True Energy Trust Announces Second Quarter 2008 Financial Results



    TSX: TUI.UN

    CALGARY, Aug. 7 /CNW/ - (TSX: TUI.UN) True Energy Trust ("True" or the
"Trust") announces its financial and operating results for the three and six
months ended June 30, 2008.
    During the first half of 2008, True successfully implemented its new
strategic direction. Focused on improving balance sheet strength while
providing a consistent monthly distribution, the Trust is now positioned to
efficiently execute a second half 2008 capital program of 28 net wells.
Accomplishments during the first half of 2008 include:

    
    -   In the first six months of 2008 True reduced its net debt by
        approximately $62 million and the debt to funds flow from
        operations(*) ratio to 1.8 times.
    -   As of June 30, 2008, True renewed its $152 million credit facility,
        which extends to June 26, 2009.
    -   The Board announced a third quarter distribution policy of $0.04 per
        unit per month consistent with the first and second quarter
        distribution policy.
    -   For the six month period ended June 30, 2008 sales volumes averaged
        12,737 boe/d. Second quarter 2008 sales volumes averaged 11,922 boe/d
        with full year guidance remaining at 12,000 to 12,500 boe/d.
    -   True closed first half 2008 dispositions totalling $44.3 million of
        net proceeds after adjustments and costs.

    Highlights from the second quarter include:

    -   True's total net debt as at June 30, 2008, excluding commodity
        contract liabilities, future income taxes and asset retirement
        obligations, was $189.4 million. During the six month period ended
        June 30, 2008, True has reduced its net debt by approximately
        $62 million. As at June 30, 2008, the debt to funds flow from
        operations(*) ratio, calculated based upon annualized second quarter
        2008 funds flow from operations(*), is 1.8 times.

    -   During the second quarter of 2008, True participated in 1 (0.4 net)
        successful working interest natural gas well. True's planned second
        half drilling program is underway with 4 gross (2.9 net) gas wells
        drilled thus far in the third quarter of 2008. A further 25 net wells
        are planned through the remainder of the year.

    -   During the second quarter of 2008, True closed on the sale of its
        Dodsland-Stranraer property for net proceeds of $38.5 million, after
        closing adjustments and costs.

    -   In the second quarter of 2008, monthly distributions of $0.04 per
        unit were declared and paid on May 15, 2008, June 16, 2008 and
        July 15, 2008. The Board has announced it has set a distribution
        policy for the third quarter of 2008 at a monthly rate of $0.04 per
        unit, subject to monthly confirmation, based on current commodity
        prices, hedging program, anticipated production volumes and market
        conditions. True anticipates its $0.04 per unit monthly distributions
        to be sustainable in the current gas price, foreign exchange rate and
        cost environment.

    -   True generated average sales volumes for the second quarter of 2008
        of 11,922 boe/d as compared to 17,122 boe/d for the second quarter of
        2007. For the six month period ended June 30, 2008, sales volumes
        averaged 12,737 boe/d as compared to 17,788 boe/d for the same period
        in 2007. Dispositions totalling approximately 1,000 boe/d were closed
        during the first half of 2008. In addition to natural production
        decline, field production was impacted approximately 150 boe/d by
        third party maintenance and severe thunderstorm activity in the
        second quarter of 2008. Full year 2008 field production guidance
        remains at 12,000 to 12,500 boe/d.

    -   Funds flow from operations(*) for the second quarter of 2008 was
        $26.3 million on gross sales of $82.1 million compared to funds flow
        from operations of $34.2 million on gross sales of $75 million for
        the same period in 2007. The decrease in funds flow for the 2008
        second quarter was primarily the result of lower sales volumes and
        higher realized hedging losses, partially offset by higher overall
        commodity prices and operating netbacks for the period. Funds flow
        from operations for the second quarter of 2008 increased 1% from
        first quarter 2008 funds flow from operations of $24.3 million,
        primarily reflecting further improved commodity prices.

    -   True maintains a commodity price risk management program to provide a
        measure of stability to cash distributions and capital expenditures.
        Unrealized mark-to-market gains or losses are non-cash adjustments to
        the current fair market value of the contract over its entire term
        and are included in the calculation of net income (loss).

    -   A net loss of $21.4 million for the second quarter of 2008 compared
        to a net income of $1.7 million for the second quarter of 2007 was
        primarily due to higher unrealized mark-to-market, non-cash, losses
        on commodity price risk management contracts of $25.6 million. The
        net loss for the six month period ended June 30, 2008 was
        $40.0 million compared to $6.8 million for the same period in 2007.

    -   As of June 30, 2008, the credit facility was renewed and consists of
        a $15 million demand operating facility provided by one Canadian bank
        and a $137 million extendible revolving credit facility syndicated by
        two Canadian chartered banks, a Canadian financial institution, one
        institutional lender and a U.S. bank. The revolving period on the
        revolving term credit facility ends on June 26, 2009, unless extended
        for a further 364 day period. Should the facilities not be renewed
        they convert to 366 day non-revolving facilities on the renewal date.
        The borrowing base was renewed effective June 27, 2008 and is
        currently scheduled for renewal on September 30, 2008. As at
        June 30, 2008, there was approximately $26.0 million undrawn, net of
        $0.5 million of prepaid interest, under these facilities.

    (*) Refer to note (2) in the highlights section of the second quarter
        report in respect of the term "funds flow from operations", which is
        also commonly referred to as "cash flow from operations".

    True's second quarter report is presented below.



                                 HIGHLIGHTS

    -------------------------------------------------------------------------
                                Three months ended          Six months ended
                                           June 30,                  June 30,
                                 2008         2007         2008         2007
    -------------------------------------------------------------------------
    FINANCIAL (unaudited)
    (CDN$000s except unit
     and per unit amounts)
    Revenue (before
     royalties and
     hedging(1))               82,074       74,991      152,107      146,187
    Funds flow from
     operations(2)             26,304       34,192       50,537       64,180
      Per basic trust
       unit               $      0.33   $     0.47  $      0.64  $      0.89
      Per diluted trust
       unit(5)            $      0.33   $     0.45  $      0.64  $      0.88
    Net income (loss)         (21,374)       1,741      (39,995)      (6,830)
      Per basic trust
       unit               $     (0.27)  $     0.02  $     (0.50) $     (0.10)
      Per diluted trust
       unit (5)           $     (0.27)  $     0.02  $     (0.50) $     (0.09)
    Distributions
     declared                   9,505       18,376       19,012       35,242
       Per unit           $      0.12   $     0.24  $      0.24  $      0.48
    -------------------------------------------------------------------------
    Exploration and
     development                3,654       15,116       12,107       60,769
    Corporate and
     property
     acquisitions                 426          649          623        1,354
    -------------------------------------------------------------------------
    Capital expenditures
     - cash                     4,080       15,765       12,730       62,123
    Property dispositions
     - cash                   (38,530)      (9,026)     (44,318)     (27,469)
    Corporate
     acquisitions
     and other
     - non-cash                (2,521)         311       (2,714)        (313)
    -------------------------------------------------------------------------
    Total capital
     expenditures - net       (36,971)       7,050      (34,302)      34,341
    -------------------------------------------------------------------------
    Long-term debt            125,458      142,153      125,458      142,153
    Convertible debentures     80,253       78,636       80,253       78,636
    Working capital
     deficiency (excess)      (16,357)         256      (16,357)         256
    -------------------------------------------------------------------------
    Total net debt(3)         189,354      221,045      189,354      221,045
    -------------------------------------------------------------------------
    Total assets              793,883      941,122      793,883      941,122
    Unitholders' equity       404,062      520,326      404,062      520,326

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

    OPERATING
    Daily sales volumes
      Crude oil,
       condensate
       and NGLs   (bbls/d)      4,170        5,546        4,506        6,007
      Natural
       gas         (mcf/d)     46,515       69,455       49,383       70,686
      Total oil
       equivalent  (boe/d)     11,922       17,122       12,737       17,788
    Average prices
      Crude oil,
       condensate
       and NGLs    ($/bbl)     103.14        50.90        86.19        45.74
      Crude oil,
       condensate
       and NGLs
      (including
      hedging(1))  ($/bbl)      82.56        50.14        71.50        46.71
      Natural gas  ($/mcf)       9.94         7.60         8.90         7.43
      Natural gas
      (including
      hedging(1))  ($/mcf)       8.80         7.65         8.37         7.58
      Total oil
       equivalent  ($/boe)      74.85        47.33        64.99        44.96
      Total oil
       equivalent
       (including
       hedging(1)) ($/boe)      63.22        47.25        57.76        45.90
    Statistics
      Operating
       netback     ($/boe)      42.66        26.79        35.54        25.53
      Operating
       netback
      (including
       hedging(1)) ($/boe)      31.01        26.71        28.30        26.47
      Transpor-
       tation      ($/boe)       2.28         1.56         1.43         0.97
      Production
       expenses    ($/boe)      14.90        12.69        14.31        10.79
      General &
       adminis-
       trative     ($/boe)       4.14         2.78         3.56         2.87
      Royalties
       as a % of
       sales after
       transpor-
       tation                      21%          14%          22%          17%

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



    -------------------------------------------------------------------------
                                Three months ended          Six months ended
                                           June 30,                  June 30,
                                 2008         2007         2008         2007
    -------------------------------------------------------------------------

    TRUST UNITS
    Trust units
     outstanding           79,095,460   79,709,119   79,095,460   79,709,119
    Trust unit incentive
     rights outstanding     5,006,079    6,687,499    5,006,079    6,687,499
    Units issuable for
     exchangeable shares      347,254      309,216      347,254      309,216
    Units issuable for
     convertible
     debentures             5,390,625    5,390,625    5,390,625    5,390,625
    -------------------------------------------------------------------------
    Diluted trust units
     outstanding           89,839,418   92,296,459   89,839,418   92,296,459
    Diluted weighted
     average trust
     units(5)              79,203,976   75,810,961   79,213,532   71,891,887

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

    TRUST UNIT TRADING STATISTICS
    (CDN$, except volumes) based
     on intra-day trading
    High                         4.69         6.83         4.69         7.47
    Low                          3.54         5.71         2.94         4.87
    Close                        4.40         5.75         4.40         5.75
    Average daily volume      266,304      438,393      261,833      520,700
    -------------------------------------------------------------------------

    (1) The Trust has entered into various commodity risk management
        contracts which are considered to be economic hedges. Per unit
        metrics after hedging includes only the realized portion of gains or
        losses on commodity contracts.

        Effective January 1, 2007 on adoption of CICA handbook sections 3855
        and 3865, 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. These unrealized gains or
        losses on commodity contracts are not included for purposes of per
        unit metrics calculations disclosed.

    (2) The highlights section contains the term "funds flow from
        operations" (or as commonly referred to as "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 funds flow from operations or funds
        flow from operations per trust unit may not be comparable with the
        calculation of similar measures for other entities. Management uses
        funds flow from operations to analyze operating performance and
        leverage and considers funds 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 funds flow from operations and cash flow from
        operating activities can be found in the Management Discussion and
        Analysis ("MD&A"). Funds flow from operations per trust unit is
        calculated using the weighted average number of trust units for the
        period.

    (3) Net debt includes the net working capital deficiency (excess) before
        short-term commodity contract assets and liabilities and short-term
        future income tax assets. Total net debt also includes the liability
        component of convertible debentures and excludes asset retirement
        obligations and the future income tax liability.

    (4) Operating netbacks are calculated by subtracting royalties,
        transportation, and operating costs from revenues.

    (5) In computing weighted average diluted earnings per trust unit for the
        three month period ended June 30, 2008 nil (2007: 2,320,716) trust
        incentive units were added to the 79,203,976 (2007: 73,490,245)
        weighted average number of trust units outstanding during the period
        for the dilutive effect of exchangeable shares and convertible
        debentures. A total of 5,006,079 (2007: 4,875,999) trust incentive
        units, 347,254 (2007: nil) exchangeable shares and 5,390,625
        (2007: 5,390,625) trust units issuable pursuant to the conversion of
        convertible debentures were excluded from the calculation for the
        three month period ended June 30, 2008 as they were not dilutive. To
        calculate weighted average diluted funds flow from operations for the
        three month period ended June 30, 2007, a total of $2.0 million for
        interest accretion expense was added to the numerator and 5,390,625
        trust units were added to the denominator for units issuable on
        conversion of convertible debentures, resulting in diluted weighted
        average trust units of 81,201,586 and funds flow from operations per
        diluted unit of $0.45 under this calculation.

        In computing weighted average diluted earnings per trust unit for the
        six month period ended June 30, 2008 5,006,079 (2007: 6,887,499)
        trust incentive units, 347,254 (2007: 309,216) exchangeable shares
        and 5,390,625 (2007: 5,390,625) trust units issuable pursuant to the
        conversion of convertible debentures were excluded from the
        calculation for the six month period ended June 30, 2008 as they were
        not dilutive. To calculate weighted average diluted funds flow from
        operations for the six month period ended June 30, 2007, a total of
        $4.0 million for interest accretion expense was added to the
        numerator and 5,390,625 trust units were added to the denominator for
        units issuable on conversion of convertible debentures, resulting in
        diluted weighted average trust units of 77,591,728 and funds flow
        from operations per diluted unit of $0.88 under this calculation.


                            REPORT TO UNITHOLDERS
    

    Improved commodity prices in the second quarter combined with the
proceeds of our property disposition program have been utilized to reduce
True's bank indebtedness and increase the Trust's financial flexibility. After
concentrating on debt reduction in the first half of 2008, our focus for
remainder of the year now shifts to the efficient execution of the capital
program. Drilling has begun in West Central Alberta and True will soon move
onto exciting projects such as the Viking Horizontal program in Kindersley and
further exploration drilling with a view to expand our reserve and production
base.
    Accomplishments for the second quarter ended June 30, 2008 include:

    Distributions

    In the second quarter of 2008, monthly distributions of $0.04 per unit
were declared and paid on May 15, 2008, June 16, 2008 and July 15, 2008.
    On July 15, 2008, the Trust announced that the Board has set the
distribution policy for the third quarter of 2008 at a monthly distribution
rate of $0.04 per unit, subject to monthly confirmation by the Board of
Directors, based on current commodity prices, hedging program, anticipated
production volumes and market conditions. True anticipates its $0.04 per unit
monthly distributions to be sustainable in the current gas price, foreign
exchange rate and cost environment.

    Production

    2008 second quarter sales volumes averaged 11,922 boe/d as compared to
17,122 boe/d for the same period in 2007. For the six month period ended
June 30, 2008, sales volumes averaged 12,737 boe/d compared to 17,788 boe/d
for the same period in 2008. Dispositions totalling approximately 1,000 boe/d
were closed during the first half of 2008. In addition to natural production
decline, field production was impacted approximately 150 boe/d by third party
maintenance and severe thunderstorm activity in the second quarter of 2008.
Full year 2008 field production guidance remains at 12,000 to 12,500 boe/d.

