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True Energy Trust announces first quarter 2007 financial results


View All News Releases May 9, 2007

    TSX: TUI.UN

    CALGARY, May 9 /CNW/ - (TSX: TUI.UN) True Energy Trust ("True" or the
"Trust") is pleased to announce its financial and operating results for the
three months ended March 31, 2007. Highlights from the quarter include:-   During the first quarter of 2007, True achieved a 97% success rate in
        the drilling or participation in 34 (24.0 net) wells, resulting in
        16 (8.6 net) natural gas wells, 15 (12.9 net) oil wells, 2 (2.0 net)
        stratagraphic test oil wells and 1 (0.5 net) dry holes. True
        successfully participated in or drilled 20 (10.4 net) wells in
        Alberta, and 14 (13.1 net) wells in Saskatchewan. The focus of True's
        drilling program for the first quarter was on the West Central
        Alberta area and the further execution of True's steam assisted
        gravity drainage ("SAGD") project in the Kerrobert, Saskatchewan
        heavy oil area.

    -   Further to our press release dated March 15, 2007, we announced a
        restructuring of our senior management team for May 2007. We are
        pleased to announce that effective May 14, 2007 Wayne M. Chorney will
        join True in the capacity of President and Chief Operating Officer,
        bringing with him 23 years of industry experience.

    -   True generated average sales volumes for the 2007 first quarter of
        18,461 boe per day, a 58% increase from 11,672 boe per day in the
        first quarter of 2006. Sales volumes decreased 7% from the fourth
        quarter 2006 volumes. This takes into account the impact of
        curtailment in production at the Trust's Kerrobert project during
        offset drilling of additional wells necessary for further
        implementation of the SAGD project and reduced volumes of
        approximately 420 boe per day at the Trust's Mantario heavy oil
        project due to reservoir performance. True is reviewing strategies to
        mitigate continued impact during the remainder of the year.

    -   Cash flow from operations(*) for the first quarter was $30.0 million
        on gross sales of $71.2 million compared to cash flow from
        operations(*) of $19.0 million on gross sales of $46.4 million for
        the same period in 2006. The increase in cash flow for the 2007 first
        quarter was the result of higher production volumes offset by lower
        natural gas prices. True's realized natural gas prices in the 2007
        first quarter averaged $7.26/mcf compared to $7.89/mcf for the first
        quarter of 2006.

    -   Total capital expenditures for 2007 first quarter, excluding
        corporate and property acquisitions and dispositions, were
        $45.8 million compared to $22.6 million in 2006. This increase
        reflects the execution of True's successful drilling program in the
        quarter.

    -   Property dispositions were closed at the end of the first quarter for
        net proceeds of $18.4 million.

    -   True recently entered into two new commodity price risk management
        contracts: 1) a oil put option with a West Texas Intermediate ("WTI")
        reference crude oil price floor of US$60.00 per barrel on
        2,000 barrels per day for the third quarter of 2007; and 2) an
        additional WTI reference crude oil costless collar with a floor price
        of US$65.00 per barrel and a ceiling price of US$75.00 per barrel on
        2,000 barrels per day for the fourth quarter of 2007 and the first
        quarter of 2008. True has currently hedged approximately 36% of
        current natural gas production for the second quarter and third
        quarters of 2007 and approximately 17% is hedged for the fourth
        quarter. Approximately 34% of current oil and NGL volume is hedged in
        the second quarter and 31% is hedged in each of the third and fourth
        quarters of 2007 and the first quarter of 2008.

    -   True maintains a large undeveloped land base of 1.0 million
        (0.7 million net) acres.

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

    True's first quarter report is presented below.


                                 HIGHLIGHTS

    -------------------------------------------------------------------------
                                                 Three months ended March 31
                                                          2007          2006
    -------------------------------------------------------------------------
    FINANCIAL (unaudited)
    (CDN$000s except unit and per unit amounts)
    Revenue (before royalties and hedging(1))           71,196        46,396
    Cash flow from operations(2)                        29,988        18,995
      Per basic trust unit                               $0.43         $0.52
      Per diluted trust unit(3)                          $0.42         $0.52
    Net income (loss)                                   (8,571)        3,259
      Per basic trust unit                         $     (0.12)  $      0.09
      Per diluted trust unit(3)                    $     (0.12)  $      0.09
    Distributions paid                                  16,866        26,150
      Per unit                                     $      0.24   $      0.72
    Payout ratio before DRIP(4)(5)                          35%          246%
    Payout ratio after DRIP(4)(5)                           35%          234%
    -------------------------------------------------------------------------
    Exploration and development                         45,841        22,451
    Corporate and property acquisitions                    705           124
    -------------------------------------------------------------------------
    Capital expenditures - cash                         46,546        22,585
    Property dispositions - cash                       (18,443)            -
    Other - non-cash                                       624           635
    -------------------------------------------------------------------------
    Total capital expenditures - net                    28,727        23,220
    -------------------------------------------------------------------------
    Long-term debt                                     178,379             -
    Convertible debentures                              78,243             -
    Bank debt                                                -       109,853
    Working capital deficiency                          32,450        29,758
    -------------------------------------------------------------------------
    Total net debt                                     289,072       139,611
    -------------------------------------------------------------------------
    Total assets                                       979,160       734,489
    Unitholders' equity                                481,547       375,189
    -------------------------------------------------------------------------
    OPERATING
    Daily sales volumes
      Crude oil and NGLs                 (bbls/d)        6,472         4,507
      Natural gas                         (mcf/d)       71,931        42,992
      Total oil equivalent                (boe/d)       18,461        11,672
    Average prices
      Crude oil and NGLs                  ($/bbl)        41.26         39.28
      Crude oil and NGLs (including
       hedging(1))                        ($/bbl)        43.59         39.28
      Natural gas                         ($/mcf)         7.26          7.89
      Natural gas (including hedging(1))  ($/mcf)         7.15          7.89
      Total oil equivalent                ($/boe)        42.74         44.22
      Total oil equivalent (including
       hedging(1))                        ($/boe)        43.15         44.22
    Statistics
      Operating netback                   ($/boe)        24.36         24.43
      Operating netback (including
       hedging(1))                        ($/boe)        24.76         24.43
      Production expenses                 ($/boe)         9.01          8.73
      General & administrative            ($/boe)         2.95          2.47
      Royalties as a % of sales after
       transportation                                       21%           23%

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


    -------------------------------------------------------------------------
                                                 Three months ended March 31
                                                          2007          2006
    -------------------------------------------------------------------------
    TRUST UNITS
    Trust units outstanding                         70,276,890    36,399,240
    Trust unit incentive rights outstanding          5,227,333     3,273,165
    Units issuable for exchangeable shares             303,547       334,372
    Units issuable for convertible debentures        5,390,625             -
    -------------------------------------------------------------------------
    Diluted trust units outstanding                 81,198,395    40,006,777
    Diluted weighted average trust units(3)         70,579,317    36,630,699
    -------------------------------------------------------------------------
    TRUST UNIT TRADING STATISTICS

    (CDN$, except volumes) based on intra-day trading
    High                                                  7.47         21.30
    Low                                                   4.87         12.99
    Close                                                 5.85         15.57
    Average daily volume                               601,721       388,648
    -------------------------------------------------------------------------


    (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 Management Discussion and Analysis ("MD&A") 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 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 March 31, 2007 303,547 (2006: 334,372) trust
        units were added to the 70,275,770 (2006: 36,296,327) weighted
        average number of trust units outstanding during the period for the
        dilutive effect of exchangeable shares. A total of 5,227,333 (2006:
        3,273,165) 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 March 31, 2007 as they were not
        dilutive. To calculate weighted average diluted cash flow from
        operations for the three month period ended March 31, 2007, a total
        of $1.98 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 75,969,942 under this
        calculation.

    (4) "Payout ratio" refers to distributions measured as a percentage of
        cash flow from operating activities including the change in non-cash
        working capital balances. Previously, until the second quarter ended
        June 30, 2006, the Trust had calculated the payout ratio as
        distributions divided by cash flow from operations, which excludes
        the change in non-cash working capital balances. This change in
        calculation of the payout ratio is consistent with recent staff
        notices provided by the Canadian Securities Administrators in respect
        of income trusts.

