---------------------------------------------------------------------
        Issued on June 15, 2006             86,250    $ 81,131      $ 5,119
        Accretion                                -         420            -
        ---------------------------------------------------------------------
        Balance, December 31, 2006          86,250      81,551        5,119
        ---------------------------------------------------------------------
        Impact of change in accounting
         policy for financial
         instruments on January 1,
         2007 (note 3)                           -      (3,699)           -
        Accretion                                -       1,169            -
        ---------------------------------------------------------------------
        Balance, September 30, 2007         86,250    $ 79,021      $ 5,119
        ---------------------------------------------------------------------


        The following table shows the deferred financing charges activities
        for the nine month period ended September 30, 2007 and the year ended
        December 31, 2006:

        Deferred financing charges
        ---------------------------------------------------------------------
        ($000s)                                    September 30, December 31,
                                                           2007         2006
        ---------------------------------------------------------------------
        Balance, beginning of period                    $ 3,552      $     -
        Costs incurred for convertible debenture
         offering                                             -        3,989
        Less amortization in the period                       -         (437)
        Impact of change in accounting policy for
         financial instruments on January 1, 2007
         (note 3)                                        (3,552)           -
        ---------------------------------------------------------------------
        Balance, end of period                          $     -      $ 3,552
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    9.  ASSET RETIREMENT OBLIGATIONS

        The Trust's asset retirement obligations result from net ownership
        interests in petroleum and natural gas assets including well sites,
        gathering systems and processing facilities. The Trust estimates the
        total undiscounted amount of cash flows required to settle its asset
        retirement obligations is approximately $74.6 million which will be
        incurred between 2007 and 2053. A credit-adjusted risk-free rate of 8
        percent and an inflation rate of 2 percent were used to calculate the
        fair value of the asset retirement obligation.

        ---------------------------------------------------------------------
        ($000s)                                    September 30, December 31,
                                                           2007         2006
        ---------------------------------------------------------------------
        Asset retirement obligation, beginning
         of period                                     $ 26,605     $ 10,457
        Liabilities acquired through corporate
         acquisitions                                         -       13,704
        Liabilities incurred on development
         activities                                         433        1,210
        Changes in prior period estimates                    16          810
        Liabilities released on dispositions               (927)        (641)
        Accretion expense                                 1,581        1,065
        ---------------------------------------------------------------------
        Asset retirement obligation, end of period     $ 27,708     $ 26,605
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    10. EXCHANGEABLE SHARES OF SUBSIDIARY

        ---------------------------------------------------------------------
                                 September 30, 2007       December 31, 2006
                                 Number      Amount      Number      Amount
                                             ($000s)                 ($000s)
        ---------------------------------------------------------------------
        Balance, beginning of
         period                 403,536     $ 4,153     788,558     $ 9,709
        Non-controlling
         interest expense
         (recovery)                   -         (94)          -        (803)
        Exchanged for trust
         units                  (12,723)       (131)   (385,022)     (4,753)
        ---------------------------------------------------------------------
        Balance, end of period  390,813     $ 3,928     403,536     $ 4,153
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        The exchange ratio is calculated monthly based on the five day
        weighted average trust unit trading price preceding the monthly
        effective date, and at September 30, 2007 was 0.80997. The
        exchangeable shares are not eligible for cash distributions; however
        cash distributions will increase the exchange ratio.

    11. UNITHOLDERS' CAPITAL

        a. Trust Units of True Energy Trust

           ------------------------------------------------------------------
                                   September 30, 2007      December 31, 2006
                                    Number     Amount      Number     Amount
                                               ($000s)                ($000s)
           ------------------------------------------------------------------
           Balance, beginning
            of period           70,275,703  $ 876,904  36,176,196  $ 418,968
           Issued for cash
            (net of issue costs
            of $3.1 million)     9,430,000     54,375           -          -
           Issued to acquire
            Prairie Schooner
            (net of issue costs
             of $1.8 million)            -          -  25,759,563    341,089
           Issued to acquire
            Shellbridge (net of
            issue costs of
            $0.6 million)                -          -   4,389,366     67,669
           Exchangeable shares
            converted                9,892        131     231,035      4,753
           Units issued pursuant
            to DRIP                      -          -   3,574,185     42,608
           Issued to acquire
            property interest            -          -     145,358      1,817
           ------------------------------------------------------------------
           Balance, end of
            period              79,715,595  $ 931,410  70,275,703  $ 876,904
           ------------------------------------------------------------------


