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True Energy Trust announces second quarter 2007 financial results


View All News Releases August 9, 2007

    TSX: TUI.UN

    CALGARY, Aug. 9 /CNW/ - (TSX: TUI.UN) True Energy Trust ("True" or the
"Trust") is pleased to announce its financial and operating results for the
three and six months ended June 30, 2007. Highlights from the quarter include:-   True generated average sales volumes for the second quarter of 2007
        of 17,122 boe/d as compared to 10,697 boe/d for the same period in
        2006, representing a 60% increase. Sales volumes decreased 7% from
        first quarter 2007 volumes. In addition to the property dispositions
        during the first six months of 2007, third party plant turnarounds
        during the month of June reduced production by approximately 400 to
        600 boe/d. The Trust continues to experience production declines at
        its Mantario heavy oil property due to various performance issues.
        During the second quarter, production at Mantario was approximately
        1,000 boe/d less than the 2006 exit rate from the property.
        Production volumes from the property were approximately 1,200 boe/d
        as at June 30, 2007. True is proceeding with its strategies to
        mitigate continued impact from the property.

    -   Cash flow from operations(*) for the second quarter of 2007 was
        $34.2 million on gross sales of $75.0 million compared to cash flow
        from operations of $16.4 million on gross sales of $43.0 million for
        the same period in 2006. The increase in cash flow for the 2007
        second quarter was primarily the result of higher production volumes
        as well as overall higher realized commodity prices and a more active
        hedging program as compared to the same period in 2006. In
        comparison, cash flow from operations for the first quarter of 2007
        was $30.0 million on gross sales of $71.2 million.

    -   On May 31, 2007, True completed its equity offering, including an
        over-allotment option, for an aggregate of 9,430,000 trust units at
        $6.10 per unit for gross proceeds of $57.5 million. The net proceeds
        of $54.4 million, after deducting unit issue costs, were used to pay
        down debt.

    -   An additional property disposition closed in the second quarter for
        net proceeds of $9.0 million.

    -   True has reduced its net debt by approximately $54.8 million for the
        six month period ended June 30, 2007. This was achieved as a result
        of many factors including the proceeds received from the Trust's
        recent equity offering, proceeds received from three property
        dispositions, maintaining sustainable distributions compared to cash
        flows from operations and capital expenditure requirements in the
        period and continuation of the Trust's active hedging program.

    -   True recently entered into two new commodity price risk management
        contracts: 1) an oil collar with a West Texas Intermediate ("WTI")
        reference crude oil price floor of US$65.00 per barrel and a price
        ceiling of US$82.00 per barrel on 1,000 barrels per day for the
        second quarter of 2008 through to the fourth quarter of 2008; and
        2) an AECO reference price natural gas collar with a floor price of
        $8.00 per GJ and a ceiling price of $9.05 per GJ on 5,000 GJ per day
        for the period of November 1, 2007 through March 31, 2008. Currently,
        the Trust has hedged volumes of 2,000 bbls/d of crude oil and
        25,000 GJ/d of natural gas for the third quarter 2007, 2,000 bbls/d
        of crude oil and 15,055 GJ/d of natural gas for the fourth quarter
        2007, 2,000 bbls/d of crude oil and 5,000 GJ/d of natural gas for the
        first quarter of 2008, and 1,000 bbls/d of crude oil for the second
        to fourth quarters of 2008.

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

    True's second quarter report is presented below.

                                 HIGHLIGHTS
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30                 June 30
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    FINANCIAL (unaudited)
    (CDN$000s except unit and
     per unit amounts)
    Revenue (before royalties
     and hedging(1))              74,991      43,004     146,187      89,400
    Cash flow from operations(2)  34,192      16,386      64,180      35,381
      Per basic trust unit         $0.47       $0.43       $0.89       $0.97
      Per diluted trust unit(3)    $0.45       $0.42       $0.88       $0.95
    Net income (loss)              1,741      12,243      (6,830)     15,502
      Per basic trust unit         $0.02       $0.33      $(0.10)      $0.43
      Per diluted trust unit(3)    $0.02       $0.33      $(0.09)      $0.42
    Distributions declared        18,376      27,771      35,242      53,921
      Per unit                     $0.24       $0.72       $0.48       $1.44
    -------------------------------------------------------------------------
    Exploration and development   15,503      17,368      61,344      39,829
    Corporate and property
     acquisitions                    649          68       1,354         192
    -------------------------------------------------------------------------
    Capital expenditures - cash   16,152      17,436      62,698      40,021
    Property dispositions - cash  (9,026)    (24,514)    (27,469)    (24,514)
    Corporate acquisitions and
     other - non-cash                311      47,321        (313)     47,956
    -------------------------------------------------------------------------
    Total capital expenditures
     - net                         7,437      40,243      34,916      63,463
    -------------------------------------------------------------------------
    Long-term debt               142,153      21,834     142,153      21,834
    Convertible debentures        78,636      81,168      78,636      81,168
    Working capital deficiency       256      26,519         256      26,519
    -------------------------------------------------------------------------
    Total net debt               221,045     129,521     221,045     129,521
    -------------------------------------------------------------------------
    Total assets                 941,122     759,489     941,122     759,489
    Unitholders' equity          520,326     449,975     520,326     449,975
    -------------------------------------------------------------------------
    OPERATING
    Daily sales volumes
      Crude oil and NGLs
       (bbls/d)                    5,546       3,639       6,007       4,070
      Natural gas (mcf/d)         69,455      42,348      70,686      42,668
      Total oil equivalent
       (boe/d)                    17,122      10,697      17,788      11,181
    Average prices
      Crude oil and NGLs ($/bbl)   50.90       57.43       45.74       47.44
      Crude oil and NGLs
       (including hedging(1))
       ($/bbl)                     49.64       56.60       46.40       47.07
      Natural gas ($/mcf)           7.60        5.98        7.43        6.94
      Natural gas (including
       hedging(1)) ($/mcf)          8.63        5.98        7.88        6.94
      Total oil equivalent ($/boe) 47.33       43.23       44.96       43.74
      Total oil equivalent
       (including hedging(1))
       ($/boe)                     51.08       42.95       46.99       43.60
    Statistics
      Operating netback ($/boe)    26.79       22.20       25.53       23.35
      Operating netback
       (including hedging(1))
       ($/boe)                     30.53       21.92       27.55       23.22
      Production expenses ($/boe)  12.69        9.58       10.79        9.14
      General & administrative
       ($/boe)                      2.78        3.91        2.87        3.16
      Royalties as a % of sales
       after transportation           14%         24%         17%         24%

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



    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30                 June 30
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    TRUST UNITS
    Trust units outstanding   79,709,119  41,837,743  79,709,119  41,837,743
    Trust unit incentive
     rights outstanding        6,687,499   3,552,333   6,687,499   3,552,333
    Units issuable for
     exchangeable shares         309,216     258,445     309,216     258,445
    Units issuable for
     convertible debentures    5,390,625   5,390,625   5,390,625   5,390,625
    -------------------------------------------------------------------------
    Diluted trust units
     outstanding              92,296,459  51,039,146  92,296,459  51,039,146
    Diluted weighted average
     trust units(3)           75,810,961  38,489,057  72,201,103  37,412,422

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

    (CDN$, except volumes)
     based on intra-day trading
    High                            6.83       17.65        7.47       21.30
    Low                             5.71       12.66        4.87       12.66
    Close                           5.75       13.74        5.75       13.74
    Average daily volume         438,393     231,034     520,700     310,462
    -------------------------------------------------------------------------

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

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

    (3) In computing weighted average diluted earnings per trust unit for the
        three month period ended June 30, 2007 2,320,716 (2006: 1,156,883)
        trust units were added to the 73,490,245 (2006: 37,332,174) weighted
        average number of trust units outstanding during the period for the
        dilutive effect of exchangeable shares and convertible debentures. A
        total of 4,875,999 (2006: 3,448,203) trust incentive units and
        5,390,625 (2006: nil) trust units issuable pursuant to conversion of
        convertible debentures were excluded from the calculation of diluted
        earnings per trust unit for the three month period ended June 30,
        2007 as they were not dilutive. To calculate weighted average diluted
        cash 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 under this calculation.

        In computing weighted average diluted earnings per trust unit for the
        six month period ended June 30, 2007 309,216 (2006: 941,528) trust
        units were added to the 71,891,887 (2006: 36,470,894) weighted
        average number of trust units outstanding during the period for the
        dilutive effect of exchangeable shares and convertible debentures. A
        total of 6,887,499 (2006: 3,435,717) trust incentive units and
        5,390,625 (2006: nil) trust units issuable pursuant to conversion of
        convertible debentures were excluded from the calculation of diluted
        earnings per trust unit for the six month period ended June 30, 2007
        as they were not dilutive. To calculate weighted average diluted cash
        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 under this
        calculation.

                            REPORT TO UNITHOLDERSThe second quarter of 2007 the Trust focused on improving its balance
sheet, executing our disposition program, improving the working capital
position and identifying the opportunities for the next 18 months from an
extensive list of drilling prospects. Accomplishments for the second quarter
ended June 30, 2007 include:

    Distributions

    In the second quarter of 2007, monthly distributions of $0.08 per unit
were declared and paid on May 15, 2007, June 15, 2007 and July 16, 2007. The
Board has announced it has set a distribution policy for the third quarter of
2007 at a monthly rate of $0.08 per unit, subject to monthly confirmation,
based on current commodity prices, hedging program, production volumes and
market conditions. This go-forward strategy for the distribution level is
consistent with providing a balance between providing income to unitholders
and funding for True's capital program required to further develop its land
base.

    Production

    2007 second quarter sales volumes averaged 17,122 boe/d as compared to
10,697 boe/d for the same period in 2006, representing a 60% increase. For the
six month period ended June 30, 2007, sales volumes averaged 17,788 boe/d as
compared to 11,181 boe/d for the same period in 2006. Sales volumes in the
second quarter decreased 7% from the first quarter 2007 volumes. This takes
into account the impact of dispositions of certain properties at the end of
March 2007 and other properties in May 2007. In addition to the dispositions,
third party plant turnarounds during the month of June reduced production by
approximately 400 to 600 boe/d. The Trust continues to experience production
declines at its Mantario heavy oil property due to various performance issues.
During the second quarter, production at Mantario was approximately
1,000 boe/d less than the 2006 exit rate from the property. Production volumes
from the property were approximately 1,200 boe/d as at June 30, 2007. True is
proceeding with its strategies to mitigate continued impact from the property.
    During the first quarter of 2007, new Kerrobert thermal wells were
drilled and facility upgrades continued throughout the second quarter.
Execution of the Kerrobert steam assisted gravity drainage ("SAGD") project is
on track with expected steam injection for phase one to commence at the end of
the third quarter. We are forecasting that the third quarter will be
negatively impacted by additional major third party plant turnarounds in West
Central Alberta. Approximately 2,000 boe/d of production will be shut-in for a
period during the third quarter from our Willesden Green properties. During
the shut-in period the Trust will gather extensive pressure data on the tight
gas reservoirs and perform a number of workovers. The remaining behind pipe
production, workovers, and the Kerrobert SAGD start-up will provide visible
growth prior to the end of the 2007 year. With these forecasted turnarounds
and completed dispositions the Trust is anticipating 2007 annual average
volumes of approximately 17,000 boe/d.

    Financial

    Cash flow from operations for the second quarter was $34.2 million on
gross sales of $75.0 million compared to cash flow from operations of
$16.4 million on gross sales of $43.0 million for the same period in 2006. The
increase in cash flow for the 2007 second quarter was primarily the result of
higher production volumes as well as overall higher realized commodity prices
and a more active hedging program as compared to the same period in 2006.
    Cash flow from operations for the six month period ended June 30, 2007
was $64.2 million on gross sales of $146.2 million compared to cash flow from
operations of $35.4 million on gross sales of $89.4 million for the same
period in 2007.
    The net income for the 2007 second quarter was $1.7 million compared to
net income of $12.2 million in second quarter of 2006. The net loss for the
six month period ended June 30, 2007 was $6.8 million compared to net income
of $15.5 million for the same period in 2006. This is primarily reflective of
increased cash flow from operations, unrealized gains on commodity contracts
in 2007, offset by a lower future tax recovery and by higher depletion,
depreciation and accretion charges from recent 2006 acquisitions.

    Drilling

    Following the execution of True's extensive Q1 drilling program of
34 (24.0 net) wells, the main focus for the second quarter was on tie-ins and
further upgrades to the Kerrobert SAGD facility. During the second quarter of
2007, True successfully drilled 1 (0.8 net) natural gas well in the Pembina
area of West Central Alberta.

    Dispositions

    Dispositions during the second quarter of 2007 consisted of the sale of
certain Peace River Arch properties, which are outside of the Trust's core
areas for future development. This property sale closed on May 15, 2007 with
net proceeds after adjustments of $9.0 million that was used to pay down debt.
The Trust continues to evaluate further opportunities with its divestiture
program.
    Subsequent to June 30, 2007, True closed the sale of two minor
properties. The total net proceeds received on the sale of these properties
after adjustments was $0.8 million and was used to pay down debt.

    International

    The Trust along with Veraz Petroleum Ltd. ("Veraz") was successful in
acquiring the right to evaluate a 2.5 million acre concession in Peru. At this
stage the Trust has no financial obligation under the arrangement but holds an
option to participate in the opportunity through participating in future
equity issues done by Veraz to finance the project. The Board will evaluate
the opportunity and decide if this is a prudent long-term opportunity for the
unitholders. This proposed structure is similar to that which has been pursued
by other Canadian Trusts on international ventures.