    (5) DRIP refers to distributions reinvested pursuant to the Premium
        Distribution™ Reinvestment, Distribution Reinvestment and Optional
        Trust Unit Purchase Plan.


                            REPORT TO UNITHOLDERSThe first quarter of 2007 marks the execution of an active and very
successful drilling program. Accomplishments for the first quarter ended
March 31, 2007 include:

    Distributions

    In the first quarter of 2007, monthly distributions of $0.12 per unit
were declared and paid on February 15, 2007 and March 15, 2007. Following the
results of True's Special and Annual Meeting, the Board has announced it has
set a distribution policy for the second 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 first quarter production averaged 18,461 boe/d as compared to
11,672 boe/d for the same period in 2006, representing a 58% increase. Sales
volumes decreased 7% from the fourth quarter 2006 volumes. This takes into
account the impact of curtailment in production at the Trust's Kerrobert
project during offset drilling of additional wells necessary for further
implementation of the SAGD project and reduced volumes of approximately 420
boe/d at the Trust's Mantario heavy oil project due to reservoir performance.
True is reviewing strategies to mitigate continued impact during the remainder
of the year.
    Production for the remainder of 2007, considering Q1 drilling results and
further planned drilling activities and property divestitures for later in
2007, is anticipated to average approximately 18,000 - 19,000 boe/d. The
decrease in production in the first quarter of 2007 reflects shut-in
production at Kerrobert as facility upgrades and new steam injection wells
were being drilled, which is expected to materially increase production later
in the year.

    Financial

    Cash flow from operations for the first quarter was $30.0 million on
gross sales of $71.2 million compared to cash flow from operations of
$19.0 million on gross sales of $46.4 million for the same period in 2006. The
increase in cash flow for the 2007 first quarter was the result of higher
production volumes offset by lower natural gas prices. True's realized natural
gas prices in the 2007 first quarter averaged $7.26/mcf compared to $7.89/mcf
for the first quarter of 2006.
    The net loss for the 2007 first quarter was $8.6 million compared to net
income of $3.3 million in first quarter of 2006. This is primarily reflective
of increased cash flow from operations, offset by higher depletion,
depreciation and accretion charges from recent 2006 acquisitions.

    Drilling

    During the first quarter of 2007, True achieved a 97% success rate in the
drilling or participation in 34 (24.0 net) wells, resulting in 16 (8.6 net)
natural gas wells, 15 (12.9 net) oil wells, 2 (2.0 net) stratagraphic test oil
wells and 1 (0.5 net) dry holes. True successfully participated in or drilled
20 (10.4 net) wells in Alberta, and 14 (13.1 net) wells in Saskatchewan. The
focus of True's drilling program for the first quarter was on the West Central
Alberta area and the further execution of True's SAGD project in the
Kerrobert, Saskatchewan heavy oil area.

    Dispositions

    Dispositions during the first three months of 2007 consisted of two
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 both property sales after adjustments was an aggregate of
$18.4 million and was used to pay down debt. The properties disposed of had
production of approximately 360 boe/d. True continues to evaluate further
opportunities with its divestiture program.

    Liquidity

    True's net debt as at March 31, 2007 was $289.1 million, representing
$178.4 million outstanding on the credit facility, $78.2 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 $210 million extendible revolving
term credit facility syndicated by the Canadian chartered bank, a U.S. bank, a
foreign bank and one institutional lender. As at March 31, 2007, there is
approximately $45 million available 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) a oil put option with a West Texas Intermediate ("WTI") reference crude oil
price floor of US$60.00 per barrel on 2,000 barrels per day for the third
quarter of 2007; and 2) an additional WTI reference crude oil costless collar
with a floor price of US$65.00 per barrel and a ceiling price of US$75.00 per
barrel on 2,000 barrels per day for the fourth quarter of 2007 and the first
quarter of 2008. As of May 8, 2007, the Trust has hedged volumes of
2,200 bbls/d of crude oil and 25,000 GJ/d of natural gas for the second
quarter 2007, 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 11,740 GJ/d of natural gas
for the fourth quarter 2007, and 2,000 bbls of crude oil for the first quarter
of 2008. The Trust will continue its hedging strategies during 2007 focusing
on maintaining sufficient cash flow to fund True's unitholder distributions
and capital program.

    Personnel Announcements

    Further to our press release dated March 15, 2007, we announced a
restructuring of our senior management team for May 2007. We are pleased to
announce that effective May 14, 2007 Wayne M. Chorney will join True in the
capacity of President and Chief Operating Officer, bringing with him 23 years
of industry experience. I will assume the role of Chairman and remain as Chief
Executive Officer of True. As well, William C. Dunn, current Chairman of True,
will assume the role of Lead Independent Director of True.
    In addition, as announced on April 30, 2007, we are pleased to report the
appointment of Doug Baker, B.Comm, FCA and Keith E. Macdonald, CA to the Board
of True. Mr. Baker and Mr. Macdonald bring significant financial and industry
experience to the Board and have both been appointed to the Audit Committee.
Mr. James Saunders has decided to resign from the Board effective immediately.
On behalf of the Board I would like to thank Mr. Saunders for his
contribution.
    As a result of these changes to our senior management team and the
additions to the Board, we believe True is very well positioned for the
future.

    Paul R. Baay
    President & CEO
    May 9, 2007MANAGEMENT'S DISCUSSION AND ANALYSISMay 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 months
ended March 31, 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, May 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 terms "payout
ratio" and "distributable cash" which are not recognized measures under
Canadian GAAP. Management uses payout ratio to refer to distributions measured
as a percentage of cash flow available for development and acquisition
opportunities as well as overall sustainability of distributions. True
calculates this measure consistent with recent staff notices provided by the
Canadian Securities Administrators in respect of income trusts. 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, effects of
drilling or wells to be tied-in, 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, 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 $30.0 million ($0.42 per
diluted unit) for the three months ended March 31, 2007, up 58% from the
$19.0 million ($0.52 per diluted unit) for the first quarter of 2006. Lower
commodity prices, despite increased volumes, and increased average outstanding
trust units were the primary factors contributing to the decrease in cash flow
per diluted unit.
    True generated a net loss of $8.6 million ($(0.12) per diluted unit) in
the first quarter of 2007 compared to net income of $3.3 million ($0.09 per
diluted unit) in 2006. Net loss per unit in the first quarter of 2007 was
impacted primarily as a result of an increase in cash flow from operations,
offset 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, and the
associated higher production volumes.Cash Flow From Operations and Net Income
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except per unit amounts)                      2007          2006
    -------------------------------------------------------------------------
    Cash flow from operations                           29,988        18,995
      Basic   ($/unit)                                    0.43          0.52
      Diluted ($/unit)                                    0.42          0.52

    Net income (loss)                                   (8,571)        3,259
      Basic   ($/unit)                                   (0.12)         0.09
      Diluted ($/unit)                                   (0.12)         0.09
    -------------------------------------------------------------------------

    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 March 31,
    ($000s, except per unit amounts)                      2007          2006
    -------------------------------------------------------------------------
    Cash flow from operations                           29,988        18,995
    Change in non-cash working capital                  18,227        (8,386)
    -------------------------------------------------------------------------
    Cash flow from operating activities                 48,215        10,609
    Funding from long-term debt and DRIP                     -        15,541
    Cash withheld to fund capital and other
     expenditures                                      (31,349)            -
    -------------------------------------------------------------------------
    Distributions paid                                  16,866        26,150
    Accumulated distributions, beginning of period     141,716        17,361
    -------------------------------------------------------------------------
    Accumulated distributions, end of period           158,582        43,511
    -------------------------------------------------------------------------
    Distributions per unit for outstanding units
     in the period                                        0.24          0.72
    Accumulated distributions per unit,
     beginning of year                                    3.12          0.48
    -------------------------------------------------------------------------
    Accumulated distributions per unit, end of year       3.36          1.20
    -------------------------------------------------------------------------

    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.