    Drilling

    During the second quarter of 2008, True participated in 1 (0.4 net)
successful working interest natural gas well. True's planned second half
drilling program is underway with 4 gross (2.9 net) gas wells drilled thus far
in the third quarter of 2008.
    A further 25 net wells are planned through the remainder of the year
including at least 3 horizontal Viking light oil wells in the Kindersley area,
1.5 vertical heavy oil wells at Mantario, and 18.5 natural gas wells in
Alberta. A further 2 exploration wells are also scheduled.

    Kerrobert

    The Kerrobert SAGD project was adversely impacted by severe thunderstorm
and lightning activity in June and July 2008. Electrical equipment issues
impacted steam generation. Oil production rates were subsequently reduced to
retain the steam chamber and ensure uniform heating and conformance. Repairs
are largely complete and response to the ongoing reservoir heating continues
to improve with temperatures of up to 200 degrees Celsius observed in 2 of the
4 new thermal producing wells as compared to initial reservoir temperatures of
approximately 30 degrees Celsius.

    Financial

    Funds flow from operations for the second quarter of 2008 was
$26.3 million on gross sales of $82.1 million compared to funds flow from
operations of $34.2 million on gross sales of $75.0 million for the same
period in 2007. The decrease in funds flow for the 2008 second quarter was
primarily the result of lower sales volumes and higher realized hedging
losses, offset significantly by improved commodity pricing and operating
netbacks for 2008. Funds flow from operations for the second quarter of 2008
increased 1% from first quarter 2008 funds flow from operations of
$24.3 million, primarily reflecting further improved commodity prices.
    Funds flow from operations for the six month period ended June 30, 2008
was $50.5 million on gross sales of $152.1 million compared to funds flow from
operations of $64.2 million on gross sales of $146.2 million for the same
period in 2007.
    True maintains a commodity price risk management program to provide a
measure of stability to cash distributions and capital expenditures.
Unrealized mark-to-market gains or losses are non-cash adjustments to the
current fair market value of the contract over its entire term and are
included in the calculation of net income (loss).
    A net loss of $21.4 million for the second quarter of 2008 compared to a
net income of $1.7 million for the second quarter of 2007 was primarily due to
higher unrealized mark-to-market, non-cash, losses on commodity price risk
management contracts of $25.6 million. The net loss for the six month period
ended June 30, 2008 was $40.0 million compared to $6.8 million for the same
period in 2007.

    Dispositions

    On December 17, 2007, True announced its intention to divest of its
Saskatchewan assets and reduce the distribution level as part of a new
strategic direction for the Trust. Proceeds from the proposed divestiture
would be utilized to reduce True's bank indebtedness and the reduced
distribution level ensured additional financial resources.
    The additional cash flow generated through improved pricing has eased
debt concerns and allowed the Trust to modify the path of the new strategic
direction. On April 30, 2008 True announced that the sale of the
Dodsland-Stranraer asset, one of five asset packages comprising the
Saskatchewan divestiture program, had been successfully completed for net
proceeds after adjustments and closing costs of $38.5 million. True further
announced its decision to not pursue further Saskatchewan asset disposition
options at this time. The Trust feels that the goal of increased financial
flexibility is sufficiently achieved through the combination of improved
commodity prices, receipt of the Dodsland-Stranraer sale proceeds, and a
continued distribution level of $0.04 per unit per month, while retaining a
larger asset and production base.
    Combined with the sale of the Thorhild property in Northern Alberta which
closed at the end of the first quarter of 2008 for net proceeds of
$5.8 million, after closing adjustments and costs, and other minor property
dispositions, total net proceeds from the sale of properties for the first six
months of 2008 were $44.3 million.
    The net proceeds from these dispositions were used to pay down debt. The
Trust continuously reviews and optimizes its portfolio, divesting of non-core
and high cost properties.

    Liquidity

    True's net debt, excluding unrealized commodity contract assets and
liabilities, future income taxes and asset retirement obligations, as at
June 30, 2008 was $189.4 million, representing $125.5 million outstanding on
the credit facility, $80.3 million in convertible debentures (liability
component) and the net balance of working capital.
    Combined funding requirements for distributions declared and True's
capital expenditures represented 51.6% and 62.8% of funds flow from operations
in the three and six months ended June 30, 2008, respectively. The excess
funds flow from operations was applied to the repayment of net debt.
    As of June 30, 2008, the credit facility was renewed and consists of a
$15 million demand operating facility provided by one Canadian bank and a
$137 million extendible revolving credit facility syndicated by two Canadian
chartered banks, a Canadian financial institution, one institutional lender
and a U.S. bank. The revolving period on the revolving term credit facility
ends on June 26, 2009, unless extended for a further 364 day period. Should
the facilities not be renewed they convert to 366 day non-revolving facilities
on the renewal date. The borrowing base was renewed effective June 27, 2008
and is currently scheduled for renewal on September 30, 2008. Further details
of the credit facilities are disclosed in note 6 of the consolidated financial
statements. As at June 30, 2008, there was approximately $26.0 million, net of
$0.5 million of prepaid interest, not drawn under these facilities.
    True does not hold any Asset-Backed Commercial Paper investments. As a
non-operating working interest owner, True has a minor exposure of
approximately $70,000 from oil sales marketed through SemCanada Crude Company,
which filed for CCAA protection on July 22, 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. Starting in the
fourth quarter and through the end of 2007, 500,000 units were repurchased at
a total price of $1.7 million. In the second quarter of 2008, 135,000
additional units were repurchased at a total price of $0.6 million. Future
repurchases will be dependent on excess cash available after consideration of
the Trust's priority uses of cash and the trading price of the Trust's units.
    True maintains an active commodity price risk management program.
Approximately 50% of current natural gas production is hedged through the
remainder of 2008 with approximately 23% hedged through the first half of
2009. Approximately 40% of current liquids production is hedged through the
remainder of 2008. No liquids are currently hedged subsequent to December 31,
2008. The Trust will continue its hedging strategies focusing on maintaining
sufficient cash flow to fund True's unitholder distributions and the capital
program.

    2008 True Capex Budget

    True's capital program for the first six months of 2008 of approximately
$12.7 million compares to a front end loaded 2007 capital program of
approximately $62.1 million in the six month period ended June 30, 2007. True
plans to continue to take a balanced approach to the priority use of cash flow
between level of distributions and size of its 2008 capital program. True's
2008 capital expenditure program is currently planned at $40 to $45 million.
True plans to focus on increasing its farm-out activity in non-core areas and
may look to increase its capital spending in the latter part of 2008 dependant
upon available cash flow.

    Wayne M. Chorney, P. Eng.
    President, CEO and COO
    August 7, 2008

    
                     MANAGEMENT'S DISCUSSION AND ANALYSIS
    

    August 7, 2008 - 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 six
months ended June 30, 2008 and the audited consolidated financial statements
for the years ended December 31, 2007 and 2006 for the Trust. This commentary
is based on information available to, and is dated as of, August 7, 2008. 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 equivalent (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 "funds flow from operations" (or also commonly referred to as "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 funds flow from operations or funds flow from
operations per unit may not be comparable with the calculation of similar
measures for other entities. Management uses funds flow from operations to
analyze operating performance and leverage and considers funds 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 funds flow from operations and cash flow from
operating activities can be found in the Management's Discussion and Analysis.
Funds flow from operations per unit is calculated using the weighted average
number of units for the period.
    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 transportation, 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 income 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, drilling plans and the timing thereof, expected
production increases from certain projects and the timing thereof, the effect
of government announcements, proposals and legislation, plans regarding wells
to be drilled, expected or anticipated production rates, hedging strategies,
expected exchange rates, distributions and method of funding thereof,
proportion of distributions anticipated to be taxable and non-taxable,
maintenance of productive capacity and 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. In addition, forward-looking statements or information are based on a
number of factors and assumptions which have been used to develop such
statements and information but which may prove to be incorrect. Although the
Trust believes that the expectations reflected in such forward-looking
statements or information are reasonable, undue reliance should not be placed
on forward-looking statements because the Trust can give no assurance that
such expectations will prove to be correct. In addition to other factors and
assumptions which may be identified herein, assumptions have been made
regarding, among other things: the impact of increasing competition; the
general stability of the economic and political environment in which the Trust
operates; the timely receipt of any required regulatory approvals; the ability
of the Trust to obtain qualified staff, equipment and services in a timely and
cost efficient manner; drilling results; the ability of the operator of the
projects which the Trust has an interest in to operate the field in a safe,
efficient and effective manner; the ability of the Trust to obtain financing
on acceptable terms; field production rates and decline rates; the ability to
replace and expand oil and natural gas reserves through acquisition,
development of exploration; the timing and costs of pipeline, storage and
facility construction and expansion and the ability of the Trust to secure
adequate product transportation; future commodity gas prices; currency,
exchange and interest rates; the regulatory framework regarding royalties,
taxes and environmental matters in the jurisdictions in which the Trust
operates; and the ability of the Trust to successfully market its oil and
natural gas products. Readers are cautioned that the foregoing list is not
exhaustive of all factors and assumptions which have been used. As a
consequence, actual results may differ materially from those anticipated in
the forward-looking statements. 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 Funds Flow from Operations

    True generated funds flow from operations of $26.3 million ($0.33 per
diluted unit) for the three months ended June 30, 2008, down 23% from
$34.2 million ($0.45 per diluted unit) from the second quarter of 2007. The
decrease in funds flow from operations for the 2008 period was primarily the
result of lower sales volumes and higher realized hedging losses, offset
significantly by improved commodity prices and operating netbacks for 2008.
Funds flow from operations for the first quarter of 2008 increased 25% from
fourth quarter 2007 funds flow from operations of $19.5 million. Funds flow
from operations for the six month period ended June 30, 2008 was $50.5 million
($0.64 per diluted unit), down from the $64.2 million ($0.88 per diluted unit)
for the same period in 2007.
    True maintains a commodity price risk management program to provide a
measure of stability to cash distributions and capital expenditures.
Unrealized mark-to-market gains or losses are non-cash adjustments to the
current fair market value of the contract over its entire term and are
included in the calculation of net income (loss).
    True generated a net loss of $21.4 million ($(0.27) per diluted unit) in
the second quarter of 2008 primarily due to higher unrealized mark-to-market,
non-cash, losses on commodity risk management contracts of $25.6 million. This
compares to net income of $1.7 million ($0.02 per diluted unit) for the same
period in 2007. The net loss for the six months ended June 30, 2008 was
$40.0 million compared to a net loss of $6.8 million for the same period in
2007.

    Funds Flow From Operations and Net Income (Loss)

    
    -------------------------------------------------------------------------
                                Three months ended          Six months ended
    ($000s, except                         June 30,                  June 30,
     per unit amounts)           2008         2007         2008         2007
    -------------------------------------------------------------------------

    Funds flow from
     operations                26,304       34,192       50,537       64,180
      Basic ($/unit)             0.33         0.47         0.64         0.89
      Diluted ($/unit)           0.33         0.45         0.64         0.88

    Net income (loss)         (21,374)       1,741      (39,995)      (6,830)
      Basic ($/unit)            (0.27)        0.02        (0.50)       (0.10)
      Diluted ($/unit)          (0.27)        0.02        (0.50)       (0.09)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Reconciliation of Funds Flow from Operations and Cash Flow from Operating
    Activities

    -------------------------------------------------------------------------
                                Three months ended          Six months ended
    ($000s, except                         June 30,                  June 30,
     per unit amounts)           2008         2007         2008         2007
    -------------------------------------------------------------------------

    Funds flow from
     operations                26,304       34,192       50,537       64,180

    Asset retirement
     costs incurred              (123)        (387)        (712)        (575)

    Change in non-cash
     working capital           (6,289)     (29,403)     (12,090)     (19,244)
    -------------------------------------------------------------------------

    Cash flow from
     operating
     activities                19,892        4,402       37,735       44,361
    -------------------------------------------------------------------------
    

    Sales Volumes

    Sales volumes for the three months ended June 30, 2008 averaged
11,922 boe/d as compared to 17,122 boe/d for the same period in 2007,
representing a 30% decrease. Sales volumes for the six months ended June 30,
2008 averaged 12,737 boe/d as compared to 17,788 boe/d for the same period in
2007, representing a 28% decrease. In comparison, sales volumes for the first
quarter of 2008 averaged 13,552 boe/d.
    Dispositions totalling approximately 1,000 boe/d were closed during the
first half of 2008. In addition to natural production decline, field
production was impacted approximately 150 boe/d by third party maintenance and
severe thunderstorm activity in the second quarter of 2008. Full year 2008
field production guidance remains at 12,000 to 12,500 boe/d. The disposition
of the Dodsland/Stranraer property, consisting of primarily natural gas
reserves, on April 30, 2008 reduced average sales volumes for the second
quarter by approximately 500 boe/d as compared to the first quarter of 2008.

    
    Sales Volumes
    -------------------------------------------------------------------------
                                Three months ended          Six months ended
                                           June 30,                  June 30,
                                 2008         2007         2008         2007
    -------------------------------------------------------------------------

    Natural gas    (mcf/d)     46,515       69,455       49,383       70,686
    -------------------------------------------------------------------------

    Heavy oil     (bbls/d)      2,721        3,058        2,773        3,703
    Light oil and
     condensate   (bbls/d)      1,116        1,743        1,253        1,632
    NGLs          (bbls/d)        333          745          480          672
    -------------------------------------------------------------------------
    Total crude
     oil and NGLs (bbls/d)      4,170        5,546        4,506        6,007
    -------------------------------------------------------------------------
    Total boe/d      (6:1)     11,922       17,122       12,737       17,788
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    During the second quarter of 2008, True participated in 1 (0.4 net)
successful working interest gas well. True's planned second half drilling
program is underway with 4 gross (2.9 net) gas wells drilled thus far in the
third quarter of 2008. A further 25 net wells are planned through the
remainder of the year including at least 3 horizontal Viking light oil wells
in the Kindersley area, 1.5 vertical heavy oil wells at Mantario, and 18.5
natural gas wells in Alberta. A further 2 exploration wells are also
scheduled.
    The Kerrobert SAGD project was adversely impacted by severe thunderstorm
and lightning activity in June and July 2008. Electrical equipment issues
impacted steam generation. Oil production rates were subsequently reduced to
retain the steam chamber and ensure uniform heating and conformance. Repairs
are largely complete and response to the ongoing reservoir heating continues
to improve with temperatures of up to 200 degrees Celsius observed in 2 of the
4 new thermal producing wells as compared to initial reservoir temperatures of
approximately 30 degrees Celsius.
    For the three months ended June 30, 2008, the weighting towards natural
gas sales averaged 65% compared to 68% in the same period in 2007. For the six
month period ended June 30, 2008, the weighting towards natural gas averaged
65% compared to 66% for the same period in 2007. Heavy oil sales made up 23%
of total production for the 2008 second quarter compared to 18% in the 2007
second quarter. In comparison, heavy oil sales made up 21% of total production
in the first quarter of 2008.
    Sales of natural gas averaged 46.5 mmcf/d for the second quarter of 2008,
compared to 69.5 mmcf/d in the same period of 2007, a decrease of 33%. Crude
oil and NGL sales for the second quarter of 2008 averaged 4,170 bbls/d,
compared to 2007 second quarter average sales of 5,546 bbls/d.