    Liquidity

    On May 31, 2007, the Trust completed its offering, including an
over-allotment option, for an aggregate of 9,430,000 trust units at $6.10 per
unit for gross proceeds of $57.5 million. The net proceeds of $54.4 million,
after deducting unit issue costs, was used to pay down debt.
    True's net debt as at June 30, 2007 was $221.0 million, representing
$142.2 million outstanding on the credit facility, $78.6 million in
convertible debentures (liability component) and the balance a net working
capital deficiency.
    The existing credit facility consists of a $15 million demand operating
facility provided by one Canadian bank and a $185 million extendible revolving
term credit facility syndicated by two Canadian chartered banks, a U.S. bank,
a Canadian financial institution and one institutional lender. As at June 30,
2007, there is approximately $57 million undrawn under these lending
facilities.
    True has continued its active commodity price risk management program.
True recently entered into two new commodity price risk management contracts:
1) an oil collar with a West Texas Intermediate ("WTI") reference crude oil
price floor of US$65.00 per barrel and a price ceiling of US$82.00 per barrel
on 1,000 barrels per day for the second quarter of 2008 through to the fourth
quarter of 2008; and 2) an AECO reference price natural gas collar with a
floor price of $8.00 per GJ and a ceiling price of $9.05 per GJ on 5,000 GJ
per day for the period of November 1, 2007 through March 31, 2008. As of
August 8, 2007, the Trust has hedged volumes of 2,000 bbls/d of crude oil and
25,000 GJ/d of natural gas for the third quarter 2007, 2,000 bbls/d of crude
oil and 15,055 GJ/d of natural gas for the fourth quarter 2007, 2,000 bbls/d
of crude oil and 5,000 GJ/d of natural gas for the first quarter of 2008, and
1,000 bbls/d of crude oil for the second to fourth quarters of 2008. The Trust
will continue its hedging strategies focusing on maintaining sufficient cash
flow to fund True's unitholder distributions and capital program.

    SIFT tax enactment

    In June 2007, the federal 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.
This new tax will take effect in 2011 provided certain conditions continue to
be met. As a result of the enactment of the SIFT tax, the Trust recorded a
future income tax recovery of $1.2 million. The SIFT tax enactment and the
related future income tax recovery did not affect cash flow or distributions
in the quarter and is not expected to affect our distribution policies until
2011 at the earliest. Our Board of Directors and Management continue to review
the impact of this tax on our business strategy although we do not expect any
changes in the short term.

    Personnel Announcements

    Further to our press release dated March 15, 2007, we announced a
restructuring of our senior management team for May 2007. On May 14, 2007
Wayne M. Chorney joined True in the capacity of President and Chief Operating
Officer, bringing with him 23 years of industry experience. On July 24, 2007,
Wayne Jessee stepped down from his role as Executive Vice President to pursue
other opportunities. In addition, Garth Wiggins recently resigned from the
Board. On behalf of the Board, I would like to thank Mr. Wiggins and Mr.
Jessee for their significant contributions to the Trust.

    Paul R. Baay
    Chairman & CEO
    August 9, 2007MANAGEMENT'S DISCUSSION AND ANALYSISAugust 9, 2007 - The following Management's Discussion and Analysis of
financial results as provided by the management of True Energy Trust ("True"
or the "Trust") should be read in conjunction with the unaudited interim
consolidated financial statements and selected notes for the three and six
months ended June 30, 2007 and 2006 and the audited consolidated financial
statements and Management's Discussion and Analysis for the years ended
December 31, 2006 and 2005 for the Trust. This commentary is based on
information available to, and is dated, August 9, 2007. The financial data
presented is in accordance with Canadian generally accepted accounting
principles ("GAAP") in Canadian dollars, except where indicated otherwise.

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

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

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

    Net Income (Loss) and Cash Flow from Operations

    True generated cash flow from operations of $34.2 million ($0.45 per
diluted unit) for the three months ended June 30, 2007, up 110% from the
$16.4 million ($0.42 per diluted unit) for the second quarter of 2006. The
increase in cash flow for the 2007 second quarter was the result of higher
production volumes as well as higher overall realized commodity prices and a
more active commodity hedging program as compared to the same period in 2006.
Cash flow from operations for the six month period ended June 30, 2007 was
$64.2 million ($0.88 per diluted unit), up 81% from the $35.4 million
($0.95 per diluted unit) for the same period in 2006.
    The net income for the 2007 second quarter was $1.7 million compared to
net income of $12.2 million in second quarter of 2006. The net loss for the
six month period ended June 30, 2007 was $6.8 million compared to net income
of $15.5 million for the same period in 2006. This is primarily reflective of
increased cash flow from operations, unrealized gains on commodity contracts
in 2007, offset by a lower future tax recovery compared to 2006 and by higher
depletion, depreciation and accretion charges from the Q2 and Q3 2006
acquisitions of Shellbridge Oil & Gas, Inc. ("Shellbridge") and Prairie
Schooner Petroleum Ltd. ("Prairie Schooner"), respectively.Cash Flow From Operations and Net Income
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
    ($000s, except per unit                  June 30                 June 30
     amounts)                       2007        2006        2007        2006
    -------------------------------------------------------------------------

    Cash flow from operations     34,192      16,386      64,180      35,381
      Basic ($/unit)                0.47        0.43        0.89        0.97
      Diluted ($/unit)              0.45        0.42        0.88        0.95

    Net income (loss)              1,741      12,243      (6,830)     15,502
      Basic ($/unit)                0.02        0.33       (0.10)       0.43
      Diluted ($/unit)              0.02        0.33       (0.09)       0.42
    -------------------------------------------------------------------------Reconciliation of Cash Flow from Operations and Distributions

    Distributable cash is determined by aggregating various amounts received,
including interest income on notes of subsidiaries and other interest income
received or receivable, income generated under net profits interest, royalty,
other permitted investments and dividends and other distributions on
securities of subsidiaries, after deduction of all expenses and liabilities of
the Trust. The portion of distributable cash declared payable to unitholders
on any distribution date is determined on recommendation of the Board of
Directors of True Energy Inc., as administrator of the Trust.Reconciliation of Cash Flow from Operations and Distributions
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
    ($000s, except per unit                  June 30                 June 30
     amounts)                       2007        2006        2007        2006
    -------------------------------------------------------------------------

    Cash flow from operations     34,192      16,386      64,180      35,381
    Change in non-cash working
     capital                     (29,403)     (7,523)    (19,244)    (15,909)
    -------------------------------------------------------------------------
    Cash flow from operating
     activities                    4,789       8,863      44,936      19,472
    Cash withheld to fund
     capital expenditures, net
     of disposition proceeds      (7,126)      7,078     (35,229)    (15,507)
    Funding from DRIP                  -      13,747           -      15,064
    Net proceeds from issue of
     trust units                  54,386           -      54,386           -
    Proceeds from issue of
     convertible debentures,
     net of issue costs                -      82,227           -      82,227
    Debt repayment and working
     capital changes             (33,673)    (84,144)    (28,851)    (47,335)
    -------------------------------------------------------------------------
    Distributions paid            18,376      27,771      35,242      53,921
    Accumulated distributions,
     beginning of period         158,582      43,511     141,716      17,361
    -------------------------------------------------------------------------
    Accumulated distributions,
     end of period               176,958      71,282     176,958      71,282
    -------------------------------------------------------------------------
    Distributions per unit for
     outstanding units in
     the period                     0.24        0.72        0.48        1.44
    Accumulated distributions
     per unit, beginning of
     period                         3.36        1.20        3.12        0.48
    -------------------------------------------------------------------------
    Accumulated distributions
     per unit, end of period        3.60        1.92        3.60        1.92
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------The Premium Distribution™ Reinvestment, Distribution Reinvestment and
Optional Trust Unit Purchase Plan ("DRIP") was implemented effective March 27,
2006. Funds reinvested in the Trust through this plan were available to fund
capital and other expenditures. On November 16, 2006, the Trust announced the
suspension of equity available for reinvestment under DRIP until further
notice.

    Sales Volumes

    2007 second quarter sales volumes averaged 17,122 boe/d as compared to
10,697 boe/d for the same period in 2006, representing a 60% increase. For the
six month period ended June 30, 2007, sales volumes averaged 17,788 boe/d as
compared to 11,181 boe/d for the same period in 2007. Sales volumes in the
second quarter decreased 7% from the first quarter 2007 volumes. This takes
into account the impact of dispositions of certain properties at the end of
March 2007 and other properties in May 2007. In addition to the dispositions,
third party plant turnarounds during the month of June reduced production by
approximately 400 to 600 boe/d. The Trust continues to experience production
declines at its Mantario heavy oil property due to various performance issues.
During the second quarter of 2007, production at Mantario was approximately
1,000 boe/d less than the 2006 exit rate from the property. Production volumes
from the property were approximately 1,200 boe/d as at June 30, 2007. True is
proceeding with its strategies to mitigate continued impact from the property.
At the end of the second quarter, 6 wells in West Central Alberta were
awaiting down-hole completion and/or completion of production facilities.
True's significant drilling activity in the first quarter of 2007 is expected
to contribute to production primarily in the third and fourth quarters of
2007.
    For the three month period ended June 30, 2007, the weighting towards
natural gas production averaged 68% compared to 66% in the same period in
2006. For the six month period ended June 30, 2007, the weighting towards
natural gas averaged 66% compared to 64% for the same period in 2006. Heavy
oil sales made up 18% of total production for the second quarter of 2007
compared to 21% in the same period in 2006. In comparision, heavy oil sales
made up 24% of total production in the first quarter of 2007; the decrease in
heavy oil sales from Q1 to Q2 2007 is primarily due to reduced heavy oil
production in the Mantario area. The September 2006 acquisition of Prairie
Schooner also added significant natural gas volumes which has increased the
natural gas production weighting. Currently, the Trust estimates that the
weighting towards natural gas production is approximately 67%.Sales Volumes
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30                 June 30
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    Natural gas     (mcf/d)       69,455      42,348      70,686      42,668
    -------------------------------------------------------------------------

    Heavy oil      (bbls/d)        3,058       2,232       3,703       2,400

    Light oil and
     condensate    (bbls/d)        1,743       1,122       1,632       1,386

    NGLs           (bbls/d)          745         285         672         284
    -------------------------------------------------------------------------
    Total crude
     oil and NGLs  (bbls/d)        5,546       3,639       6,007       4,070
    -------------------------------------------------------------------------
    Total boe/d       (6:1)       17,122      10,697      17,788      11,181
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Sales of natural gas averaged 69.4 mmcf/d for the second quarter of 2007,
compared to 42.3 mmcf/d in 2006, an increase of 64%. In comparison, natural
gas volumes averaged 71.9 mmcf/d for the first quarter of 2007.
    Crude oil and NGL sales for the second quarter of 2007 averaged 5,546
bbls/d up 52% from average sales of 3,639 bbls/d in the same period of 2006.
Most of this increase was due to greater oil volumes from the acquisition of
Shellbridge in June 2006 and an increased drilling program in 2006 and 2007.
In comparison, crude oil and NGL sales for the first quarter of 2007 were
6,472 bbls/d; the decrease from the first quarter of 2007 to the second
quarter of 2007 is primarily due to a reduction in heavy oil volumes,
primarily in the Mantario area.Commodity Prices

    Average Commodity Prices
    -------------------------------------------------------------------------
                       Three months ended June 30,  Six months ended June 30,
                           2007     2006  % Change    2007     2006  % Change
    -------------------------------------------------------------------------

    Exchange rate
     (US$/Cdn$)          0.9108   0.8920        2   0.8810   0.8791        -

    Natural gas:
    NYMEX (US$/mmbtu)      7.66     6.64       15     7.41     7.23        3
    Alberta spot ($/mcf)   7.07     6.00       18     7.23     6.76        7
    True's average price
     ($/mcf)               7.60     5.98       27     7.43     6.94        7
    True's average price
     (including hedging)
     ($/mcf)               8.63     5.98       44     7.88     6.94       14

    Crude oil:
    WTI (US$/bbl)         65.02    70.72       (8)   61.67    67.13       (8)
    Edmonton par -
     light oil ($/bbl)    72.66    78.85       (7)   70.21    74.13       (5)
    Bow River - medium/
     heavy oil ($/bbl)    50.69    60.48      (16)   50.24    50.66       (1)
    Hardisty Heavy -
     heavy oil ($/bbl)    42.95    42.00        2    42.82    53.35      (20)
    True's average
     prices ($/bbl)
      Light crude and
       condensate         64.89    70.48       (8)   60.53    63.27       (4)
      Light crude and
       condensate
       (including
       hedging)           60.89    67.80      (10)   62.97    62.18        1
      NGLs                50.54    56.59      (11)   45.35    53.46      (15)
      Light crude oil,
       condensate,
       and NGLs           60.59    67.66      (10)   56.10    61.60       (9)
      Light crude oil,
       condensate and
       NGLs (including
       hedging)           57.79    65.53      (12)   57.83    60.69       (5)
      Heavy crude oil     43.01    50.97      (16)   39.28    37.59        3
      Total crude oil
       and NGLs           50.90    57.43      (11)   45.74    47.44       (4)
      Total crude oil
       and NGLs
       (including
       hedging)           49.64    56.60       (12)  46.40    47.07       (1)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------True's natural gas is primarily sold on the daily spot market. During
second quarter of 2007, the Alberta Spot reference price increased by 18%
compared to the same period in 2006. True's average sales price before
transportation and hedging for the second quarter of 2007 averaged $7.60/mcf
for its natural gas, 27% more than the $5.98/mcf received in 2006. In
comparison, True's average sales price for natural gas averaged $7.26/mcf for
the fourth quarter of 2006. The natural gas revenues for the period reflect
adjustments related to prior production periods; excluding these adjustments
the average sales price for natural gas would have been approximately
$7.29/mcf for the second quarter of 2007.
    For heavy crude oil, True received an average price before transportation
of $43.01/bbl during the second quarter of 2007, a decrease of 16% over 2006
prices. The Bow River reference price decreased by 16% and the Hardisty Heavy
reference price increased by 2% 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. A different heavy oil property mix as
compared to the prior year has resulted in True's price for the quarter being
more closely aligned with the Hardisty Heavy price. In comparison, True
received an average heavy oil price of $36.64/bbl for the first quarter of
2007.
    For light oil, condensate and NGLs, True recorded an average $60.59/bbl
before hedging during the second quarter of 2007, 10% lower than the average
price received in 2006. During this same period, the Edmonton par price
decreased by 7%. In comparison, True received an average oil price for light
oil, condensate and NGLs of $50.77/bbl in the first quarter of 2007. True's
realized price increased 19% from the first quarter to the second quarter of
2007, whereas the Edmonton par price increased by 7% over the same period. The
primary reason for this difference is a 30% increase in True's average price
received for NGLs and higher NGL volumes experienced for the period, as well
as the impact of average condensate prices realized of approximately
$69.00/bbl in the second quarter.