    Payout Ratio
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except percentages)                           2007          2006
    -------------------------------------------------------------------------
    Cash flow from operations                           29,988        18,995
    Change in non-cash working capital                  18,227        (8,386)
    -------------------------------------------------------------------------
    Cash flow from operating activities                 48,215        10,609
    -------------------------------------------------------------------------

    Distributions paid before DRIP                      16,866        26,150
    DRIP                                                     -        (1,317)
    -------------------------------------------------------------------------
    Distributions after DRIP                            16,866        24,833
    -------------------------------------------------------------------------
    Payout ratio before DRIP                                35%          246%
    Payout ratio after DRIP                                 35%          234%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Payout ratio refers to distributions measured as a percentage of cash
flow from operating activities including the change in non-cash working
capital balances. Previously, until the second quarter ended June 30, 2006,
the Trust had calculated the payout ratio as distributions divided by cash
flow from operations, which excludes the change in non-cash working capital
balances. This change in calculation of the payout ratio is consistent with
recent staff notices provided by the Canadian Securities Administrators in
respect of income trusts.

    Sales Volumes

    Sales volumes for the first three months of 2007 averaged 18,461 boe/d,
an increase of 58% compared to 11,672 boe/d reported in 2006. This increase
was due to a combination of results from drilling activity and the
acquisitions of Shellbridge effective June 23, 2006 and Prairie Schooner
effective September 22, 2006. Production for the first quarter of 2007 is down
by 7% from average sales volumes of 19,747 boe/d during the fourth quarter of
2006. The decrease from fourth quarter volumes was a result of the impact of
curtailment in production at the Trust's Kerrobert project during offset
drilling of additional wells necessary for further implementation of the steam
assisted gravity drainage ("SAGD") project and reduced volumes of
approximately 420 boe per day at the Trust's Mantario heavy oil project due to
reservoir performance. True is reviewing strategies to mitigate continued
impact during the remainder of the year. At the end of the first quarter, 17
wells were awaiting down-hole completion and/or completion of production
facilities. Work is ongoing in the second quarter as ground and weather
conditions permit. 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 March 31, 2007, the weighting towards
natural gas production averaged 65% compared to 61% in the same period in
2006. Heavy oil sales made up 24% of total production for the first quarter of
2007 compared to 22% in the same period in 2006. The increase in heavy oil
weighting from the first quarter of 2006 to that in 2007 was due to the
addition of primarily heavy oil weighted assets from Shellbridge at the end of
the second quarter of 2006, offset by certain shut-in heavy oil production at
Kerrobert during the first quarter of 2007. The September 2006 acquisition of
Prairie Schooner 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 64%.Sales Volumes
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
                                                          2007          2006
    -------------------------------------------------------------------------
    Natural gas                           (mcf/d)       71,931        42,992
    -------------------------------------------------------------------------
    Heavy oil                            (bbls/d)        4,355         2,571
    Light oil and condensate             (bbls/d)        1,519         1,653
    NGLs                                 (bbls/d)          598           283
    -------------------------------------------------------------------------
    Total crude oil and NGLs             (bbls/d)        6,472         4,507
    -------------------------------------------------------------------------
    Total boe/d                             (6:1)       18,461        11,672
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Sales of natural gas averaged 71.9 mmcf/d for the first three months of
2007, compared to 43.0 mmcf/d in 2006, an increase of 67%. In comparison,
natural gas volumes averaged 73.8 mmcf/d for the fourth quarter of 2006.
    Crude oil and NGL sales for the first three months of 2007 averaged
6,472 bbls/d up 44% from average sales of 4,507 bbls/d in 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 fourth quarter of 2006 were 7,440 bbls/d; the
decrease from the fourth quarter of 2006 to the first quarter of 2007 is due
to a reduction in heavy oil volumes.


    Commodity Prices

    The impact of changes in the Canadian dollar from the conversion of US
dollar based commodities prices marginally reduced profitability during the
first three months of 2007 when compared to the same period in 2006. The
U.S./Canadian exchange rate changed 1% from an average of 0.8662 in 2006 to
0.8535 in 2007.

    Average Commodity Prices
    -------------------------------------------------------------------------
                                   Three months ended March 31,
                                            2007          2006      % change
    -------------------------------------------------------------------------
    Exchange rate (US$/Cdn$)              0.8535        0.8662            (1)

    Natural gas:
    NYMEX (US$/mmbtu)                       7.17          7.84            (9)
    Alberta spot ($/mcf)                    7.00          7.34            (5)
    True's average price ($/mcf)            7.26          7.89            (8)
    True's average price
     (including hedging) ($/mcf)            7.15          7.89            (9)

    Crude oil:
    WTI (US$/bbl)                          58.27         63.34            (8)
    Edmonton par - light oil ($/bbl)       67.73         69.27            (2)
    Bow River - medium/heavy oil ($/bbl)   49.73         40.19            24
    Hardisty Heavy - heavy oil ($/bbl)     42.50         30.54            39
    True's average prices ($/bbl)
      Light crude and condensate           55.48         58.32            (5)
      Light crude and condensate
       (including hedging)                 65.39         58.32            12
      NGLs                                 38.83         50.25           (23)
      Light crude oil, condensate
       and NGLs                            50.77         57.14           (11)
      Light crude oil, condensate
       and NGLs (including hedging)        57.88         57.14             1
      Heavy crude oil                      36.64         25.84            42
      Total crude oil and NGLs             41.26         39.28             5
      Total crude oil and NGLs
       (including hedging)                 43.59         39.28            11
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------True's natural gas is primarily sold on the daily spot market. During
first three months of 2007, the Alberta Spot reference price decreased by 5%
compared to the same period in 2006. Similarly, True's average sales price
before transportation and hedging for the first three months of 2007 averaged
$7.26/mcf for its natural gas, 8% less than the $7.89/mcf received in 2006. In
comparison, True's average sales price for natural gas averaged $6.98/mcf for
the fourth quarter of 2006.
    For heavy crude oil, True received an average price before transportation
of $36.64/bbl during the first quarter of 2007, an increase of 42% over 2006
prices. The Bow River and Hardisty Heavy reference prices increased by 24% and
39%, respectively. The majority of True's heavy crude oil density ranges
between 11 and 16 degrees API consistent with the Hardisty Heavy reference
price. The price differential of heavy oil reference crude compared to light
oil has improved since last fall. In comparison, True received an average
heavy oil price of $34.82/bbl for the fourth quarter of 2006.
    For light oil, condensate and NGLs, True recorded an average $50.77/bbl
before hedging during the first quarter of 2007, 11% lower than the average
price received in 2006 due to a higher proportion of heavy crude oil. During
this same period, the Edmonton par price increased by 2%. In comparison, True
received an average oil price for light oil, condensate and NGLs of $60.34/bbl
in the fourth quarter of 2006. True's realized price decreased 16% from the
fourth quarter of 2006 to the first quarter of 2007, whereas the Edmonton par
price increased by 4% over the same period. The primary reason for this
difference is a 22% decrease in True's average price received for NGLs over
this period due to a current quarter adjustment of fourth quarter 2006 price
estimates.