    Commodity Prices

    
    Average Commodity Prices
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30,                June 30,
                                                   %                       %
                                2008    2007  Change     2008   2007  Change
    -------------------------------------------------------------------------

    Exchange rate (US$/Cdn$)  1.0000  0.9108     10%  0.9989  0.8810     13%

    Natural gas:
    NYMEX (US$/mmbtu)          11.47    7.66     50%    9.99    7.41     35%
    Alberta spot ($/mcf)       10.20    7.07     44%    9.09    7.23     26%
    True's average price
     ($/mcf)                    9.94    7.60     31%    8.90    7.43     20%
    True's average price
     (including hedging(1))
     ($/mcf)                    8.80    7.65     15%    8.37    7.58     10%

    Crude oil:
    WTI (US$/bbl)             123.80   65.02     90%  109.92   61.67     78%
    Edmonton par - light oil
     ($/bbl)                  126.37   72.66     74%  112.30   70.21     60%
    Bow River - medium/heavy
     oil ($/bbl)              103.98   50.69    105%   90.74   50.24     81%
    Hardisty Heavy - heavy
     oil ($/bbl)               96.34   42.95    124%   83.20   42.82     94%
    True's average prices
     ($/bbl)
      Light crude oil,
       condensate, and NGLs   110.23   60.59    82%    95.92   56.10     71%
      Heavy crude oil          99.37   43.01   131%    80.11   39.28    104%
      Total crude oil and
       NGLs                   103.14   50.90   103%    86.19   45.74     88%
      Total crude oil and
       NGLs (including
       hedging(1))             43.82   50.14   (13%)   71.50   46.71     53%
    -------------------------------------------------------------------------
    (1) Per unit metrics including hedging include realized gains or losses
        on commodity contracts and exclude unrealized gains or losses on
        commodity contracts.
    

    True's natural gas is primarily sold on the daily spot market. During the
second quarter of 2008, the AECO Spot reference price increased by 44%
compared to the same period in 2007. True's average sales price before hedging
for the second quarter of 2008 increased by 31% compared to the same period in
2007. In comparison, True's second quarter 2008 natural gas price before
hedging was 25% higher than the first quarter 2008 price of $7.97/mcf. True's
natural gas price after including hedging for the second quarter of 2008 was
$8.80/mcf compared to $7.65/mcf for the same period in 2007.
    For heavy crude oil, True received an average price before transportation
of $99.37/bbl for the second quarter of 2008, an increase of 131% over prices
in the 2007 period. The Bow River reference price increased by 105% and the
Hardisty Heavy reference price increased by 124% 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. During 2008, the blend
costs for condensate were lower and a certain portion of our heavy oil sales
have been sold through the Bow River pipeline which has also contributed to
higher pricing received. In comparison, True's second quarter 2008 heavy oil
price was 62% higher than the first quarter of 2008 price of $61.55/bbl.
    For light oil, condensate and NGLs, True recorded an average $110.23/bbl
before hedging during the second quarter of 2008, 82% higher than the average
price received in the same period of 2007. The Edmonton par price increased by
74% over the same period. The average WTI crude oil US dollar based price
increased 90% from the second quarter of 2007 to that in 2008. In comparison,
True's realized price for the second quarter of 2008 increased 29% from the
first quarter 2008 average price of $85.65/bbl, whereas the Edmonton par price
also increased by 29%. True's realized price after including hedging was
$50.99/bbl for the second quarter of 2008 compared to $58.90/bbl for the same
period in 2007.

    Revenue

    Revenue before other income and hedging for the three months ended June
30, 2008 was $81.2 million, 10% higher than the $73.7 million in the same
period in 2007. The higher revenue for the 2008 period was the result of
significantly higher commodity prices, despite lower sales volumes.

    
    -------------------------------------------------------------------------
                                Three months ended          Six months ended
                                           June 30,                  June 30,
    ($000s)                      2008         2007         2008         2007
    -------------------------------------------------------------------------

    Light crude oil,
     condensate and NGLs       14,528       13,719       30,262       23,394
    Heavy oil                  24,608       11,967       40,426       26,329
    -------------------------------------------------------------------------
    Crude oil and NGLs         39,136       25,686       70,688       49,723
    Natural gas                42,067       48,058       79,961       95,040
    -------------------------------------------------------------------------
    Total revenue before
     other                     81,203       73,744      150,649      144,763
    Other (1)                     871        1,247        1,458        1,424
    -------------------------------------------------------------------------
    Total revenue before
     royalties and hedging     82,074       74,991      152,107      146,187
    -------------------------------------------------------------------------
    (1) Other revenue primarily consists of processing and other third party
        income.
    

    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, 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.
    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 as of August 7, 2008 is shown in the following tables (see Note 16
to the consolidated financial statements for a detailed disclosure of all
commodity contracts in place as at August 7, 2008):

    
    Crude oil and liquids     Average Volumes (bbls/d)
    -------------------------------------------------------------------------

                              Q3 2008      Q4 2008      Q1 2009      Q2 2009
    -------------------------------------------------------------------------
    Collars                     2,000        2,000            -            -
    -------------------------------------------------------------------------
    Total bbls/d                2,000        2,000            -            -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average Price (US$/bbl WTI)
    -------------------------------------------------------------------------

                              Q3 2008      Q4 2008      Q1 2009      Q2 2009
    -------------------------------------------------------------------------
    Collar ceiling price        82.00        82.00            -            -
    Collar floor price          65.00        65.00            -            -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Natural gas      Average Volumes (GJ/d)
    -------------------------------------------------------------------------

                              Q3 2008      Q4 2008      Q1 2009      Q2 2009
    -------------------------------------------------------------------------
    Collars                         -            -            -            -
    Fixed                      24,326       24,326       10,550       10,550
    -------------------------------------------------------------------------
    Total GJ/d                 24,326       24,326       10,550       10,550
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Average Price ($/GJ AECO C)
    -------------------------------------------------------------------------

                              Q3 2008      Q4 2008      Q1 2009      Q2 2009
    -------------------------------------------------------------------------
    Collar ceiling price            -            -            -            -
    Collar floor price              -            -            -            -
    Fixed                        6.68         6.89         7.74         7.01
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    As of June 30, 2008, the fair value of True's outstanding commodity
contracts is an unrealized liability of $53.6 million as reflected in the
financial statements.
    The following is a summary of the gain (loss) on commodity contracts for
the three and six month periods ended June 30, 2008 and 2007:

    
    Commodity contracts
    -------------------------------------------------------------------------
                            Crude Oil      Natural      Q2 2008      Q2 2007
    ($000s)                 & Liquids          Gas        Total        Total
    -------------------------------------------------------------------------
    Realized cash gain
     (loss) on contracts(1)    (7,807)      (4,812)     (12,619)        (118)
    Unrealized gain (loss)
     on contracts(2)          (14,700)     (10,850)     (25,550)       5,953
    -------------------------------------------------------------------------
    Total gain (loss) on
     commodity contracts      (22,507)     (15,662)     (38,169)       5,835
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                            Crude Oil      Natural     YTD 2008     YTD 2007
    ($000s)                 & Liquids          Gas        Total        Total
    -------------------------------------------------------------------------
    Realized cash gain
     (loss) on contracts(1)   (12,046)      (4,715)     (16,761)       3,026
    Unrealized gain (loss)
     on contracts(2)          (13,802)     (29,435)     (43,237)       3,488
    -------------------------------------------------------------------------
    Total gain (loss) on
     commodity contracts      (25,848)     (34,150)     (59,998)       6,514
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes the crude oil and natural gas commodity contract premium
        expenses in the 2007 period and the amortization of prior year crude
        oil and natural gas commodity contract premiums of a total
        $1.0 million and $3.4 million, respectively, for the three and
        six months ended June 30, 2007.
    (2) Unrealized gain (loss) commodity contracts represent non-cash
        adjustments for changes in the fair value of these contracts during
        the period.
    

    Royalties

    For the three months ended June 30, 2008, total royalties were
$16.3 million, compared to $9.8 million incurred in the same period in 2007.
Overall royalties as a percentage of revenue (after transportation costs) in
the second quarter of 2008 were 21%, compared with 14% in the same period in
2007. Royalties for the 2007 second quarter included the impact of the
reversal of certain over accruals of light and heavy crude oil royalties from
periods prior to 2007 of approximately $5.3 million; excluding that
adjustment, the average royalty rate for the second quarter of 2007 would have
been 22%. Royalties for the six months ended June 30, 2008 were $31.8 million
compared to $24.7 million for the same period in 2007.

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

    Royalties by
     Commodity Type
    ($000s, except      Three months ended June 30, Six months ended June 30,
     where noted)                2008         2007         2008         2007
    -------------------------------------------------------------------------
    Light crude oil,
     condensate and NGLs        2,897        3,657        6,663        4,537
      $/bbl                     21.98        16.15        21.12        10.88
      Average light crude
       oil, condensate and
       NGLs royalty rate (%)       20           26           23           19

    Heavy Oil                   5,341        1,416        7,632        2,936
      $/bbl                     21.57         5.08        15.12         4.38
      Average heavy oil
       royalty rate (%)            23           13           20           12

    Natural Gas                 8,051        4,728       17,494       17,222
      $/mcf                      1.90         0.74         1.95         1.35
      Average natural gas
       royalty rate (%)            20           10           22           18

    -------------------------------------------------------------------------
                     Total     16,289        9,801       31,789       24,695
    -------------------------------------------------------------------------
                     $/boe      15.01         6.29        13.71         7.67
    -------------------------------------------------------------------------
             Average total
          royalty rate (%)         21           14           22           17
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Royalties, by Type
    -------------------------------------------------------------------------
                        Three months ended June 30, Six months ended June 30,
    ($000s)                      2008         2007         2008         2007
    -------------------------------------------------------------------------
    Crown royalties             9,587        6,229       18,543       13,234
    Indian Oil and Gas
     Canada royalties           1,854          762        3,535        3,311
    Freehold & GORR             4,848        2,810        9,711        8,150
    -------------------------------------------------------------------------
    Total                      16,289        9,801       31,789       24,695
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Expenses
    -------------------------------------------------------------------------
                        Three months ended June 30, Six months ended June 30,
    ($000s)                      2008         2007         2008         2007
    -------------------------------------------------------------------------
    Production                 16,170       19,778       33,166       34,750
    Transportation              2,478        2,431        3,321        3,120
    General and
     administrative             4,492        4,332        8,262        9,236
    Interest and
     financing charges          3,487        4,573        8,003        9,120
    Unit-based compensation       160        1,275          429        2,387
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Expenses per boe
    -------------------------------------------------------------------------
                        Three months ended June 30, Six months ended June 30,
    ($ per boe)                  2008         2007         2008         2007
    -------------------------------------------------------------------------
    Production                  14.90        12.69        14.31        10.79
    Transportation               2.28         1.56         1.43         0.97
    General and
     administrative              4.14         2.78         3.56         2.87
    Interest and
     financing charges           3.21         2.93         3.45         2.83
    Unit-based compensation      0.15         0.82         0.19         0.74
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    


    Production Expenses

    For the three months ended June 30, 2008, production expenses totaled
$16.2 million, compared to $19.8 million recorded in the same period in 2007.
During the second quarter of 2008, production expenses averaged $14.90/boe,
compared to $12.69/boe over the same period in 2007. Production expenses are
increased as additional natural gas input costs are required to operate the
Kerrobert SAGD facility after startup in late 2007; this adds approximately
$2.80/boe to production expenses in the second quarter of 2008. The increase
in 2008 costs on a boe basis was also due to a significant fixed component of
production expenses in combination with substantially reduced production
volumes. For the six months ended June 30, 2008, production expenses totaled
$33.2 million, compared to $34.8 million for the same period in 2007.

    
    Production Expenses, by Commodity Type
    -------------------------------------------------------------------------

    ($000s, except     Three months ended June 30, Six months ended June 30,
     where noted)                2008         2007         2008         2007
    -------------------------------------------------------------------------
    Light crude oil,
     condensate and NGLs        2,193        2,251        5,274        4,768
    $/bbl                       16.64         9.94        16.71        11.43

    Heavy oil                   5,808        5,612       10,843       11,017
    $/bbl                       23.45        20.17        21.49        16.44

    Natural gas                 8,169       11,915       17,049       18,965
    $/mcf                        1.93         1.89         1.90         1.48

    -------------------------------------------------------------------------
    Total                      16,170       19,778       33,166       34,750
    -------------------------------------------------------------------------
    $/boe                       14.90        12.69        14.31        10.79
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Total                      16,170       19,778       33,166       34,750
    -------------------------------------------------------------------------
    Processing and other
     third party income(1)       (871)      (1,247)      (1,458)      (1,424)
    -------------------------------------------------------------------------
    Total after deducting
     processing and other
     third party income        15,299       18,531       31,708       33,326
    -------------------------------------------------------------------------
    $/boe                       14.10        11.90        13.68        10.35
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Processing and other third party income is included within petroleum
        and natural gas sales on the statement of income.
    

    Transportation

    Transportation expenses are expected to be approximately 2% to 3% of
gross revenues for the 2008 year. For the three and six months ended June 30,
2008, transportation expenses averaged approximately 3% and 2%, respectively.
Higher transportation expenses on a percentage basis in the second quarter of
2008, as compared to the first quarter of 2008, reflect certain accrual
revisions in respective periods.

    Operating Netback

    For the second quarter of 2008, corporate field operating netback (before
hedging) was $42.66/boe compared to $26.79/boe in the same period in 2007.
This was the result of increased overall commodity prices, partially offset by
higher royalties and operating costs experienced in the 2008 period. By
comparison, corporate field operating netback (before hedging) for the first
quarter of 2008 was $29.28/boe. After including hedging activities, the
corporate field operating netback for the second quarter of 2008 was
$31.01/boe compared to $26.71/boe in the same period in 2007.