           In August 2007, the Trust announced approval of its normal course
           issuer bid ("NCIB") program to repurchases up to 7.8 million of
           its outstanding trust units during the period August 28, 2007
           through to August 27, 2008, subject to certain conditions. During
           the three months ended September 30, 2007, no units were
           repurchased for cancellation. Any excess of the purchase price
           over carrying amount of the units purchased would be recorded as a
           reduction of contributed surplus and retained earnings, or
           conversely an increase to contributed surplus.

        b. Trust Unit Incentive Plan

           The Trust has a trust unit incentive plan where the Trust may
           grant trust unit incentive rights to its directors, officers and
           employees. Under this plan, the exercise price of each trust unit
           incentive right initially equals the market price of the Company's
           stock on the date of grant. The maximum term of an incentive right
           is five years.

           The grant price per Incentive Right ("Grant Price") shall be equal
           to the per Trust Unit closing price on the trading day immediately
           preceding the date of grant, unless otherwise permitted. Under the
           terms of the Incentive Plan, the exercise price of each Incentive
           Right is initially equal to the Grant Price and thereafter is
           reduced pursuant to a formula. This formula provides that the
           exercise price of each Incentive Right is reduced by any decreases
           in the daily closing price on the Toronto Stock Exchange of the
           Trust Units that is in excess of a 2.5% return on the Trust's
           consolidated net fixed assets (the "Hurdle Rate"); provided
           however, that such decrease in the exercise price will not exceed
           the amount by which the Trust Unit distributions exceed the Hurdle
           Rate. Effective June 1, 2006, the Trust amended its Hurdle Rate to
           0% per quarter. In no case may the exercise price be less than
           $0.001 per Trust Unit and a participant may elect to have the
           exercise price equal the Grant Price. Incentive Rights are non-
           transferable or assignable except in accordance with the Incentive
           Plan and the holding of Incentive Rights shall not entitle a
           holder to any rights as a Unitholder of True Energy Trust.

           Unit rights, entitling the holder to purchase units from the
           Trust, have been granted to directors, officers, employees and
           service providers of the Trust. Effective May 1, 2006, one third
           of the initial grant of trust unit incentives vest on each of the
           first, second, and third anniversary from the date of grant.

           The following tables summarize information regarding trust unit
           incentive rights for the nine month ended and as at September 30,
           2007.

           Unit Rights Continuity
           ------------------------------------------------------------------
                                                      Average
                                                     Exercise
                                                      Price(a)        Number
           ------------------------------------------------------------------
           Balance, December 31, 2006                 $ 14.18      5,429,831
           Granted                                    $  6.13      2,113,500
           Forfeited                                  $ 13.76     (1,456,499)
           ------------------------------------------------------------------
           Balance, September 30, 2007                $ 10.93      6,086,832
           ------------------------------------------------------------------



    Unit Rights Outstanding
    -------------------------------------------------------------------------
                                                     Outstanding
                                                        Exercise
    Exercise          Exercise Price            At         Price   Remaining
    Price Before              Net of      Sept. 30, Net of Price Contractual
    Price Reductions      Reductions          2007  Reductions(b)     Life(b)
    -------------------------------------------------------------------------
    $ 4.98 - $ 6.70  $ 4.95 - $ 6.32     2,009,000       $  5.80         4.6
    $10.58 - $12.53  $ 9.46 - $11.31     1,102,500       $  9.73         4.0
    $13.74 - $14.83  $11.94 - $13.11       665,500       $ 12.37         3.8
    $15.92 - $16.70  $13.72 - $14.47        10,833       $ 13.98         3.6
    $18.25 - $20.98  $15.46 - $18.41     2,208,999       $ 15.63         3.1
    -------------------------------------------------------------------------
    $ 4.98 - $20.98  $ 4.95 - $18.41     6,086,832       $ 10.93         3.9
    -------------------------------------------------------------------------