    Revenue

    Revenue before other income and transportation for the three months ended
March 31, 2007 was $71.0 million, 53% greater than the $46.4 million in the
same period of 2006. The higher revenue was the result of significant growth
in production volumes for natural gas, crude oil, condensate and NGLs, despite
lower overall crude oil and natural gas prices.-------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s)                                               2007          2006
    -------------------------------------------------------------------------
    Light crude oil and condensate                       7,584         8,675
    NGLs                                                 2,091         1,278
    Heavy oil                                           14,362         5,977
    -------------------------------------------------------------------------
    Crude oil and NGLs                                  24,037        15,930
    Natural gas                                         46,982        30,514
    -------------------------------------------------------------------------
    Total revenue before other                          71,019        46,444
    Other                                                  177           (48)
    -------------------------------------------------------------------------
    Total revenue before royalties and hedging          71,196        46,396
    Gain (loss) on commodity contracts                     679             -
    -------------------------------------------------------------------------
    Total revenue before royalties                      71,875        46,396
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    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 May 8, 2007, the Trust has hedged volumes of 2,200 bbls/d of crude
oil and 25,000 GJ/d of natural gas for the second quarter 2007, 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 11,740 GJ/d of natural gas for the fourth
quarter 2007, and 2,000 bbls of crude oil for the first quarter of 2008. The
Trust will continue its hedging strategies during 2007 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 18 to the consolidated
financial statements for a detailed disclosure of all commodity contracts in
place as at May 8, 2007):

    Crude oil and liquids    Average Volumes (bbls/d)
    -------------------------------------------------------------------------
                                       Q2 2007   Q3 2007   Q4 2007   Q1 2008
    -------------------------------------------------------------------------
    Costless collars                         -         -     2,000     2,000
    Put option (price floor)             2,200     2,000         -         -
    -------------------------------------------------------------------------
    Total bbls/d                         2,200     2,000     2,000     2,000
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Average Price (US$/bbl WTI)
    -------------------------------------------------------------------------
                                       Q2 2007   Q3 2007   Q4 2007   Q1 2008
    -------------------------------------------------------------------------
    Collar ceiling price                     -         -     75.00     75.00
    Collar floor price                       -         -     65.00     65.00
    Put option price floor               64.55     60.00         -         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Natural gas    Average Volumes (GJ/d)
    -------------------------------------------------------------------------
                                       Q2 2007   Q3 2007   Q4 2007   Q1 2008
    -------------------------------------------------------------------------
    Costless collars                    15,000    15,000     5,050         -
    Fixed                               10,000    10,000     6,690         -
    -------------------------------------------------------------------------
    Total GJ/d                          25,000    25,000    11,740         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


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

    The following is a summary of the gain (loss) on commodity contracts for
the three months ended March 31, 2007:

    Commodity contracts
    -------------------------------------------------------------------------
                                     Crude Oil   Natural      2007      2006
    ($000s)                          & Liquids       Gas     Total     Total
    -------------------------------------------------------------------------
    Realized cash gain (loss) on
     contracts(1)                        1,447     1,697     3,144         -
    Unrealized gain (loss) on
     contracts                             (92)   (2,373)   (2,465)        -
    -------------------------------------------------------------------------
    Total gain (loss) on commodity
     contracts                           1,355      (676)      679         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes the amortization of crude oil and natural gas commodity
        contract premiums of $0.8 million and $1.6 million, respectively, for
        the three month period ended March 31, 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 current quarter results, 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 three months
ended March 31, 2007.

    Royalties

    For the three months ending March 31, 2007, total royalties were
$14.9 million, compared to $10.6 million incurred in the same period in 2006
up 40%, which was slightly less than the 53% increase in total revenue for the
period. Overall royalties as a percentage of revenue (after transportation
costs) in the first quarter of 2007 was 21%, compared with 23% in the same
period in 2006. The average royalty rate of 21% for the quarter includes the
impact of the reversal of certain overaccruals of light and heavy crude oil
royalties from prior periods of approximately $1.9 million. Excluding this
adjustment, the average royalty rate for the first quarter of 2007 would be
approximately 24%. This is consistent with the 25% average total royalty rate
for the fourth quarter of 2006.

    -------------------------------------------------------------------------
    Royalties by Commodity Type                  Three months ended March 31,
    ($000s, except where noted)                           2007          2006
    -------------------------------------------------------------------------
    Light crude oil and condensate                         251         1,518
      $/bbl                                               1.84         10.20
      Average light crude oil and condensate
       royalty rate (%)                                      3            18

    NGLs                                                   630           309
      $/bbl                                              11.70         12.15
      Average NGLs royalty rate (%)                         30            24

    Heavy Oil                                            1,519         1,099
      $/bbl                                               3.88          4.53
      Average heavy oil royalty rate (%)                    11            20

    Natural Gas                                         12,494         7,715
      $/mcf                                               1.93          1.99
      Average natural gas royalty rate (%)                  27            26

    -------------------------------------------------------------------------
    Total                                               14,894        10,641
    -------------------------------------------------------------------------
      $/boe                                               8.96         10.13
    -------------------------------------------------------------------------
      Average total royalty rate (%)                        21            23
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Royalties, by Type
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s)                                               2007          2006
    -------------------------------------------------------------------------
    Crown royalties, net of ARTC                         6,203         7,135
    Indian Oil and Gas Canada royalties                  3,142           782
    Freehold & GORR                                      5,549         2,724
    -------------------------------------------------------------------------
    Total                                               14,894        10,641
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Expenses
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s)                                               2007          2006
    -------------------------------------------------------------------------
    Production                                          14,972         9,167
    Transportation                                         689           973
    General and administrative                           4,904         2,597
    Interest and financing charges                       4,547         1,763
    Unit-based compensation                              1,112         1,410
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Expenses per boe
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($ per boe)                                           2007          2006
    -------------------------------------------------------------------------
    Production                                            9.01          8.73
    Transportation                                        0.41          0.93
    General and administrative                            2.95          2.47
    Interest and financing charges                        2.74          1.68
    Unit-based compensation                               0.67          1.34
    -------------------------------------------------------------------------


    Production Expenses

    For the three months ended March 31, 2007, production expenses totaled
$15.0 million, compared to $9.2 million recorded in 2006. During the first
quarter of 2007, production expenses averaged $9.01/boe, an increase of 3%
over the same period in 2006. This increase in production expenses is largely
due to a different property mix along with inflationary pressure on the costs
of services. True is forecasting production expenses to average $9.00/boe in
2007.

    Production Expenses, by Commodity Type
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except where noted)                           2007          2006
    -------------------------------------------------------------------------
    Light crude oil and condensate                       2,335         1,866
      $/bbl                                              17.08         12.54

    NGLs                                                   182           230
      $/bbl                                               3.38          9.05

    Heavy oil                                            5,405         1,927
      $/bbl                                              13.79          8.33

    Natural gas                                          7,050         5,144
      $/mcf                                               1.09          1.33

    -------------------------------------------------------------------------
    Total                                               14,972         9,167
    -------------------------------------------------------------------------
      $/boe                                               9.01          8.73
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Transportation

    Transportation costs are expected to be approximately 2% to 3% of gross
revenues for the 2007 year. For the three months ended March 31, 2007,
transportation costs averaged less than 1% due to the impact of the reversal
of overaccruals of certain product transportation estimates of $1.0 million
from prior periods.

    Operating Netback

    For the three months ended March 31, 2007, corporate field operating
netback (before hedging) was $24.36/boe compared to $24.43/boe in 2006.
Decreased commodity prices were offset by primarily reduced average royalties
due to prior period crude oil royalty adjustments. By comparison, corporate
field operating netback (before hedging) for the fourth quarter of 2006 was
$21.05/boe. After including hedging activities, corporate field operating
netback for the first quarter was $24.76/boe compared to $24.43/boe in 2006.

    Field Operating Netback - Corporate (before hedging)
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($/boe)                                               2007          2006
    -------------------------------------------------------------------------
    Sales                                                42.74         44.22
    Transportation                                       (0.41)        (0.93)
    Royalties                                            (8.96)       (10.13)
    Production expense                                   (9.01)        (8.73)
    -------------------------------------------------------------------------
    Field operating netback                              24.36         24.43
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Field operating netback for natural gas for the three months ended
March 31, 2007 decreased 8% to $4.09/mcf, compared to $4.44/mcf for 2006,
reflecting the weaker natural gas prices experienced. After including hedging
activities, field operating netback for natural gas for the first quarter of
2007 was $3.98/mcf compared to $4.44/mcf in 2006.

    Field Operating Netback - Natural Gas (before hedging)
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($/mcf)                                               2007          2006
    -------------------------------------------------------------------------
    Sales                                                 7.26          7.89
    Transportation                                       (0.15)        (0.13)
    Royalties                                            (1.93)        (1.99)
    Production expense                                   (1.09)        (1.33)
    -------------------------------------------------------------------------
    Field operating netback                               4.09          4.44
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Field operating netback for crude oil and NGLs averaged $24.06/bbl for the
three months ended March 31, 2007, up 15% compared to $20.95/bbl for 2006,
compared to an 5% increase in the crude oil and NGLs sales price. Prior period
adjustments recorded in the quarter for transportation and royalties
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 $26.39/boe compared to $20.95/boe in 2006.