    
    Field Operating Netback - Corporate (before hedging)
    -------------------------------------------------------------------------
                        Three months ended June 30, Six months ended June 30,
    ($/boe)                      2008         2007         2008         2007
    -------------------------------------------------------------------------
    Sales                       74.85        47.33        64.99        44.96
    Transportation              (2.28)       (1.56)       (1.43)       (0.97)
    Royalties                  (15.01)       (6.29)      (13.71)       (7.67)
    Production expense         (14.90)      (12.69)      (14.31)      (10.79)
    -------------------------------------------------------------------------
    Field operating netback     42.66        26.79        35.54        25.53
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Field operating netback for natural gas for the second quarter of 2008
increased 23% to $5.77/mcf, compared to $4.68/mcf for the same period in 2007,
reflecting stronger natural gas prices experienced, the effects of which were
partially offset by higher royalties and production expenses. After including
hedging activities, field operating netback for natural gas for the second
quarter of 2008 was $4.62/mcf compared to $4.73/mcf in the same period in
2007.

    Field Operating Netback - Natural Gas (before hedging)
    -------------------------------------------------------------------------
                        Three months ended June 30, Six months ended June 30,
    ($/mcf)                      2008         2007         2008         2007
    -------------------------------------------------------------------------
    Sales                        9.94         7.60         8.90         7.43
    Transportation              (0.34)       (0.29)       (0.11)       (0.22)
    Royalties                   (1.90)       (0.74)       (1.95)       (1.35)
    Production expense          (1.93)       (1.89)       (1.90)       (1.48)
    -------------------------------------------------------------------------
    Field operating netback      5.77         4.68         4.94         4.38
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Field operating netback for crude oil, condensate and NGLs averaged
$57.65/bbl for the second quarter of 2008, up 140% compared to $24.03/bbl for
the same period in 2007. This compares to a 103% increase in the crude oil,
condensate and NGLs sales price combined with a lower corresponding increase
in overall expenses over the same period. After including hedging activities,
field operating netback for crude oil and NGLs for the second quarter of 2008
was $37.08/boe compared to $23.27/boe in the same period in 2007.

    Field Operating Netback - Crude Oil, Condensate  and NGLs (before
    hedging)
    -------------------------------------------------------------------------
                        Three months ended June 30, Six months ended June 30,
    ($/bbl)                      2008         2007         2008         2007
    -------------------------------------------------------------------------
    Sales                      103.14        50.90        86.19        45.74
    Transportation              (2.69)       (1.23)       (2.83)       (0.30)
    Royalties                  (21.71)      (10.06)      (17.43)       (6.87)
    Production expense         (21.09)      (15.58)      (19.65)      (14.52)
    -------------------------------------------------------------------------
    Field operating netback     57.65        24.03        46.28        24.05
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    


    General and Administrative

    Net general and administrative ("G&A") expenses for the three and six
months ended June 30, 2008 were $4.5 million and $8.3 million, respectively,
compared to $4.3 million and $9.2 million, respectively, for the same period
in 2007. The decrease in the G&A expense for the six month period ended
June 30, 2008 from the same period in 2007 reflects a reduction of the number
of salaried personnel on staff and other efforts to reduce costs. The
reduction in amounts of capitalized G&A for 2008 is consistent with a lower
capital program. On a per boe basis, G&A expenses for the three and six months
ended June 30, 2008 were $4.14/boe and $3.56/boe, respectively compared to
$2.78/boe and $2.87/boe, respectively for the same period in 2007. The
increase in G&A on a per boe basis is consistent with reduced sales volumes
experienced in the first and second quarters of 2008 compared to 2007.

    
    General and Administrative Expenses
    -------------------------------------------------------------------------

    ($000s, except     Three months ended June 30, Six months ended June 30,
     where noted)                2008         2007         2008         2007
    -------------------------------------------------------------------------
    Gross expenses              5,508        5,872       10,387       12,282
    Capitalized                  (692)      (1,121)      (1,199)      (1,814)
    Recoveries                   (324)        (419)        (926)      (1,232)
    -------------------------------------------------------------------------
    Net expenses                4,492        4,332        8,262        9,236
    -------------------------------------------------------------------------
    Net expenses,
     per unit ($/boe)            4.14         2.78         3.56         2.87
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Interest and Financing Charges

    True recorded $3.5 million of interest and financing charges for the three
months ended June 30, 2008 compared to $4.6 million in the same period in
2007. For the six months ended June 30, 2008, interest and financing charges
totaled $8.0 million compared to $9.1 million for the same period in 2007.
True's net debt at June 30, 2008 of $189.4 million includes the $80.3 million
liability portion of convertible debentures, $125.5 million of bank debt and
the net balance of working capital.

    Interest and Financing Charges
    -------------------------------------------------------------------------

    ($000s, except     Three months ended June 30, Six months ended June 30,
     where noted)                2008         2007         2008         2007
    -------------------------------------------------------------------------
    Interest and financing
     charges                    3,487        4,573        8,003        9,120
    Interest and financing
     charges ($/boe)             3.21         2.93         3.45         2.83

    Net debt(1) including
     convertible debentures
     at quarter end           189,354      221,045      189,354      221,045
    Debt to periods funds
     flow from operations
     ratio annualized(2)         1.8x         1.6x         1.9x         1.7x

    Net debt excluding
     convertible debentures
     at quarter end           109,101      142,409      109,101      142,409
    Debt to periods funds
     flow from operations
     ratio annualized(2)         1.1x         1.0x         1.1x         1.1x
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Net debt includes the net working capital deficiency (excess) before
        short-term commodity contract assets and liabilities and short-term
        future tax assets. Total net debt also includes the liability
        component of convertible debentures and excludes asset retirement
        obligations and the future income tax liability.
    (2) Debt to funds flow from operations ratio is calculated based upon
        annualizing of funds flow from operations for the three and six month
        periods ended June 30, 2008, respectively.
    

    Unit-Based Compensation

    Non-cash unit-based compensation expense for the three and six month
period ended June 30, 2008 was $0.2 million and $0.4 million, respectively,
compared to $1.3 million and $2.4 million in 2007, respectively. The decrease
in the expense for the six months ended June 30, 2008 reflects a reduction in
the estimated weighted average fair value of incentive rights granted for more
recent options, a reduction to the 2008 expense of $0.4 million for a reversal
of prior year unit-based compensation expense for 2008 forfeitures of unvested
incentive rights and reduced incentive rights being granted in 2008 compared
to the 2007 period.

    Capital Expenditures

    True invested $3.7 million on exploration and development activities
during the second quarter of 2008, compared to $15.5 million in the same
period in 2007. For the six months ended June 30, 2008, the Trust invested
$12.1 million on exploration and development activities compared to
$60.8 million for the same period in 2007.
    During the second quarter of 2008, True participated in 1 (0.4 net)
successful working interest natural gas well.

    
    Capital Expenditures(1)
    -------------------------------------------------------------------------
                        Three months ended June 30, Six months ended June 30,
    ($000s)                      2008         2007         2008         2007
    -------------------------------------------------------------------------
    Lease acquisitions
     and retention                415          711          965        1,502
    Geological and geophysical    (55)      (3,455)          12        3,464
    Drilling and completion
     costs                      2,560       15,274        9,504       48,345
    Facilities and equipment      734        2,586        1,626        7,458
    -------------------------------------------------------------------------
      Exploration and
       development              3,654       15,116       12,107       60,769
    Corporate and property
     acquisitions                 426          649          623        1,354
    -------------------------------------------------------------------------
      Total capital
       expenditures - cash      4,080       15,765       12,730       62,123
    Property dispositions
     - cash                   (38,530)      (9,026)     (44,318)     (27,469)
    -------------------------------------------------------------------------
      Total net capital
       expenditures - cash    (34,450)       6,739      (31,588)      34,654
    -------------------------------------------------------------------------
    Other - non-cash(2)        (2,521)         311       (2,714)        (313)
    -------------------------------------------------------------------------
      Total capital
       expenditures           (36,971)       7,050      (34,302)      34,341
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Excludes capitalized costs related to asset retirement obligation
        expenditures incurred during the year.
    (2) Other includes current period's asset retirement obligations and unit
        based compensation capitalized
    

    The $12.7 million capital program for the first six months of 2008 was
financed entirely with funds flow from operations compared to 81% in the same
period in 2007.
    True plans to continue to take a balanced approach to the priority use of
cash flow between level of distributions and size of its 2008 capital program.
True's 2008 capital expenditure program is currently planned at $40 to
$45 million. True plans to focus on increasing its farm-out activity in
non-core areas and may look to increase its capital spending in the latter
part of 2008 dependant upon available cash flow.
    True holds an extensive land base. At June 30, 2008, True had
approximately 399,661 net undeveloped acres of land of its total developed and
undeveloped net acreage position of 705,524 net acres in Saskatchewan,
Alberta, and British Columbia.
    Dispositions during the second quarter of 2008 consisted principally of
the divestiture of the Dodsland-Stranrear property in Saskatchewan for net
proceeds after adjustments and closing costs of $38.5 million. Combined with
the sale of the Thorhild property in Northern Alberta which closed at the end
of the first quarter of 2008 for net proceeds of $5.8 million, after closing
adjustments and costs, and other minor property dispositions, total net
proceeds on sale of properties for the first six months of 2008 were
$44.3 million.
    At the end of the second quarter of 2008, the Trust had committed to
drill a total of 2 wells in Alberta 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. These wells were drilled in July 2008.

    Depletion, Depreciation and Accretion

    Depletion, depreciation and accretion expense for the second quarter of
2008 was $33.2 million ($30.61/boe), compared to the $45.3 million
($29.11/boe) in the same period of 2007, which reflects lower production
volumes combined with reduced carrying costs in the 2008 period as compared to
2007.
    For the three month period ended June 30, 2008, True has included
$53.5 million for future development costs in the depletion calculation and
excluded from the depletion calculation $34.7 million for undeveloped land and
$43.5 million for estimated salvage.

    
    Depletion, Depreciation and Accretion Costs
    -------------------------------------------------------------------------

    ($000s, except     Three months ended June 30, Six months ended June 30,
     where noted)                2008         2007         2008         2007
    -------------------------------------------------------------------------
    Depletion and
     Depreciation              32,696       44,822       68,444       91,769
    Accretion                     513          527        1,068        1,038
    -------------------------------------------------------------------------
      Total                    33,209       45,349       69,512       92,807
    -------------------------------------------------------------------------
    Per unit ($/boe)            30.61        29.11        29.99        28.33
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Ceiling Test

    The Trust calculates a ceiling test quarterly and annually to place a
limit on the aggregate carrying value of its capitalized costs, which may be
amortized against revenues of future periods. 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 June 30, 2008 resulting
in undiscounted cash flows from proved reserves and the undeveloped properties
exceeding the carrying value of oil and gas assets. Consequently, no
impairment in oil and gas assets was identified as at June 30, 2008.
    The ceiling test calculation will be updated during the remainder of 2008
on a quarterly and annual basis based upon the latest available data,
including but not limited to an updated annual external reserve engineering
report which incorporates a full evaluation of reserves or internal reserve
updates at quarterly periods, 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.

    Asset Retirement Obligations

    As at June 30, 2008, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $26.3 million, compared to $27.1 million at June 30,
2007, for future abandonment and reclamation of the Trust's properties. For
the six months ended June 30, 2008, the ARO decreased by $2.0 million total as
a result of accretion expense of $1.1 million, and $0.04 million net changes
in estimates and liabilities incurred on development activities, offset by
$2.4 million of liabilities released on dispositions and $0.7 million of
liabilities settled during the year.

    Income Taxes

    For the six months ended June 30, 2008, the Trust has recorded capital
tax expense of $1.1 million compared to $1.1 million expensed in the same
period of 2007. 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.
    Future income taxes arise from differences between the accounting and tax
bases of the Trust's assets and liabilities. For the six months ended June 30,
2008, the Trust recognized a future income tax recovery of $23.3 million
compared to a recovery of $21.5 million in the same period in 2007.
    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 SIFT legislation (as referred to below), 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.
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 SIFT 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 a 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 SIFT 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.
    In June 2008, Bill C-50, which contains legislation to adjust the deemed
provincial component on the tax rate on distributions from income and royalty
trusts expected to apply to the Trust commencing in 2011, passed third reading
in the House of Commons. Under this legislation, instead of basing the
provincial component of the SIFT tax on a flat rate of 13%, the provincial
component will instead be based on the general provincial corporate income tax
rate in each province in which the SIFT has a permanent establishment. For
purposes of calculating this component of the tax, the general corporate
taxable income allocation formula will be used. Specifically, the Trust's
taxable distributions will be allocated to provinces by taking half of the
aggregate of:
    
      -  that proportion of the Trust's taxable distributions for the year
         that the Trust's wages and salaries in the province are of its total
         wages and salaries in Canada; and
      -  that proportion of the Trust's taxable distributions for the year
         that the Trust's gross revenues in the province are of its total
         gross revenues in Canada.
    

    Under the Bill C-50 legislation, the Trust would be considered to have a
permanent establishment only in Alberta, where the provincial tax rate in 2011
is expected to be 10%. For accounting purposes, however, the adjustment to the
provincial component of the tax is not considered substantively enacted as the
income tax regulations for the adjustment have not been finalized. If the
proposal becomes enacted, we expect to record a future income tax recovery
based on temporary differences at that time.
    On July 14, 2008, the Department of Finance released proposed amendments
(the "Conversion Rules") to the Income Tax Act (Canada) to facilitate the
conversion of existing income trusts into corporations. In general, the
proposed amendments will permit a conversion to be tax deferred for both the
unitholders and the income trust. However, the Conversion Rules provide
alternative approaches to completing a tax deferred conversion. The Department
of Finance has requested comments on the Conversion Rules by September 15,
2008, which may result in amendments to the Conversion Rules. We expect future
technical interpretations and details will further clarify the legislation.
    The True Board of Directors and Management continue to review the impact
of this tax on business strategy as well as the Conversion Rules in
considering alternatives available. 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
         distribution yield net of the SIFT tax in 2011 and beyond to taxable
         Canadian investors will remain approximately the same; however, the
         distribution yield to tax-deferred Canadian investors (RRSPs, RRIFs,
         pension plans, etc.) would fall by an estimated 26.5 percent in 2011
         and 25.0 percent in 2012 and beyond. For U.S. investors, the
         distribution yield net of the SIFT and withholding taxes would fall
         by an estimated 25.3 percent in 2011 and 25.1 percent in 2012 and
         beyond;
      -  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.
    