    Revenue

    Revenue before other income for the second quarter of 2007 was
$73.7 million, 75% greater than the $42.1 million in the same period of 2006.
The higher revenue for the quarter was the result of significant growth in
production volumes for natural gas, crude oil, condensate and NGLs due to 2006
acquisitions, in addition to overall higher natural gas prices.-------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30                 June 30
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Light crude oil and
     condensate                   10,293       7,193      17,877      15,868
    NGLs                           3,426       1,471       5,517       2,749
    Heavy oil                     11,967      10,353      26,329      16,330
    -------------------------------------------------------------------------
    Crude oil and NGLs            25,686      19,017      49,723      34,947
    Natural gas                   48,058      23,061      95,040      53,575
    -------------------------------------------------------------------------
    Total revenue before other    73,744      42,078     144,763      88,522
    Other                          1,247         926       1,424         878
    -------------------------------------------------------------------------
    Total revenue before
     royalties and hedging        74,991      43,004     146,187      89,400
    Gain (loss) on commodity
     contracts                     5,835        (273)      6,514        (273)
    -------------------------------------------------------------------------
    Total revenue before
     royalties                    80,826      42,731     152,701      89,127
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Financial Instruments

    The Trust has a formal risk management policy which permits management to
use specified price risk management strategies for up to 50% of crude oil,
natural gas and NGL production including fixed price contracts, costless
collars and the purchase of floor price options and other derivative financial
instruments to reduce the impact of price volatility and ensure minimum prices
for a maximum of eighteen months beyond the current date. The program is
designed to provide price protection on a portion of the Trust's future
production in the event of adverse commodity price movement, while retaining
significant exposure to upside price movements. By doing this, the Trust seeks
to provide a measure of stability to cash distributions, as well as, to ensure
True realizes positive economic returns from its capital developments and
acquisition activities.
    As of August 8, 2007, the Trust has hedged volumes of 2,000 bbls/d of
crude oil and 25,000 GJ/d of natural gas for the third quarter 2007,
2,000 bbls/d of crude oil and 15,055 GJ/d of natural gas for the fourth
quarter 2007, 2,000 bbls/d of crude oil and 5,000 GJ/d of natural gas for the
first quarter of 2008, and 1,000 bbls/d of crude oil for the second to fourth
quarters of 2008. The Trust will continue its hedging strategies focusing on
maintaining sufficient cash flow to fund True's unitholder distributions and
capital program.
    A summary of the hedge volumes and average prices by quarter currently
outstanding is shown in the following tables (see Note 19 to the consolidated
financial statements for a detailed disclosure of all commodity contracts in
place as at August 8, 2007):Crude oil and liquids   Average Volumes (bbls/d)
    -------------------------------------------------------------------------
                                 Q3 2007     Q4 2007     Q1 2008  Q2-Q4 2008
    -------------------------------------------------------------------------
    Costless collars                   -       2,000       2,000       1,000
    Put option (price floor)       2,000           -           -           -
    -------------------------------------------------------------------------
    Total bbls/d                   2,000       2,000       2,000       1,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Average Price (US$/bbl WTI)
    -------------------------------------------------------------------------
                                 Q3 2007     Q4 2007     Q1 2008  Q2-Q4 2008
    -------------------------------------------------------------------------
    Collar ceiling price               -       75.00       75.00       82.00
    Collar floor price                 -       65.00       65.00       65.00
    Put option price floor         60.00           -           -           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Natural gas    Average Volumes (GJ/d)
    -------------------------------------------------------------------------
                                 Q3 2007     Q4 2007     Q1 2008  Q2-Q4 2008
    -------------------------------------------------------------------------
    Costless collars              15,000       8,370       5,000           -
    Fixed                         10,000       6,685           -           -
    -------------------------------------------------------------------------
    Total GJ/d                    25,000      15,055       5,000           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Average Price ($/GJ AECO C)
    -------------------------------------------------------------------------
                                 Q3 2007     Q4 2007     Q1 2008  Q2-Q4 2008
    -------------------------------------------------------------------------
    Collar ceiling price            9.29        9.20        9.05           -
    Collar floor price              7.00        7.40        8.00           -
    Fixed                           7.05        7.03           -           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

    Commodity contracts
    -------------------------------------------------------------------------
                               Crude Oil     Natural     Q2 2007     Q2 2006
    ($000s)                    & Liquids         Gas       Total       Total
    -------------------------------------------------------------------------
    Realized cash gain (loss)
     on contracts(1)                (384)        266        (118)       (273)
    Unrealized gain (loss) on
     contracts                      (251)      6,204       5,953           -
    -------------------------------------------------------------------------
    Total gain (loss) on
     commodity contracts            (635)      6,470       5,835        (273)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                               Crude Oil     Natural    YTD 2007    YTD 2006
    ($000s)                    & Liquids         Gas       Total       Total
    -------------------------------------------------------------------------
    Realized cash gain (loss)
     on contracts(2)               1,063       1,963       3,026        (273)
    Unrealized gain (loss) on
     contracts                      (343)      3,831       3,488           -
    -------------------------------------------------------------------------
    Total gain (loss) on
     commodity contracts             720       5,794       6,514        (273)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Includes crude oil and natural gas commodity contract premiums
        expensed in the period and the amortization of prior year crude oil
        and natural gas commodity contract premiums of a total $1.0 million
        for the three month period ended June 30, 2007.
    (2) Includes crude oil and natural gas commodity contract premiums
        expensed in the period and the amortization of prior year crude oil
        and natural gas commodity contract premiums of a total $3.4 million
        for the six month period ended June 30, 2007.Effective January 1, 2007, new accounting standards were implemented
relating to financial instruments. The impacts of adopting the new standards
are reflected in the Trust's results for the six month period June 30, 2007,
and prior year comparative financial statements have not been restated. For a
description of the new accounting standards and the impact on the Trust's
financial statements of adopting such rules, including the impact on the
Trust's prepaid expenses, deferred financing charges, long-term debt,
convertible debentures and unrealized gains on commodity contracts, refer to
note 3 of the unaudited interim consolidated financial statements of the Trust
for the six months ended June 30, 2007.

    Royalties

    For the three months ending June 30, 2007, total royalties were
$9.8 million, compared to $9.7 million incurred in the same period in 2006.
Overall royalties as a percentage of revenue (after transportation costs) in
the second quarter of 2007 were 14%, compared with 24% in the same period in
2006. The average royalty rate of 14% for the quarter includes the impact of
the reversal of certain overaccruals of heavy crude oil and natural gas
royalties from prior periods of approximately $5.3 million. The Trust has
grown significantly in the past two years and has acquired a significant
number of new properties. Based upon the latest and most up-to-date
information and experience, it was determined that certain prior period
royalty accrual estimates were overstated by approximately 2% per month on
average as a percentage of revenue after transportation costs. Excluding this
adjustment for a reduction to prior period royalties, the average royalty
rate, as a percentage of revenue after transportation costs, for the second
quarter of 2007 would have been approximately 22%, which is consistent with
the weighted average royalty rate anticipated on a go-forward basis.-------------------------------------------------------------------------
                                  Three months ended        Six months ended
    Royalties by Commodity Type              June 30,                June 30,
    ($000s, except where noted)     2007        2006        2007        2006
    -------------------------------------------------------------------------
    Light crude oil and
     condensate                    1,623         873       1,874       2,392
      $/bbl                        10.23        8.55        6.34        9.53
      Average light crude oil
       and condensate royalty
       rate (%)                       16          13          10          16

    NGLs                           2,034         311       2,663         619
      $/bbl                        30.00       11.96       21.89       12.04
      Average NGLs royalty
       rate (%)                       59          21          48          23

    Heavy Oil                      1,416       2,513       2,936       3,612
      $/bbl                         5.08       12.37        4.38        8.31
      Average heavy oil royalty
       rate (%)                       13          25          12          23

    Natural Gas                    4,728       5,960      17,222      13,675
      $/mcf                         0.74        1.55        1.35        1.77
      Average natural gas royalty
       rate (%)                       10          27          18          26

    -------------------------------------------------------------------------
    Total                          9,801       9,657      24,695      20,298
    -------------------------------------------------------------------------
      $/boe                         6.29        9.92        7.67       10.03
    -------------------------------------------------------------------------
      Average total royalty
       rate (%)                       14          24          17          24
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Royalties, by Type
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30                 June 30
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Crown royalties, net of ARTC   6,229       5,759      13,234      12,894
    Indian Oil and Gas Canada
     royalties                       762         631       3,311       1,413
    Freehold & GORR                2,810       3,267       8,151       5,991
    -------------------------------------------------------------------------
    Total                          9,801       9,657      24,695      20,298
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Expenses
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30                 June 30
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Production                    19,778       9,321      34,750      18,488
    Transportation                 2,431       1,490       3,120       2,463
    General and administrative     4,332       3,810       9,236       6,407
    Interest and financing
     charges                       4,573       1,847       9,120       3,610
    Unit-based compensation        1,275       1,641       2,387       3,051
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Expenses per boe
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30,                June 30,
    ($ per boe)                     2007        2006        2007        2006
    -------------------------------------------------------------------------
    Production                     12.69        9.58       10.79        9.14
    Transportation                  1.56        1.53        0.97        1.22
    General and administrative      2.78        3.91        2.87        3.16
    Interest and financing
     charges                        2.93        1.90        2.83        1.78
    Unit-based compensation         0.82        1.69        0.74        1.51
    -------------------------------------------------------------------------Production Expenses

    For the three months ended June 30, 2007, production expenses totaled
$19.8 million, compared to $9.3 million recorded in 2006. During the second
quarter of 2007, production expenses averaged $12.69/boe, compared to
$9.58/boe over the same period in 2006. For the first quarter, production
expenses averaged $9.00/boe. The large increase in second quarter costs was
due to an underaccrual of prior period costs of approximately $4.9 million,
with approximately $3.1 million relating to 2006 and prior periods and with
approximately 53% of the total attributable to properties acquired from the
Prairie Schooner acquisition in September 2006. The majority of the total
prior period costs relate to third party and joint venture billings for
gathering and processing fees. The Trust has revised its estimates going
forward based upon the latest available information. This increase in
production expenses is also generally due to a different property mix; recent
reduced production volumes have also increased production expenses on a per
boe basis because of a significant fixed component of production expenses.
Excluding the impact of prior period costs, production expenses would have
been approximately $9.55/boe. Production expenses are expected to increase
later in the fourth quarter of 2007 as additional natural gas input costs are
required to operate the Kerrobert SAGD facility after startup.Production Expenses, by Commodity Type
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30,                June 30,
    ($000s except where noted)      2007        2006        2007        2006
    -------------------------------------------------------------------------
    Light crude oil and
     condensate                    1,833       1,784       4,168       3,650
      $/bbl                        11.56       17.49       14.11       14.56

    NGLs                             418         489         600         719
      $/bbl                         6.17       18.81        4.93       13.98

    Heavy oil                      5,612       1,974      11,017       3,901
      $/bbl                        20.17        9.72       16.44        8.98

    Natural gas                   11,915       5,074      18,965      10,218
      $/mcf                         1.89        1.32        1.48        1.32

    -------------------------------------------------------------------------
    Total                         19,778       9,321      34,750      18,488
    -------------------------------------------------------------------------
      $/boe                        12.69        9.58       10.79        9.14
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Transportation

    Transportation costs are expected to be approximately 2% to 3% of gross
revenues for the 2007 year. For the second quarter of 2007, transportation
costs averaged 3%, which is consistent with expectations.