    Field Operating Netback - Crude Oil and NGLs (before hedging)
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($/bbl)                                               2007          2006
    -------------------------------------------------------------------------
    Sales                                                41.26         39.28
    Transportation                                        0.52         (1.19)
    Royalties                                            (4.12)        (7.22)
    Production expense                                  (13.60)        (9.92)
    -------------------------------------------------------------------------
    Field operating netback                              24.06         20.95
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    General and Administrative

    Net general and administrative expenses for the three months ended
March 31, 2007 were $4.9 million compared to $2.6 million for the same period
in 2006. On a per-unit of production basis, general and administrative
expenses ("G&A") in the first quarter of 2007 is $2.95/boe, compared to
$2.47/boe in 2006.
    The increase in the G&A on a per boe basis from the first quarter of 2006
to the same period in 2007 is consistent with the increase in staffing levels,
higher compensation and other administrative costs as a result of two
acquisitions completed in 2006.

    General and Administrative Expenses
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except where noted)                           2007          2006
    -------------------------------------------------------------------------
    Gross expenses                                       6,410         3,813
    Capitalized                                           (693)         (536)
    Recoveries                                            (813)         (680)
    -------------------------------------------------------------------------
    Net expenses                                         4,904         2,597
    -------------------------------------------------------------------------
    Net expenses, per unit ($/boe)                        2.95          2.47
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    G&A expenses for the three month period ended March 31, 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 $4.5 million of interest and financing charges the three
months ended March 31, 2007 compared to $1.8 million in the same period of
2006. The increase in interest and financing charges for the 2007 first
quarter compared to the same period in 2006 is consistent with the increase in
bank debt and convertible debentures. True's net debt at March 31, 2007 of
$289.1 million includes the $78.2 million liability portion of convertible
debentures, $178.4 million of bank debt and the balance a working capital
deficiency.

    Interest and Financing Charges
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except where noted)                           2007          2006
    -------------------------------------------------------------------------
    Interest and financing charges                       4,547         1,763
    Interest and financing charges ($/boe)                2.74          1.68

    Net debt including convertible debentures
     at quarter end                                    289,072       139,611
    Debt to periods cash flow from operations
     ratio annualized                                     2.4x          1.8x

    Net debt excluding convertible debentures
     at quarter end                                    210,829       139,611
    Debt to periods cash flow from operations
     ratio annualized                                     1.8x          1.8x
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Unit-Based Compensation

    Non-cash unit-based compensation expense for the three months ended March
 1, 2007 was $1.1 million compared to $1.4 million in 2006. The slight
decrease in the 2007 expense reflects no further new incentive rights being
granted since 2006 and only the charge to income in the period in relation to
pre-2007 grants.

    Capital Expenditures

    True invested $45.8 million on exploration and development activities
during the first three months of 2007, compared to $22.5 million in the same
period in 2006. During the first quarter of 2007, True achieved a 97% success
rate in the drilling or participation in 34 (24.0 net) wells, resulting in 16
(8.6 net) natural gas wells, 15 (12.9 net) oil wells, 2 (2.0 net)
stratagraphic test oil wells and 1 (0.5 net) dry holes. True successfully
participated in or drilled 19 (10.4 net) wells in Alberta, and 14 (13.1 net)
wells in Saskatchewan. The focus of True's drilling program for the first
quarter was on the West Central Alberta area and the further execution of
True's SAGD project in the Kerrobert, Saskatchewan heavy oil area.

    Capital Expenditures
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s)                                               2007          2006
    -------------------------------------------------------------------------
    Lease acquisitions and retention                       791         1,875
    Geological and geophysical                           6,919           664
    Drilling and completion costs                       33,259        17,285
    Facilities and equipment                             4,872         2,637
    -------------------------------------------------------------------------
      Exploration and development                       45,841        22,461
    Corporate and property acquisitions                    705           124
    -------------------------------------------------------------------------
      Total capital expenditures - cash                 46,546        22,585
    Property dispositions - cash                       (18,443)            -
    -------------------------------------------------------------------------
      Total net capital expenditures - cash             28,103        22,585
    -------------------------------------------------------------------------

    Other - non-cash (1)                                   624           635
    -------------------------------------------------------------------------
      Total capital expenditures                        28,727        23,220
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Other includes current period's asset retirement obligations and unit
        based compensation capitalized.True holds an extensive land base. At March 31, 2007, True has
approximately 696,000 net undeveloped acres of land of its total developed and
undeveloped net acreage position of 1,115,000 net acres in Saskatchewan,
Alberta, and British Columbia.
    Dispositions during the first three months of 2007 consist of two
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 both property sales after adjustments was an aggregate of
$18.4 million.
    At the end of the first quarter of 2007, True had no formal drilling
commitments. True expects to be making further drilling commitments during the
latter part of 2007 to carry out the remainder of its 2007 capital program.

    Depletion, Depreciation and Accretion

    Depletion, depreciation and accretion (site restoration) expense for the
first three months of 2007 was $47.5 million, compared to the $29.2 million
for the same period in 2006, reflecting the acquisition of Shellbridge in 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 first quarter of 2007 of $28.56/boe was lower than
$29.21/boe DD&A rate for the fourth quarter of 2006, which reflects the
adjustment after a fourth quarter 2006 ceiling test impairment was recorded.
    For the three month period ended March 31, 2007, True has excluded from
the depletion calculation $46.9 million for undeveloped land and $48.7 million
for estimated salvage.Depletion, Depreciation and Accretion Costs
    -------------------------------------------------------------------------
                                                 Three months ended March 31,
    ($000s, except where noted)                           2007          2006
    -------------------------------------------------------------------------
    Depletion                                           45,636        25,163
    Depreciation                                         1,311         3,837
    Accretion                                              511           212
    -------------------------------------------------------------------------
      Total                                             47,458        29,212
    -------------------------------------------------------------------------
    Per unit ($/boe)                                     28.56         27.81
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------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 March 31, 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 March 31, 2007, the Trust calculated the ceiling test using prices of
$40.51/bbl for heavy oil, $67.89/bbl for light and medium gravity oil, and
$47.33/bbl for NGLs, and $8.33/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 in special meeting costs within the statement of
income for the period.

    Asset Retirement Obligation

    As at March 31, 2007, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $26.4 million, compared to $10.9 million at March 31,
2006, for future abandonment and reclamation of the Trust's properties. For
the three month period ended March 31, 2007, the ARO decreased by $0.2 million
total as a result of accretion expense of $0.5 million, $0.8 million of
liabilities released on dispositions and included $0.1 million net changes in
estimates and development activities.

    Income Taxes

    For the first three months of 2007, the Trust has recorded a provision
for capital taxes of $0.9 million compared to $0.6 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. Increased gross sales
revenue from Saskatchewan based properties in is the reason for the quarter
over quarter increase in capital taxes. 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 operating companies' assets and liabilities. For the first three
months of 2007, the Trust recognized a future income tax recovery provision of
$12.8 million compared to a recovery provision of $13.2 million in the same
period 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 the Trust's structure, payments are made between the operating
subsidiaries and the Trust transferring income and future income tax liability
to the unitholders. Therefore, it is currently expected, based on existing
legislation, that no cash income taxes are to be paid by the operating
subsidiaries. As such, the future income tax liability recorded on the balance
sheet will be recovered through earnings over time. As at March 31, 2007, the
operating subsidiaries have a future income tax liability balance of
$111.4 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 March 31, 2007 the Trust and operating subsidiaries of the Trust had
approximately $522 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       334,445       349,550
    Undepreciated capital cost                 -       150,768       150,768
    Loss carryforwards (expire
     through 2026)                             -         6,256         6,256
    Unit issue costs                       8,931         6,228        15,159
    Other                                      -           243           243
    -------------------------------------------------------------------------
                                          24,036       497,940       521,976
    -------------------------------------------------------------------------

    The October 31, 2006 announcement of the Tax Fairness Plan by the Federal
Government anticipates a distribution tax on distributions from publicly
traded income trusts and similar structures. For existing income trusts and
similar structures, the government is proposing a four-year transition period.
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. Refer
to "Business Risks and Uncertainties" of the Trust's 2006 MD&A for further
details.
    As at March 31, 2007, and until third reading of the Bill in Parliament,
current and future income taxes have not been adjusted as a result of this
announcement. If implemented as currently proposed, the Trust would be
required to recognize in its accounts, in the period in which the change is
substantively enacted, future income taxes on temporary differences in the
Trust.