    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.
    As at June 30, 2008, the operating subsidiaries and the Trust itself have
a total net future income tax liability balance of $41.0 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 June 30, 2008, the Trust and operating subsidiaries of the Trust had
approximately $469 million in tax pools available for deduction against future
income as follows:

    
    -------------------------------------------------------------------------
                                                      Operating
    ($000s)                                  Trust subsidiaries        Total
    -------------------------------------------------------------------------
    Intangible resource pools               15,000      296,000      311,000
    Undepreciated capital cost                   -      138,000      138,000
    Loss carryforwards (expire through 2027)     -       14,000       14,000
    Unit issue costs                         3,000        3,000        6,000
    -------------------------------------------------------------------------
                                            18,000      451,000      469,000
    -------------------------------------------------------------------------

    Distributions

    Trust unitholders who held their trust units throughout the first six
months of 2008 received distributions of $0.24 per unit. For the six months
ended June 30, 2008 the Trust declared distributions as follows:

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

    ($000s, except per unit amount)                Distribution
    Six months ended June 30, 2008                     Per Unit        Total
    -------------------------------------------------------------------------

    Distributions declared                          $      0.24  $    19,012
    -------------------------------------------------------------------------


    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                               $     2.640  $     2.033  $     0.607
    -------------------------------------------------------------------------
    Cumulative to Dec. 31, 2006        $     3.120  $     2.489  $     0.631
    -------------------------------------------------------------------------
    2007 year                          $     0.960  $     0.960            -
    -------------------------------------------------------------------------
    Cumulative to Dec. 31, 2007        $     4.080  $     3.449  $     0.631
    -------------------------------------------------------------------------
    2008 year to date ( six months)(3) $     0.240
    -----------------------------------------------
    Cumulative to June 30, 2008        $     4.320
    -----------------------------------------------
    (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) It is currently estimated that the approximate taxable portion of
        2008 distributions to Canadian unitholders will be between 90 to
        100%. 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 from
        operations experienced throughout the year.

        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 2008 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 February 27, 2008 press release
        addressing this.

    Monthly Distributions

    Actual distributions paid and declared per trust unit along with relevant
payment dates for 2008 to date are as follows:

    -------------------------------------------------------------------------
                                                                Distribution
    Ex-distribution Date   Record Date          Payment Date        per unit
    -------------------------------------------------------------------------
    December 27, 2007      December 31, 2007    January 15, 2008    $ 0.08
    January 29, 2008       January 31, 2008     February 15, 2008     0.04
    February 27, 2008      February 29, 2008    March 17, 2008        0.04
    March 27, 2008         March 31, 2008       April 15, 2008        0.04
    April 28, 2008         April 30, 2008       May 15, 2008          0.04
    May 28, 2008           May 30, 2008         June 16, 2008         0.04
    June 26, 2008          June 30, 2008        July 15, 2008         0.04
    July 29, 2008          July 31, 2008        August 15, 2008       0.04
    August 27, 2008(1)     August 29, 2008      September 15, 2008    0.04(2)
    September 26, 2008(1)  September 30, 2008   October 15, 2008      0.04(2)
    -------------------------------------------------------------------------
    (1) Anticipated ex-distribution dates for August and September 2008.
        These dates are subject to change and/or confirmation by the Toronto
        Stock Exchange and will be confirmed by monthly press.

    (2) Subject to confirmation by the board of directors and based on True's
        current commodity prices, hedge positions, anticipated production
        volumes and market conditions and subject to change based an actual
        conditions.
    

    During 2008, to date distributions have been funded from funds flow from
operations.

    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
July 18, 2008 approximately 27 percent of unitholders are non-Canadian
residents with the remaining 73 percent being Canadian residents.

    Liquidity and Capital Resources

    True's net debt as at June 30, 2008 was $189.4 million, representing
$125.5 million outstanding on the credit facility, $80.3 million in
convertible debentures (liability component) and the net balance of working
capital. Our calculation of net debt includes the net working capital before
short-term commodity contract assets and liabilities and short-term future
income tax assets. Total net debt also includes the liability component of
convertible debentures and excludes asset retirement obligations and long-term
future income taxes.
    During the six month period ended June 30, 2008, the Trust has reduced
its net debt by approximately $61.8 million.
    Combined funding requirements for distributions declared and True's
capital expenditures represented 51.6% and 62.8% of funds flow from operations
in the three and six months ended June 30, 2008, respectively. The excess
funds flow from operations was applied to the repayment of net debt.
    As of June 30, 2008, the credit facility was renewed and consists of a
$15 million demand operating facility provided by one Canadian bank and a
$137 million extendible revolving credit facility syndicated by two Canadian
chartered banks, a Canadian financial institution, one institutional lender
and a U.S. bank. The revolving period on the revolving term credit facility
ends on June 26, 2009, unless extended for a further 364 day period. Should
the facilities not be renewed they convert to 366 day non-revolving facilities
on the renewal date. The borrowing base was renewed effective June 27, 2008
and is currently scheduled for renewal on September 30, 2008. Further details
of the credit facilities are disclosed in note 6 of the consolidated financial
statements. As at June 30, 2008, there was approximately $26.0 million, net of
$0.5 million of prepaid interest, not drawn under these facilities.
    The Trust does not hold any Asset-Backed Commercial Paper investments. As
a non-operating working interest owner, True has a minor exposure of
approximately $70,000 from oil sales marketed through SemCanada Crude Company,
which filed for CCAA protection on July 22, 2008.
    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 July 31, 2008, the Trust had outstanding a total of 2,670,499
incentive units exercisable at an average exercise price of $4.43 per unit,
373,311 exchangeable shares (convertible, as at July 31, 2008 into an
aggregate of 349,960 trust units, subject to further adjustments based on
distributions made on trust units), $86.25 million principal amount of
debentures convertible into trust units (at a conversion price of $16.00 per
trust unit) and 79,031,932 trust units.

    Commitments

    As at June 30, 2008, the Trust had committed to drill a total of 2 wells
in Alberta pursuant to various farm-in agreements with oil and gas companies.
True expects to satisfy these various drilling commitments at an estimated
cost of approximately $2.8 million. These wells were drilled in July 2008.

    Off-Balance Sheet Arrangements

    The Trust has certain lease agreements, including primarily office space
leases, which were entered into in the normal course of operations. All leases
have been treated as operating leases whereby the lease payments are included
in operating expenses or G&A expenses depending on the nature of the lease. No
asset or liability value has been assigned to these leases in the balance
sheet as of June 30, 2008.

    Business Prospects and 2008 Outlook

    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.
    True has budgeted the US$/Cdn.$ exchange rate to average 1.00 through the
2008 year.
    The Trust continues to maintain a large undeveloped land base of
approximately 635,541 (399,361 net) acres containing a significant multi-year
drilling inventory.
    True's capital program for the first six months of 2008 of approximately
$12.7 million compares to a front end loaded 2007 capital program of
approximately $62.1 million in first and second quarters of 2007. True plans
to continue to take a balanced approach to the priority use of cash flow
between level of distributions and size of its 2008 capital program. True's
2008 capital expenditure program is currently planned at $40 to $45 million.
True plans to focus on increasing its farm-out activity in non-core areas and
may look to increase its capital spending in the latter part of 2008 dependant
upon available cash flow.
    True's planned second half drilling program is underway with 4 gross
(2.9 net) gas wells drilled thus far in the third quarter of 2008. A further
25 net wells are planned through the remainder of the year including at least
3 horizontal Viking light oil wells in the Kindersley area, 1.5 vertical heavy
oil wells at Mantario, and 18.5 natural gas wells in Alberta. A further 2
exploration wells are also scheduled.
    Full year 2008 field production guidance remains at 12,000 to
12,500 boe/d.

    Financial Reporting Update

    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. Refer to note 15 of the financial statements for additional
disclosure for this new section.

    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. The additional disclosures required under
these sections are included in note 15 of the financial statements.

    Goodwill and intangible assets

    In February 2008, the CICA issued a new accounting standard, Section 3064
- Goodwill and Intangible Assets, which replaces Section 3062 - Goodwill and
Other Intangible Assets, and Section 3450 - Research and Development costs.
The new section establishes standards for the recognition, measurement and
disclosure of goodwill and intangible assets. The section is effective for the
Trust beginning January 1, 2009. Application of the new section is not
currently expected to have any impact on the Trust's financial statements.

    International Financial Reporting Standards ("IFRS")

    On February 13, 2008 the CICA Accounting Standards Board announced that
Canadian public reporting issuers will be required to report under
International Financial Reporting Standards ("IFRS"), which will replace
Canadian generally accepted accounting principles ("GAAP") for years beginning
on or after January 1, 2011. True is monitoring industry discussion regarding
the replacement of the CICA's Accounting Guideline 16, which is expected to
have major implications for True's current full cost accounting policies.
Currently, we are assessing the effects of adoption and developing a plan
accordingly. We will continue to monitor any changes in the adoption of IFRS
and will update plans as necessary.

    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 for the year ended December 31, 2007 or the Trust's Annual
Information Form. In addition, the Trust is also subject to the following
business risks and uncertainties:

    Environmental Regulations and Risks

    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. The Federal
government has introduced legislation aimed at reducing greenhouse gas
emissions using a "intensity based" approach, the specifics of which have yet
to be determined. Bill C-288, which is intended to ensure that Canada meets
its global climate change obligations under the Kyoto Protocol, was passed by
the House of Commons on February 14, 2007. 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.
    In January 24, 2008, the Alberta Government announced a new climate
change action plan that will cut Alberta's projected 400 million tonnes of
emissions in half by 2050. This plan is based on three areas: (i) carbon
capture and storage, which will be mandatory for in situ oil sand facilities
that use heavy fuels for steam generation; (ii) energy conservation and
efficiency; and (iii) greening production through increased investment in
clean energy technology, including supporting research on new oil sands
extraction processes, as well as the funding of projects that reduce the cost
of separating CO(2) from other emissions supporting carbon capture and
storage.
    The Government of Canada and the Province of Alberta released on
January 31, 2008 the final report of the Canada-Alberta ecoENERGY Carbon
Capture and Storage Task Force, which recommends among others: (i)
incorporating carbon capture and storage into Canada's clean air regulations;
(ii) allocating new funding into projects through competitive process; and
targeting research to lower the cost of technology.
    On March 10, 2008, the Government of Canada released "Turning the Corner
- Taking Action to Fight Climate Change" (the "Updated Action Plan") which
provides some additional guidance with respect to the Government's plan to
reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050.
Details of the Updated Action Plan are provided in the Trust's Annual
Information Form for the year ended December 31, 2007.
    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.

    Alberta Royalty Regime

    On October 25, 2007, the Alberta Government announced its intent to
increase royalty rates commencing on January 1, 2009. As of December 31, 2007,
the province had not introduced the enabling legislation nor had they provided
enough clarity on a number of issues for the Trust's independent reserves
evaluator, GLJ Petroleum Consultants Ltd. ("GLJ"), to provide a precise
calculation of the net reserves and NPV under the New Royalty Framework
("NRF"). However, GLJ did provide analysis of the proposed royalty regime,
based on a high and low sensitivity to the NRF utilizing the Consultants'
Consensus Methodology recommended by the Society of Petroleum Engineers,
Calgary Chapter (the "Consensus Methodology"). Based on public information
available when the Trust's reserves were evaluated, the net present value of
future net revenue of proved and probable reserves based on the high scenario
at a 10% discount rate using the Consultants' Average Forecast Prices would be
$8.9 million or 1.5 percent higher and $1.9 million or 0.33% percent higher
based on the NRF for the low scenario, in each case, as compared to the
existing royalty rules. The proposed royalty changes are very sensitive to
production rate and natural gas prices.
    Since the foregoing sensitivity was prepared, the Alberta Government has
announced new royalty incentives for deep, high-cost drilling. The incentives
will apply to oil exploration wells and to both development and exploration
gas wells. This initiative provides some relief to the recently introduced
NRF. On the oil side, a royalty credit of up to $1 million will pertain to
exploration wells drilled below 2,000m. Gas wells drilled below 2,500m qualify
for credits with no distinction for development versus exploration wells
drilled from 2,500m-4,000m. Overall, the deep royalty credits are a modest
positive for the industry with a more significant impact for producers that
target deep and prolific gas wells at a depth greater than 4,000m. The impact
of these new incentives is not expected to be significant to True.
    The majority of True's current Alberta wells are in the 500m to 1,000m
depth range and typically produce at lower rates. The overall impact of the
NRF, as currently announced, is mitigated by the Trust's current Saskatchewan
properties and the lower shallow gas Alberta natural gas rate royalty
production in True's Alberta conventional oil and gas production portfolio.
The NRF will impact future drilling decisions in order for the Trust to
maintain acceptable rates of return on its capital deployed.

    Critical Accounting Estimates

    The reader is advised that the critical accounting estimates, policies,
and practices as described in the Management Discussion and Analysis for the
year ended December 31, 2007 continue to be critical in determining True's
unaudited financial results as at June 30, 2008. Except as described in note 3
of the attached unaudited interim consolidated financial statement, there were
no changes in accounting policies for the six month period ended June 30, 2008

    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 known 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 June 30, 2008, 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 revised and re-issued in July 2007
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 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 and NP 41-201.