    Operating Netback

    For the second quarter of 2007, corporate field operating netback (before
hedging) was $26.79/boe compared to $22.20/boe in 2006. This was a result of
increased commodity prices and reduced average royalties due to prior period
royalty adjustments, both of which were offset somewhat by adjustments for
prior period operating costs. By comparison, corporate field operating netback
(before hedging) for the first quarter of 2007 was $24.35/boe. After including
hedging activities, corporate field operating netback for the second quarter
was $30.53/boe compared to $21.92/boe in 2006.Field Operating Netback - Corporate (before hedging)
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30,                June 30,
    ($/boe)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Sales                          47.33       43.23       44.96       43.74
    Transportation                 (1.56)      (1.53)      (0.97)      (1.22)
    Royalties                      (6.29)      (9.92)      (7.67)     (10.03)
    Production expense            (12.69)      (9.58)     (10.79)      (9.14)
    -------------------------------------------------------------------------
    Field operating netback        26.79       22.20       25.53       23.35
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Field operating netback for natural gas for the second quarter of 2007
increased 62% to $4.68/mcf, compared to $2.89/mcf for 2006, reflecting the
stronger natural gas prices experienced in addition to prior period royalty
and production cost adjustments. After including hedging activities, field
operating netback for natural gas for the first quarter of 2007 was $5.71/mcf
compared to $2.89/mcf in 2006.

    Field Operating Netback - Natural Gas (before hedging)
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30,                June 30,
    ($/mcf)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Sales                           7.60        5.98        7.43        6.94
    Transportation                 (0.29)      (0.22)      (0.22)      (0.18)
    Royalties                      (0.74)      (1.55)      (1.35)      (1.77)
    Production expense             (1.89)      (1.32)      (1.48)      (1.32)
    -------------------------------------------------------------------------
    Field operating netback         4.68        2.89        4.38        3.67
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Field operating netback for crude oil and NGLs averaged $24.03/bbl for
the second quarter of 2007, down 24% compared to $31.58/bbl for 2006, compared
to a 10% decrease in the crude oil and NGLs sales price. Prior period
adjustments recorded in the quarter for royalties and production expenses
contributed primarily to a temporary increase in field operating netback for
crude oil and NGLs. After including hedging activities, field operating
netback for crude oil and NGLs was $22.77/boe compared to $30.76/boe in 2006.Field Operating Netback - Crude Oil and NGLs (before hedging)
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30,                June 30,
    ($/bbl)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Sales                          50.90       57.43       45.74       47.44
    Transportation                 (1.23)      (1.85)      (0.30)      (1.49)
    Royalties                     (10.06)     (11.17)      (6.87)      (8.99)
    Production expense            (15.58)     (12.83)     (14.52)     (11.23)
    -------------------------------------------------------------------------
    Field operating netback        24.03       31.58       24.05       25.73
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------General and Administrative

    Net general and administrative expenses for the three and six months
ended June 30, 2007 were $4.3 million and $9.2 million, respectively, compared
to $3.8 million and $6.4 million, respectively, for the same periods in 2006.
    The increase in the G&A expense from the respective 2007 periods as
compared to the same periods in 2006 is consistent with the increase in
staffing levels, higher compensation and other administrative costs as a
result of two acquisitions completed in 2006. The decrease in G&A on a per boe
basis is consistent with additional production volumes from those same
acquisitions.General and Administrative Expenses
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30,                June 30,
    ($000s except where noted)      2007        2006        2007        2006
    -------------------------------------------------------------------------
    Gross expenses                 5,872       5,117      12,282       8,930
    Capitalized                   (1,121)       (886)     (1,814)     (1,422)
    Recoveries                      (419)       (421)     (1,232)     (1,101)
    -------------------------------------------------------------------------
    Net expenses                   4,332       3,810       9,236       6,407
    -------------------------------------------------------------------------
    Net expenses, per unit ($/boe)  2.78        3.91        2.87        3.16
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------G&A expenses for the six month period ended June 30, 2007 do not include
the costs of the March 30, 2007 Special Meeting, which are presented
separately on the Statement of Income and discussed in the Special Meeting
Costs section of this report.

    Interest and Financing Charges

    True recorded $4.6 million of interest and financing charges in the three
months ended June 30, 2007 compared to $1.8 million in the same period of
2006. For the six months ended June 30, 2007, interest and financing charges
were $9.1 million compared to $3.6 million in the same period in 2006. The
increase in interest and financing charges for both the three and six month
periods ended June 30, 2007 compared to the same periods in 2006 is consistent
with the increase in bank debt. True's net debt at June 30, 2007 of
$221.0 million includes the $78.6 million liability portion of convertible
debentures, $142.2 million of bank debt and the balance a working capital
deficiency.Interest and Financing Charges
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30,                June 30,
    ($000s except where noted)      2007        2006        2007        2006
    -------------------------------------------------------------------------
    Interest and financing
     charges                       4,573       1,847       9,120       3,610
    Interest and financing
     charges ($/boe)                2.93        1.90        2.83        1.78

    Net debt including
     convertible debentures
     at quarter end              221,045     129,521     221,045     129,521
    Debt to periods cash flow
     from operations ratio
     annualized                     1.6x        2.0x        1.8x        1.8x

    Net debt excluding
     convertible debentures
     at quarter end              142,409      48,353     142,409      48,353
    Debt to periods cash flow
     from operations ratio
     annualized                     1.0x        0.7x        1.1x        0.7x
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Unit-Based Compensation

    Non-cash unit-based compensation expense for the three and six months
ended June 30, 2007 was $1.3 million and $2.4 million, respectively, compared
to $1.6 million and $3.0 million in 2006, respectively. The slight decrease in
the 2007 expense for both periods reflects reduced incentive rights being
granted in the first six months of 2007, compared to the same period in 2006,
in addition to a reduction in the estimated weighted average fair value of
incentive rights granted for more recent options.

    Capital Expenditures

    True invested $15.5 million on exploration and development activities
during the second quarter of 2007, compared to $17.4 million in the same
period in 2006. Following the execution of True's extensive Q1 drilling
program of 34 (24.0 net) wells, the main focus for the second quarter was on
completions and tie-ins of first quarter drills and further upgrades to the
Kerrobert SAGD facility. During the second quarter of 2007, True successfully
drilled 1 (0.8 net) natural gas well in the Pembina area of West Central
Alberta.Capital Expenditures
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30,                June 30,
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    Lease acquisitions and
     retention                       711         657       1,502       2,532
    Geological and geophysical    (3,455)        197       3,464         861
    Drilling and completion
     costs                        15,661      12,722      48,920      30,007
    Facilities and equipment       2,586       3,792       7,458       6,429
    -------------------------------------------------------------------------
      Exploration and
       development                15,503      17,368      61,344      39,829
    Corporate and property
     acquisitions                    649          68       1,354         192
    -------------------------------------------------------------------------
      Total capital expenditures
       - cash                     16,152      17,436      62,698      40,021
    Property dispositions - cash  (9,026)    (24,514)    (27,469)    (24,514)
    -------------------------------------------------------------------------
      Total net capital
       expenditures - cash         7,126      (7,078)     35,229      15,507
    -------------------------------------------------------------------------
    Corporate acquisitions -
     non-cash                          -      47,529           -      47,529
    Other - non-cash(1)              311        (208)       (313)        427
    -------------------------------------------------------------------------
    Corporate acquisitions
     and other                       311      47,321        (313)     47,956
    -------------------------------------------------------------------------
      Total capital expenditures   7,437      40,243      34,916      63,463
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Other includes current period's asset retirement obligations and unit
        based compensation capitalized.True holds an extensive land base. At June 30, 2007, True has
approximately 649,000 net undeveloped acres of land of its total developed and
undeveloped net acreage position of 1,057,000 net acres in Saskatchewan,
Alberta, and British Columbia.
    Dispositions during the first six months of 2007 consist of three
separate oil and gas property sales involving areas outside of the Trust's
core areas for future development. On March 30, 2007, True closed the sale of
its Columbia/Minehead and Sylvan Lake, Alberta properties. The net proceeds
received on these property sales after adjustments was an aggregate of
$18.4 million. On May 15, 2007, closed the sale of its Gage, Alberta
properties. The net proceeds received on this property sale after adjustments
was $9.0 million.
    The Trust continues to evaluate further opportunities with its
divestiture program.
    Subsequent to June 30, 2007, True closed the sale of two minor
properties. The net proceeds received on both of the property sales after
adjustments was $0.8 million and was used to pay down debt.
    At the end of the second quarter of 2007, the Trust had committed to
drill a total of 2 wells in Alberta and recomplete 1 well in Alberta with
varying commitment dates up to March 2008 pursuant to various farm-in
agreements with oil and gas companies. True expects to satisfy these various
drilling commitments at an estimated cost for True's interest of approximately
$3.5 million.

    Depletion, Depreciation and Accretion

    Depletion, depreciation and accretion (site restoration) expense for the
second quarter of 2007 was $45.4 million, compared to the $27.5 million for
the same period in 2006, reflecting the acquisition of Shellbridge at the end
of June 2006, Prairie Schooner in September 2006 in conjunction with increased
production volumes and True's active drilling program over 2006 and 2007.
True's DD&A rate for the second quarter of 2007 of $29.11/boe was higher than
$28.56/boe DD&A rate for the first quarter of 2007, which reflects the
adjustment to reserves after 2007 property dispositions.
    For the six month period ended June 30, 2007, True has excluded from the
depletion calculation $44.1 million for undeveloped land and $48.3 million for
estimated salvage.Depletion, Depreciation and Accretion Costs
    -------------------------------------------------------------------------
                                  Three months ended        Six months ended
                                             June 30,                June 30,
    ($000s except where noted)      2007        2006        2007        2006
    -------------------------------------------------------------------------
    Depletion                     44,738      22,592      90,374      47,755
    Depreciation                      84       4,732       1,395       8,569
    Accretion                        527         206       1,038         418
    -------------------------------------------------------------------------
      Total                       45,349      27,530      92,807      56,742
    -------------------------------------------------------------------------
    Per unit ($/boe)               29.11       28.28       28.83       28.04
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------The Trust's independent reserve report effective December 31, 2006 is
summarized in its Annual Information Form and can be found at www.sedar.com.

    Ceiling Test

    The Trust calculates a ceiling test quarterly and annually whereby the
carrying value of petroleum and natural gas properties is compared to
estimated future cash flow from the production of proved reserves. The ceiling
test is performed in accordance with the requirements of the Canadian
Institute of Chartered Accountants ("CICA") AcG-16 "Oil and Gas Accounting -
Full Cost, a two step process.
    The Trust performed a ceiling test calculation at June 30, 2007 resulting
in undiscounted cash flows from proved reserves and the unproved properties
not exceeding the carrying value of oil and gas assets. Consequently, True
performed stage two of the ceiling test assessing whether discounted future
cash flows from the production of proved plus probable reserves plus the
carrying cost of unproved properties, net of any impairment allowance, exceeds
the carrying value of its petroleum and natural gas properties. No impairment
in oil and gas assets was identified.
    At June 30, 2007, the Trust calculated the ceiling test using weighted
average prices of $38.92/bbl for heavy oil, $64.45/bbl for light and medium
gravity oil, and $39.80/bbl for NGLs, and $7.71/mcf for natural gas.

    Special Meeting Costs

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

    Asset Retirement Obligation

    As at June 30, 2007, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $27.1 million, compared to $11.8 million at June 30,
2006, for future abandonment and reclamation of the Trust's properties. For
the six month period ended June 30, 2007, the ARO decreased by $0.5 million
total as a result of accretion expense of $1.0 million, and $0.4 million net
changes in estimates and liabilities incurred on development activities,
offset by $0.9 million of liabilities released on dispositions.

    Income Taxes

    For the first six months of 2007, the Trust has recorded a provision for
capital taxes of $1.1 million compared to $1.5 million expensed in the same
period in 2006. Capital taxes are based on debt and equity levels of the Trust
at the end of the year in addition to a resource surcharge component of
provincial taxes calculated as a percentage of revenues. In the second quarter
of 2006, the federal government enacted legislation that eliminates federal
capital tax, retroactive to January 1, 2006. As a result, capital taxes on a
go-forward basis are based on only provincial capital taxes.
    Future income taxes arise from differences between the accounting and tax
bases of the Trust's assets and liabilities. For the first six months of 2007,
the Trust recognized a future income tax recovery provision of $21.5 million
compared to a recovery provision of $39.1 million in the same period in 2006.
The larger recovery for the 2006 period was primarily reflective of more
significant enacted tax rate reductions in 2006. On April 10, 2006 the Alberta
government enacted a decrease of 1.5 percent to the provincial corporate tax
rate. In addition, on June 6, 2006 the Federal government enacted a two
percent decrease to the federal corporate tax rate from January 1, 2008 to
January 1, 2010 and an elimination of the 1.12 percent federal surtax at
January 1, 2008. In addition, on June 12, 2007, the federal government further
reduced the general corporate tax rate by 0.5 percent starting 2011.
    Under our current structure, the operating entities make interest and
royalty payments to the Trust, which transfers taxable income to the Trust to
eliminate income subject to corporate and other income taxes in the operating
entities. With the new legislation, such amounts transferred to the Trust
could be taxable beginning in 2011 as distributions will no longer be
deductible for income tax purposes. At that time, True could claim tax pools
in its operating companies, reduce the income transferred to the Trust, and
pay all or a portion of distributions on a return of capital basis. Until
2011, under the terms of its Trust indenture, the Trust is required to
distribute amounts equal to at least its taxable income. In the event that the
Trust has undistributed taxable income in a taxation year (prior to 2011), an
additional special taxable distribution, subject to certain withholding taxes,
would be required by the terms of its trust indenture.
    The estimate of future taxes is based on the current tax status of the
Trust. Future events, which could materially affect future income taxes such
as acquisitions and dispositions and modifications to the distribution policy,
are not reflected under Canadian GAAP until the events occur and the related
legal requirements have been fulfilled. As a result, future changes to the tax
legislation could lead to a material change in the recorded amount of future
income taxes.
    The new legislation is not expected to directly affect our cash flow
levels and distribution policies until 2011 at the earliest.