    Distributions

    Trust unitholders who held their trust units throughout the first quarter
of 2007 received distributions of $0.24 per unit. For the three months ended
March 31, 2007 the Trust declared $16.9 million in total distributions as
follows:

    -------------------------------------------------------------------------
    ($000s, except per unit amount)               Distribution
    Three months ended March 31, 2007                 Per Unit         Total
    -------------------------------------------------------------------------

    Distributions paid                             $      0.24   $    16,866
    -------------------------------------------------------------------------

    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(3)      0.631(3)
    -------------------------------------------------------------------------
    2007 year to date                      0.240
    ---------------------------------------------
    Cumulative to March 31, 2007           3.360
    -------------------------------------------------------------------------

    (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) A portion 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:

    -------------------------------------------------------------------------
    Ex-distribution                                           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(1)      May 31, 2007         June 15, 2007           0.08(2)
    June 27, 2007(1)     June 29, 2007        July 16, 2007           0.08(2)
    -------------------------------------------------------------------------

    (1) Anticipated ex-distribution dates for May and June. 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 three months of 2007, the distributions were funded
directly from cash flows from operating activities.
    The Trust declared and paid distributions of $0.12 per unit on
February 15, 2007 and March 15, 2007. 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. The Board of True reviewed the go-forward
strategy for the distribution level to provide a balance between providing
income to unitholders and budgeting for capital expenditures required to
further develop the Trust's land base. In a press release dated April 17,
2007, the Board announced it has set a distribution policy for the second
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.

    Foreign Ownership Update

    Based on information from Trust records and information provided by
intermediaries holding Trust units for others, we estimate that, as of
April 20, 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

    True's net debt as at March 31, 2007 was $289.1 million, representing
$178.4 million outstanding on the credit facility, $78.2 million in
convertible debentures (liability component) and the balance a net working
capital deficiency.
    The current credit facility consists of a $15 million demand operating
facility provided by one Canadian bank and a $210 million extendible revolving
term credit facility syndicated by the Canadian chartered bank, a U.S. bank, a
foreign bank and one institutional lender. The revolving period on the
revolving term credit facility ends on June 29, 2007, 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 revised credit facility are disclosed in note 7 of the consolidated
financial statements. As at March 31, 2007, there is approximately $45 million
available 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 will 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 April 30, 2007 the Trust had outstanding a total of 5,342,166
incentive units exercisable at an average exercise price of $13.51 per unit,
401,964 exchangeable shares (convertible, as at April 30, 2007 into an
aggregate of 303,547 trust units, subject to further adjustments based on
distributions made on trust units) and 70,276,890 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 is continuing 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 plans to convert a number
of existing wells to steam injectors and drill 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 95 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 Trust currently anticipates spending
approximately $80 million in total capital spending for 2007. The remainder of
the 2007 capital program will emphasize True's core areas of West Central
Alberta and West Central Saskatchewan. These expenditures will be mainly in
the third quarter, following up on successful development campaigns in the
first quarter. It will include facility modifications and conversion of
existing producers to steam injection service at the Kerrobert SAGD project.
Continued participation in what has been a highly successful non-operated
drilling program in West Central Alberta will also carry on in the third
quarter.
    The Trust currently anticipates that 2007 year average production will be
approximately 18,000 to 19,000 boe/d, weighted approximately 64% toward
natural gas. True further anticipates the US$/Cdn.$ exchange rate to average
0.90 through the 2007 year.
    The Trust continues to maintain a large undeveloped land base of
approximately 1.0 million (0.7 million net) acres and has identified a multi-
year drilling inventory of over 600 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 March 31, 2007. Except as described
in Note 3 of the attached unaudited interim consolidated financial statements,
there were no changes in accounting policies for the three month period ended
March 31, 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 circumstance.

    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 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 March 31, 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 March 31, 2007 and average production volumes of
18,500 boe/d during that period, as well as the same level of debt outstanding
at March 31, 2007. Diluted weighted average trust units is based upon the
first 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
                                                     Cash Flow          from
                                                          from    Operations
                                                    Operations   Per Diluted
                                                   (annualized)         Unit
    -------------------------------------------------------------------------
    Sensitivity Analysis                                ($000s)           ($)
    -------------------------------------------------------------------------
    Change of US $1/bbl WTI                              2,800          0.04
    Change of $0.10/ mcf                                 2,600          0.04
    Change of US $0.01 Cdn/ US exchange rate             1,400          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 first
quarter of 2007.

    -------------------------------
    2007 - Quarter ended
     (unaudited)
    ($000s, except
     per unit amounts)    March 31
    -------------------------------
    Revenues before
     royalties and
     hedging                71,196
    Cash flow from
     operations(1)          29,988
    Cash flow from
     operations per
     unit(1)
      Basic                  $0.43
      Diluted                $0.42
    Net income (loss)       (8,571)
    Net income (loss)
     per unit
      Basic                 $(0.12)
      Diluted               $(0.12)
    Net capital
     expenditures (cash)    28,103
    Distributions declared  16,866
    Distributions per unit   $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 fourth
quarter of 2006 to the first 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 since primarily since
the November 2005 reverse takeover of TKE 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 March 31 and December 31 (unaudited)
    -------------------------------------------------------------------------

    ($000s)                                               2007          2006
    -------------------------------------------------------------------------

    ASSETS
    Current assets
      Accounts receivable                         $     62,508   $    73,199
      Deposits and prepaid expenses                      3,247         7,928
      Capital taxes receivable                              41
      Commodity contract asset (note 18)                   853             -
                                                  ---------------------------
                                                        66,649        81,127
    Property, plant and equipment (note 6)             912,511       931,979
    Deferred financing charges (note 8)                      -         3,552
                                                  ---------------------------
    Total assets                                  $    979,160   $ 1,016,658
                                                  ---------------------------
                                                  ---------------------------

    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities    $     97,515   $   107,431
      Distribution payable to unitholders                    -         8,433
      Capital taxes payable                                  -         1,513
      Current portion of obligations under
       capital lease                                        29           111
      Commodity contract liability (note 18)             1,555             -
                                                  ---------------------------
                                                        99,099       117,488
    Long-term debt (note 7)                            178,379       157,904
    Convertible debentures (note 8)                     78,243        81,551
    Asset retirement obligations (note 9)               26,421        26,605
    Future income taxes (note 14)                      111,372       123,861
                                                  ---------------------------
    Total liabilities                                  493,514       507,409
                                                  ---------------------------

    NON-CONTROLLING INTEREST
      Exchangeable shares of subsidiary (note 10)        4,099         4,153

    UNITHOLDERS' EQUITY
      Unitholders' capital (note 11)                   876,920       876,904
      Equity component of convertible
       debentures (note 8)                               5,119         5,119
      Contributed surplus (note 12)                     14,000        12,818
      Deficit                                         (415,085)     (389,745)
      Accumulated other comprehensive income               593             -
                                                  ---------------------------
    Total unitholders' equity                          481,547       505,096
                                                  ---------------------------
    Total liabilities and unitholders' equity     $    979,160   $ 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 months ended March 31 (unaudited)

    ($000s)                                               2007          2006
    -------------------------------------------------------------------------

    REVENUES
      Petroleum and natural gas sales             $     71,196        46,396
      Royalties                                        (14,894)      (10,641)
      Gain on commodity contracts (note 18)                679             -
                                                  ---------------------------
                                                        56,981        35,755
                                                  ---------------------------
    EXPENSES
      Production                                        14,972         9,167
      Transportation                                       689           973
      General and administrative                         4,904         2,597
      Interest and financing charges                     4,547         1,763
      Unit-based compensation (note 12)                  1,112         1,410
      Depletion, depreciation and accretion             47,458        29,212
      Special meeting costs (note 15)                    3,805             -
                                                  ---------------------------
                                                        77,487        45,122