    
                        Three months ended June 30, Six months ended June 30,
    ($000s, except per
     unit amounts and
     percentages)                2008         2007         2008         2007
    -------------------------------------------------------------------------

    Net income (loss)         (21,374)       1,741      (39,995)      (6,830)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash flow from
     operating activities      19,892        4,402       37,735       44,361
    Productive capacity
     maintenance(1)            (3,654)     (15,116)     (12,107)     (60,769)
    -------------------------------------------------------------------------
    Standardized
     distributable cash        16,238      (10,714)      25,628      (16,408)
    Proceeds on sale of
     property, plant and
     equipment                 38,530        9,026       44,318       27,469
    Corporate and property
     acquisition and other
     capital expenditures        (426)        (649)        (623)      (1,354)
    Net proceeds from issue
     of trust units                 -       54,386            -       54,386
    Repurchase of trust
     units under normal
     course issuer bid           (596)           -         (596)           -
    Bank borrowings (debt
     repayment) and working
     capital changes and
     other                    (44,241)     (33,673)     (49,715)     (28,851)
    -------------------------------------------------------------------------
    Cash Distributions
     declared                   9,505       18,376       19,012       35,242
    Accumulated distributions,
     beginning of period      224,674      158,582      215,167      141,716
    -------------------------------------------------------------------------
    Accumulated distributions,
     end of period            234,179      176,958      234,179      176,958
    -------------------------------------------------------------------------
    Standardized
     distributable cash
     per unit - basic     $      0.21  $     (0.15) $      0.32  $     (0.24)
    Standardized
     distributable cash
     per unit - diluted   $      0.21  $     (0.15) $      0.32  $     (0.24)
    -------------------------------------------------------------------------
    Standardized
     distributable cash
     payout ratio(2)             0.59          N/A         0.74          N/A
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Distributions declared
     per unit for
     outstanding units
     in the period               0.12         0.24         0.24         0.48
    Accumulated
     distributions per
     unit, beginning of
     period                      4.20         3.36         4.08         3.12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Accumulated
     distributions per
     unit, end of period         4.32         3.60         4.32         3.60
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Excess (shortfall) of
     net income over cash
     distributions
     declared                 (30,879)     (16,635)     (59,007)     (42,072)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Excess of cash flow
     from operating
     activities over cash
     distributions
     declared                  10,387      (13,974)      18,723        9,119
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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 funds flow from operations. True's 2008 capital budget was initially set
at approximately 40% to 50% of annual funds 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 forecasted funds 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 with cash
flow from operating activities. Cash flow from operating actitivies, used in
our standardized distributable cash calculation, includes a deduction for
abandonment expenditures incurred in the year. 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 ratios)                                  To June 30, 2008
    -------------------------------------------------------------------------
    Cumulative distributable cash from operations(1)                  49,926
    Proceeds on sale of property, plant and equipment                100,640
    Corporate and property acquisitions and other capital
     expenditures                                                    (20,506)
    Net proceeds from issue of trust units                            54,375
    Proceeds from issue of convertible debentures, net of
     issue costs                                                      82,261
    Repurchase of trust units under normal course issuer bid          (2,254)
    Funding from DRIP                                                 42,909
    Bank borrowings (debt repayment) and working capital
     changes and other                                               (43,172)
    -------------------------------------------------------------------------
    Cumulative cash distributions declared(1)                        234,179
    -------------------------------------------------------------------------
    Standardized distributable cash payout ratio(2)                     4.70
    -------------------------------------------------------------------------
    (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 funds flow as a result of product
price and operational changes. This is based on actual average prices received
for the second quarter of 2008 and average production volumes of 11,922 boe/d
during that period, as well as the same level of debt outstanding at
June 30, 2008. Diluted weighted average trust units is based upon the second
quarter of 2008. 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 funds flow as
shown in the table below:

    
    -------------------------------------------------------------------------
                                                                       Funds
                                                                   Flow from
                                                Funds Flow from   Operations
                                                     Operations  Per Diluted
                                                    (annualized)        Unit
    -------------------------------------------------------------------------
    Sensitivity Analysis                                 ($000s)          ($)
    -------------------------------------------------------------------------
    Change of US $1/bbl WTI                               1,200         0.02
    Change of $0.10/mcf                                   1,400         0.02
    Change of US $0.01 Cdn/US exchange rate               1,200         0.02
    Change in prime of 1%                                 1,300         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

    -------------------------------------------------------------------------
    2008 - Quarter ended (unaudited)
    ($000s, except per unit
     amounts)                March 31      June 30
    -------------------------------------------------------------------------
    Revenues before
     royalties and hedging     70,033       82,074
    Funds flow from
     operations(1)             24,233       26,304
    Funds flow from
     operations per unit(1)
      Basic               $      0.31  $      0.33
      Diluted             $      0.30  $      0.33
    Net income (loss)         (18,621)     (21,374)
    Net income (loss) per
     unit
      Basic               $     (0.24) $     (0.27)
      Diluted             $     (0.24) $     (0.27)
    Net capital
     expenditures (cash)        2,862      (34,450)
    Distributions declared      9,507        9,505
    Distributions per
     unit                 $      0.12  $       0.12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    2007 - Quarter ended (unaudited)
    ($000s, except per unit
     amounts)                March 31      June 30     Sept. 30      Dec. 31
    -------------------------------------------------------------------------
    Revenues before
     royalties and hedging     71,196       74,991       50,547       61,756
    Funds flow from
     operations(1)             29,988       34,192       17,478       19,514
    Funds flow from
     operations per unit(1)
      Basic               $      0.43  $      0.47  $      0.22  $      0.25
      Diluted             $      0.42  $      0.45  $      0.22  $      0.25
    Net income (loss)          (8,571)       1,741      (17,003)        (434)
    Net income (loss) per
     unit
      Basic               $     (0.12) $      0.02  $     (0.21) $     (0.01)
      Diluted             $     (0.12) $      0.02  $     (0.21) $     (0.01)
    Net capital
     expenditures (cash)       27,915        6,739        7,612       14,828
    Distributions declared     16,866       18,376       19,132       19,077
    Distributions per
     unit                 $      0.24  $       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
    Funds flow from
     operations(1)             18,995       16,386       23,225       31,785
    Funds 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)       22,561       (7,080)      46,095       29,922
    Distributions declared     26,150       27,771       36,846       33,588
    Distributions per
     unit                 $      0.72  $      0.72  $      0.72  $      0.48
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) refer to "Non-GAAP Measures" in respect of the term "funds flow from
        operations" and "funds flow from operations per unit".



    TRUE ENERGY TRUST
    CONSOLIDATED BALANCE SHEETS

    As at June 30 and December 31 (unaudited)
    -------------------------------------------------------------------------

    ($000s)                                                2008         2007
    -------------------------------------------------------------------------

    ASSETS
    Current assets
      Accounts receivable                           $    53,579  $    48,522
      Marketable securities (note 4)                        850          850
      Deposits and prepaid expenses                       5,031        6,096
      Capital taxes recoverable                             391          626
      Commodity contract asset (note 15)                      -        1,061
      Future income taxes (note 12)                      16,084        3,116
                                                   --------------------------
                                                         75,935       60,271
    Property, plant and equipment (note 5)              717,948      819,981
                                                   --------------------------
    Total assets                                    $   793,883  $   880,252
                                                   --------------------------
                                                   --------------------------
    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities      $    40,326  $    52,188
      Distribution payable to unitholders                 3,168        6,337
      Commodity contract liability (note 15)             53,579       11,404
                                                   --------------------------
                                                         97,073       69,929
    Long-term debt (note 6)                             125,458      168,475
    Convertible debentures                               80,253       79,407
    Asset retirement obligations (note 7)                26,331       28,373
    Future income taxes (note 12)                        57,122       67,366
                                                   --------------------------
    Total liabilities                                   386,237      413,550
                                                   --------------------------

    NON-CONTROLLING INTEREST
      Exchangeable shares of subsidiary (note 8)          3,584        3,922

    UNITHOLDERS' EQUITY
      Unitholders' capital (note 9)                     924,158      925,573
       Equity component of convertible debentures         5,119        5,119
      Contributed surplus (note 10)                      21,158       19,454
      Deficit                                          (546,373)    (487,366)
                                                   --------------------------
    Total unitholders' equity                           404,062      462,780
                                                   --------------------------
    Total liabilities and unitholders' equity       $   793,883  $   880,252
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying selected notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

    For the three and six months ended June 30 (unaudited)

                        Three months ended June 30, Six months ended June 30,
    ($000s)                      2008         2007         2008         2007
    -------------------------------------------------------------------------

    REVENUES
      Petroleum and natural
       gas sales          $    82,074  $    74,991  $   152,107  $   146,187
      Royalties               (16,289)      (9,801)     (31,789)     (24,695)
      Gain (loss) on
       commodity contracts
       (note 15)              (38,169)       5,835      (59,998)       6,514
                         ----------------------------------------------------
                               27,616       71,025       60,320      128,006

    EXPENSES
      Production               16,170       19,778       33,166       34,750
      Transportation            2,478        2,431        3,321        3,120
      General and
       administrative           4,492        4,332        8,262        9,236
      Interest and financing
       charges                  3,487        4,573        8,003        9,120
      Unit-based compensation
       (notes 9 and 10)           160        1,275          429        2,387
      Depletion,
       depreciation and
       accretion               33,209       45,349       69,512       92,807
      Special meeting costs
       (note 13)                    -            -            -        3,805
                         ----------------------------------------------------
                               59,996       77,738      122,693      155,225

    LOSS BEFORE TAXES         (33,380)      (6,713)     (62,373)     (27,219)

    TAXES (note 12)
      Capital taxes               651          159        1,114        1,091
      Future income taxes
       (recovery)             (11,562)      (8,627)     (23,316)     (21,456)
                         ----------------------------------------------------
                              (10,911)      (8,468)     (22,202)     (20,365)

    NET INCOME (LOSS) BEFORE
     NON-CONTROLLING
     INTEREST                 (21,469)       1,755      (40,171)      (6,854)
      Non-controlling
       interest                   (95)          14         (176)         (24)
                         ----------------------------------------------------
                         ----------------------------------------------------

    NET INCOME (LOSS)         (21,374)       1,741      (39,995)      (6,830)
                         ----------------------------------------------------
    Net changes in cash
     flow hedges (net of
     tax of $0.2 million
     and $1.8 million,
     respectively)                  -         (409)           -       (3,565)
                         ----------------------------------------------------

    COMPREHENSIVE INCOME
     (LOSS)               $   (21,374) $     1,332  $   (39,995) $   (10,395)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net income (loss) per
     trust unit
      Basic               $     (0.27) $      0.02  $     (0.50) $     (0.10)
      Diluted             $     (0.27) $      0.02  $     (0.50) $     (0.09)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying selected notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY

    For the three and six months ended June 30 (unaudited)

                                Three months ended          Six months ended
                                           June 30,                  June 30,
    ($000s)                      2008         2007         2008         2007
    -------------------------------------------------------------------------

    UNITHOLDERS' CAPITAL
      Balance, beginning
       of period          $   925,735  $   876,920  $   925,573  $   876,904
      Issued for cash
       (net of issue costs
       of $3.1 million)             -       54,386            -       54,386
      Repurchased under
       normal course issuer
       bid                     (1,577)           -       (1,577)           -
      Exchangeable shares
       converted                    -           30          162           46
                         ----------------------------------------------------
      Balance, end of
       period                 924,158      931,336      924,158      931,336
                         ----------------------------------------------------

    EQUITY COMPONENT OF
     CONVERTIBLE DEBENTURES
                         ----------------------------------------------------
      Balance, beginning
       and end of period        5,119        5,119        5,119        5,119
                         ----------------------------------------------------

    CONTRIBUTED SURPLUS
      Balance, beginning
       of period               19,872       14,000       19,454       12,818
      Unit-based compensation
       expense (note 9 and 10)    562        1,407        1,165        2,589
      Reversal of prior
       year unit-based
       compensation expense
       for forfeitures of
       unvested incentive
       units                     (257)           -         (442)           -
      Adjustment for repurchase
       of units under
       normal course issuer
       bid                        981            -          981            -
                         ----------------------------------------------------
      Balance, end of
       period                  21,158       15,407       21,158       15,407
                         ----------------------------------------------------

    DEFICIT
      Balance, beginning of
       period                (515,494)    (415,085)    (487,366)    (389,745)
      Net income (loss)       (21,374)       1,741      (39,995)      (6,830)
      Impact of changes in
       accounting policy for
       financial instruments
       (net of tax of
       $0.05 million)(1)            -            -            -           97
      Distributions
       declared                (9,505)     (18,376)     (19,012)     (35,242)
                         ----------------------------------------------------
      Balance, end of
       period                (546,373)    (431,720)    (546,373)    (431,720)
                         ----------------------------------------------------

    ACCUMULATED OTHER
     COMPREHENSIVE INCOME
      Balance, beginning
       of period                    -          593            -            -
      Impact of new cash
       flow hedge accounting
       standards (net of tax
       of $1.8 million)(1)          -            -            -        3,749
      Reclassification to
       earnings of net
       hedging gains on
       commodity contracts
       (net of tax of
       $1.6 million)                -         (409)           -       (3,565)
                         ----------------------------------------------------
      Balance, end of
       period                       -          184            -          184
                         ----------------------------------------------------

    -------------------------------------------------------------------------
    TOTAL UNITHOLDERS'
     EQUITY               $   404,062  $   520,326  $   404,062  $   520,326
    -------------------------------------------------------------------------

    (1) Represents the January 1, 2007 transitional adjustments on adoption
        of the CICA handbook sections 1530, 3251, 3655 and 3865.

    See accompanying selected notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF CASH FLOWS

    For the three and six months ended June 30 (unaudited)

                                Three months ended          Six months ended
                                           June 30,                  June 30,
    ($000s)                      2008         2007         2008         2007
    -------------------------------------------------------------------------

    Cash provided by
     (used in):
    CASH FLOW FROM
     OPERATING ACTIVITIES
    Net income (loss)     $   (21,374) $     1,741  $   (39,995) $    (6,830)
    Items not involving
     cash:
      Non-controlling
       interest (note 8)          (95)          14         (176)         (24)
      Depletion, depreciation
       and accretion           33,209       45,349       69,512       92,807
      Unit-based compensation
       (notes 9 and 10)           160        1,275          429        2,387
      Unrealized loss
       (gain) on commodity
       contracts (note 15)     25,550       (5,953)      43,237       (3,488)
      Accretion on
       convertible
       debentures                 416          393          846          784
      Future income taxes
       (recovery) (note 12)   (11,562)      (8,627)     (23,316)     (21,456)
                         ----------------------------------------------------
                               26,304       34,192       50,537       64,180
      Asset retirement
       costs incurred            (123)        (387)        (712)        (575)
      Change in non-cash
       working capital
       (note 11)               (6,289)     (29,403)     (12,090)     (19,244)
                         ----------------------------------------------------
                               19,892        4,402       37,735       44,361

    CASH FLOW FROM (USED IN)
     FINANCING ACTIVITIES
      Increase (decrease)
       in bank debt           (46,392)     (36,226)     (43,017)     (14,731)
      Obligations under
       capital lease                -          (29)           -         (111)
      Issue of trust units
       for cash                     -       57,523            -       57,523
      Unit issue costs              -       (3,137)           -       (3,137)
      Repurchase of trust
       units under normal
       course issuer bid         (596)           -         (596)           -
      Distributions declared   (9,505)     (18,376)     (19,012)     (35,242)
                         ----------------------------------------------------
                              (56,493)        (245)     (62,625)       4,302
      Change in non-cash
       working capital
       (note 11)                   50        6,563       (3,110)      (1,813)
                         ----------------------------------------------------
                              (56,443)       6,318      (65,735)       2,489

    CASH FLOW FROM (USED IN)
     INVESTING ACTIVITIES
      Additions to property,
       plant and equipment     (4,080)     (15,765)     (12,730)     (62,123)
      Proceeds on sale of
       property, plant and
       equipment               38,530        9,026       44,318       27,469
                         ----------------------------------------------------
                               34,450       (6,739)      31,588      (34,654)
      Change in non-cash
       working capital
       (note 11)                2,101       (3,981)      (3,588)     (12,196)
                         ----------------------------------------------------
                               36,551      (10,720)      28,000      (46,850)

      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

    June 30, 2008 and 2007 (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. Pursuant to a Plan of Arrangement (the "TKE Arrangement")
        that became effective on November 2, 2005, 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. and its indirect wholly owned
        subsidiary True Energy Peru S.A.C. The Trust owns, directly and
        indirectly, 100% of the common shares, (excluding the exchangeable
        shares - see note 8) of True Energy Inc. and True Energy Peru S.A.C.
        The activities of True Energy Inc. are financed through interest
        bearing notes from the Trust and third party debt.