                  Exercisable
                          Exercise
                 At          Price
           Sept. 30,  Net of Price
               2007   Reductions(b)
    -------------------------------
                  -            N/A
            284,981        $  9.61
            215,163        $ 12.36
             56,667        $ 14.06
          1,512,653        $ 15.63
    -------------------------------
          2,067,464        $ 14.42
    -------------------------------

    (a) Exercise prices reflect grant prices less reduction in exercise
        prices.
    (b) Based on weighted average unit rights outstanding.


        c. Employee Trust Unit Savings Plan

           Effective October 1, 2006, the Trust introduced an employee trust
           unit savings plan for the benefit of all employees. Under the
           savings plan, employees may elect to contribute up to 10 percent
           of their salary and contributions are used to fund the acquisition
           of trust units. The Trust matches employee contributions at a rate
           of $1.00 for each $1.00 contributed. Trust units are purchased in
           the open market by the plan administrator, an investment firm, on
           behalf of the participants in the plan. For the nine months ended
           September 30, 2007, the Trust matched $0.4 million under the plan.

    12. CONTRIBUTED SURPLUS

        ---------------------------------------------------------------------
                                                  September 30,  December 31,
        ($000s)                                           2007          2006
        ---------------------------------------------------------------------
        Balance, beginning of period                  $ 12,818       $ 5,127
        Unit-based compensation expense                  3,537         7,691
        ---------------------------------------------------------------------
        Balance, end of period                        $ 16,355       $12,818
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Unit-based Compensation

        During the nine months ended September 30, 2007, the Trust granted
        2,113,500 unit incentive rights to employees and directors. During
        the nine months ended September 30, 2007, the Trust recorded unit-
        based compensation of $3.5 million, of which $0.3 million was
        capitalized to property, plant and equipment.

        The fair values of all incentive rights granted are estimated on the
        date of grant using the Black-Scholes option-pricing model.

        The weighted average fair market value of incentive rights granted
        during the nine month period ended September 30, 2007 and the
        assumptions used in their determination are as noted below.

        ---------------------------------------------------------------------
                                        Nine months ended September 30, 2007
        ---------------------------------------------------------------------
        Assumptions:
          Risk free interest rate (%)                                      4
          Expected life (years)                                            5
          Expected volatility (%)                                         24
        ---------------------------------------------------------------------
        Results:
          Weighted average fair value of
           each incentive right granted                               $ 1.38
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    13. SUPPLEMENTAL CASH FLOW INFORMATION

        Cash Interest and Taxes Paid
        ---------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
        ($000s)                     2007        2006        2007        2006
        ---------------------------------------------------------------------
        Cash paid:
          Interest              $  3,555   $     691   $  12,284    $  3,565
          Taxes (net of
           refunds)             $    219   $     657   $   3,978    $  3,871
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        Change in Non-cash Working Capital
        ---------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                        September 30,           September 30,
        ($000s)                     2007        2006        2007        2006
        ---------------------------------------------------------------------
        Changes in non-cash
         working capital items:
          Accounts receivable   $  1,313   $ (24,019)  $  17,580    $ (6,223)
          Deposits and prepaid
           expenses               (1,873)     (4,733)      1,169      (5,332)
          Accounts payable and
           accrued liabilities    (7,547)     39,909     (55,451)      3,666
          Capital taxes
           recoverable/payable       356           -      (2,246)          -
        ---------------------------------------------------------------------
                                $ (7,751)  $  11,157   $ (38,948)   $ (7,889)
        ---------------------------------------------------------------------
          Changes related to
           operating activities $ (2,598)  $  20,284   $ (21,842)   $  4,375
          Changes related to
           financing activities     (262)      1,255         (19)      2,148
          Changes related to
           investing activities   (4,891)    (10,382)    (17,087)    (14,412)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
                                $ (7,751)  $ (11,157)  $ (38,948)   $ (7,889)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    14. INCOME TAXES

        The Trust is a mutual fund trust as defined under the Income Tax Act
        (Canada). All taxable income earned by the Trust has been allocated
        to unitholders and such allocations are deducted for income tax
        purposes.