    INCOME (LOSS) BEFORE TAXES                         (20,506)       (9,367)

    TAXES (note 14)
      Capital taxes                                        932           571
      Future income taxes (recovery)                   (12,829)      (13,233)
                                                  ---------------------------
                                                       (11,897)      (12,662)

    NET INCOME (LOSS) BEFORE
     NON-CONTROLLING INTEREST                           (8,609)        3,295

    Non-controlling interest (note 10)                     (38)           36
                                                  ---------------------------
    NET INCOME (LOSS)                                   (8,571)        3,259

    Net changes in cash flow hedges
     (net of tax of $1.6 million)                       (3,156)            -
                                                  ---------------------------
    COMPREHENSIVE INCOME (LOSS)                   $    (11,727)  $     3,259
    -------------------------------------------------------------------------

    Net income (loss) per trust unit (note 16)
      Basic                                       $      (0.12)  $      0.09
      Diluted                                     $      (0.12)  $      0.09
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying selected notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF UNITHOLDERS' EQUITY
    For the three months ended March 31 (unaudited)

    ($000s)                                               2007          2006
    -------------------------------------------------------------------------

    UNITHOLDERS' CAPITAL
      Balance, beginning of period                $    879,904   $   418,968
      Exchangeable shares converted (note 11)               16         2,864
      Units issued pursuant to DRIP                          -         1,317
                                                  ---------------------------
      Balance, end of period                           876,920       423,149
                                                  ---------------------------

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

    CONTRIBUTED SURPLUS
      Balance, beginning of period                      12,818         5,127
      Unit-based compensation expense (note 12)          1,182         1,630
                                                  ---------------------------
      Balance, end of period                            14,000         6,757
                                                  ---------------------------

    DEFICIT
      Balance, beginning of period                    (389,745)      (31,826)
      Net income (loss)                                 (8,571)        3,259
      Impact of  change in accounting policy
       for financial instruments on
       January 1, 2007 (net of tax of
       $0.05 million) (note 3)                              97             -
      Distributions declared                           (16,866)      (26,150)
                                                  ---------------------------
      Balance, end of period                          (415,085)      (54,717)
                                                  ---------------------------

    ACCUMULATED OTHER COMPREHENSIVE INCOME
      Balance, beginning of period                           -             -
      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 $1.6 million)                     (3,156)
                                                  ---------------------------
      Balance, end of period                               593             -
                                                  ---------------------------

    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    TOTAL UNITHOLDERS' EQUITY                      $   481,547   $   375,189
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying selected notes to the consolidated financial statements.



    TRUE ENERGY TRUST
    CONSOLIDATED STATEMENTS OF CASH FLOWS
    For the three months ended March 31 (unaudited)

    ($000s)                                               2007          2006
    -------------------------------------------------------------------------

    Cash provided by (used in):
    CASH FLOW FROM OPERATING ACTIVITIES
    Net income (loss)                              $    (8,571)  $     3,259
    Items not involving cash:
      Non-controlling interest (note 10)                   (38)           36
      Depletion, depreciation and accretion             47,458        29,212
      Unit-based compensation (note 12)                  1,112         1,410
      Unrealized loss on commodity contracts
       (note 18)                                         2,465             -
      Accretion on convertible debentures (note 8)         391             -
      Future income taxes (recovery)  (note 14)        (12,829)      (13,233)
      Capital taxes                                          -        (1,689)
                                                  ---------------------------
                                                        29,988        18,995
      Change in non-cash working capital (note 13)      18,227        (8,386)
                                                  ---------------------------
                                                        48,215        10,609
                                                  ---------------------------

    CASH FLOW FROM (USED IN) FINANCING ACTIVITIES
      Increase in bank debt                             21,495        38,488
      Obligations under capital lease                      (82)          (48)
      Payment of cash component of distributions       (25,299)      (24,774)
                                                  ---------------------------
                                                        (3,886)       13,666
      Change in non-cash working capital (note 13)          57             -
                                                  ---------------------------
                                                        (3,829)       13,666
                                                  ---------------------------

    CASH FLOW FROM (USED IN) INVESTING ACTITIVIES
      Additions to property, plant and equipment       (46,546)      (22,585)
      Proceeds on sale of property, plant
       and equipment                                    18,443             -
                                                  ---------------------------
                                                       (28,103)      (22,585)
      Change in non-cash working capital (note 13)     (16,283)       (1,690)
                                                  ---------------------------
                                                       (44,386)      (24,275)
                                                  ---------------------------

    Change in cash                                           -             -

    Cash, beginning of year                                  -             -
    -------------------------------------------------------------------------

    Cash, end of year                              $         -   $         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying selected notes to the consolidated financial statements.



    SELECTED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

    March 31, 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
        March 31, 2007                      Cost   depreciation        value
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                  $ 1,341,148   $   430,934   $   910,214
        Office furniture and
         equipment                         3,292           995         2,297
        ---------------------------------------------------------------------
                                     $ 1,344,440   $   431,929   $   912,511
        ---------------------------------------------------------------------

        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 $46.9 million for undeveloped land and
        $48.7 million for estimated salvage from the depletion calculation
        during the three month period ended March 31, 2007.

        For the three month period ended March 31, 2007, the Trust
        capitalized $1.0 million of general and administrative expenses and
        $0.1 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 $210 million extendible revolving term credit
        facility syndicated by the Canadian chartered bank, a U.S. bank, a
        foreign bank 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 $1.2 million at March 31, 2007, is now netted
        against long-term debt and amortized on the effective interest basis.

        As at March 31, 2007, there was $nil million outstanding under the
        operating facility and $179.6 million outstanding under the revolving
        term credit facility. As at March 31, 2007, there is approximately
        $45.4 million available under the facility.

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

        The revolving period on the new revolving term credit facility ends
        on June 29, 2007, 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 March 31, 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 three month period ended March 31, 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                              -           391             -
        ---------------------------------------------------------------------
        Balance, March 31, 2007           86,250   $    78,243   $     5,119
        ---------------------------------------------------------------------

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

        Deferred financing charges
        ---------------------------------------------------------------------
        ($000s)                                       March 31,  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 $73.7 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)                                       March 31,  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                                         90         1,210
        Changes in prior period estimates                   14           810
        Liabilities released on dispositions              (799)         (641)
        Accretion expense                                  511         1,065
        ---------------------------------------------------------------------
        Asset retirement obligation, end of period $    26,421   $    26,605
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    10. EXCHANGEABLE SHARES OF SUBSIDIARY

        ---------------------------------------------------------------------
                              March 31, 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)              -           (38)            -          (803)
        Exchanged for
         trust units        (1,572)          (16)     (385,022)       (4,753)
        ---------------------------------------------------------------------
        Balance, end
         of period         401,964   $     4,099       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 March 31, 2007 was 0.75516. 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

           ------------------------------------------------------------------
                               March 31, 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 to
            acquire
            Prairie
            Schooner             -             -    25,759,563       341,089
           (net of issue
            costs of
            $1.8 million)
           Issued to
            acquire
            Shellbridge          -             -     4,389,366        67,669
           (net of issue
            costs of
            $0.6 million)
           Exchangeable
            shares
            converted        1,187            16       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   70,276,890   $   876,920    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 three month ended and as at March 31,
           2007.