    Enactment of the Tax on Income Trusts

    On June 12, 2007, the legislation implementing the new tax (the "SIFT
tax") on publicly traded income trusts and limited partnerships, referred to
as "Specified investment flow-through" ("SIFTs") entities (Bill C-52) received
third reading in the House of Commons and on June 22, 2007, Bill C-52 received
Royal assent. As a result, the tax was considered to be enacted for accounting
purposes in June 2007, which resulted in a $1.2 million future income tax
recovery amount being recorded to reflect current temporary differences
between the book and tax basis of assets and liabilities expected to be
remaining in the Trust in 2011. The SIFT tax announcement and the related
future income tax recovery did not affect our cash flow or distributions and
is not expected to affect our 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, we can increase
our equity by approximately $737 million between now and 2011 without
prematurely triggering the SIFT tax.
    Under the SIFT tax, distributions will not be deductible for income tax
purposes by SIFTs in 2011 and thereafter and any trust level taxable income
will be taxed at an approximate of the corporate income tax rate. The
resultant distributions will be considered taxable dividends to unitholders,
generally eligible for the dividend tax credit. Distributions representing a
return of capital will continue to be an adjustment to a unitholder's adjusted
cost base of trust units.
    Our Board of Directors and Management continue to review the impact of
this tax on our business strategy. At the present time, True believes some or
all of the following actions will or could result due to the enactment of the
SIFT tax:-   If structural or other similar changes are not made, the after-tax
        distribution yield in 2011 to taxable Canadian investors will remain
        approximately the same, however, the distribution yield in 2011 to
        tax-deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.)
        and foreign investors would fall by an estimated 31.5 percent and
        26.5 percent, respectively;
    -   A portion of True's cash flow could be allocated to the payment of
        the SIFT tax, or other forms of tax, and would not be available for
        distribution or re-investment;
    -   True could convert to a corporate structure to facilitate investing a
        higher proportion or all of its cash flow in exploration and
        development projects. Such a conversion and change to capital
        programs could result in a significant reduction to or elimination of
        distributions and/or dividends;
    -   True might determine that it is more economic to remain in the trust
        structure, at least for a period of time, and shelter its taxable
        income using tax pools and pay all or a portion of its distributions
        on a return of capital basis, likely at a lower payout ratio.
        Further, as the SIFT tax rate exceeds the corporate income tax rate
        that would be applicable to True, some corporate tax might be paid
        resulting in all or a portion of distributions being paid on a return
        of capital basis at a lower payout ratio.The Trust is reviewing all organizational structures and alternatives to
minimize the impact of the SIFT tax on our unitholders. While there can be no
assurance that the negative effect of the tax can be minimized or eliminated,
True and its advisors will continue to work diligently on these issues.

    The table below, provided by the Government of Canada in a backgrounder
accompanying its October 31, 2006 announcement, shows a simplified comparison
of the effects of the changes to investor tax rates in 2011:Current System          Proposed System
                              -----------------------------------------------
                                  Income                  Income
                                 portion                 portion
                                of trust       Large    of trust       Large
                                 distri-  corporation    distri-  corporation
    Investor                     butions   (dividend)    butions   (dividend)
    -------------------------------------------------------------------------
    Taxable Canadian individuals(1)   46%         46%       45.5%       45.5%
    Canadian tax-exempt investors      0%         32%       31.5%       31.5%
    Taxable U.S. investors(2)         15%         42%       41.5%       41.5%
    -------------------------------------------------------------------------

    (1) All rates in the table are as of 2011, and include both entity- and
        investor-level tax (as applicable). Rates for "taxable Canadian
        individuals" assume that top personal income tax rates apply and that
        provincial governments increase their dividend tax credit for
        dividends of large corporations.
    (2) Canadian taxes only. U.S. tax will also apply in most cases, net of
        any foreign tax credits.As at June 30, 2007, the operating subsidiaries and the Trust itself have
a total future income tax liability balance of $102.5 million. Canadian GAAP
requires that a future income tax liability be recorded when the book value of
assets exceeds the balance of tax pools. It further requires that a future tax
liability be recorded on an acquisition when a corporation acquires assets
with associated tax pools that are less than the purchase price.
    At June 30, 2007 the Trust and operating subsidiaries of the Trust had
approximately $507 million, net of partnership deferrals, in tax pools
available for deduction against future income as follows:-------------------------------------------------------------------------
                                                      Operating
    ($000s)                                  Trust  subsidiaries       Total
    -------------------------------------------------------------------------
    Intangible resource pools (net of
     partnership deferrals)                 15,105      331,946      347,051
    Undepreciated capital cost                   -      140,379      140,379
    Loss carryforwards (expire through
     2026)                                       -        5,624        5,624
    Unit issue costs                         8,262        5,499       13,761
    Other                                        -          243          243
    -------------------------------------------------------------------------
                                            23,367      483,691      507,058
    -------------------------------------------------------------------------

    Distributions

    Trust unitholders who held their trust units throughout the first six
months of 2007 received distributions of $0.48 per unit. For the six month
period ended June 30, 2007 the Trust declared $35.2 million in total
distributions as follows:

    -------------------------------------------------------------------------
    ($000s, except per unit amount)                Distribution
    Six month period ended June 30, 2007               Per Unit        Total
    -------------------------------------------------------------------------
    Distributions declared                            $    0.48    $  35,242
    -------------------------------------------------------------------------

    Distribution Paid History(1)

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

    -------------------------------------------------------------------------
                                     Distributions      Taxable    Return of
    Calendar Year                         per unit      Portion      Capital
    -------------------------------------------------------------------------
    2005 (two months)(2)                 $   0.480    $   0.456    $   0.024
    2006(3)                                  2.640        2.033        0.607
    -------------------------------------------------------------------------
    Cumulative to Dec. 31, 2006          $   3.120    $   2.489    $   0.631
    -------------------------------------------------------------------------
    2007 year to date                        0.480           (3)          (3)
    -----------------------------------------------
    Cumulative to June 30, 2007          $   3.600
    -------------------------------------------------------------------------

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

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

    Monthly Distributions

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

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

    (1) Anticipated ex-distribution dates for August and September. These
        dates are subject to change and/or confirmation by the Toronto Stock
        Exchange and will be confirmed by monthly press release.
    (2) Subject to confirmation, the Management and Board of the Trust
        continuously assesses distribution levels, in light of current
        commodity prices, hedge positions, production volumes, market
        conditions and other factors, and announces the distribution per unit
        amount on a monthly basis.During the first six months of 2007, the distributions were funded
directly from cash flows from operating activities.
    On January 15, 2007, the Trust announced its intention to convert to a
growth oriented, dividend paying intermediate exploration and production
company (the "Reorganization"), which was voted upon by securityholders at an
Annual and Special Meeting (the "Meeting") held on March 30, 2007. Further as
announced on February 15, 2007, the Board of True determined that no
distribution would be declared for the month of March 2007, which would
normally have been paid on April 16, 2007 to unitholders of record as at
March 30, 2007, pending the consideration of the Reorganization at the
Meeting.
    As a result of the outcome of the Meeting, wherein the Reorganization was
not approved, True remains a trust.
    In the second quarter of 2007, monthly distributions of $0.08 per unit
were declared and paid on May 15, 2007, June 15, 2007 and July 16, 2007.
Further, the Board has announced it has set a distribution policy for the
third quarter of 2007 at a monthly rate of $0.08 per unit, subject to monthly
confirmation, based on current commodity prices, hedging program, production
volumes and market conditions. This go-forward strategy for the distribution
level is consistent with providing a balance between providing income to
unitholders and funding for True's capital program required to further develop
its land base.

    Foreign Ownership Update

    Based on information from Trust records and information provided by
intermediaries holding Trust units for others, we estimate that, as of
July 18, 2007 approximately 29 percent of our Unitholders are non-Canadian
residents with the remaining 71 percent being Canadian residents. True's Trust
Indenture provides that not more than 40 percent of its trust units can be
held by non-Canadian residents.

    Liquidity and Capital Resources

    On May 31, 2007, the Trust completed its offering, including an over-
allotment option, for an aggregate of 9,430,000 trust units at $6.10 per unit
for gross proceeds of $57.5 million. The net proceeds of $54.4 million, after
deducting unit issue costs, was used to pay down debt.
    True's net debt as at June 30, 2007 was $221.0 million, representing
$142.2 million outstanding on the credit facility, $78.6 million in
convertible debentures (liability component) and the balance a net working
capital deficiency.
    During the six month period ended June 30, 2007, the Trust has reduced
its net debt by approximately $54.8 million. As at June 30, 2007, the working
capital deficiency has been reduced to $0.3 million from $36.3 million at
December 31, 2006. This was achieved as a result of many factors including the
proceeds received from the Trust's recent equity offering, proceeds received
from three property dispositions, maintaining sustainable distributions
compared to cash flows from operations and capital expenditure requirements in
the period and continued execution of the Trust's hedging program.
    The current credit facility consists of a $15 million demand operating
facility provided by one Canadian bank and a $185 million extendible revolving
term credit facility syndicated by two Canadian chartered banks, a U.S. bank,
a Canadian financial institution and one institutional lender. The revolving
period on the revolving term credit facility ends on June 29, 2008, unless
extended for a further 364 day period. Should the facilities not be renewed
they convert to 366 day non-revolving term facilities on the renewal date.
Further details of the credit facilities are disclosed in note 7 of the
consolidated financial statements. As at June 30, 2007, there is approximately
$57 million undrawn under these lending facilities.
    Management expects to be able to fund the $80 million capital expenditure
program for 2007 using cash flow from operations, available credit facilities,
the proceeds from the expected sale of certain non-core assets, and the
maintenance of sustainable distributions. If cash flows are other than
projected, capital expenditure levels are expected to be adjusted. The
practice of continually monitoring spending opportunities in comparison to
expected cash flow levels allows for adjustments to the capital program as
required.
    On June 15, 2006 the Trust completed a bought deal public offering of
86,250 7.5% convertible unsecured subordinated debentures at a price of $1,000
per Debenture for aggregate gross proceeds of $86,250,000.
    The debentures have a face value of $1,000 per debenture and a maturity
date of June 30, 2011. The debentures bear interest at an annual rate of 7.50%
payable semi-annually on June 30 and December 31 in each year commencing
December 31, 2006. The debentures are convertible at anytime at the option of
the holders into trust units of the Trust at a conversion price of $16.00 per
trust unit. The Trust will have the right to redeem all or a portion of the
debentures at a price of $1,050 per debenture after June 30, 2009 and on or
before June 30, 2010 and at a price of $1,025 per debenture after June 30,
2010 and before the maturity date. Upon maturity or redemption of the
debentures, the Trust may, subject to notice and regulatory approval, pay the
outstanding principal and premium (if any) on the debentures in cash or
through the issue of additional trust units at 95% of the weighted average
trading price of the trust units.
    As at July 31, 2007 the Trust had outstanding a total of 6,565,665
incentive units exercisable at an average exercise price of $11.23 per unit,
390,813 exchangeable shares (convertible, as at July 31, 2007 into an
aggregate of 306,878 trust units, subject to further adjustments based on
distributions made on trust units) and 79,715,595 trust units.
    On February 13, 2007, True announced it had identified certain small,
non- core properties, for possible disposition. The proceeds will be used to
fund capital expenditures and pay down debt. The Trust closed on two
dispositions at the end of the first quarter and an additional disposition in
May 2007. Subsequent to June 30, 2007, True closed on the sale of two minor
properties for total net proceeds after adjustments of $0.8 million, which was
used to pay down debt. The Trust will continue to evaluate opportunities under
its divestiture program.