        In June 2007, the government legislation implementing the new tax
        (the "SIFT tax") on publicly traded income trust and limited
        partnerships (Bill C-52) received third reading in the House of
        Commons and Royal Assent. For existing income trusts and limited
        partnerships, the SIFT tax will be effective in 2011 unless certain
        rules related to "undue expansion" are not adhered to. As such, the
        Trust would not be subject to the new measures until the 2011
        taxation year provided the Trust continues to meet certain
        requirements.

        As a result of the enactment of the SIFT tax, the Trust recorded a
        future income tax recovery of $1.2 million to reflect current
        temporary differences between the book and tax basis of assets and
        liabilities expected to be remaining in the Trust in 2011. In
        accordance with generally accepted accounting principles, prior to
        the enactment, the Trust's temporary differences were not recorded as
        future income taxes. As at September 30, 2007, the total "temporary
        difference" (tax basis exceeds accounting basis) in the Trust is
        $10.5 million. As at September 30, 2007, the Trust's subsidiaries
        have tax basis of approximately $480 million that is available to
        shelter future taxable income. Included in this tax basis are
        estimated non-capital loss carry forwards of approximately
        $29.3 million that expire in years through 2026. In addition, the
        Trust has approximately $21 million of tax basis.

        The provision for income taxes differs from the expected amount
        calculated by applying the combined Federal and Provincial corporate
        income tax rate of 32.94% (2006: 40.10%) to earnings before income
        taxes.

        This difference results from the following items:

        ---------------------------------------------------------------------
                                              Nine months ended September 30,
        ($000s)                                            2007         2006
        ---------------------------------------------------------------------
        Expected income tax expense (recovery)        $ (17,244)   $ (10,539)
        Distributions deducted for tax purposes         (12,516)     (21,873)
        Impact of SIFT legislation                       (1,165)           -
        Crown royalties and charges                           -        3,354
        Resource allowance                                    -       (2,929)
        Unit based compensation expense                   1,073        1,755
        Change in enacted tax rates                        (137)     (19,825)
        Other                                                32        1,014
        ---------------------------------------------------------------------
        Future income tax expense (recovery)          $ (29,957)   $ (49,043)
        ---------------------------------------------------------------------


    15. SPECIAL MEETING COSTS

        On January 15, 2007, the Trust announced its proposal to convert into
        an intermediate exploration and production company (the
        "Reorganization"). Pursuant to the Reorganization, it was
        contemplated that holders of trust units of the Trust would receive
        an equal number of common shares of a newly formed corporation that
        will hold the assets previously held directly or indirectly by the
        Trust. The exchangeable shares were also to be exchanged for common
        shares based on the conversion ratio thereof. The Reorganization was
        subject to all required regulatory approvals and securityholder
        approval by at least 66 2/3% of the votes cast by unitholders of the
        Trust and holders of the exchangeable shares. At the Special and
        Annual Meeting held on March 30, 2007, the special resolution related
        to the Reorganization was not approved. As a result, the plan of
        arrangement was not approved.

        The Trust incurred $3.8 million in costs for legal, financial
        advisory, accounting, unitholder solicitation services, printing,
        mailing and other expenses that are included as special meeting costs
        within the statement of income for the nine month period ended
        September 30, 2007.