           Unit Rights Continuity
           ------------------------------------------------------------------
                                                       Average
                                                      Exercise
                                                       Price(a)       Number
           ------------------------------------------------------------------
           Balance, December 31, 2006              $     14.18     5,429,831
           Granted                                 $         -             -
           Forfeited                               $     14.64      (202,498)
           ------------------------------------------------------------------
           Balance, March 31, 2007                 $     13.93     5,227,333
           ------------------------------------------------------------------



    Unit Rights Outstanding
    -------------------------------------------------------------------------
                                                             Exercisable
                                   Outstanding
                                      Exercise                      Exercise
    Exercise                             Price                         Price
    Price         Exercise              Net of  Remaining             Net of
    Before           Price         At    Price      Cont-        At    Price
    Price           Net of   March 31,   Reduc-  ractual   March 31,   Reduc-
    Reductions  Reductions       2007  tions(b)   Life(b)      2007  tions(b)
    -------------------------------------------------------------------------
     $10.58      $ 9.91     1,494,000  $ 10.16       4.5          -      N/A
      - $12.53    - $11.76

     $13.74      $12.39       668,500  $ 12.82       4.3          -      N/A
      - $14.83    - $13.56

     $15.92      $14.17       227,500  $ 14.37       4.1     29,166  $ 14.69
      - $16.70    - $14.92

     $18.25      $15.91     2,837,333  $ 16.13       3.6  1,891,554  $ 16.13
      - $20.98    - $18.86
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
     $10.58      $ 9.91     5,227,333  $ 13.93       4.0  1,920,720  $ 16.11
      - $20.98    - $18.86
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 three months ended
           March 31, 2007, the Trust matched $0.1 million under the plan.

    12. CONTRIBUTED SURPLUS

        ---------------------------------------------------------------------
        ($000s)                                       March 31,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------
        Balance, beginning of period               $    12,818   $     5,127
        Unit-based compensation expense                  1,182         7,691
        ---------------------------------------------------------------------
        Balance, end of period                     $    14,000   $    12,818
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Unit-based Compensation

        During the three months ended March 31, 2007, the Trust granted nil
        unit incentive rights to employees and directors. During the quarter,
        the Trust recorded unit-based compensation of $1.2 million, of which
        $0.07 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. During
        the three month period ended March 31, 2007, there were no new
        incentive rights granted.

    13. SUPPLEMENTAL CASH FLOW INFORMATION

        Cash Interest and Taxes Paid
        ---------------------------------------------------------------------
                                                 Three months ended March 31,
        ($000s)                                           2007          2006
        ---------------------------------------------------------------------
        Cash paid:
        Interest                                   $     2,560   $       988
        Taxes (net of refunds)                     $     2,493   $     2,654
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        Change in Non-cash Working Capital
        ---------------------------------------------------------------------
                                                 Three months ended March 31,
        ($000s)                                           2007          2006
        ---------------------------------------------------------------------
        Changes in non-cash working capital items:
          Accounts receivable                    $     10,691   $    (8,755)
          Deposits and prepaid expenses                 2,783          (386)
          Accounts payable and accrued liabilities     (9,918)         (935)
          Capital taxes receivable/payable             (1,555)            -
        ---------------------------------------------------------------------
                                                  $      2,001   $   (10,076)
        ---------------------------------------------------------------------

        Changes related to operating activities   $     18,227   $    (8,386)
        Changes related to financing activities             57             -
        Changes related to investing activities        (16,283)       (1,690)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
                                                  $      2,001   $   (10,076)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    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. The Trust does not recognize any future income tax assets
        or liabilities on "temporary differences" (difference between the
        accounting basis and tax basis of assets and liabilities) in the
        Trust. As at March 31, 2007, this "temporary difference" (tax basis
        exceeds accounting basis) is $11.8 million. The Trust's subsidiaries
        are subject to income taxation and provide income tax obligations
        based upon statutory corporate rates.

        As at March 31, 2007, the Trust's subsidiaries have tax basis of
        approximately $498 million that is available to shelter future
        taxable income. Included in this tax basis are estimated non-capital
        loss carry forwards of approximately $6.2 million that expire in
        years through 2026. In addition, the Trust has approximately
        $24 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 33.3% (2006: 37.5%) to earnings before income
        taxes. This difference results from the following items:

        ---------------------------------------------------------------------
                                                 Three months ended March 31,
        ($000s)                                           2007          2006
        ---------------------------------------------------------------------
        Expected income tax expense (recovery)     $    (6,819)  $    (3,512)
        Amount in Trust income                          (7,090)       (9,591)
        Crown royalties and charges                          -           989
        Resource allowance                                   -          (990)
        Unit based compensation expense                    370           529
        Change in enacted tax rates                        918          (579)
        Other                                             (208)          (79)
        ---------------------------------------------------------------------
        Future income tax expense (recovery)           (12,829)      (13,233)
        Capital tax expense                                932           571
        ---------------------------------------------------------------------
        Total tax expense (recovery)               $   (11,897)  $   (12,662)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The October 31, 2006 announcement of the Tax Fairness Plan by the
        Federal Government anticipates a distribution tax on distributions
        from publicly traded income trusts and similar structures. For
        existing income trusts and limited partnerships, the government is
        proposing a four-year transition period. 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.

        The government's plans must first be enacted in Parliament and it may
        be some time before the plans, translated into legislation, are
        substantially enacted, particularly given the fact that there is a
        minority government in place. As such, as at March 31, 2007, and
        until third reading of the Bill in Parliament, current and future
        income taxes have not been adjusted as a result of this recent
        announcement. If implemented as currently proposed, the Trust would
        be required to recognize in its accounts, in the period in which
        the change is substantively enacted, future income taxes on temporary
        differences in the Trust.

    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 in special meeting costs
        within the statement of income for the period.

    16. PER TRUST UNIT AMOUNTS

        ---------------------------------------------------------------------
                                                 Three months ended March 31,
                                                          2007          2006
        ---------------------------------------------------------------------
        Basic trust units outstanding               70,276,890    36,399,240
        Dilutive effect of:
          Trust unit incentive rights outstanding    5,227,333     3,273,165
          Units issuable for exchangeable shares       303,547       334,372
          Units issuable for convertible debentures  5,390,625             -
        ---------------------------------------------------------------------
        Diluted trust units outstanding             81,198,395    40,006,777
        ---------------------------------------------------------------------
        Weighted average trust units outstanding    70,275,770    36,296,327
        Dilutive effect of exchangeable shares,
         trust unit incentive plan and
         convertible debentures(1)                     303,547       334,372
        ---------------------------------------------------------------------
        Diluted weighted average trust units
         outstanding                                70,579,317    36,630,699
        ---------------------------------------------------------------------
        (1) A total of 5,227,333 (2006: 3,273,165) 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 March 31, 2007 as
            they were not dilutive.

    17. RELATED PARTY TRANSACTIONS

        During the three month period ended March 31, 2007, the Trust paid
        $0.9 million (2006: $0.1 million) for legal services provided by a
        firm in which a current director 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. FINANCIAL INSTRUMENTS

        At March 31, 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                   $       853   $       853
        Commodity contract liability                     1,555         1,555
        Long-term debt                                 178,379       178,379
        Convertible debentures
          Debt component                  78,243
          Equity component                 5,119
                                    ---------------------------
                                                        83,362        81,300
        ---------------------------------------------------------------------

        The carrying values of accounts receivable, 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 March 31, 2007.

        For the three month period ended March 31, 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                            $       679
        Interest expense                                               4,547
        ---------------------------------------------------------------------

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

    -------------------------------------------------------------------------
                                               Price       Price
    Type               Period      Volume      Floor      Ceiling      Index
    -------------------------------------------------------------------------
    Oil put       Jan. 1, 2007 to   1,000     $70.00 US           -      WTI
     option          June 30, 2007   bbl/d

    Oil put       April 1, 2007 to  1,200     $60.00 US           -      WTI
     option          June 30, 2007   bbl/d

    Oil put       July 1, 2007 to   2,000     $60.00 US           -      WTI
     option(1)      Sept. 30, 2007   bbl/d

    Oil collar(1) Oct. 1, 2007 to   2,000     $65.00 US   $75.00 US      WTI
                    March 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   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) These contracts were entered into subsequent to March 31, 2007.


        For the three month period ended March 31, 2007, the gain (loss) on
        commodity contracts was comprised of the following:

        ---------------------------------------------------------------------
        ($000s)                                    Adjustments
                                     Activity in       for new
                                      the period   standards(1)        Total
        ---------------------------------------------------------------------

        Gain (loss) on commodity
         contracts
          Realized(2)                $     5,576   $    (2,432)  $     3,144
          Unrealized(3)                   (9,607)        7,142        (2,465)
        ---------------------------------------------------------------------
                                     $    (4,031)  $     4,710   $       679
        ---------------------------------------------------------------------

        (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