    Business Prospects and 2007 Outlook

    Since its formation in September 2000, True Energy Inc. has experienced
significant growth in its production and land base. The Trust continues to
develop its core assets and conduct some exploration programs utilizing its
large inventory of geological prospects. In addition, the Trust will continue
to explore potential acquisition opportunities. Currently, the Trust's
producing properties are located in Saskatchewan, Alberta and British
Columbia.
    Following the results of the Special and Annual Meeting held on March 30,
2007, True remains a trust. Therefore, the focus will continue to be
maintaining sufficient cash flow to provide a balance between unitholder
distributions and funding of the Trust's capital program.
    Late in September 2006, the Trust completed the purchase of a facility in
the Kerrobert, Saskatchewan area and wells which has allowed the Trust to
begin implementation of the steam assisted gravity drainage ("SAGD") phase of
the project. Continuing through June 2007, the Trust converted a number of
existing wells to steam injectors and drilled additional wells that will be
used as producing well bores. During the first quarter of 2007, True completed
its initial drilling campaign of five cold producers and four thermal wells.
All five cold producers are on-line, currently averaging 60 bbls/d per well.
The four thermal wells are cased and awaiting equipping prior to the
conversion and subsequent steaming of the paired injectors. Execution of the
SAGD project is on track with expected steam injection for phase one to
commence at the end of the third quarter. Capital expenditure levels will be
adjusted as appropriate. The remainder of the 2007 capital program will
emphasize True's core areas of West Central Alberta and West Central
Saskatchewan. These expenditures will be mainly in the third quarter,
following up on successful development campaigns in the first quarter. It will
include facility modifications and conversion of existing producers to steam
injection service at the Kerrobert SAGD project. Continued participation in
what has been a highly successful non-operated drilling program in West
Central Alberta will also carry on in the third quarter.
    During the first quarter of 2007, new Kerrobert thermal wells were
drilled and facility upgrades continued throughout the second quarter.
Execution of the Kerrobert SAGD project is on track with expected steam
injection for phase one to commence at the end of the third quarter. We are
forecasting that the third quarter will be negatively impacted by additional
major third party plant turnarounds in West Central Alberta. Approximately
2,000 boe/d of production will be shut-in for a period during the third
quarter from our Willesden Green properties. During the shut-in period the
Trust will gather extensive pressure data on the tight gas reservoirs and
execute a number of workovers. The remaining behind pipe production,
workovers, and the Kerrobert SAGD start-up will provide visible growth prior
to the end of the 2007 year. With these forecasted turnarounds and completed
dispositions the Trust is anticipating 2007 annual average volumes of
approximately 17,000 boe/d, weighted approximately 67% towards natural gas.
    True further anticipates the US$/Cdn.$ exchange rate to average 0.91
through the 2007 year.
    The Trust continues to maintain a large undeveloped land base of
approximately 0.9 million (0.6 million net) acres and has identified a multi-
year drilling inventory of over 450 net locations.

    Business Risks and Uncertainties

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

    Environmental Regulation and Risk

    All phases of the oil and natural gas business present environmental
risks and hazards and are subject to environmental regulation pursuant to a
variety of federal, provincial and local laws and regulations. Compliance with
such legislation can require significant expenditures and a breach may result
in the imposition of fines and penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in
stricter standards and enforcement, larger fines and liability and potentially
increased capital expenditures and operating costs. In 2002, the Government of
Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to
reduce its greenhouse gas emissions to specified levels. There has been much
public debate with respect to Canada's ability to meet these targets and the
Government's strategy or alternative strategies with respect to climate change
and the control of greenhouse gases. Implementation of strategies for reducing
greenhouse gases whether to meet the limits required by the Protocol or as
otherwise determined could have a material impact on the nature of oil and
natural gas operations, including those of the Trust.
    The Federal Government released on April 26, 2007, its Action Plan to
Reduce Greenhouse Gases and Air Pollution (the "Action Plan"), also known as
ecoACTION and 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. Regarding large industry and industry related projects the
Government's Action Plan intends to achieve the following: (i) an absolute
reduction of 150 megatonnes in greenhouse gas emissions by 2020 by imposing
mandatory targets; and (ii) air pollution from industry is to be cut in half
by 2015 by setting certain targets. New facilities using cleaner fuels and
technologies will have a grace period of three years. In order to facilitate
the companies' compliance of the Action Plan's requirements, while at the same
time allowing them to be cost-effective, innovative and adopt cleaner
technologies, certain options are provided. These are: (i) in-house
reductions; (ii) contributions to technology funds; (iii) trading of emissions
with below-target emission companies; (iv) offsets; and (v) access to Kyoto's
Clean Development Mechanism.
    On March 8, 2007, the Alberta Government introduced Bill 3, the Climate
Change and Emissions Management Amendment Act, which intends to reduce
greenhouse gas emission intensity from large industries. Bill 3 states that
facilities emitting more than 100,000 tonnes of greenhouse gases a year must
reduce their emissions intensity by 12% starting July 1, 2007; if such
reduction is not initially possible the companies owning the large emitting
facilities will be required to pay $15 per tonne for every tonne above the 12%
target. These payments will be deposited into an Alberta-based technology fund
that will be used to develop infrastructure to reduce emissions or to support
research into innovative climate change solutions. As an alternate option,
large emitters can invest in projects outside of their operations that reduce
or offset emissions on their behalf, provided that these projects are based in
Alberta. Prior to investing, the offset reductions, offered by a prospective
operation, must be verified by a third party to ensure that the emission
reductions are real.
    Given the evolving nature of the debate related to climate change and the
control of greenhouse gases and resulting requirements, it is not possible to
predict the impact of those requirements on the Trust and its operations and
financial condition.

    Review of Alberta Royalty and Tax Regime

    On February 16, 2007, the Alberta Government announced that a review of
the province's royalty and tax regime (including income tax and freehold
mineral rights tax) pertaining to oil and gas resources, including oil sands,
conventional oil and gas and coalbed methane, will be conducted by a panel of
experts, with the assistance of individual Albertans and key stakeholders. The
review panel is to produce a final report that will be presented to the
Minister of Finance by August 31, 2007. At this time, the Trust cannot
determine the potential impact of any changes to the royalty rate on its
operations.

    Critical Accounting Estimates

    The reader is advised that the critical accounting estimates, policies,
and practices as described in the Management Discussion and Analysis in the
Trust's December 31, 2006 Annual Report continue to be critical in determining
True's unaudited financial results as at June 30, 2007. Except as described in
Note 3 of the attached unaudited interim consolidated financial statements,
there were no changes in accounting policies for the six month period ended
June 30, 2007.

    Legal, Environmental Remediation and Other Contingent Matters

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

    Controls and Procedures

    Disclosure Controls and Procedures

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

    Internal Controls over Financial Reporting

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

    Sensitivity Analysis

    The table below shows sensitivities to cash flow as a result of product
price and operational changes. This is based on actual prices received for the
three month period ended June 30, 2007 and average production volumes of
17,122 boe/d during that period, as well as the same level of debt outstanding
at June 30, 2007. Diluted weighted average trust units is based upon the
second quarter of 2007. These sensitivities are approximations only, and not
necessarily valid under other significantly different production levels or
product mixes. Hedging activities can significantly affect these
sensitivities. Changes in any of these parameters will affect cash flow as
shown in the table below:-------------------------------------------------------------------------
                                                                   Cash Flow
                                                                        from
                                               Cash Flow from     Operations
                                                   Operations    Per Diluted
                                                  (annualized)          Unit
    -------------------------------------------------------------------------
    Sensitivity Analysis                               ($000s)            ($)
    -------------------------------------------------------------------------
    Change of US $1/bbl WTI                             1,400           0.02
    Change of $0.10/ mcf                                2,000           0.03
    Change of US $0.01 Cdn/ US exchange rate            1,200           0.02
    Change in prime of 1%                               1,700           0.02
    -------------------------------------------------------------------------

    Selected Quarterly Consolidated Information

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

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


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


    2005 - Quarter ended
     (unaudited)(2)
    ($000s, except per unit
     amounts)                   March 31     June 30    Sept. 30     Dec. 31
    -------------------------------------------------------------------------
    Revenues before royalties
     and hedging                  22,441      33,663      44,510      61,056
    Cash flow from operations(1)  10,732      18,013      25,500      32,892
    Cash flow from operations
     per unit(1)
      Basic                        $0.63       $0.73       $1.04       $1.02
      Diluted                      $0.61       $0.72       $1.01       $1.00
    Net income (loss)              1,030       3,130       6,502       3,228
    Net income (loss) per unit
      Basic                        $0.06       $0.13       $0.26       $0.10
      Diluted                      $0.06       $0.13       $0.26       $0.10
    Net capital expenditures
     (cash)                       13,161      21,316      28,651      52,843
    Distributions declared             -           -           -      17,361
    Distributions per unit(2)          -           -           -       $0.48
    -------------------------------------------------------------------------
    (1) refer to "Non-GAAP Measures" in respect of the term "cash flow from
        operations" and "cash flows from operations per unit".
    (2) restated for changes in accounting policies and to reflect the
        consolidation of units effective November 2, 2005.The reasons for differences in results experienced from the first quarter
of 2007 to the second quarter of 2007 are described previously in this report.
    The quarterly results as presented for 2005 and 2006 varied significantly
for two main reasons: 1) the timing of acquisitions during 2005 and 2006 and
2) changes in commodity prices over those periods.
    During 2005, True completed two acquisitions. The acquisition of Meridian
Energy Corporation was closed effective March 15, 2005 and the reverse
takeover of TKE Energy Trust closed on November 2, 2005. In addition, True
completed the purchases of Shellbridge and Prairie Schooner on June 23, 2006
and September 22, 2006, respectively.
    True's revenue, net income, and cash flow from operations over 2005 and
2006 has reflected its production base after considering the timing of the
above noted acquisitions, the results of ongoing drilling activities, as well
as the changes in commodity prices, primarily that for natural gas. Beginning
in the first quarter of 2005 and continuing into the first quarter of 2006,
natural gas revenue was gradually increasing which resulted in a corresponding
increase in the Trust's petroleum and natural gas revenue, net income and cash
flow from operations in the period. This trend started to reverse in the
second quarter of 2006 with declining natural gas prices influencing a
corresponding relative decrease in the Trust's revenues, net income and cash
flows from operations.
    Net income also reflects an increase in DD&A rates primarily since the
November 2005 reverse takeover of TKE Energy Trust offset by future tax
recoveries beginning in the same period. The increase in the Trust's DD&A rate
is due to an increase in its depletable base as a result of the acquisitions
and further capital spending. Futures tax recoveries recognized since December
2005 result from additional interest deductions associated with True's new
Trust structure as well as reductions in rates for both federal and provincial
taxes which were enacted during 2006. Net income for the fourth quarter of
2006 is also reflective of a ceiling test write-down of $110.0 million and a
goodwill impairment charge of $169.8 million.TRUE ENERGY TRUST
    CONSOLIDATED BALANCE SHEETS
    As at June 30 and December 31 (unaudited)
    -------------------------------------------------------------------------

    ($000s)                                              2007           2006
    -------------------------------------------------------------------------
    ASSETS
    Current assets
      Accounts receivable                             $   56,934  $   73,199
      Deposits and prepaid expenses                        3,673       7,928
      Capital taxes receivable                             1,089           -
      Commodity contract asset (note 19)                   4,299           -
                                                   --------------------------
                                                          65,995      81,127
    Property, plant and equipment (note 6)               875,127     931,979
    Deferred financing charges (note 8)                        -       3,552
                                                   --------------------------
    Total assets                                      $  941,122  $1,016,658
                                                   --------------------------
                                                   --------------------------

    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities        $   59,531  $  107,431
      Distribution payable to unitholders                  6,377       8,433
      Capital taxes payable                                    -       1,513
      Current portion of obligations under capital
       lease                                                   -         111
      Commodity contract liability (note 19)                 343           -
                                                   --------------------------
                                                          66,251     117,488
    Long-term debt (note 7)                              142,153     157,904
    Convertible debentures (note 8)                       78,636      81,551
    Asset retirement obligations (note 9)                 27,129      26,605
    Future income taxes (note 14)                        102,544     123,861
                                                   --------------------------
    Total liabilities                                    416,713     507,409
                                                   --------------------------

    NON-CONTROLLING INTEREST
      Exchangeable shares of subsidiary (note 10)          4,083       4,153

    UNITHOLDERS' EQUITY
      Unitholders' capital (note 11)                     931,336     876,904
      Equity component of convertible debentures
       (note 8)                                            5,119       5,119
      Contributed surplus (note 12)                       15,407      12,818
      Deficit                                           (431,720)   (389,745)
      Accumulated other comprehensive income                 184           -
                                                   --------------------------
    Total unitholders' equity                            520,326     505,096
                                                   --------------------------
    Total liabilities and unitholders' equity         $  941,122  $1,016,658
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying selected notes to the consolidated financial statements.