    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
        statement for the fiscal year ended December 31, 2007, 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 as at and for
        the year ended December 31, 2007.

        Certain prior period comparative figures have been restated to
        conform to the current year's presentation.

    3.  CHANGES IN ACCOUNTING POLICIES AND RECENT ACCOUNTING PRONOUNCEMENTS

        Effective January 1, 2008, the Trust adopted the following new
        accounting standards:

        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. Refer to
           note 15 for additional disclosure for this new section.

        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 replace Section 3861
           "Financial Instruments - Disclosure and Presentation" and are
           effective for the Trust beginning January 1, 2008. 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. The
           additional disclosures required under these sections are included
           in note 15.

        Goodwill and intangible assets

        In February 2008, the CICA issued a new accounting standard, Section
        3064 - Goodwill and Intangible Assets, which replaces Section 3062 -
        Goodwill and Other Intangible Assets, and Section 3450 - Research and
        Development costs. The new section establishes standards for the
        recognition, measurement and disclosure of goodwill and intangible
        assets. The section is effective for the Trust beginning
        January 1, 2009. Application of the new section is not currently
        expected to have any impact on the Trust's financial statements.

        International Financial Reporting Standards ("IFRS")

        On February 13, 2008 the CICA Accounting Standards Board announced
        that Canadian public reporting issuers will be required to report
        under International Financial Reporting Standards ("IFRS"), which
        will replace Canadian generally accepted accounting principles for
        years beginning on or after January 1, 2011. Currently, we are
        assessing the effects of adoption and developing a plan accordingly.
        We will continue to monitor any changes in the adoption of IFRS and
        will update plans as necessary.

    4.  MARKETABLE SECURITIES

        The Trust's investment in Veraz Petroleum Ltd. is classified as
        available-for-sale and has been recorded at fair value.

    5.  PROPERTY, PLANT AND EQUIPMENT

        ($000s)
        ---------------------------------------------------------------------
                                                  Accumulated
                                                depletion and       Net book
        June 30, 2008                     Cost   depreciation          value
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties               $  1,336,457   $    621,088   $    715,369
        Office furniture and
         equipment                       4,265          1,686          2,579
        ---------------------------------------------------------------------
                                  $  1,340,722   $    622,774   $    717,948
        ---------------------------------------------------------------------

        December 31, 2007
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties               $  1,370,219   $    552,899   $    817,320
        Office furniture and
         equipment                       4,092          1,431          2,661
        ---------------------------------------------------------------------
                                  $  1,374,311   $    554,330   $    819,981
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        The Trust has included $53.4 million (2007: $36.7 million) for future
        development costs and excluded $34.7 million (2007: $44.1 million)
        for undeveloped land and $43.5 million (2007: $48.3 million) for
        estimated salvage from the depletion calculation during the six month
        period ended June 30, 2008.

        For the six month period ended June 30, 2008, the Trust capitalized
        $1.2 million of general and administrative expenses and $0.4 million,
        including the future tax effect thereon of $0.1 million, of unit-
        based compensation expense directly related to exploration and
        development activities.

    6.  LONG-TERM DEBT

        As of June 30, 2008, the credit facility was renewed and consists of
        a $15 million demand operating facility provided by one Canadian bank
        and $137 million extendible revolving term credit facility syndicated
        by two Canadian chartered banks, a Canadian financial institution,
        one institutional lender and a U.S. bank. 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 0.10% and 2.05%, 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 0.150%
        and 0.400% on the undrawn portion of the facility, depending on the
        Trust's debt to cash flow ratio.

        As at June 30, 2008, there was $7.5 million outstanding under the
        operating facility and $118 million outstanding under the revolving
        term credit facility. As at June 30, 2008, there was approximately
        $26.0 million, net of $0.5 million of prepaid interest, not drawn
        under the existing facility.

        The revolving period on the new revolving term credit facility ends
        on June 26, 2009, 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 June 27, 2008 and is currently scheduled for
        renewal on September 30, 2008.

        Payment will not be required under the revolving term facility for
        more than 365 days from the balance sheet date and as at
        June 30, 2008 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.

    7.  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 $68.5 million which will be
        incurred between 2008 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)                                         June 30, December 31,
                                                           2008         2007
        ---------------------------------------------------------------------
        Asset retirement obligation, beginning of
         period                                     $    28,373  $    26,605
        Liabilities incurred on development
         activities                                          53          433
        Changes in prior period estimates                    (9)         960
        Liabilities released on dispositions             (2,442)        (927)
        Liabilities settled during the year                (712)        (835)
        Accretion expense                                 1,068        2,137
        ---------------------------------------------------------------------
        Asset retirement obligation, end of period  $    26,331  $    28,373
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    8.  EXCHANGEABLE SHARES OF SUBSIDIARY/NON-CONTROLLING INTEREST

        ---------------------------------------------------------------------
                                 June 30, 2008           December 31, 2007
                               Number       Amount       Number       Amount
                                            ($000s)                   ($000s)
        ---------------------------------------------------------------------
        Balance, beginning
         of period            390,276  $     3,922      403,536  $     4,153
        Non-controlling
         interest expense
         (recovery)                 -         (176)           -          (95)
        Exchanged for
         trust units          (16,177)        (162)     (13,260)        (136)
        ---------------------------------------------------------------------
        Balance, end of
         period               374,099  $     3,584      390,276  $     3,922
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The exchange ratio is calculated monthly based on the five day
        weighted average trust unit trading price preceding the monthly
        effective date and at June 30, 2008 was 0.92824. The exchangeable
        shares are not eligible for cash distributions; however cash
        distributions will increase the exchange ratio.

    9.  UNITHOLDERS' CAPITAL

        a. Trust Units

        ---------------------------------------------------------------------
                                     June 30, 2008         December 31, 2007
                               Number       Amount       Number       Amount
                                            ($000s)                   ($000s)
        ---------------------------------------------------------------------
        Balance,
         beginning
         of period         79,216,046  $   925,573   70,275,703  $   876,904
        Issued for cash
         (net of issue
         costs of
         $3.1 million)              -            -    9,430,000       54,375
        Repurchased under
         normal course
         issuer bid          (135,000)      (1,577)    (500,000)      (5,842)
        Exchangeable
         shares converted      14,414          162       10,343          136
        ---------------------------------------------------------------------
        Balance, end of
         period            79,095,460      924,158   79,216,046  $   925,573
        ---------------------------------------------------------------------

        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. 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.

        Incentive rights, entitling the holder to purchase units from the
        Trust, have been granted to directors, officers, employees and
        service providers of the Trust. One third of the initial grant of
        trust unit incentive rights normally 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 six month period ended June 30, 2008


        Unit Rights Continuity
        ---------------------------------------------------------------------
                                               Weighted Average
                                               Exercise Price(a)      Number
        ---------------------------------------------------------------------
        Balance, December 31, 2007                      $  9.18    5,931,997
        Granted                                         $  4.03      197,000
        Forfeited                                       $ 10.82   (1,122,918)
        ---------------------------------------------------------------------
        Balance, June 30, 2008                          $  8.30    5,006,079
        ---------------------------------------------------------------------
        (a) Exercise prices reflect grant prices less reduction in exercise
            prices.


    Unit Rights Outstanding, June 30, 2008
    -------------------------------------------------------------------------
                                 Outstanding                 Exercisable
                                        Weighted
                                         Average
                                        Exercise  Weighted
    Exercise                               Price   Average           Exercise
    Price         Exercise                Net of Remaining              Price
    Before           Price         At      Price   Contr-       At     Net of
    Price           Net of    June 30,     Redu-   actual  June 30,     Price
    Reductions  Reductions       2008     ctions     Life     2008 Reductions
    -------------------------------------------------------------------------
    $ 2.92      $ 2.71      2,647,332     $ 4.31    4.1    517,980     $5.29
     - $ 6.70    - $ 5.81
    $10.58      $ 8.95        692,414     $ 9.30    3.3    246,902     $9.29
     - $12.53    - $10.80
    $13.74      $11.43        438,833     $11.74    3.0    165,164    $11.76
     - $14.83    - $12.16
    $15.15      $13.05         52,500     $13.58    2.8     49,167    $13.55
     - $16.70    - $13.96
    $18.25      $14.95      1,175,000     $15.17    2.4  1,175,000    $15.17
     - $20.98    - $17.90
    -------------------------------------------------------------------------
    $ 2.92      $ 2.83      5,006,079     $ 8.30    3.5  2,154,213    $11.82
     - $20.98    - $17.90
    -------------------------------------------------------------------------

        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 six months ended June 30, 2008,
        the Trust matched $0.2 million under the plan.

        10. CONTRIBUTED SURPLUS

        ---------------------------------------------------------------------
                                                        June 30, December 31,
        ($000s)                                            2008         2007
        ---------------------------------------------------------------------
        Balance, beginning of period                   $ 19,454     $ 12,818
        Unit-based compensation expense                   1,165        4,249
        Reversal of prior year unit-based
         compensation expense for forfeitures
         of unvested incentive units                       (442)      (1,797)
        Adjustment for repurchase of units
         under NCIB                                         981        4,184
        ---------------------------------------------------------------------
        Balance, end of period                         $ 21,158     $ 19,454
        ---------------------------------------------------------------------

        Unit-based Compensation Expense

        During the six months ended June 30, 2008, the Trust granted 197,000
        unit incentive rights to employees. During the six months ended June
        30, 2008, the Trust recorded unit-based compensation of $1,165
        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 six month period ended June 30, 2008 and the assumptions used in
        their determination are as noted below:

        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Assumptions:
          Risk free interest rate (%)                                      3
          Expected life (years)                                            5
          Expected volatility (%)                                         26%
        ---------------------------------------------------------------------
        Results:
          Weighted average fair value of each incentive right
           granted                                               $      1.15
        ---------------------------------------------------------------------

        11. SUPPLEMENTAL CASH FLOW INFORMATION

        Cash Interest and Taxes Paid
        ---------------------------------------------------------------------
                                Three months ended          Six months ended
                                           June 30,                  June 30,
        ($000s)                  2008         2007         2008         2007
        ---------------------------------------------------------------------
        Cash paid:
          Interest        $     5,580  $     5,717  $     8,085  $     8,277
          Taxes (net of
           refunds)       $       246  $     1,206  $       531  $     3,214
        ---------------------------------------------------------------------


        Change in Non-cash Working Capital
        ---------------------------------------------------------------------
                                Three months ended          Six months ended
                                           June 30,                  June 30,
        ($000s)                  2008         2007         2008         2007
        ---------------------------------------------------------------------
        Changes in
         non-cash working
         capital items:
          Accounts
           receivable     $     4,122  $     5,576  $    (5,057) $    16,267
          Deposits and
           prepaid
           expenses             1,446          259        1,065        3,042
          Accounts
           payable and
           accrued
           liabilities         (9,935)     (37,986)     (11,862)     (47,904)
          Capital taxes
           recoverable            230       (1,047)         235       (2,602)
          Distribution
           payable to
           unitholders             (1)       6,377       (3,169)      (2,056)
        ---------------------------------------------------------------------
                          $    (4,138) $   (26,821) $   (18,788) $   (33,253)
        ---------------------------------------------------------------------

        Changes related
         to operating
         activities       $    (6,289) $   (29,403) $   (12,090) $   (19,244)
        Changes related
         to financing
         activities                50        6,563       (3,110)      (1,813)
        Changes related
         to investing
         activities             2,101       (3,981)      (3,588)     (12,196)
        ---------------------------------------------------------------------
                          $    (4,138) $   (26,821) $   (18,788) $   (33,253)
        ---------------------------------------------------------------------

        12. 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.

        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 June 30, 2008, the total "temporary
        difference" (tax basis exceeds accounting basis) in the Trust is
        $9.0 million. As at June 30, 2008, the Trust's subsidiaries have a
        tax basis of approximately $451 million that is available to shelter
        future taxable income. Included in this tax basis are estimated non-
        capital loss carry forwards of approximately $13.7 million that
        expire in years through 2027. In addition, the Trust itself has
        approximately $18.6 million of tax basis.

        As at June 30, 2008, a current future tax asset of $16.1 million has
        been recorded in respect of the unrealized commodity contract
        liability of $53.6 million.

        13. 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
        Reorganization was not completed. 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 six months ended June 30, 2007.

        14. PER TRUST UNIT AMOUNTS

        ---------------------------------------------------------------------
                                Three months ended          Six months ended
                                           June 30,                  June 30,
        ($000s)                  2008         2007         2008         2007
        ---------------------------------------------------------------------
        Basic trust units
         outstanding       79,095,460   79,709,119   79,095,460   79,709,119
        Dilutive effect of:
          Trust unit
           incentive
           rights
           outstanding      5,006,079    6,887,499    5,006,079    6,887,499
          Units issuable
           for
           exchangeable
           shares             347,254      309,216      347,254      309,216
          Units issuable
           for convertible
           debentures       5,390,625    5,390,625    5,390,625    5,390,625
        ---------------------------------------------------------------------
        Diluted
         trust units
         outstanding       89,839,418   92,296,459   89,839,418   92,296,459
        ---------------------------------------------------------------------
        Weighted average
         trust units
         outstanding       79,203,976   73,490,245   79,213,532   71,891,887
        Dilutive effect
         of exchangeable
         shares, trust
         unit incentive
         plan and
         convertible
         debentures(1)              -    2,320,716            -            -
        ---------------------------------------------------------------------
        Diluted weighted
         average trust
         units
         outstanding       79,203,976   75,810,961   79,213,532   71,891,887
        ---------------------------------------------------------------------
        (1) A total of 5,006,079 (2007: 4,875,999) trust incentive units,
            347,254 (2007: nil) exchangeable shares and 5,390,625 (2007:
            5,390,625) trust units issuable pursuant to the conversion of
            convertible debentures were excluded from the calculation for the
            three month period ended June 30, 2008 as they were not dilutive.
            A total of 5,006,079 (2007: 6,887,499) trust incentive
            units, 347,254 (2007: 309,216) exchangeable shares and 5,390,625
            (2007: 5,390,625) trust units issuable pursuant to the conversion
            of convertible debentures were excluded from the calculation for
            the six month period ended June 30, 2008 as they were not
            dilutive.

        15. FINANCIAL RISK MANAGEMENT

        a. Overview

        The Trust has exposure to the following risks from its use of
        financial instruments:
        -  Credit risk
        -  Liquidity risk
        -  Market risk

        This note presents information about the Trust's exposure to each of
        the above risks, the Trust's objectives, policies and processes for
        measuring and managing risk, and the Trust's management of capital.
        Further quantitative disclosures are included throughout these
        financial statements.

        The Board of Directors has overall responsibility for the
        establishment and oversight of the Trust's risk management framework.
        The Board has implemented and monitors compliance with risk
        management policies.