    16. PER TRUST UNIT AMOUNTS

        ---------------------------------------------------------------------
                                  Three months ended       Nine months ended
                                            Sept. 30,               Sept. 30,
                                    2007        2006        2007        2006
        ---------------------------------------------------------------------
        Basic trust units
         outstanding          79,715,595  69,321,703  79,709,119  69,321,703
        Dilutive effect of:
          Trust unit
           incentive rights
           outstanding         6,086,832   5,516,500   6,086,832   5,516,500
          Units issuable
           for exchangeable
           shares                316,547     272,264     316,547     272,264
          Units issuable for
           convertible
           debentures          5,390,625   5,390,625   5,390,625   5,390,625
        ---------------------------------------------------------------------
        Diluted trust units
         outstanding          91,509,599  80,501,092  91,509,599  80,501,092
        ---------------------------------------------------------------------
        Weighted average
         trust units
         outstanding          79,714,539  44,934,827  74,528,093  39,549,352
        Dilutive effect of
         exchangeable shares,
         trust unit incentive
         plan and convertible
         debentures(1)                 -     272,264           -     272,264
        ---------------------------------------------------------------------
        Diluted weighted
         average trust units
         outstanding          79,714,539  45,207,091  74,528,093  39,821,616
        ---------------------------------------------------------------------

        (1) A total of 316,547 (2006: nil) exchangeable shares, 6,086,832
            (2006: 3,103,033) trust incentive units and 5,390,625 (2006:
            5,390,625) trust units issuable pursuant to the conversion of
            convertible debentures were excluded from the calculation for the
            three month period ended September 30, 2007 as they were not
            dilutive. A total of 316,547 (2006: nil) exchangeable shares,
            6,086,832 (2006: 721,377) trust incentive units and 5,390,625
            (2006: 2,132,555) trust units issuable pursuant to the conversion
            of convertible debentures were excluded from the calculation for
            the nine month period ended September 30, 2007 as they were not
            dilutive.

    17. RELATED PARTY TRANSACTIONS

        During the nine month period ended September 30, 2007, the Trust paid
        $1.0 million (2006: $1.0 million) for legal services provided by a
        firm in which a current director and corporate secretary is a
        partner. These payments were made in the normal course of operations,
        on commercial terms, and therefore were recorded at the exchange
        amount.

    18. COMMITMENTS

        At the end of the third quarter of 2007, the Trust had committed to
        drill a total of 2 wells in Alberta with varying commitment dates up
        to end of the first quarter of 2008 pursuant to various farm-in
        agreements with oil and gas companies. True expects to satisfy these
        various drilling commitments at an estimated cost for True's interest
        of approximately $2.8 million.

    19. FINANCIAL INSTRUMENTS

        At September 30, 2007, the following table provides the carrying
        amount and fair value of the Company's financial instruments:

        ---------------------------------------------------------------------
        ($000s)                                 Carrying amount   Fair value
        ---------------------------------------------------------------------
        Commodity contract asset                        $ 3,295      $ 3,295
        Commodity contract liability                      2,598        2,598
        Long-term debt                                  159,212      159,212
        Convertible debentures
          Debt component                 79,021
          Equity component                5,119
                                         ----------------------
                                                         84,140       81,075
        ---------------------------------------------------------------------

        The carrying values of accounts receivable, deposits and prepaid
        expenses, capital taxes receivable, and accounts payable and accrued
        liabilities approximate their fair value due to their short-term
        maturity.

        The Trust's derivatives are exchange traded or transacted in an over-
        the-counter market. Where available, valuation is determined by
        reference to readily available public data.

        The carrying value of long-term debt approximates fair value due to
        the cost of borrowing being at a floating rate.

        The fair value of convertible debentures is based upon the closing
        market trading price as at September 30, 2007.

        For the nine month period ended September 30, 2007, the statement of
        income included the following:

        ---------------------------------------------------------------------
        ($000s)                                                         2007
        ---------------------------------------------------------------------
        Change in fair value of derivative assets and
         liabilities included in
          Gain on commodity contracts                                $ 7,670
        Interest expense                                              13,542
        ---------------------------------------------------------------------


        The Trust has entered into commodity price risk management
        arrangements as follows:

    -------------------------------------------------------------------------
                                                              Price
    Type             Period        Volume    Price Floor    Ceiling   Index
    -------------------------------------------------------------------------
    Oil collar   Oct. 1, 2007 to    2,000
                  March 31, 2008    bbl/d    $ 65.00 US  $ 75.00 US      WTI
    Oil collar   April 1, 2008 to   1,000
                  Dec. 31, 2008     bbl/d    $ 65.00 US  $ 82.00 US      WTI
    Oil collar   April 1, 2008 to   1,000
                  Dec. 31, 2008     bbl/d    $ 65.00 US  $ 82.00 US      WTI
    Natural Gas  April 1, 2007 to   5,000
     collar       Oct. 31, 2007    GJ/day    $ 7.00 CDN  $ 11.00 CDN  AECO C
    Natural Gas  April 1, 2007 to   5,000
     collar       Oct. 31, 2007    GJ/day    $ 7.00 CDN  $ 8.76 CDN   AECO C
    Natural Gas  April 1, 2007 to   5,000
     collar       Oct. 31, 2007    GJ/day    $ 7.00 CDN  $ 8.12 CDN   AECO C
    Natural Gas  Nov. 1, 2007 to    5,000
     collar       March 31, 2008   GJ/day    $ 8.00 CDN  $ 9.05 CDN   AECO C
    Natural Gas  April 1, 2007 to   5,000
     fixed        Oct. 31, 2007    GJ/day    $ 7.10 CDN  $ 7.10 CDN   AECO C
    Natural Gas  April 1, 2007 to   5,000
     fixed        Dec. 31, 2007    GJ/day    $ 7.00 CDN  $ 7.00 CDN   AECO C
    Natural Gas  Jan. 1, 2008 to    5,000
     fixed(1)     Dec. 31, 2008    GJ/day    $ 6.65 CDN  $ 6.65 CDN   AECO C
    Natural Gas  Jan. 1, 2008 to   10,546
     fixed(1)     Dec. 31, 2008    GJ/day    $ 6.65 CDN  $ 6.65 CDN   AECO C
    -------------------------------------------------------------------------

    (1) These contracts were entered into subsequent to September 30, 2007.



        For the nine month period ended September 30, 2007, the gain (loss)
        on commodity contracts was comprised of the following:

        ---------------------------------------------------------------------
        ($000s)                           Activity  Adjustments
                                            in the      for new
                                            period  standards(1)       Total
        ---------------------------------------------------------------------
        Gain (loss) on commodity contracts
          Realized(2)                     $ 10,352     $ (3,262)     $ 7,090
          Unrealized(3)                     (7,858)       8,438          580
        ---------------------------------------------------------------------
                                          $  2,494     $  5,176      $ 7,670
        ---------------------------------------------------------------------

        (1) Refer to note 3 which describes the transitional adjustments for
            adoption of the accounting for the new financial instrument
            standards in relation to the Trust's commodity contracts.

        (2) Realized gains and losses on commodity contracts represent actual
            cash settlements and other amounts paid under these contracts.

        (3) Unrealized gains and losses on commodity contracts represent non-
            cash adjustments for changes in the fair value of these contracts
            during the period.
    

    True Energy Trust is a Calgary-based oil and natural gas trust. True is
an open-ended, incorporated investment trust governed by the laws of the
Province of Alberta. The purpose of the Trust is to indirectly explore for,
develop and hold interests in petroleum and natural gas properties, through
investments in securities of subsidiaries and net profits interests. The trust
structure allows individual unitholders to participate in the cash flow of the
business. Cash flow is realized from the Trust's subsidiaries' ownership of
natural gas and petroleum properties and related facilities. Trust units of
True trade on the Toronto Stock Exchange ("TSX") under the symbol TUI.UN.

    %SEDAR: 00021401E




For further information:

For further information: Wayne M. Chorney, President, CEO & COO, (403)
750-2420 or Edward J. Brown, CA, Vice President, Finance & CFO, (403) 750-2655
or Scott Koyich, Investor Relations, (403) 750-2428 or Troy Winsor, US
Investor Relations, (800) 663-8072, True Energy Trust, 2300, 530 - 8th Avenue
SW, Calgary, Alberta T2P 3S8, Phone: (403) 266-8670, Fax: (403) 264-8163,
www.trueenergytrust.com


Custom Packages

Browse our custom packages or build your own to meet your unique communications needs.

Start today.

CNW Membership

Fill out a CNW membership form or contact us at 1 (877) 269-7890

Learn about CNW services

Request more information about CNW products and services or call us at 1 (877) 269-7890