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

                                        Three months              Six months
                                       ended June 30,          ended June 30,
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------

    REVENUES
      Petroleum and natural
       gas sales               $  74,991   $  43,004   $ 146,187   $  89,400
      Royalties                   (9,801)     (9,657)    (24,695)    (20,298)
      Gain (loss) on commodity
       contracts (note 19)         5,835        (273)      6,514        (273)
                               ----------------------------------------------
                                  71,025      33,074     128,006      68,829

    EXPENSES
      Production                  19,778       9,321      34,750      18,488
      Transportation               2,431       1,490       3,120       2,463
      General and administrative   4,332       3,810       9,236       6,407
      Interest and financing
       charges                     4,573       1,847       9,120       3,610
      Unit-based compensation
       (notes 11 and 12)           1,275       1,641       2,387       3,051
      Depletion, depreciation
       and accretion              45,349      27,530      92,807      56,742
      Special meeting costs
       (note 15)                       -           -       3,805           -
                               ----------------------------------------------
                                  77,738      45,639     155,225      90,761

    LOSS BEFORE TAXES             (6,713)    (12,565)    (27,219)    (21,932)

    TAXES (note 14)
      Capital taxes                  159         953       1,091       1,524
      Future income taxes
       (recovery)                 (8,627)    (25,861)    (21,456)    (39,094)
                               ----------------------------------------------
                                  (8,468)    (24,908)    (20,365)    (37,570)

    NET INCOME (LOSS) BEFORE
     NON-CONTROLLING INTEREST      1,755      12,343      (6,854)     15,638

    Non-controlling interest          14         100         (24)        136
                               ----------------------------------------------
                               ----------------------------------------------
    NET INCOME (LOSS)              1,741      12,243      (6,830)     15,502
                               ----------------------------------------------
    Net changes in cash flow
     hedges (net of tax of
     $0.2 million and
     $1.8 million,
     respectively)                  (409)          -      (3,565)          -
                               ----------------------------------------------
    COMPREHENSIVE INCOME
     (LOSS)                    $   1,332   $  12,243   $ (10,395)  $  15,502
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net income (loss) per trust
     unit
      Basic                    $    0.02   $    0.33   $   (0.10)  $    0.43
      Diluted                  $    0.02   $    0.33   $   (0.09)  $    0.42
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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              Six months
                                       ended June 30,          ended June 30,
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------
    UNITHOLDERS' CAPITAL
      Balance, beginning of
       period                  $ 876,920   $ 423,149   $ 876,904   $ 418,968
      Issued for cash (net of
       issue costs of
       $3.1 million)              54,386           -      54,386           -
      Issued to acquire
       Shellbridge (net of
       issue costs of
       $0.6 million                    -      67,668           -      67,668
      Exchangeable shares
       converted                      30       1,813          46       4,677
      Units issued pursuant to
       DRIP                            -      13,747           -      15,064
                               ----------------------------------------------
      Balance, end of period     931,336     506,377     931,336     506,377

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

    CONTRIBUTED SURPLUS
      Balance, beginning of
       period                     14,000       6,757      12,818       5,127
      Unit-based compensation
       expense (note 12)           1,407       1,967       2,589       3,597
                               ----------------------------------------------
      Balance, end of period      15,407       8,724      15,407       8,724

    DEFICIT
      Balance, beginning of
       period                   (415,085)    (54,717)   (389,745)    (31,826)
      Net income (loss)            1,741      12,243      (6,830)     15,502
      Impact of changes in
       accounting policy for
       financial instruments
       on January 1, 2007
       (net of tax of
       $0.05 million) (note 3)         -           -          97           -
      Distributions declared     (18,376)    (27,771)    (35,242)    (53,921)
                               ----------------------------------------------
      Balance, end of period    (431,720)    (70,245)   (431,720)    (70,245)

    ACCUMULATED OTHER
     COMPREHENSIVE INCOME
      Balance, beginning of
       period                        593           -           -           -
      Impact of new cash flow
       hedge accounting
       standards on January 1,
       2007 (net of tax of
       $1.8 million) (note 3)          -           -       3,749           -
      Reclassification to
       earnings of net hedging
       gains on commodity
       contracts (net of tax
       of $0.2 million and
       $1.8 million,
       respectively)                (409)          -      (3,565)          -
                               ----------------------------------------------
      Balance, end of period         184           -         184           -

    -------------------------------------------------------------------------
    TOTAL UNITHOLDERS' EQUITY  $ 520,326   $ 449,975   $ 520,326   $ 449,975
    -------------------------------------------------------------------------

    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              Six months
                                       ended June 30,          ended June 30,
    ($000s)                         2007        2006        2007        2006
    -------------------------------------------------------------------------

    Cash provided by (used in):
    CASH FLOW FROM OPERATING
     ACTIVITIES
    Net income (loss)          $   1,741   $  12,243   $  (6,830)  $  15,502
    Items not involving cash:
      Non-controlling interest
       (note 10)                      14         100         (24)        136
      Depletion, depreciation
       and accretion              45,349      27,530      92,807      56,742
      Unit-based compensation
       (note 12)                   1,275       1,641       2,387       3,051
      Unrealized gain on
       commodity contracts
       (note 19)                  (5,953)          -      (3,488)          -
      Amortization of deferred
       financing charges
       (note 8)                        -          35           -          35
      Accretion on convertible
       debentures (note 8)           393          37         784          37
      Future income taxes
       (recovery) (note 14)       (8,627)    (25,861)    (21,456)    (39,094)
      Capital taxes                    -         661           -      (1,028)
                               ----------------------------------------------
                                  34,192      16,386      64,180      35,381
      Change in non-cash
       working capital
       (note 13)                 (29,403)     (7,523)    (19,244)    (15,909)
                               ----------------------------------------------
                                   4,789       8,863      44,936      19,472

    CASH FLOW FROM (USED IN)
     FINANCING ACTIVITIES
      Increase (decrease) in
       bank debt                 (36,226)    (88,019)    (14,731)    (49,531)
      Obligations under capital
       lease                         (29)        (50)       (111)        (98)
      Issuance of convertible
       debentures                      -      86,250           -      86,250
      Deferred financing charges       -      (4,023)          -      (4,023)
      Issue of trust units for
       cash                       57,523           -      57,523           -
      Unit issue costs            (3,137)       (629)     (3,137)       (629)
      Payment of cash component
       of distributions          (11,999)    (12,721)    (37,298)    (37,495)
                               ----------------------------------------------
                                   6,132     (19,192)      2,246      (5,526)
      Change in non-cash
       working capital
       (note 13)                     186         893         243         893
                               ----------------------------------------------
                                   6,318     (18,299)      2,489      (4,633)

    CASH FLOW FROM (USED IN)
     INVESTING ACTIVITIES
      Additions to property,
       plant and equipment       (16,152)    (17,436)    (62,698)    (40,021)
      Corporate transaction
       costs                           -        (520)          -        (520)
      Proceeds on sale of
       property, plant and
       equipment                   9,026      24,514      27,469      24,514
                               ----------------------------------------------
                                  (7,126)      6,558     (35,229)    (16,027)
      Change in non-cash
       working capital
       (note 13)                  (3,981)     (2,340)    (12,196)     (4,030)
                               ----------------------------------------------
                                 (11,107)      4,218     (47,425)    (20,057)

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

      Change in cash                   -           -           -           -

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

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

    See accompanying selected notes to the consolidated financial statements.


           SELECTED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

    1.  STRUCTURE OF THE TRUST

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

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

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

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

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

    2.  SIGNIFICANT ACCOUNTING POLICIES

        The interim consolidated financial statements of the Trust have been
        prepared by management in accordance with generally accepted
        accounting policies in Canada. The unaudited interim consolidated
        financial statements have been prepared following the same accounting
        policies and methods of computation as the consolidated financial
        statements for the fiscal year ended December 31, 2006, except as
        described in note 3. The interim consolidated financial statement
        note disclosures do not include all of those required by Canadian
        generally accepted accounting principles ("GAAP") applicable for
        annual financial statements. Accordingly, the interim consolidated
        financial statements should be read in conjunction with the
        consolidated financial statements and the notes thereto contained in
        the Trust's annual report for the year ended December 31, 2006.

    3.  CHANGES IN ACCOUNTING POLICIES

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

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

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

        a. Financial instruments - recognition and measurement

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

        b. Derivatives

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

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

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

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

        c. Embedded derivatives

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

        d. Other comprehensive income

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

        e. Effective interest rate method

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

    4.  FUTURE CHANGES IN ACCOUNTING POLICIES

        a. Capital disclosures

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

        b. Financial instruments

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

    5.  ACQUISITIONS

        a. Acquisition of Prairie Schooner Petroleum Ltd.

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

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

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

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

        b. Acquisition of Shellbridge Oil & Gas, Inc.

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

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

           The purchase price equation is as follows:

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

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

    6.  PROPERTY, PLANT AND EQUIPMENT

        ($000s)
        ---------------------------------------------------------------------
                                                     Accumulated
                                                       depletion
                                                             and    Net book
        June 30, 2007                         Cost  depreciation       value
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                     $1,347,935   $  475,608   $  872,327
        Office furniture and equipment       3,942        1,142        2,800
        ---------------------------------------------------------------------
                                        $1,351,877   $  476,750   $  875,127
        ---------------------------------------------------------------------

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

        The Trust has excluded $44.1 million for undeveloped land and
        $48.3 million for estimated salvage from the depletion calculation
        during the six month period ended June 30, 2007.

        For the six month period ended June 30, 2007, the Trust capitalized
        $2.2 million of general and administrative expenses and $0.2 million
        of unit-based compensation expense directly related to exploration
        and development activities.

    7.  LONG-TERM DEBT

        The Trust has a $15 million demand operating facility provided by one
        Canadian bank and $185 million extendible revolving term credit
        facility syndicated by two Canadian chartered banks, a U.S. bank, a
        Canadian financial institution and one institutional lender. Amounts
        borrowed under the credit facility bear interest at a floating rate
        based on the applicable Canadian prime rate, U.S. base rates, LIBOR
        rates, plus between 0% and 1.95%, depending on the types of
        borrowings and the Trust's debt to cash flow ratio. Security is
        provided by a $400 million debenture containing a first ranking
        security interest on all of the Trust's assets. The credit facility
        is secured against all the assets of True Energy Inc., the Trust and
        all material subsidiaries. True has provided a negative pledge and
        undertaking to provide fixed charges over major petroleum and natural
        gas reserves in certain circumstances. A standby fee is charged on
        between 0.125% and 0.400% on the undrawn portion of the facility,
        depending on the Trust's debt to cash flow ratio.

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

        As at June 30, 2007, there was $10.0 million outstanding under the
        operating facility and $133.0 million outstanding under the revolving
        term credit facility. As at June 30, 2007, there is approximately
        $57.0 million undrawn under the facility.

        The borrowing base is currently scheduled for renewal on or before
        August 31, 2007.

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

    8.  CONVERTIBLE DEBENTURES

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

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

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

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

        Convertible debentures
        ---------------------------------------------------------------------
                                                           Debt       Equity
                                         Number of    Component    Component
                                        Debentures      ($000s)      ($000s)
        ---------------------------------------------------------------------
        Issued on June 15, 2006             86,250   $   81,131   $    5,119
        Accretion                                -          420            -
        ---------------------------------------------------------------------
        Balance, December 31, 2006          86,250       81,551        5,119
        ---------------------------------------------------------------------
        Impact of  change in
         accounting policy for
         financial instruments on
         January 1, 2007 (note 3)                -       (3,699)           -
        Accretion                                -          784            -
        ---------------------------------------------------------------------
        Balance, June 30, 2007              86,250   $   78,636   $    5,119
        ---------------------------------------------------------------------

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

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

    9.  ASSET RETIREMENT OBLIGATIONS

        The Trust's asset retirement obligations result from net ownership
        interests in petroleum and natural gas assets including well sites,
        gathering systems and processing facilities. The Trust estimates the
        total undiscounted amount of cash flows required to settle its asset
        retirement obligations is approximately $73.9 million which will be
        incurred between 2007 and 2053. A credit-adjusted risk-free rate of
        8.0 percent and an inflation rate of 2.4 percent were used to
        calculate the fair value of the asset retirement obligation.

        ---------------------------------------------------------------------
        ($000s)                                         June 30, December 31,
                                                           2007         2006
        ---------------------------------------------------------------------
        Asset retirement obligation, beginning
         of period                                   $   26,605   $   10,457
        Liabilities acquired through corporate
         acquisitions                                         -       13,704
        Liabilities incurred on development
         activities                                         390        1,210
        Changes in prior period estimates                    16          810
        Liabilities released on dispositions               (921)        (641)
        Accretion expense                                 1,039        1,065
        ---------------------------------------------------------------------
        Asset retirement obligation, end of period   $   27,129   $   26,605
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    10. EXCHANGEABLE SHARES OF SUBSIDIARY

        ---------------------------------------------------------------------
                                    June 30, 2007        December 31, 2006
                                 Number      Amount      Number      Amount
                                            ($000s)                  ($000s)
        ---------------------------------------------------------------------
        Balance, beginning of
         period                  403,536  $    4,153     788,558  $    9,709
        Non-controlling
         interest expense
         (recovery)                    -         (24)          -        (803)
        Exchanged for trust
         units                    (4,476)        (46)   (385,022)     (4,753)
        ---------------------------------------------------------------------
        Balance, end of period   399,060  $    4,083     403,536  $    4,153
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The exchange ratio is calculated monthly based on the five day
        weighted average trust unit trading price preceding the monthly
        effective date, and at June 30, 2007 was 0.77486. The exchangeable
        shares are not eligible for cash distributions; however cash
        distributions will increase the exchange ratio.