        The Trust risk management policies are established to identify and
        analyze the risks faced by the Trust, to set appropriate risk limits
        and controls, and to monitor risks and adherence to market conditions
        and the Trust's activities.

        b. Credit risk

        Credit risk is the risk of financial loss to the Trust if a customer
        or counterparty to a financial instrument fails to meet its
        contractual obligations, and arises principally from the Trust's
        trade receivables from joint venture partners and petroleum and
        natural gas marketers.

        A substantial portion of the Trust's accounts receivable are with
        customers and joint interest partners in the petroleum and natural
        gas industry and are subject to normal industry credit risks. The
        Trust sells substantially all of its production to eleven primary
        purchasers under normal industry sale and payment terms. Purchasers
        of the Trust's natural gas, crude oil and natural gas liquids are
        subject to an internal credit review to minimize the risk of non-
        payment.

        Receivables from petroleum and natural gas marketers are normally
        collected on the 25th day of the month following production. The
        Trust's policy to mitigate credit risk associated with these balances
        is to establish marketing relationships with large purchasers. The
        Trust historically has not experienced any collection issues with its
        petroleum and natural gas marketers. Joint venture receivables are
        typically collected within one to three months of the joint venture
        bill being issued to the partner. The Trust attempts to mitigate the
        risk from joint venture receivables by obtaining partner approval of
        significant capital expenditures prior to expenditure. However, the
        receivables are from participants in the petroleum and natural gas
        sector, and collection of the outstanding balances is dependent on
        industry factors such as commodity price fluctuations, escalating
        costs and the risk of unsuccessful drilling, in addition further risk
        exists with joint venture partners as disagreements occasionally
        arise that increase the potential for non-collection. The Trust does
        not typically obtain collateral from petroleum and natural gas
        marketers or joint venture partners; however, in certain instances
        the Trust does have the ability to withhold production from joint
        venture partners in the event of non-payment.

        As at June 30, 2008, accounts receivable was comprised of the
        following:

        ---------------------------------------------------------------------
        ($000s)
        ---------------------------------------------------------------------
        Trade accounts receivable                                     11,020
        Accrued and other accounts receivable                         42,559
        ---------------------------------------------------------------------
                                                                      53,579
        ---------------------------------------------------------------------

        The carrying amount of accounts receivable represents the maximum
        credit exposure. The Trust has an allowance for doubtful accounts as
        at June 30, 2008 of $0.5 million. As at June 30, 2008 the Trust
        estimates its trade accounts receivables to be aged as follows:

        ---------------------------------------------------------------------
        Aging ($000s)
        ---------------------------------------------------------------------
        Not past due (less than 90 days)                               3,292
        Past due 0-30 days                                               516
        Past due 31 or more days                                       7,212
        ---------------------------------------------------------------------
        Total                                                         11,020
        ---------------------------------------------------------------------

        After considering offsetting June 30, 2008 trade accounts payable
        from the same companies and cash receipts received subsequent to June
        30, 2008, the Trust's trade receivables aged more than 90 days of
        approximately $7.7 million are reduced to a net balance of
        approximately $3.0 million.

        c. Liquidity risk

        Liquidity risk is the risk that the Trust will not be able to meet
        its financial obligations as they are due. The Trust's approach to
        managing liquidity is to ensure, as far as possible, that it will
        have sufficient liquidity to meet its liabilities when due, under
        both normal and stressed conditions without incurring unacceptable
        losses or risking harm to the Trust's reputation.

        The Trust prepares annual capital expenditure budgets and confirms
        unitholder distributions on a monthly basis. Capital expenditure
        budgets and levels of monthly unitholder distributions are regularly
        monitored and updated as considered necessary. Further, the Trust
        utilizes authorizations for expenditures on both operated and non-
        operated projects to further manage capital expenditures. To
        facilitate the capital expenditure program, the Trust has a revolving
        reserve based credit facility, as outlined in note 6, which is at
        least reviewed annually by the lender. The Trust also attempts to
        match its payment cycle with collection of petroleum and natural gas
        revenues on the 25th of each month.

        The following are the contractual maturities of financial liabilities
        and associated interest payments as at June 30, 2008:

        ---------------------------------------------------------------------
        Financial             (less than)
        liability ($000s)         1 Year   1-2 Years   2-5 Years  Thereafter
        ---------------------------------------------------------------------

        Accounts payable and
         accrued liabilities      40,326           -           -           -

        Distribution payable
         to unitholders            3,168           -           -           -

        Derivative contracts      53,579           -           -           -

        Bank debt - principal          -     125,458           -           -

        Convertible debentures
         - principal                   -           -      86,250           -
        ---------------------------------------------------------------------

        Total                     97,073     125,458      86,250           -
        ---------------------------------------------------------------------

        d. Market risk

        Market risk is the risk that changes in market prices, such as
        foreign exchange rates, commodity prices, and interest rates will
        affect the Trust's net earnings or the value of financial
        instruments. The objective of market risk management is to manage and
        control market risk exposures within acceptable limits, while
        maximizing returns.

        The Trust utilizes both financial derivatives and physical delivery
        sales contracts to manage market risks. All such transactions are
        conducted in accordance with the risk management policy that has been
        approved by the Board of Directors.

        The Trust's formal risk management policy 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.

        Foreign currency exchange rate risk

        Foreign currency exchange rate risk is the risk that the fair value
        of future cash flows will fluctuate as a result of changes in foreign
        exchange rates. Although substantially all of the company's petroleum
        and natural gas sales are denominated in Canadian dollars, the
        underlying market prices in Canada for petroleum and natural gas are
        impacted by changes in the exchange rate between the Canadian and
        United States dollar. As at June 30, 2008, if the Canadian/US dollar
        exchange rate had decreased by US$0.01 with all other variables held
        constant, after tax net earnings for the three month period ended
        June 30, 2008 would have been approximately $0.9 million lower. An
        equal and opposite impact would have occurred to net earnings had the
        Canadian/US dollar exchange rate increased by US$0.01.

        The Trust had no forward exchange rate contracts in place as at or
        during the year ended June 30, 2008.

        Commodity price risk

        Commodity price risk is the risk that the fair value or future cash
        flows will fluctuate as a result of changes in commodity prices.
        Commodity prices for petroleum and natural gas are impacted by not
        only the relationship between the Canadian and United States dollar,
        as outlined above, but also world economic events that dictate the
        levels of supply and demand. The Trust has attempted to mitigate
        commodity price risk through the use of various financial derivative
        and physical delivery sales contracts. The Trust's policy is to enter
        into commodity contracts considered appropriate to a maximum of 50%
        of forecasted production volumes.

        As at June 30, 2008, the Trust had entered into commodity price risk
        management arrangements as follows:

        ---------------------------------------------------------------------
                                                    Price       Price
        Type               Period       Volume      Floor     Ceiling  Index
        ---------------------------------------------------------------------
        Oil collar   April 1, 2008 to   1,000  $ 65.00 US  $ 82.00 US    WTI
                      Dec. 31, 2008      bbl/d

        Oil collar   April 1, 2008 to   1,000  $ 65.00 US  $ 82.00 US    WTI
                      Dec. 31, 2008      bbl/d

        Natural Gas  Jan. 1, 2008 to    5,000  $ 6.65 CDN  $ 6.65 CDN   AECO
         fixed        Dec. 31, 2008      GJ/day

        Natural Gas  Jan. 1, 2008 to   10,551  $ 6.65 CDN  $ 6.65 CDN   AECO
         fixed        Dec. 31, 2008      GJ/day

        Natural Gas  April 1, 2008 to   5,275  $ 6.64 CDN  $ 6.64 CDN   AECO
         fixed        Oct. 31, 2008      GJ/day

        Natural Gas  April 1, 2008 to   3,500  $ 6.90 CDN  $ 6.90 CDN   AECO
         fixed        Oct. 31, 2008      GJ/day

        Natural Gas  Nov. 1, 2008 to    3,500  $ 7.58 CDN  $ 7.58 CDN   AECO
         fixed        Dec. 31, 2008      GJ/day

        Natural Gas  Nov. 1, 2008 to    5,275  $ 7.61 CDN  $ 7.61 CDN   AECO
         fixed        March 31, 2009     GJ/day

        Natural Gas  Jan. 1, 2009 to    5,275  $ 7.86 CDN  $ 7.86 CDN   AECO
         fixed        March 31, 2009     GJ/day

        Natural Gas  April 1, 2009 to   5,275  $ 7.01 CDN  $ 7.01 CDN   AECO
         fixed        June 30, 2009      GJ/day

        Natural Gas  April 1, 2009 to   5,275  $ 7.015 CDN $ 7.015 CDN  AECO
         fixed        June 30, 2009      GJ/day
        ---------------------------------------------------------------------

        For the three and six months ended June 30, 2008, the gain (loss) on
        commodity contracts was comprised of the following:

        ---------------------------------------------------------------------
                                                  Three months ended June 30,
        ($000s)                                             2008        2007
        ---------------------------------------------------------------------
        Gain (loss) on commodity contracts
          Realized(1)                                  $ (12,619)    $  (118)
          Unrealized(2)                                  (25,550)      5,953
        ---------------------------------------------------------------------
                                                       $ (38,169)    $ 5,835
        ---------------------------------------------------------------------


        ---------------------------------------------------------------------
                                                    Six months ended June 30,
        ($000s)                                             2008        2007
        ---------------------------------------------------------------------

        Gain (loss) on commodity contracts
          Realized(1)                                  $ (16,761)    $ 3,026
          Unrealized (2)                                 (43,237)      3,488
        ---------------------------------------------------------------------
                                                       $ (59,998)    $ 6,514
        ---------------------------------------------------------------------
        (1) Realized gains and losses on commodity contracts represent actual
            cash settlements and other amounts paid under these contracts.
        (2) Unrealized gains and losses on commodity contracts represent non-
            cash adjustments for changes in the fair value of these contracts
            during the period.

        As at June 30, 2008, if oil and natural gas liquids prices had been
        US$1 per barrel and natural gas prices $0.10 per mcf lower, with all
        other variables held constant, after tax net earnings for the three
        month period ended June 30, 2008 would have been approximately $1.8
        million lower. An equal and opposite impact would have occurred to
        net earnings had oil and natural gas liquids prices been US$1 per
        barrel and natural gas $0.10 per mcf higher.

        Interest rate risk

        Interest rate risk is the risk that future cash flows will fluctuate
        as a result of changes in market interest rates. The Trust is exposed
        to interest rate fluctuations on its bank debt which bears a floating
        rate of interest. As at June 30, 2008, if interest rates had been 1%
        lower with all other variables held constant, after tax net earnings
        for the three month period ended June 30, 2008 would have been
        approximately $0.9 million higher, due to lower interest expense. An
        equal and opposite impact would have occurred to net earnings had
        interest rates been 1% higher.

        The Trust had no interest rate swap or financial contracts in place
        as at or during the six months ended June 30, 2008.

        e. Capital management

        The Trust's policy is to maintain a strong capital base so as to
        maintain investor, creditor and market confidence and to sustain the
        future development of the business. The Trust manages its capital
        structure and makes adjustments to it in the light of changes in
        economic conditions and the risk characteristics of the underlying
        petroleum and natural gas assets. The Trust considers its capital
        structure to include unitholders' equity, bank debt, convertible
        debentures and working capital. In order to maintain or adjust the
        capital structure, the Trust may from time to time issue trust units,
        adjust its capital spending, and/or dispose of certain assets to
        manage current and projected debt levels.

        The Trust monitors capital based on the ratio of net debt to
        annualized cash flow (the "ratio"). This ratio is calculated as net
        debt, defined as outstanding bank debt plus or minus working capital
        (excluding commodity contract assets and liabilities), divided by
        cash flow from operations before changes in non-cash working capital
        for the most recent calendar quarter, annualized (multiplied by
        four). The Trust's strategy is to target a ratio of between 1.0 and
        1.5 times. This ratio may increase at certain times as a result of
        acquisitions and other factors. In order to facilitate the management
        of this ratio, the Trust prepares annual capital expenditure budgets
        and sets unitholder distributions on a monthly basis. Capital
        expenditure budgets and levels of monthly unitholder distributions
        are reviewed and updated as necessary depending on varying factors
        including current and forecast prices, successful capital deployment
        and general industry conditions. The annual and updated budgets and
        monthly unitholder distributions are approved by the Board of
        Directors.

        As at June 30, 2008, the Trust's ratio of net debt to annualized cash
        flow was 1.8 times, which the Trust projects will decrease during the
        remainder of 2008 as net debt levels are reduced as True continues to
        take a balanced approach to the priority use of cash flows between
        levels of distributions and its 2008 capital program. This ratio as
        at June 30, 2008 was reduced from that at March 31, 2008 due to asset
        dispositions competed in the second quarter of 2008. The Trust's bank
        debt facility is based on petroleum and natural gas reserves (see
        note 6).

        The Trust's ability to issue trust units is subject to external
        restrictions as a result of the Specified Investment Flow-Through
        Entities Legislation (the "SIFT tax") whereby the Trust may lose the
        benefit of a four year grandfathering period if the Trust exceeds the
        limits on the issuance of new trust units and convertible debt that
        constitute normal growth during the grandfathering period (subject to
        certain exceptions). The normal growth limits are calculated as a
        percentage of the Trust's market capitalization of approximately
        $737 million on October 31, 2006, which the Trust may currently issue
        in additional equity without offending the normal growth guidelines
        between now and 2011. The normal growth restriction on trust unit
        issuance is monitored by management as part of the overall capital
        management objectives. The Trust is in compliance with the normal
        growth restrictions.

        There were no changes in the Trust's approach to capital management
        during the year.

        f. Fair value of financial instruments

        The Trust's financial instruments as at June 30, 2008 include
        accounts receivable, deposits, capital taxes recoverable, marketable
        securities, commodity contract liability, accounts payable and
        accrued liabilities, distributions payable, long-term debt and
        convertible debentures. The fair value of accounts receivable,
        accounts payable and accrued liabilities and distributions payable
        approximate their carrying amounts due to their short-terms to
        maturity.

        The fair value of commodity contracts is determined by discounting
        the difference between the contracted price and published forward
        price curves as at the balance sheet date, using the remaining
        contracted petroleum and natural gas volumes.

        Long-term bank debt bears interest at a floating market rate and
        accordingly the fair market value approximates the carrying value.

        The fair value of the convertible debentures of $84.9 million is
        based on exchange traded values.

        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, P.Eng., President, CEO & COO,
(403) 750-2420; or Edward J. Brown, CA, Vice President, Finance & CFO, (403)
750-2655; or Sacha Ravelli, Manager, Investor Relations, (403) 750-7085; 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, Canada, T2P 3S8, Phone: (403) 266-8670, Fax: (403) 264-8163,
www.trueenergytrust.com


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