    11. UNITHOLDERS' CAPITAL

        a. Trust Units of True Energy Trust

        ---------------------------------------------------------------------
                                  June 30, 2007         December 31, 2006
                                 Number     Amount      Number        Amount
                                            ($000s)                  ($000s)
        ---------------------------------------------------------------------
        Balance, beginning of
         period               70,275,703 $   876,904  36,176,196 $   418,968
        Issued for cash (net
         of issue costs of
         $3.1 million)         9,430,000      54,386           -           -
        Issued to acquire
         Prairie Schooner (net
         of issue costs of
         $1.8 million)                 -           -  25,759,563     341,089
        Issued to acquire
         Shellbridge (net
         of issue costs of
         $0.6 million)                 -           -   4,389,366      67,669
        Exchangeable shares
         converted                 3,416          46     231,035       4,753
        Units issued
         pursuant to DRIP              -           -   3,574,185      42,608
        Issued to acquire
         property interest             -           -     145,358       1,817
        ---------------------------------------------------------------------
        Balance, end
         of period            79,709,119 $   931,336  70,275,703 $   876,904
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        b. Trust Unit Incentive Plan

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

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

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

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

           Unit Rights Continuity
           ------------------------------------------------------------------
                                                      Average
                                                     Exercise
                                                      Price(a)        Number
           ------------------------------------------------------------------


           Balance, December 31, 2006             $      14.18     5,429,831
           Granted                                $       6.18     2,080,000
           Forfeited                              $      13.14      (622,332)
           ------------------------------------------------------------------
           Balance, June 30, 2007                 $      11.46     6,887,499
           ------------------------------------------------------------------


    Unit Rights Outstanding
    -------------------------------------------------------------------------
                                                     Outstanding
                                                        Exercise
    Exercise                Exercise            At         Price   Remaining
    Price Before        Price Net of       June 30, Net of Price  Contractual
    Price Reductions      Reductions          2007  Reductions(b)     Life(b)
    -------------------------------------------------------------------------
    $ 5.89 - $ 6.70  $ 5.68 - $ 6.53     2,053,000       $  6.02         4.9
    $10.58 - $12.53  $ 9.67 - $11.52     1,294,500       $  9.91         4.3
    $13.74 - $14.83  $12.15 - $13.32       668,500       $ 12.58         4.0
    $15.92 - $16.70  $13.85 - $14.68       150,833       $ 14.18         3.8
    $18.25 - $20.98  $15.67 - $18.62     2,720,666       $ 15.86         3.4
    -------------------------------------------------------------------------
    $ 5.89 - $20.98  $ 5.68 - $18.62     6,887,499       $ 11.46         4.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Unit Rights Outstanding
    -----------------------------
               Exercisable
                       Exercise
               At         Price
          June 30, Net of Price
             2007  Reductions(b)
    -----------------------------
                -           N/A
                -           N/A
           76,666         12.79
           98,334       $ 14.19
        1,829,317       $ 15.86
    -----------------------------
        2,004,317       $ 15.66
    -----------------------------
    -----------------------------
    (a) Exercise prices reflect grant prices less reduction in exercise
        prices.
    (b) Based on weighted average unit rights outstanding.


        c. Employee Trust Unit Savings Plan

           Effective October 1, 2006, the Trust introduced an employee trust
           unit savings plan for the benefit of all employees. Under the
           savings plan, employees may elect to contribute up to 10 percent
           of their salary and contributions are used to fund the acquisition
           of trust units. The Trust matches employee contributions at a rate
           of $1.00 for each $1.00 contributed. Trust units are purchased in
           the open market by the plan administrator, an investment firm, on
           behalf of the participants in the plan. For the six months ended
           June 30, 2007, the Trust matched $0.2 million under the plan.

    12. CONTRIBUTED SURPLUS

        ---------------------------------------------------------------------
                                                       June 30,  December 31,
        ($000s)                                           2007          2006
        ---------------------------------------------------------------------
        Balance, beginning of period              $     12,818  $      5,127
        Unit-based compensation expense                  2,589         7,691
        ---------------------------------------------------------------------
        Balance, end of period                    $     15,407  $     12,818
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Unit-based Compensation

        During the six months ended June 30, 2007, the Trust granted
        2,080,000 unit incentive rights to employees and directors. During
        the six months ended June 30, 2007, the Trust recorded unit-based
        compensation of $2.6 million, of which $0.2 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, 2007 and the assumptions
        used in their determination are as noted below.

        ---------------------------------------------------------------------
                                              Six months ended June 30, 2007
        ---------------------------------------------------------------------
        Assumptions:
          Risk free interest rate (%)                                      4
          Expected life (years)                                            5
          Expected volatility (%)                                         24
        ---------------------------------------------------------------------
        Results:
          Weighted average fair value of incentive rights granted     $ 1.23
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    13. SUPPLEMENTAL CASH FLOW INFORMATION

        Cash Interest and Taxes Paid
        ---------------------------------------------------------------------
                                        Three months              Six months
                                       ended June 30,          ended June 30,
        ($000s)                     2007        2006        2007        2006
        ---------------------------------------------------------------------
        Cash paid:
          Interest            $    6,169  $    1,886  $    8,729  $    2,874
          Taxes (net of
           refunds)           $    1,206  $      560  $    3,699  $    3,214
        ---------------------------------------------------------------------


        Change in Non-cash Working Capital
        ---------------------------------------------------------------------
                                        Three months              Six months
                                       ended June 30,          ended June 30,
        ($000s)                     2007        2006        2007        2006
        ---------------------------------------------------------------------
        Changes in non-cash
         working capital
         items:
          Accounts receivable $    5,576  $   26,551  $   16,267  $   17,796
          Deposits and
           prepaid expenses          259        (213)      3,042        (599)
          Accounts payable
           and accrued
           liabilities           (37,986)    (35,308)    (47,904)    (36,243)
        Capital taxes
         receivable/payable       (1,047)          -      (2,602)          -
        ---------------------------------------------------------------------
                              $  (33,198) $   (8,970) $  (31,197) $  (19,046)
        ---------------------------------------------------------------------

        Changes related to
         operating activities $  (29,403) $   (7,523) $  (19,244) $  (15,909)
        Changes related to
         financing activities        186         893         243         893
        Changes related to
         investing activities     (3,981)     (2,340)    (12,196)     (4,030)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
                              $  (33,198) $   (8,970) $  (31,197) $  (19,046)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


    14. INCOME TAXES

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

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

        As a result of the enactment of the SIFT tax, the Trust recorded a
        future income tax recovery of $1.2 million to reflect current
        temporary differences between the book and tax basis of assets and
        liabilities expected to be remaining in the Trust in 2011. In
        accordance with generally accepted accounting principles, prior to
        the enactment, the Trust's temporary differences were not recorded as
        future income taxes. As at June 30, 2007, the total "temporary
        difference" (tax basis exceeds accounting basis) in the Trust is
        $11.8 million.

        As at June 30, 2007, the Trust's subsidiaries have tax basis of
        approximately $484 million that is available to shelter future
        taxable income. Included in this tax basis are estimated non-capital
        loss carry forwards of approximately $5.6 million that expire in
        years through 2026. In addition, the Trust has approximately $23
        million of tax basis.

        The provision for income taxes differs from the expected amount
        calculated by applying the combined Federal and Provincial corporate
        income tax rate of 32.94% (2006: 34.19%) to earnings before income
        taxes.

        This difference results from the following items:

        ---------------------------------------------------------------------
                                                    Six months ended June 30,
        ($000s)                                            2007         2006
        ---------------------------------------------------------------------
        Expected income tax expense (recovery)       $   (8,966)  $   (7,499)
        Distributions deducted for tax purposes         (10,490)     (13,127)
        Impact of SIFT legislation                       (1,165)           -
        Crown royalties and charges                           -        1,956
        Resource allowance                                    -       (1,717)
        Unit based compensation expense                     786          968
        Change in enacted tax rates                      (1,725)     (19,305)
        Other                                               104         (370)
        ---------------------------------------------------------------------
        Future income tax expense (recovery)            (21,456)     (39,094)
        Capital tax expense                               1,091        1,524
        ---------------------------------------------------------------------
        Total tax expense (recovery)                 $  (20,365)  $  (37,570)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    15. SPECIAL MEETING COSTS

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

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

    16. PER TRUST UNIT AMOUNTS

        ---------------------------------------------------------------------
                                        Three months              Six months
                                       ended June 30,          ended June 30,
                                    2007        2006        2007        2006
        ---------------------------------------------------------------------
        Basic trust units
         outstanding          79,709,119  41,837,743  79,709,119  41,837,743
        Dilutive effect of:
          Trust unit
           incentive rights
           outstanding         6,887,499   3,552,333   6,887,499   3,552,333
          Units issuable for
           exchangeable shares   309,216     258,445     309,216     258,445
          Units issuable for
           convertible
           debentures          5,390,625   5,390,625   5,390,625   5,390,625
        ---------------------------------------------------------------------
        Diluted trust units
         outstanding          92,296,459  51,039,146  92,296,459  51,039,146
        ---------------------------------------------------------------------
        Weighted average
         trust units
         outstanding          73,490,245  37,332,174  71,891,887  36,470,894
        Dilutive effect of
         exchangeable
         shares, trust unit
         incentive plan and
         convertible
         debentures(1)         2,320,716   1,156,883     309,216     941,528
        ---------------------------------------------------------------------
        Diluted weighted
         average trust
         units
         outstanding          75,810,961  38,489,057  72,201,103  37,412,422
        ---------------------------------------------------------------------
        (1)  A total of 4,875,999 (2006: 3,448,203) trust incentive units
             and 5,390,625 (2006: nil) trust units issuable pursuant to the
             conversion of convertible debentures were excluded from the
             calculation for the three month period ended June 30, 2007 as
             they were not dilutive. A total of 6,887,499 (2006: 3,435,717)
             trust incentive units and 5,390,625 (2006: nil) trust units
             issuable pursuant to the conversion of convertible debentures
             were excluded from the calculation for the six month period
             ended June 30, 2007 as they were not dilutive.

    17. RELATED PARTY TRANSACTIONS

        During the six month period ended June 30, 2007, the Trust paid
        $1.0 million (2006: $0.6 million) for legal services provided by a
        firm in which a current director and corporate secretary is a
        partner. These payments were made in the normal course of
        operations, on commercial terms, and therefore were recorded at the
        exchange amount.

    18. COMMITMENTS

        At the end of the second quarter of 2007, the Trust had committed to
        drill a total of 2 wells in Alberta and recomplete 1 well in Alberta
        with varying commitment dates up to March 2008 pursuant to various
        farm-in agreements with oil and gas companies. True expects to
        satisfy these various drilling commitments at an estimated cost for
        True's interest of approximately $3.5 million.

    19. FINANCIAL INSTRUMENTS

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

        ---------------------------------------------------------------------
        ($000s)                                 Carrying amount   Fair value
        ---------------------------------------------------------------------
        Commodity contract asset                    $     4,299  $     4,299
        Commodity contract liability                        343          343
        Long-term debt                                  142,153      142,153
        Convertible debentures
          Debt component                    78,636
          Equity component                   5,119
                                        ------------------------
                                                         83,755       84,956
        ---------------------------------------------------------------------

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

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

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

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

        For the six month period ended June 30, 2007, the statement of income
        included the following:

        ---------------------------------------------------------------------
        ($000s)                                                         2007
        ---------------------------------------------------------------------
        Change in fair value of derivative assets and liabilities
         included in
          Gain on commodity contracts                            $     6,514
        Interest expense                                               9,120
        ---------------------------------------------------------------------

        The Trust has entered into commodity price risk management
        arrangements as follows:
    -------------------------------------------------------------------------
                                                             Price
    Type             Period        Volume    Price Floor    Ceiling   Index
    -------------------------------------------------------------------------
    Oil put      July 1, 2007 to   2,000      $60.00 US           -      WTI
     option       Sept. 30, 2007    bbl/d

    Oil collar   Oct. 1, 2007 to   2,000      $65.00 US   $75.00 US      WTI
                  March 31, 2008    bbl/d

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

    Natural Gas  April 1, 2007 to  5,000     $ 7.00 CDN  $11.00 CDN   AECO C
     collar       Oct. 31, 2007     GJ/day

    Natural Gas  April 1, 2007 to  5,000     $ 7.00 CDN  $ 8.76 CDN   AECO C
     collar       Oct. 31, 2007     GJ/day

    Natural Gas  April 1, 2007 to  5,000     $ 7.00 CDN  $ 8.12 CDN   AECO C
     collar       Oct. 31, 2007     GJ/day

    Natural Gas   Nov. 1, 2007 to  5,000     $ 8.00 CDN  $ 9.05 CDN   AECO C
     collar        March 31, 2008   GJ/day

    Natural Gas  April 1, 2007 to  5,000     $ 7.10 CDN  $ 7.10 CDN   AECO C
     fixed        Oct. 31, 2007     GJ/day

    Natural Gas  April 1, 2007 to  5,000     $ 7.00 CDN  $ 7.00 CDN   AECO C
     fixed        Dec. 31, 2007     GJ/day
    -------------------------------------------------------------------------
    (1)  This contract was entered into subsequent to June 30, 2007.

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

        ($000s)                           Activity  Adjustments
                                            in the      for new
                                            period  standards(1)       Total
        ---------------------------------------------------------------------
        Gain (loss) on commodity contracts
        Realized(2)                     $    6,144    $  (3,118)   $   3,026
        Unrealized(3)                       (4,950)       8,438        3,488
        ---------------------------------------------------------------------
                                        $    1,194    $   5,320    $   6,514
        ---------------------------------------------------------------------
        (1)  Refer to note 3 which describes the transitional adjustments for
             adoption of the accounting for the new financial instrument
             standards in relation to the Trust's commodity contracts.
        (2)  Realized gains and losses on commodity contracts represent
             actual cash settlements and other amounts paid under these
             contracts.
        (3)  Unrealized gains and losses on commodity contracts represent
             non-cash adjustments for changes in the fair value of these
             contracts during the period.True Energy Trust is a Calgary-based oil and natural gas trust. True is
an open-ended, incorporated investment trust governed by the laws of the
Province of Alberta. The purpose of the Trust is to indirectly explore for,
develop and hold interests in petroleum and natural gas properties, through
investments in securities of subsidiaries and net profits interests. The trust
structure allows individual unitholders to participate in the cash flow of the
business. Cash flow is realized from the Trust's subsidiaries' ownership of
natural gas and petroleum properties and related facilities. Trust units of
True trade on the Toronto Stock Exchange ("TSX") under the symbol TUI.UN.

    %SEDAR: 00021401E



Bellatrix Exploration Ltd.
1920, 800 5th Avenue SW
Calgary, Alberta T2P 3T6
Main: 403-266-8670
Fax: 403-264-8163
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Bellatrix Exploration
Investor Relations
investor.relations@bxe.com
Emergency Contact
1-403-266-8670